WSR 21-02-022

PERMANENT RULES

UTILITIES AND TRANSPORTATION

COMMISSION

[Dockets UE-191023 and UE-190698, General Order 601—Filed December 28, 2020, 12:41 p.m., effective December 31, 2020]

In the matter of adopting rules relating to clean energy implementation plans (CEIPs) and compliance with the Clean Energy Transformation Act (CETA); and WAC 480-100-238, relating to integrated resource planning.

The Washington utilities and transportation commission (commission) adopts rules implementing chapter 19.405 RCW, CETA, and revisions to chapters 19.280 and 80.28 RCW. The commission's goals in this rule making are to implement sections of this new legislation, incorporate changes to existing rules, identify commission decisions and preferred practices implementing CETA, and engage with stakeholders to address and resolve ambiguity where appropriate. The rules adopted here today include two primary sections addressing CETA's CEIPs and integrated resource plans (IRPs).

1STATUTORY OR OTHER AUTHORITY:The commission takes this action under Notice No. WSR 20-21-053, filed with the code reviser on October 14, 2020. The commission has authority to take this action pursuant to RCW 80.01.040, 80.04.160, and chapters 80.28, 19.280, and 19.405 RCW.

2STATEMENT OF COMPLIANCE: This proceeding complies with the Administrative Procedure Act (chapter 34.05 RCW), the State Register Act (chapter 34.08 RCW), the State Environmental Policy Act of 1971 (chapter 43.21C RCW), and the Regulatory Fairness Act (chapter 19.85 RCW).

3DATE OF ADOPTION: The commission adopts these rules on the date this order is entered.

4CONCISE STATEMENT OF PURPOSE AND EFFECT OF THE RULES:RCW 34.05.325(6) requires the commission to prepare and publish a concise explanatory statement about adopted rules. The statement must identify the commission's reasons for adopting the rules, describe the differences between the version of the proposed rules published in the register and the rules adopted (other than editing changes), summarize the comments received regarding the proposed rule changes, and state the commission's responses to the comments reflecting the commission's consideration of them.

5 To avoid unnecessary duplication in the record of this docket, the commission designates the discussion in this order, including appendices, as its concise explanatory statement. This order provides a complete but concise explanation of the agency's actions and its reasons for taking those actions.

6REFERENCE TO AFFECTED RULES: This order adopts the following sections of the Washington Administrative Code: Adopting WAC 480-100-600 Purpose, 480-100-605 Definitions, 480-100-610 Clean energy transformation standards, 480-100-620 Content of an IRP, 480-100-625 IRP development and timing, 480-100-630 IRP advisory groups, 480-100-640 CEIP, 480-100-645 Process for review of CEIP and updates, 480-100-650 Reporting and compliance, 480-100-655 Public participation in a CEIP, 480-100-660 Incremental cost of compliance, and 480-100-665 Enforcement.

7PREPROPOSAL STATEMENT OF INQUIRY AND ACTIONS THEREUNDER: On November 7, 2019, the commission filed in Docket UE-190698 a Preproposal statement of inquiry (CR-101) at WSR 19-23-005. The statement informed interested persons that the commission was initiating a rule making to incorporate statutory changes made to WAC 480-100-238, the commission's rule on IRP, since 2006, including CETA, and to consider policy and process changes to create more efficient rules that adapt to a changing energy landscape.1 The commission served notice of the CR-101 and rule making on everyone on the commission's list of persons requesting such information pursuant to RCW 34.05.320(3) and the commission's lists of electric companies and utility attorneys.

8 On January 15, 2020, the commission filed in Docket UE-191023 a CR-101 at WSR 20-03-107, initiating a rule making to develop rules implementing chapter 19.405 RCW, in particular, rules for CEIP, demonstrating compliance with CETA; statutory revisions to RCW 80.84.010, and additions to chapter 80.28 RCW, as enacted in CETA. The commission served notice of the CR-101 and rule making on everyone on the commission's list of persons requesting such information pursuant to RCW 34.05.320(3) and the commission's lists of electric companies and utility attorneys.

11CONSOLIDATION:On August 18, 2020, the commission filed a CR-101 at WSR 20-17-120 consolidating Dockets UE-191023 and UE-190698 into one rule making. The commission also informed persons of this consolidation by providing notice and the CR-101 to everyone on the commission's list of persons requesting such information pursuant to RCW 34.05.320(3), the commission's lists of electric companies and utility attorneys, and all persons who had expressed interest in Dockets UE-190698 and UE-191023.

12SMALL BUSINESS ECONOMIC IMPACT:On August 31, 2020, the commission issued a small business economic impact statement (SBEIS) questionnaire to all interested persons in the consolidated dockets. The commission received one response to this questionnaire on October 1, 2020, from Puget Sound Energy (PSE), which asserted in its response that it is likely to incur increased costs from the proposed rules. PSE, however, does not qualify as a small business under chapter 19.85 RCW, and the approximate costs of compliance, $6 million, are minor in comparison to PSE's 2019 annual electric revenue of $2.1 billion. In addition, PSE may recover a significant portion of the increased costs from its customers through general rate proceedings.

13 The commission's internal analysis shows that any cost incurred by small businesses in this rule making is either the result of implementing a statutory requirement or based on voluntary participation in a utility's IRP or CEIP public process, membership in a utility advisory group, providing public comment on a utility plan to the commission, or intervening in a commission adjudicatory proceeding. Additionally, a utility's small business customers are represented in commission proceedings by the public counsel unit of the Washington state attorney general's office (public counsel). Therefore, the commission finds that the best way to mitigate the cost impact on small businesses is to apply regulatory principles to ensure that rates are fair, just, reasonable, and sufficient.

14 The commission after full review and analysis finds that the proposed rules will only impose minor costs on electric utility companies and concludes that the proposed rules will not have a disproportionate impact on small businesses.

17RULE-MAKING HEARING:The commission considered the proposed rules for adoption at a rule-making hearing on Wednesday, December 9, 2020, before Chair David W. Danner, Commissioner Ann E. Rendahl, and Commissioner Jay M. Balasbas. The commission heard oral comments from Bradley Cebulko, representing staff; Avista Corporation, d/b/a Avista Utilities (Avista); PSE; PacifiCorp, d/b/a Pacific Power & Light Co. (PacifiCorp); public counsel; Sierra Club; Renewable Northwest; Climate Solutions; Alliance of Western Energy Consumers (AWEC); Court Olsen; Kevin Jones; Washington Environmental Council (WEC); NW Energy Coalition (NWEC); The Energy Project (TEP), and Elyette Weinstein. Those comments primarily emphasized or supplemented those commenters' written comments.

18 Court Olsen, who did not previously submit written comments, requested the commission explicitly include the social cost of greenhouse gases (SCGHG) in the lowest reasonable cost calculation and called for measures to hold utilities accountable when responding to customer comments and questions. Additionally, the commission accepted written comments in lieu of oral comments from Christine Grant due to a scheduling conflict during the public hearing. Grant expressed support for the proposed rules' implementation of public participation opportunities and community benefits.

19 CETA is a novel and complex statute that establishes many new requirements for utilities in pursuit of the legislature's overall objective of reducing and eventually eliminating carbon from the generation of electricity provided to Washington consumers. As many commenters expressed at the adoption hearing, the process of fully implementing CETA will be an iterative process, and the effort in this rule making is only the beginning. The rules we adopt here are the first step in implementing the statutory requirements applicable to investor-owned utilities. We expect to conduct additional rule makings to implement provisions of the law, and to modify and refine these rules as the commission, utilities, and stakeholders gain experience with the new law. In the meantime, we provide additional guidance in this order on our current interpretation of the statute and the rules we are adopting.

20 RCW 19.405.100 directs the commission to find ways to streamline the implementation of CETA with the requirements of the Energy Independence Act (EIA). The commission worked closely with the Washington department of commerce (commerce) to find areas to coordinate implementation of CETA with the requirements of EIA, recognizing that each statute has distinct requirements and compliance intervals. In the following section we reduce, simplify, or combine existing and new reporting requirements and identify areas that can be streamlined in the future. Finally, we explain why we must adopt some duplicative requirements based on statutory differences that would require statutory changes.

1. Reducing administrative burden and aligning existing and new requirements: WAC 480-100-620(3), 480-100-650(3), 480-100-640(1), 480-100-625, and 480-100-655.

21 On May 20, 2016, in Docket UE-131883, the commission requested that electric utilities submit semi-annual reports disclosing the amount of distributed generation interconnected to investor-owned utilities in Washington. The reports contain datapoints such as distributed generation system adoption rates, distributed generation system counts, average system sizes, and total monthly and annual energy generated. Proposed WAC 480-100-620(3) and 480-100-650(3) require utilities to provide this type of information in the distributed energy resource (DER) assessment and reporting when preparing and submitting IRPs and CEIPs. The reporting we requested in Docket UE-131883 is therefore no longer necessary, and we withdraw our request for those semi-annual reports. We nevertheless encourage companies to include substantively similar datapoints within the DER assessments in their IRPs in consultation with interested stakeholders.

22 The commission proposes to establish an October 1 due date for the CEIP required by WAC 480-100-640(1) to align with the current requirement in chapter 480-109 WAC, rules implementing EIA, that utilities provide a draft biennial conservation plan (BCP) to their energy efficiency advisory group.3 To facilitate that coordination, the proposed rules do not require that the EIA target be final before it is included in the specific energy efficiency target within the CEIP. Commission approval of a utility's CEIP requires a review of the details of the BCP. Including a draft BCP as part of the CEIP, as an appendix or attachment, best serves the public interest because it allows the utility to adjust the BCP based on feedback from the commission and the utility's advisory group.

23 Proposed WAC 480-100-625 states that utilities' IRPs must be filed with the commission by January 1, 2021, and on January 1 every four years thereafter, unless otherwise ordered by the commission. Given the changes in IRPs required by CETA, the commission ordered in Dockets UE-180259, UE-180738, UE-180607 that for each electric utility, the next draft IRP must be submitted by January 4, 2021, and its next final IRP must be submitted by April 1, 2021. To avoid last-minute changes to utility requirements as we adopt these rules, we waive the conflicting requirement in the proposed rule and retain the dates established in these three dockets for this upcoming set of IRPs.

24 Proposed WAC 480-100-650(3) requires utilities to file annual clean energy progress reports by July 1, beginning in 2023. Existing rules implementing EIA in chapter 480-109 WAC incorporate the June 1 reporting dates specified in RCW 19.285.070. EIA requires that the annual conservation report (included in WAC 480-109-120(3)) and the annual renewable portfolio standard report (included in WAC 480-109-210(1)) must be filed by June 1. A utility may satisfy these requirements in the annual informational filings under proposed WAC 480-100-650(3) by providing the references to the reports the utility filed in compliance with chapter 480-109 WAC. The utility need not duplicate the narrative from its June 1 filing when it provides its July 1 annual report filing.

25 Proposed WAC 480-100-655 does not require utilities to file a draft CEIP with the commission or the advisory group. This eliminates a potentially unnecessary regulatory burden over the long term. However, in the beginning the CEIP will involve a new and significant process and document, one that the utilities have never prepared, and that stakeholders, and this commission have never reviewed. And unlike the IRP, the CEIP will likely be subject to significant scrutiny in an adjudicative process. Therefore, the commission finds that it is appropriate to request that utilities file a draft of their first CEIP. Availability of a draft of a utility's initial CEIP will allow the utility, staff, and stakeholders to work through issues and concerns in a semi-formal process that provides transparency and record building with maximum flexibility. Utilities, therefore, should file a draft initial CEIP with the commission by August 15, 2021, which will be the initial filing in each utility's CEIP docket.4

2. Other requirements that can be reduced or eliminated in the future: WAC 480-109-120, 480-109-300.

26 In its written comments, PacifiCorp raised concerns about the apparent duplication of reporting under the CETA and EIA rules. In creating rules that fully implement CETA's requirements, we recognize that some of the reporting appears duplicative. However, as it is necessary to incorporate some elements of chapter 480-109 WAC, which implements EIA, into the rules we adopt in this order, some overlap is inevitable. While this is a necessary step in the transition to the new reporting requirements that will begin in 2023, we identify in Table One, below, how we plan to reduce the duplication in reporting over time. Table One shows how we will smoothly transition regulation under EIA into regulation under both EIA and CETA, with the goal of reducing administrative burden wherever possible. Most of the elements in the table below should stay in effect until at least June 1, 2022, thus maintaining utility reporting under EIA until the reporting under CETA begins in 2023. This transition plan will avoid a reporting gap until the first CETA reports are due in 2023.

27 In our review of EIA, we note that chapter 480-109 WAC includes some planning and reporting elements that are not explicitly required by statute. Two examples are the annual conservation plan in WAC 480-109-120(2) and the final renewable portfolio standard compliance report in WAC 480-109-210(6), which we will address by amending provisions in chapter 480-100 WAC, and then repealing these provisions in chapter 480-109 WAC. As we transition, we will likely find other requirements that the commission can reduce or repeal. We expect to address these issues in a later rule making after we have had sufficient experience with the rules we adopt today to consider appropriate changes.

3. Streamlining that would require statutory change: WAC 480-100-645, 480-100-650.

28 During the development of the proposed rules, and our effort to streamline the reporting and compliance requirements of EIA and CETA as directed under RCW 19.405.100, we identified certain inconsistencies between the statutes. Because each statute has different requirements, some filing requirements cannot be streamlined or merged and result in overlapping rules. The discussion that follows addresses changes the legislature could make to align the statutes and facilitate our ability to further streamline utility reporting and compliance.

29 EIA requires a two-year conservation target, and CETA requires a four-year energy efficiency specific target.5 The commission can implement these statutes in concert, but to do so requires us to maintain the formal filing requirements and additional approval processes for the two-year conservation target found in WAC 480-109-120(5), and to adopt review, approval, and enforcement processes for the four-year energy efficiency target under WAC 480-100-645(2). The commission could significantly streamline the rules if the different statutory reporting periods were aligned prior to November 1, 2023, which is when the utility's next EIA two-year conservation target is due.

30 In addition, the fifteen percent eligible renewable energy standard under EIA does not include the same resources as the specific target for renewable energy under CETA. Specifically, CETA allows all generation from hydropower, while EIA limits the use of hydropower to new or expanded resources. These differences require the commission to retain the incremental hydropower methodology calculation in WAC 480-109-200(7) for inclusion in EIA report, rather than develop a methodology under CETA.

31 EIA also uses the average annual load from the prior two years to set an annual renewable portfolio standard target in megawatt hours (MWh). CETA uses a four-year average of the implementation period to meet a percent of retail sales target. A utility could comply with one standard and not the other because the same years will not be included in all of the average compliance calculations.6 Implementing both of these statutes requires the commission to adopt proposed WAC 480-100-650 (1) and (3) addressing CETA compliance, while retaining WAC 480-109-210, which covers annual formal reporting and approval for renewable portfolio standard compliance under EIA. The commission could significantly streamline reporting and compliance requirements if these two statutory requirements were aligned prior to January 1, 2023, which would assist with compliance requirements for 2022.

32 Further, EIA allows utilities to use renewable energy credits (RECs) to comply with statutory targets if those credits are generated in the year prior to the compliance year or the following two years.7 For example, RECs generated between 2021 and 2023 can be used for compliance in 2022. CETA allows banking of RECs within the four-year implementation period, so any RECs generated between 2022 and 2025 can be used for compliance in any of those years. These overlapping compliance periods between EIA and CETA require the commission to adopt reporting requirements in proposed WAC 480-100-650(3) that duplicate some of the substance of the existing reporting requirements we must retain in WAC 480-109-210. Reconciling these statutory compliance periods would allow the commission to simplify and streamline the reporting on renewable energy, preferably before January 1, 2022.

B. Resource adequacy.

33 CETA requires an electric utility's IRP to determine "resource adequacy metrics for the resource plan" and to identify "an appropriate resource adequacy requirement and measurement metric consistent with prudent utility practice."8 The rules we adopt reflect those requirements. Several commentors requested additional rule language to specify that certain elements be included in the resource adequacy (RA) modeling and assessment, including the evaluation of specific needs of load service and characteristics of resources such as energy, capacity, and flexibility, and modeling of specific resources such as demand-side, storage and wind resources, and batteries.9 CETA and proposed WAC 480-100-620(8) require an RA assessment be made "for the resource plan."10 The commenters' recommended additions to the rule are unnecessary, as an RA assessment is an assessment of the resource plan and the elements identified by the commenters are already required by the plan.11 Further, the specific elements proposed for inclusion in the rule are already standard utility practice in an RA assessment.

34 The commission recognizes stakeholders' concerns with the RA methodologies that may be used in the analysis of the contribution to RA by storage and variable energy resources. As discussed above, CETA requires utilities to identify RA metrics and standards "consistent with prudent utility practice,"12 which we deem to be best practice in providing electric service. In this regard, the commission's application of WAC 480-100-620 is no different. The broad and comprehensive language in the rule is intended to encompass all aspects of load service, all available resources, and measurement and consideration of a resource's performance characteristics, which will enable advancements in utility RA assessment methodology. In light of several regional efforts to develop RA metrics and assessments,13 it is not necessary at this time, and may be counter-productive to development of RA standards for the rule to be prescriptive at this time. Accordingly, in this period of transition to clean electricity, RA assessment is critical to assuring the "lights stay on" and rates remain stable. With the adoption of these rules, the commission expects utilities to act to fulfill their responsibility to identify appropriate RA metrics and methodologies in their IRPs in a timely and prudent manner.

35 Proposed WAC 480-100-620 (11)(j) and (12)(j) outline how a utility must perform IRP portfolio analysis, including requirements to incorporate SCGHG emissions and develop a ten-year clean energy action plan (CEAP). Under RCW 19.280.030 (3)(a), each utility must incorporate SCGHG emissions as a cost adder when evaluating and selecting conservation policies, programs, and targets; developing IRPs and CEAPs, and evaluating and selecting intermediate and long-term resource options.

36 During the CR-101 process, stakeholders submitted various approaches to incorporating SCGHG into planning. PSE proposed using a modeling approach as a planning, or fixed cost adder. Climate Solutions also proposed utilities incorporate SCGHG as a fixed cost when they evaluate the comparative costs of resources and select a preferred portfolio. Climate Solutions asserted that accounting for SCGHG alternatively in dispatch in utility IRP modeling is appropriate only if utilities plan to incorporate these costs in real time into operational decisions. Invenergy, Sierra Club, and Vashon Climate Action Group proposed incorporating SCGHG as a variable cost in dispatch for greenhouse gas emitting resources. NWEC proposed incorporating SCGHG as a variable cost that should be applied to all emitting resources, including market purchases, in modeling stages that determine utility resource selection.

37 The variety of proposals demonstrates the lack of statutory direction concerning the incorporation, or modeling, of SCGHG emissions in IRPs. Accordingly, the rules we adopt by this order do not require a specific modeling approach at this time. Rather, as we discuss further below in Section III.F.2, the proposed rules require that the utility include SCGHG emissions in the alternative lowest reasonable cost and reasonably available portfolio for calculating the incremental cost of compliance in the CEIP. How the utility chooses to model SCGHG emissions in its preferred portfolio in the IRP will inform its CEAP and ultimately its CEIP. The utility must provide a description in its CEIP of how SCGHG emissions are modelled and incorporated in its preferred portfolio.

38 Utilities should also consult with their advisory groups regarding how to model SCGHG in their IRP, CEAP, and CEIP. If a utility treats SCGHG as a planning or fixed cost adder in its determination of the optimal portfolio, including retirements and new plant builds, we expect the utility to model at least one other scenario or sensitivity in which SCGHG is reflected in dispatch. Similarly, if a utility incorporates SCGHG in modeling dispatch costs, we expect the utility to provide an alternative scenario or sensitivity analysis, such as the planning adder approach, to determine the optimal portfolio, including retirements and new builds. Such modelling will help to inform how best to implement CETA's requirement to include SCGHG emissions as a cost adder.

39 Similar to our approach, commerce's draft rules do not adopt one method, but outline several methodologies utilities may use to incorporate SCGHG, which are useful examples of how a utility may describe its IRP modeling approach to incorporate SCGHG as a cost adder. The utility and advisory groups may find this list helpful. These methodologies include:

40 Next, we turn to the consideration of the accounting of upstream emissions. During the CR-102 comment period, NWEC, Climate Solutions, and Robert Briggs all expressed general concerns that the proposed rules should require consideration of upstream emissions within the application of SCGHG. NWEC proposed including upstream emissions in the SCGHG cost adder in CETA, arguing that nothing in Association of Washington Business v. Department of Ecology, 195 Wn.2d 1 (2020), undermines this approach. Climate Solutions suggested the commission adopt requirements similar to the department of ecology's (ecology) greenhouse gas assessment for projects proceeding.15 Finally, Briggs proposed clarifying that the requirement to account for SCGHG applies to costs associated with direct CO2 emissions and the social cost of upstream fugitive methane emissions. Briggs also proposed that the rules require reporting of the assumptions used in IRP analyses for upstream emissions.

41 We recognize that modeling environmental cost and compliance scenarios will likely have a significant impact on portfolio development. In fact, since the passage of CETA, utilities have begun to apply upstream emissions in IRP modeling. However, requiring the inclusion of upstream emissions, by rule, may exceed our statutory authority. Recently, the Washington supreme court found that ecology exceeded its statutory authority when promulgating the clean air rule. Ecology's rule included the impacts of third-party emissions (e.g., upstream emissions) in its emissions standards regulating direct emitters. The court found this exceeded the statutory scheme and that regulations for emission standards were limited to those directly creating the emission. While we recognize that the commission's and ecology's statutory authority is different, we do not interpret the legislature's requirement to include SCGHG emissions as clearly requiring the commission to consider upstream emissions.

42 In enacting CETA, the legislature stated its intent to address climate change by moving to a clean energy economy through "transforming its energy supply, [and] modernizing its electricity system." RCW 19.405.010(1). CETA further measures compliance by looking at a utility's retail electric load RCW 19.405.040 (1)(a), implying that regulation is focused on emissions directly attributed to load and electric energy supply.

43 Thus, while we support the current utility practice of including upstream emissions in IRP modeling, it is not a current requirement of these rules. The public participation process created by these rules is the appropriate venue to address utility assumptions and various scenarios, including upstream emissions and SCGHG emissions, used in IRP modeling analyses. We anticipate that this issue may come before the commission when it reviews regulated utilities' initial CEIPs, but decline to be more prescriptive on this issue at this time.

D. Customer Benefit: WAC 480-100-610, 480-100-605, 480-100-620, 480-100-640.

44 RCW 19.405.040(8) provides:

In complying with this section, an electric utility must, consistent with the requirements of RCW 19.280.030 and 19.405.140, ensure that all customers are benefiting from the transition to clean energy: Through the equitable distribution of energy and nonenergy benefits and reduction of burdens to vulnerable populations and highly impacted communities; long-term and short-term public health and environmental benefits and reduction of costs and risks; and energy security and resiliency.

We interpret this requirement as an affirmative mandate, as indicated by (1) the phrase "in complying with this section, an electricity utility must … ensure that all customers are benefiting"16 and (2) the location of this requirement within the greenhouse gas neutrality section. To reflect the affirmative nature of the customer benefit requirement, the three components of RCW 19.405.040(8) are included in the clean energy transformation standards section of the proposed rules in WAC 480-100-610 (4)(c)(i)-(iii).

45 Further, we received several comments regarding the term "indicator" and how it would be applied in evaluating customer benefit. To provide additional clarity regarding this term, the commission has modified the term "indicator" in the proposed rules to "customer benefit indicator." This change does not alter the function of the definition but highlights that the definition is specifically related to tracking and measuring compliance with RCW 19.405.040(8). This definition sets minimum requirements and does not limit the commission's authority to order (or the ability of stakeholders to request) the use of additional indicators or metrics.

46 Proposed WAC 480-100-610 (4)(c)(i) incorporates this statutory mandate by requiring that customers benefit from "the equitable distribution of energy and nonenergy benefits and reduction of burdens to vulnerable populations and highly impacted communities."

47 Proposed WAC 480-100-605 defines an equitable distribution as a "fair, just, but not necessarily equal allocation of benefits and burdens from a utility's transition to clean energy." The location of the customer benefit requirements within RCW 19.405.040 indicates that the benefits and burdens that must be equitably distributed are the specific actions a utility takes to comply with RCW 19.405.040. To inform the commission's decisions related to fair and just allocation, proposed WAC 480-100-620(9) requires, among other things, the assessment of certain current conditions to determine equitable distribution of benefits and burdens. The commission agrees with the observations of multiple stakeholders that current conditions should include consideration of cumulative and legacy conditions. Similarly, we concur with Front and Centered's comments that the purpose of equitable distribution in the statute is to prioritize vulnerable populations and highly impacted communities that experience the greatest inequities and disproportionate impacts, and that have the greatest unmet needs. Finally, the commission agrees with Avista's interpretation that both the distribution of benefits and the reduction of burdens must be equitable.

48 The definition of "vulnerable populations" in proposed WAC 480-100-605 is the same as provided in RCW 19.405.020(40). The definition includes a non-exhaustive list of factors (e.g., unemployment, linguistic isolation, low birth weight) associated with adverse socioeconomic conditions and sensitivity factors. Commenters proposed to include additional factors, but the commission declines to modify the statutory definition. Any additional factors used to designate vulnerable populations should reflect public input, as required by WAC 480-100-640 (4)(c).17

49 Proposed WAC 480-100-610 (4)(c)(ii) requires that customers benefit from long-term and short-term public health and environmental benefits and reduction of costs and risks.

50 Proposed WAC 480-100-610 (4)(c)(iii) requires that customers benefit from energy security and resiliency. NWEC and Front and Centered recommended that "energy security" and "resiliency" be defined in rule. The commission declines to define these terms at this time, but will review and determine issues concerning specific customer benefit indicators associated with energy security and resiliency when considering utility CEIPs, as required in WAC 480-100-640 (4)(c), following significant work on these issues by the utilities and customers. As with all customer benefit indicators, the application of these terms must reflect customer input to ensure that all customers are benefiting from the transition to clean energy.

51 Front and Centered commented that proposed WAC 480-100-610 (4)(c)(ii) and (iii) should reference highly impacted communities and vulnerable populations to support the law's intent of centering the most impacted and vulnerable. The commission declines to alter WAC 480-100-610 (4)(c)(ii) and (iii), which currently reflect the separate and distinct customer benefit requirements identified in RCW 19.405.040(8). Additionally, WAC 480-100-610 (4)(c)(i) reflects additional distinct customer benefit requirements in the statute and requires the equitable distribution of energy and nonenergy benefits. However, we interpret the statute such that WAC 480-100-610 (4)(c)(ii) and (iii) would not supersede a utility's requirement to equitably distribute those benefits under WAC 480-100-610 (4)(c)(i).

52 In addition to broad applicability as part of the clean energy transformation standards, the rules include specific requirements for utilities to address the customer benefits requirements in their IRPs (including the CEAPs), CEIPs, and compliance reports. These plans and reports are discussed in turn below.

1. IRPs and CEAPs: WAC 480-100-620, 480-100-605.

53 Proposed WAC 480-100-620(9) requires utilities to include an assessment of economic, health, and environmental burdens and benefits in their IRPs. This assessment is a required input to IRPs pursuant to RCW 19.280.030 (1)(k).18 The definition of "equitable distribution" in WAC 480-100-605 provides that this assessment, among other information, will inform the "current conditions" within a utility's service territory. These current conditions are the basis for determining whether the allocation of benefits and burdens from the utility's transition to clean energy results in equitable distribution.

54 Proposed WAC 480-100-620(9) requires that a utility's assessment be informed by the cumulative impact analysis (CIA) conducted by the department of health. RCW 19.405.140 requires the CIA to be completed by December 31, 2020, and include impacts from fossil fuel pollution and climate change. Because the CIA includes impacts associated with fossil fuels and climate change, the CIA may provide relevant information pertaining to nonenergy benefits and burdens as well as long-term and short-term public health and environmental benefits, costs, and risk. Utilities must consider the information in the CIA in developing their IRPs, but the requirement that the assessment be informed by the CIA neither waives the requirement for an assessment if the CIA is unavailable nor relieves the utility of its obligation to consider other sources of information relevant to the assessment.

55 Proposed WAC 480-100-620 (10)(c) requires utilities to include at least one sensitivity that reflects a maximum customer benefit scenario. In its written and verbal comments, Avista requested clarification on the purpose and characteristics of a maximum customer benefit scenario. A utility's resource portfolio reflects the lowest-reasonable cost portfolio that meets all operational and regulatory standards. While all scenarios should be consistent with the customer benefit requirements in RCW 19.405.040(8), this sensitivity should meet load with resources that result in the highest possible values for customer benefit indicators regardless of cost or other competing considerations. The specific resources that should be maximized within this scenario will depend on the customer benefit indicators and associated weighting factors developed pursuant to proposed WAC 480-100-640 (4)(c). As with all IRP sensitivities, the goal of this requirement is to provide information to inform highly discretionary decisions by understanding the tradeoff between different resource decisions. The commission's intent in requiring such a sensitivity in WAC 480-100-620 (10)(c) is to promote creative thinking and ensure broad consideration of customer benefit opportunities freely and without any competing considerations.

56 Proposed WAC 480-100-620 (11)(g) requires utilities to describe how their long-range IRPs expect to achieve the customer benefit requirements. This obligation is consistent with RCW 19.280.030 (1)(j), which requires the IRP to "imple[ment] RCW 19.405.030 through 19.405.050," which includes RCW 19.405.040(8). PacifiCorp commented that the IRP does not represent actual procurement decisions nor acquisitions and, as such, is not the appropriate place to comment on customer benefit requirements. As noted previously, however, RCW 19.280.030 (1)(j) requires IRPs to implement CETA requirements, including the customer benefit requirements. Additionally, the commission expects companies to consider different potential bundles of procurement that have different amounts and combinations of customer benefits to ensure least cost planning. While PacifiCorp also commented that IRP is not a rate-making plan nor does it contemplate impacts on specific customer rates, the customer benefit requirements in RCW 19.405.040(8) are more broad than the impact of rates, and concern the benefits and burdens of a utility's specific actions to transition to clean energy, including resource selection.

57 This rule also specifically requires a utility to describe its long-term strategy, interim steps, and the estimated degree to which benefits will be equitably distributed and burdens reduced over the planning horizon. PSE recommended deleting these specific requirements, contending that they are too broad. The commission finds that the information required in WAC 480-100-620 (11)(g) provides necessary context for the commission's consideration of utility compliance with RCW 19.405.040(8). RCW 19.405.040(8) requires a contextual determination. First, as discussed above, a determination regarding equitable distribution requires a consideration of current conditions, which will change over time. Second, the quantity and type of benefits and burdens associated with a utility's transition to clean energy are not currently known and will change over time based on technological developments and new load forecasts, among other things. Including a long-term view of customer benefit requirements in the IRP provides a necessary estimate of the benefits of the transition to clean energy at a point in time, while ensuring that the information is not static but can adapt to changing conditions.

58 Proposed WAC 480-100-620 (12)(c) requires a utility to describe how its specific actions in the CEAP are expected to meet the customer benefit requirement. PSE recommended deleting this requirement, commenting that it does not believe CETA requires the CEAP to address equity considerations and that it is not reasonable to require the CEAP to describe specific actions. However, the requirements in WAC 480-100-620 (12)(c) are consistent with RCW 19.280.030 (1)(l), which requires the CEAP to "imple[ment] RCW 19.405.030 through 19.405.050," which, as we note above, includes RCW 19.405.040(8). Further, the statute requires the CEAP to "identify the specific actions to be taken by the utility consistent with the long-range integrated resource plan." PacifiCorp commented that the requirements for the CEAP in WAC 480-100-620 (12)(c) appear redundant with the requirements for IRPs in WAC 480-100-620 (11)(g). RCW 19.280.030 (1)(j) and 19.280.030 (1)(l), however, require both the IRP and CEAP to address the requirements in RCW 19.405.030 through 19.405.050, including 19.405.040(8). Therefore, the rules reflect the structure of the statute and ensure that utilities address the customer benefit requirements at a high-level in long-term plans, as well as providing more detail over the ten-year planning horizon of the CEAPs.

2. CEIPs: WAC 480-100-640, 480-100-605, 480-100-610.

59 Proposed WAC 480-100-640, which addresses CEIPs, includes multiple provisions related to the customer benefit requirements. Several stakeholders commented that they do not believe customer benefit requirements should be included in the CEIPs because RCW 19.405.040(8) is not referenced in RCW 19.405.060. Under RCW 19.405.060 (1)(ii)(b), a CEIP must be informed both by a utility's CEAP and the long-term IRP, which as described above, requires a demonstration of the implementation of RCW 19.405.040(8). Additionally, under RCW 19.405.060 (1)(c)(iii), the commission may adjust targets and timelines proposed in the CEIP if doing so can be achieved in a manner consistent with the equity requirement. To evaluate whether a utility can make these adjustments, the commission needs an understanding of how the initial targets and timelines in the proposed CEIP are consistent with the customer benefit requirements. Finally, because RCW 19.405.090(9) requires the commission to determine investor-owned utilities' compliance with chapter 19.405 RCW, the commission must make a regular determination of a utility's compliance with RCW 19.405.040(8). It would be inefficient for the commission to approve a CEIP, only to determine later that a utility has not complied with RCW 19.405.040(8).

60 Proposed WAC 480-100-640(4) requires utilities to provide foundational information in the CEIP related to the customer benefit requirements. WAC 480-100-640 (4)(a) and (b) require utilities to identify highly impacted communities and vulnerable populations for which equitable distribution of benefits and reductions of burdens must be achieved pursuant to WAC 480-100-610 (4)(c)(i).

61 Proposed WAC 480-100-640 (4)(c) requires utilities to propose or update customer benefit indicators and associated weighting factors. As defined in WAC 480-100-605, a customer benefit indicator is an attribute of a resource or related distribution system investment (i.e., a specific action) associated with RCW 19.405.040(8), and is included in the clean energy transformation standards in WAC 480-100-610 (4)(c). Specifically, WAC 480-100-640(c) requires that utilities propose at least one indicator for each element of customer benefits listed in the rule as outlined below:

62 We require utilities to develop customer benefit indicators and weighting factors consistent with the advisory group process and public participation in proposed WAC 480-100-655. Customer and stakeholder input is necessary in developing customer benefit indicators. First, customer and stakeholder input is necessary to determine whether an attribute is an indicator of customer benefit, and whether it reflects a reduction of a burden. Second, customer and stakeholder input regarding weighting factors is necessary to understand the degree to which benefits can be equitability [equitably] distributed when considered in light of appropriate factors, such as current conditions and the estimated amount of benefits over the whole transition.

63 PSE commented that the rules should not reference updated customer benefit indicators. However, as customer preferences and impacts may change over time, we find that the rules should allow for updated customer benefit indicators.

64 Proposed WAC 480-100-640(5) addresses specific actions a utility plans to take under its CEIP to meet the requirements of RCW 19.405.060 (1)(b)(iii), including operational and regulatory requirements, and requires utilities to provide, among other details, information related to customer benefits for each specific action. This information includes the general location of the specific action, if applicable, and a designation of whether the specific action is located within a highly impacted community or will be governed by, serve, or otherwise benefit highly impacted communities or vulnerable populations in part or in whole. We intend to review the customer benefits on a portfolio-level. Therefore, it is important for the utility to identify which specific actions provide customer benefits.

65 Subsection (5)(c) also requires the utility to provide the customer benefit indicator values for each specific action, or designate the customer benefit indicator as nonapplicable, to establish the amount of customer benefit provided by each specific action. The rule provides flexibility for recognizing benefits in subsection (5)(b) because some benefits will be associated with the project location (e.g., local job creation), while other benefits may be associated with the governance structure of the specific action or other non-co-locational benefits (e.g., community ownership of resources). For example, highly impacted communities and vulnerable populations may benefit from a specific action if it is governed by those communities. Such governance might include majority community ownership (e.g., more than 50 percent equity interest), indirect ownership through a cooperative, nonprofit, or LLC, or majority control (e.g., voting power or decision-making interest outlined in bylaws).

66 Proposed WAC 480-100-640(6), among other provisions, requires utilities to describe narratively how the portfolio of specific actions (i.e., all the specific actions included in a utility's CEIP) are consistent with the customer benefit requirements. This narrative is necessary because a utility must provide context for the customer benefits included in WAC 480-100-640(5). Based on this information, the commission may determine whether the customer benefits are sufficient and will result in an equitable distribution, based on a consideration of current conditions and the estimated amount of benefits across the transition. The rule requires utilities to provide a narrative that assesses the current benefits and burdens on customers, including the benefits and burdens associated with specific actions the utility has taken since CETA's effective date, and after the utility has implemented a CEIP, the changes in benefits and burdens resulting from the utility's specific actions in the prior implementation period.

67 Additionally, proposed WAC 480-100-640(6) requires the utility to describe in the narrative how the specific actions are consistent with its most recent IRP and CEAP. These two elements of the narrative are necessary because the commission's compliance determination may require an evaluation of the timing and quantity of benefits throughout the transition to clean energy, both as the utility begins implementation and over the trajectory of implementation. As noted above, an equitable distribution of benefits will depend on the total benefits of the transition to clean energy, which will occur over time. An evaluation of the equitable distribution of benefits must consider when the benefits will begin accruing to customers and reflect whether the benefits will continue into future implementation periods. The narrative we require in subsection (6) provides an opportunity for utilities to describe how the CEIP, as a whole and through specific actions, will meet the customer benefit requirements.

68 Proposed WAC 480-100-640(11) allows utilities to update a CEIP based upon any changes included in an IRP progress report. Utilities should include in their updates any resulting changes to customer benefits.

3. Compliance Report: WAC 480-100-650, 480-100-655.

69 Proposed WAC 480-100-650 (1)(d) requires utilities to demonstrate that the specific actions they took in implementing the CEIP met the customer benefit requirements under RCW 19.405.040(8). The demonstration must include updated customer benefit indicator values, as well as analysis that the benefits and reduction of burdens have or will reasonably accrue to intended customers. PSE recommends removing the requirement to analyze whether benefits and reduction of burdens have or will reasonably accrue to customers. We find that the requirements in subsection (1)(d)(ii) are necessary. The distribution of benefits may vary greatly during implementation, based on numerous factors such as the specifics of the resource acquired or otherwise implemented, including project ownership, outreach to customers, and customer-specific information (e.g., benefits of a rooftop solar project must be carefully and intentionally shared or they will only reasonably accrue to customers who own their own home).

70 Proposed WAC 480-100-650 (1)(e) requires utilities to describe in the compliance report their equity advisory group process, as well as customer engagement and outcomes. Additionally, this subsection requires utilities to demonstrate that they complied with the requirements in proposed WAC 480-100-655 to engage customers in the development or update of customer benefit indicators. As noted previously, customers must be meaningfully engaged both to ensure that the specific actions taken by utilities reflect actual customer benefits and that the utility captures relevant changes in customer experiences and preferences. As required in subsection 655 (2)(a), input from designated highly-impacted communities or vulnerable populations should inform the customer benefit indicators associated with the equitable distribution of benefits and reduction of burdens to those populations, while input from all customers should inform the customer benefit indicators for public health, environmental health, cost reduction, risk reduction, energy security, and resilience.

71 The proposed rules include a section addressing the various options available to the commission for enforcing both the statutory provisions of CETA and commission orders implementing CETA. The potential penalties identified in the proposed rules include the specific penalty described in RCW 19.405.090, the administrative penalties the commission may assess for failure to comply with a commission order or rule under RCW 80.04.380 and 80.04.405, and the penalty that may be assessed under EIA in RCW 19.285.060.19 In adopting these rules, the commission retains its discretion to determine, on a case-by-case basis, if it should issue a penalty for violating a commission order based on the specific circumstances. Commissioner Balasbas opposes adopting proposed WAC 480-100-665 because, in his view, "Although many of the enforcement tools listed in the rule are restatements of existing commission authority, by including explicit provisions in this package of rules, right out of the gate the commission is taking an aggressive and unnecessary adversarial stance on utility compliance with CETA." Dissent ¶ 19. We disagree that this provision is adversarial. The commission, however, received comments early in this rule making questioning the commission's authority to enforce CETA provisions beyond the administrative penalties authorized in RCW 19.405.090. Proposed WAC 480-100-665 clarifies the commission's statutory interpretation that all of its statutory enforcement authority is available, if necessary, to ensure compliance with CETA, just as such authority extends to ensuring compliance with every statute within the commission's jurisdiction.

72 The proposed rules largely do not detail how the commission would apply the penalties the legislature adopted in RCW 19.405.090. Rather, we provide guidance below on how the commission may apply those penalties in the different scenarios envisioned in the statute.

1. Application of the penalty under RCW 19.405.090: WAC 480-100-650.

73 RCW 19.405.090(1) provides that an electric utility that fails to meet the standards established under RCW 19.405.030(1) and 19.405.040(1) must pay an administrative penalty. The requirement in RCW 19.405.030(1) that a utility must eliminate coal-fired resources from its allocation of electricity begins no later than December 31, 2025. Utilities must demonstrate compliance with the obligation in RCW 19.405.040(1) that all retail sales of electricity be greenhouse gas neutral by January 1, 2030. The administrative penalty established in RCW 19.405.090 is $100 per megawatt-hour for each megawatt-hour of electric generation used to meet load that is not renewable or non-emitting and includes multipliers for coal- and gas-fired resources.20

74 Application of the penalty in RCW 19.405.090 to standard in RCW 19.405.030(1): RCW 19.405.090 establishes a $150 per megawatt-hour penalty for each megawatt-hour of electric generation from a coal-fired resource used to meet load.21 However, the definition of coal-fired resource is limited to resources owned or under a contract longer than one month.22 Therefore, if a utility fails to remove its allocation of electricity, i.e., all costs and benefits related to coal-fired resources owned or associated with contracts longer than one month to serve load from rates between January 1, 2026, and December 31, 2029, it is subject to the $150 penalty in RCW 19.405.090(1) for each megawatt-hour of coal-fired electric generation used to meet load during the implementation period.23

75 Aspects of this compliance obligation and its measurement hinge on the question of how to define the "use" of electricity more generally because the penalty under RCW 19.405.090 (1)(a) is based upon "each megawatt-hour of electric generation used to meet load that is not electricity from a renewable resource or non-emitting electric generation" (emphasis added). As comments throughout this rule making reflect, this is a complicated issue which the commission, commerce, utilities and stakeholders will continue to discuss. Prior to the December 31, 2025, deadline in RCW 19.405.030(1), utilities and stakeholders will need to determine which megawatt-hours of generation are subject to the penalty, and how the utility will document compliance. Here, the commission clarifies only the more basic question of whether the penalty applies to "using" coal-fired resources to serve load, however that may be defined in the future, or if penalties apply only to the inclusion of the costs of coal-fired resources in customer rates.

76 PacifiCorp and AWEC have objected that the definition of "allocation of electricity" under RCW 19.405.020(1) indicates that utilities are not required to stop using coal-fired resources to meet retail customer load by 2026, but must only stop including these costs in rates.24 The crux of this argument is that RCW 19.405.030(1) requires the elimination of coal-fired resources from the utility's "allocation of electricity," which, for rate setting purposes, the statute defines as "the costs and benefits associated with the resources used to provide electricity to an electric utility's retail electricity consumers that are located in this state." While we agree that inclusion of coal-fired resources in rates is prohibited beyond 2025, we disagree that CETA only prohibits the inclusion of these resources in rates.

77 First, the "ratemaking only" interpretation contradicts the plain language of RCW 19.405.090 (1)(a), which sets penalties based on the use of coal-fired resources to serve load, not for the inclusion of those resources in rates. As we noted above, RCW 19.405.090 (1)(a) creates a penalty for failure "to meet the standards established under RCW 19.405.030(1) and 19.405.040(1)" based upon "each megawatt-hour of electric generation used to meet load that is not electricity from a renewable resource or nonemitting electric generation" (emphasis added). That description of the penalty applies to RCW 19.405.030(1) specifically. Subsection RCW 19.405.090 (1)(b) states that "[b]eginning in 2027" the penalty is adjusted for inflation, and the only applicable standard at that point in time is RCW 19.405.030(1). If the "ratemaking only" interpretation were correct, RCW 19.405.090 (1)(a) would not set a penalty for -.030 based on whether coal-fired resources were used to serve load because, under this interpretation, RCW 19.405.030(1) does not prohibit using coal to meet load, it only prohibits including those resources in rates.

78 Second, the early action coal credit option outlined in RCW 19.405.040(11) further undermines the "ratemaking only" interpretation. That subsection allows utilities that meet certain qualifications to receive credit for early compliance with RCW 19.405.030(1), but only if the utility demonstrates "that for every megawatt-hour of early action compliance credit there is a real, permanent reduction in greenhouse gas emissions in the western interconnection directly associated with that credit."25 This indicates that RCW 19.405.030(1) requires actual elimination of the use [of] coal-fired resources,26 since receiving early credit for compliance with RCW 19.405.030(1) also requires it.

79 Third, it is important to recognize the overall legislative intent.27 RCW 19.405.010(2) states: "It is the policy of the state to eliminate coal-fired electricity." Under the "ratemaking only" interpretation, however, eliminating coal-fired electricity would not be required by law until 2045 because RCW 19.405.040(1) allows an offset for up to twenty percent through alternative compliance options between 2030 and 2045. This outcome appears to be contrary to the legislative intent behind CETA as the larger statutory context demonstrates. Furthermore, under the "ratemaking only" interpretation, between 2026 and 2029 a utility would incur the penalty for coal-fired resources under RCW 19.405.090(1) only if the commission first authorized recovery of those resources in a ratemaking case, because that is all that RCW 19.405.030(1) prohibits. This reading would mean that the legislature intended a utility to be penalized if the commission (in violation of RCW 19.405.030(1)) authorized the inclusion of coal-fired resources into rates. In other words, the commission would be authorized to penalize a utility for including the costs and benefits of these resources in rates, which only the commission pursuant to WAC 480-100-620(9) could have approved. These absurd results, as well as the statutory support for a different interpretation discussed above, lead us to reject the "ratemaking only" interpretation of RCW 19.405.030(1) and the proposed "allocation of electricity" definition.

80 Finally, the definition of "allocation of electricity" does not signal that RCW 19.405.030(1) allows a utility to continue using coal-fired resources to serve load beyond 2025. The definition requires the elimination of costs and benefits, and the primary benefit of these resources is the supply and sale of electricity to consumers. The benefits of these resources cannot be eliminated from rates unless coal-fired resources are in fact no longer used to serve load, since the utility would still be receiving compensation from ratepayers for that coal-fired electricity through current rates. Again, the early action coal credit option in RCW 19.405.040(11) supports this reading of the definition. A utility receives credit for removing these resources from "the utility's allocation of electricity before December 31, 2025" but the subsection specifies that doing so requires more than simply demonstrating that customer rates no longer include the costs of those resources, it requires "a real, permanent reduction" in emissions.28 Additionally, while the definition states that it is "for the purpose of setting electricity rates," as the legislature was well aware, the commission sets rates based (in part) on the resources that are used and useful to provide service to customers.29 We adopt a reading of the "allocation of electricity" that does not conflict with requirements of RCW 80.40.250, as amended by CETA.

81 All of these compliance obligations and determinations hinge on the question of how to define the "use" of electricity more generally. As we note above, prior to December 31, 2025, utilities, stakeholders, commerce and the commission will need to determine how a utility will document its compliance with the requirements regarding the "use" of electricity. We intend to initiate proceedings regarding the definition of "use" in 2021.

82 If a utility elects to rely on the alternative compliance option in its compliance report under RCW 19.405.090(2), it must calculate the alternative compliance payment based on the actual load of the full implementation period, based upon documentation of reliance on coal-fired, gas-fired, and unspecified electricity.

83 In calculating the alternative compliance payment after January 1, 2030, even if the utility successfully removes all costs and benefits related to coal-fired resources owned or associated with contracts longer than one month from rates, it is still subject to the $150 per megawatt-hour penalty for each megawatt-hour of coal-fired electric generation used to meet load after that date. Under RCW 19.405.040(7), a utility that fails to comply with RCW 19.405.040 must pay the penalty under RCW 19.405.090(1).

84 Application of the penalty in RCW 19.405.090 to nonrenewable and emitting resources: Multiple commenters expressed concerns about how to address serial contracts of less than one month that would seem to allow the utility to use coal-fired resources without incurring penalties after 2030. Other commenters expressed concern about how to address electricity from unspecified sources, regardless of contract length.

85 RCW 19.405.090(1) states that the $100 penalty applies to "each megawatt-hour of electric generation used to meet load that is not electricity from a renewable resource or nonemitting electric generation." Thus, to avoid the application of the penalty, the electricity used to meet load must affirmatively be generated from renewable or nonemitting resources. There are two situations that require additional consideration in the application of the penalty: (1) Electricity from coal-fired resources under contracts of one month or less, and (2) unspecified electricity.

86 Under RCW 19.405.030, the utility is not required to remove the costs and benefits associated with coal-fired resources purchased under contracts of one month or less from its requests for rate recovery. However, electricity from coal-fired resources supplied under contracts of one month or less, while excluded from the definition of coal-fired resources, are not renewable or nonemitting. Thus, after 2030, instead of the $150 penalty for coal-fired resources, the utility will be subject to the $100 penalty for each megawatt-hour of coal-fired electric generation used to meet load that is provided under contracts of one month or less. The statute provides this remedy to prevent serial contracts of one month or less from sidestepping the requirement to achieve 100 percent renewable and nonemitting electricity by 2045.

87 "Unspecified electricity" is "an electricity source for which the fuel attribute is unknown or has been separated from the energy delivered to retail electric customers."30 Under this definition, unspecified electricity is not affirmatively renewable or nonemitting.31 We do not believe that the legislature intended to allow a utility to avoid compliance with applicable standards by purchasing unspecified electricity. Accordingly, we conclude that the $100 penalty applies to any unspecified electricity. This conclusion aligns the utility's incentive to identify the source of the electricity with the requirement to achieve one hundred percent renewable or nonemitting electricity by 2045.

2. Penalties on specific and interim targets: WAC 480-100-640, 480-100-645.

88 Proposed WAC 480-100-640 (1)-(3) require a utility to file, by October 1, 2021, and every four years thereafter, a CEIP with specific and interim targets for each implementation period as described in RCW 19.405.060(1). RCW 19.405.060 (1)(c), as reflected in proposed WAC 480-100-645(2), requires the commission to issue an order approving a utility's CEIP.

89 Utilities argue in their comments that the commission either may not or should not issue penalties associated with the specific and interim targets identified in the CEIP and approved by order prior to 2030. PacifiCorp asks the commission for flexibility in meeting the interim targets, and PSE requests the commission reconsider its interpretation of the application of the CETA penalty to the interim targets. We do not adopt either of these positions.

90 Specific targets: The statutory penalty in RCW 19.405.090 applies to electric generation from resources that are not renewable or nonemitting. We thus conclude that the statutory penalty does not apply to the specific targets, which concern energy efficiency, demand response, and renewable energy. However, the commission must by order approve, reject, or approve with conditions the utility's CEIP, and the CEIP must contain specific targets.32 As described in RCW 80.04.380 and 80.04.405, the commission has discretion to issue penalties for failure to comply with a commission order. The rules adopted by the commission in no way limit this discretion. Accordingly, the commission retains discretion to penalize a utility, as a violation of the commission's order, for failure to comply with specific targets the commission has approved in the utility's CEIP.33

91 Interim targets: Proposed WAC 480-100-640(2) requires a utility's CEIP to include a series of interim targets in the form of the percent of forecasted retail sales of electricity supplied by non-emitting and renewable resources prior to 2030 and from 2030 through 2045. RCW 19.405.060 (1)(c) requires that the commission approve these interim targets. Interim targets are a critical part of demonstrating progress toward meeting the standards in the law, and utilities must design a reasonable transition to achieve the standard. When the commission approves the interim targets by order, the commission retains the discretion to issue penalties for failure to comply with the commission's order, specifically if a utility fails to meet its interim target for any implementation period.34

3. Attestation of no coal in rates: WAC 480-100-650.

92 Beginning in 2027, proposed WAC 480-100-650 (3)(a) requires utilities to provide an attestation for the previous calendar year specifying that the utility did not use any coal-fired resource owned or under contracts longer than one month to serve Washington retail electric customer load. This requirement begins in 2027 because each "utility must eliminate coal-fired resources from its allocation of electricity" by December 31, 2025.35 For rate-making purposes, allocation of electricity is defined as the costs and benefits associated with the resources used to provide electricity to a utility's Washington retail electricity consumers.36 These statutory requirements, taken together with the definition of coal-fired resource in RCW 19.405.020 and the administrative penalties in RCW 19.405.090 (1)(a), mean that if a utility owns a coal-fired resource or buys electricity under a contract longer than one month that is generated by coal-fired resources, the utility may not pass on the costs of that power to consumers, or use those resources to meet load.37

93 The coal attestation requirement begins in 2027. As discussed above, the commission expects to provide additional guidance on the specifics of this requirement before that time through the rule making required by RCW 19.405.130. That rule making will also provide guidance on the issue of the "use" of electricity under RCW 19.405.040(1).

94 PacifiCorp and AWEC both argue that the attestation described in the rule goes beyond the requirement in RCW 19.405.030. As we have discussed in Section III.E.1., we disagree with the view that RCW 19.405.030, or chapter 19.405 RCW generally, require only the exclusion of these resources from rates. Public counsel, NWEC, and Renewable Northwest all support attestation, either as is, or with small changes.

95 We further clarify that the attestation required in the proposed rule does not address electricity generated by coal-fired resources purchased under contracts of one month or less. The exclusion in the definition of coal-fired resource recognizes that the source of the power can be known after the time of purchase through the utility's fuel mix report.38 The utility must exercise due diligence to discover after the fact whether coal-fired resources under contracts of any length generated the electricity used to meet load.39 The attestation must affirm that the utility did not knowingly purchase any electricity from coal-fired resources.40 The commission expects that enforcement of the removal of coal owned or under contract for longer than one month will also be addressed in general or power-cost-only rate cases. The detailed work needed to resolve this issue will also occur in the rule making required under RCW 19.405.130.

96 Stakeholder comments on the elimination of coal from utility rates illustrate the complexity of this issue. The commission must continue to consider and revise as necessary the best way to implement the requirement in RCW 19.405.030 to eliminate coal from the allocation of electricity. The attestation in the proposed rule is an important step toward accomplishing that goal.

F. Relief from Statutory Penalties – Electric System Integrity and Incremental Cost.

97 In CETA's finding and intent section, the legislature stated that Washington can achieve the goals in the bill while "maintaining safe and reliable electricity to all customers at stable and affordable rates."41 The legislature included provisions in CETA that ensure both the integrity of the electric grid and the affordability of customer rates. We will address each in turn.

1. Electric system integrity.

98 RCW 19.405.090 (3) and (6) describe circumstances under which the commission may relieve an investor-owned utility of an administrative penalty. One basis for relief is if the utility's compliance with CETA would have compromised or resulted in conflicts with the integrity of the electric grid. The administrative process for making this determination is straightforward - subsection (3)(a) allows the commission, after a hearing, to relieve a utility of an administrative penalty. The commission may take this action on its own motion or a utility may request relief.

99 Specifically, a utility may seek relief under RCW 19.405.090 (3)(a)(i) and (ii), if, after taking all reasonable measures, compliance with the statute is likely to result in conflicts or compromises to its obligation to comply with mandatory reliability standards, violate prudent resource adequacy standards, compromise the integrity of the electric grid, or if the utility is unable to comply due to reasons beyond its control. Subsections (3)(b) and (c) describe the length of time the commission may relieve the utility of its compliance obligation and what type of guidance the commission may provide the utility. Subsection (6) describes some of the conditions that are outside the utility's control.

100 We conclude that the proposed rules do not need to expand on this procedure for seeking relief from CETA penalties as the meaning and application of statutory terms relating to system integrity will depend on the specific facts of each case. We find that the statutory language is sufficient given the wide range of circumstances in which relief from an administrative penalty could be justified. Thus, we do not prescribe specific standards on reliability relief in the proposed rules.

2. Incremental Cost: WAC 480-100-660.

101 The legislature's intent in CETA is that electric utilities should transition to one hundred percent clean electricity while maintaining affordable, stable rates.42 To that end, RCW 19.405.060(3) provides that a utility should be considered compliant with RCW 19.405.040(1) and 10.405.050(1) [19.405.050(1)] if it meets a certain cost threshold or the annual incremental cost of compliance. The statute does not define "incremental cost" but provides guidance and requires the commission to establish by rule a methodology for determining the annual incremental cost of compliance. Proposed WAC 480-100-660 incorporates this statutory requirement. A utility's incremental cost of compliance is a calculation that determines which annual costs the utility incurred for the purpose of complying with RCW 19.405.040 and 19.405.050.

102 CETA obligates utilities to meet the requirements of the law at the lowest reasonable cost.43 A utility's reliance on the incremental cost of compliance to satisfy its obligations is an alternative pathway. Accordingly, we do not expect incremental cost to be the default for compliance through 2045 and beyond. The commission expects utilities to immediately begin making investments to achieve their future statutory obligations and discourages utilities from using the incremental cost compliance pathway to delay investment in the early years of implementation or from waiting until deadlines approach before making investments. The commission will review the utility's progress of compliance during the approval of each CEIP and clean energy compliance report.

103 In future proceedings, the commission will base its decisions regarding incremental cost on the specific facts in the record, as well as our wealth of experience enforcing similar statutory requirements. Through enforcement of similar statutory requirements, the commission has acquired expertise in determining the proper methods, rules, and enforcement of statutes that require us to measure different types of incremental changes.

104The statutory context of the incremental cost alternative compliance pathway: The incremental cost alternative compliance pathway is an integral part of the entire statutory scheme.

105 Generally, commenters that objected to the calculation of the annual threshold amount in proposed WAC 480-100-660 and Commissioner Balasbas in his dissent, state this calculation will result in significant rate increases. This objection assumes that utilities will be unable to meet their interim targets (which the utilities themselves propose, and the commission reviews for either approval or modification),44 or the statutory standards (which the legislature found achievable while maintaining affordable rates), without reliance on the alternative incremental cost pathway.45 The implicit argument appears to be that: (a) Utilities will regularly fail to meet their proposed targets; (b) utilities accordingly will need to rely on the incremental cost alternative compliance pathway; and (c) the annual threshold amount calculation will therefore have a substantial impact on customer rates. The commission disagrees with these assumptions. The primary and expected method of compliance with CETA is that utilities will meet their interim targets and the statutory standards in RCW 19.405.040(1) and 19.405.050(1) under CETA's lowest reasonable cost standard. We expect utilities to propose reasonable interim targets and meet the statutory standards of RCW 19.405.040(1) and 19.405.050(1) in a cost-effective manner. Like the legislature,46 we believe this is achievable without imposing unreasonable costs on customers. In most cases, the actual costs of achieving those targets, not the annual incremental cost threshold amount, will determine the real cost impact of CETA on customer rates. We believe those actual amounts will be less than the incremental cost threshold amount calculated under WAC 480-100-660.

106 Avista, PacificCorp, and AWEC raised concerns that the incremental cost calculation creates uncertainty and saddles the utility with responsibility for events outside of its control. This objection ignores the statutory authority granted to the commission to determine whether it should relieve the utility of any administrative penalties. As noted above, the commission has that authority in such circumstances.

107Compliance pathway: Contrary to arguments raised by our colleague in his dissent, the incremental cost of compliance option is not a strict cost cap nor is it a floor, but, as stated above, an alternative compliance pathway. The statute does not prohibit a utility from spending, on average over four years, more than the incremental cost threshold on compliance.47 However, the legislature intended to restrain the amount of spending a utility must invest to meet the statutory requirements.48 If a utility relies on the incremental cost of compliance pathway, the utility should restrain and target its spending to just over the compliance threshold. We understand that holding costs to "just over" the compliance threshold is challenging, and we will allow for flexibility when reviewing the utility's costs for recovery in rates. Rather than requiring utilities to precisely spend a certain amount of money to use this compliance pathway, our intent is to signal that the utility should not spend any amount seeking compliance with the statutory requirements if it has met or exceeded the incremental cost of compliance threshold, barring other considerations.49

108Incremental cost methodology: RCW 19.405.060(5) requires the commission and commerce to establish the "methodology for calculating the incremental cost of compliance … as compared to the cost of an alternative lowest reasonable cost portfolio of investments that are reasonably available." We interpret this to mean that the incremental cost methodology is a comparison of two portfolios. The first portfolio contains the specific actions and resources that the utility is taking. The second portfolio contains the counterfactual, i.e., what the utility would have done but for the requirements in RCW 19.405.040 and 19.405.050. This second portfolio is referred to as the alternative lowest reasonable cost and reasonably available portfolio in the statute and in these rules,50 but we refer to it in this order as the baseline portfolio.

109 Determining which actions a utility would have taken in the baseline portfolio is an inherently difficult task because it requires imagining what the utility would have done in a timeline that does not exist. Parties may reasonably disagree on what would have happened. Nevertheless, we expect to resolve these disagreements during our review of each utility's CEIP.

110Incremental cost calculation: The commission and commerce are adopting the same incremental cost calculation, and an approach that was supported by parties including PSE, Climate Solutions, NWEC, and Renewable Northwest. RCW 19.405.060 (3)(a) states that:

"An investor-owned utility must be considered to be in compliance with the standards under RCW 19.405.040(1) and 19.405.050(1) if, over the four-year compliance period, the average annual incremental cost of meeting the standards or the interim targets established under subsection (1) of this section equals a two percent increase of the investor-owned utility's weather-adjusted sales revenue to customers for electric operations above the previous year, as reported by the investor-owned utility in its most recent commission basis report …"51

As we explain below, the statute unambiguously directs us to adopt a calculation in which the annual threshold increases two percent above the previous year's spending. The legislature also found that the state can achieve the goals of CETA while maintaining stable and affordable rates,52 directing commission and commerce to balance the pursuit of CETA's goals while moderating the rate impact.53 The incremental cost calculation appropriately strikes the balance between giving the utilities enough room to make the required changes while restraining unfettered spending, as directed by the statute. Indeed, to adopt a lower calculation would not only be inconsistent with statute, but could restrain investment to a level that would undermine the statute's very purpose - to eliminate carbon emissions in the electricity sector. The commission and commerce adopt an approach that was advocated by parties including PSE, Climate Solutions, NWEC, and Renewable Northwest, and is consistent with the legislative direction.

111 Avista suggests that the law requires only a flat two percent rate increase over the implementation period. We disagree. RCW 19.405.060 (3)(a) requires that the average annual incremental cost of meeting the standards or interim targets equals a two percent increase of the investor-owned utility's weather-adjusted sales revenue (WASR) to customers for electric operations as reported in the commission basis report above the previous year. The statute describes a calculation that is used for determining compliance - it does not reference a customer rate impact. Moreover, as we have noted, the statute requires a 2 percent increase of the investor-owned utility's revenue above the previous year, not over the implementation period.

112 PacifiCorp argues that the commission is misinterpreting the term "the previous year," which the company believes means the single year immediately preceding the CEIP. We disagree. We interpret the term "the previous year" to mean the year prior to each year within the implementation period. In other words, for each year within the implementation period, the WASR from the previous year's commission basis report applies. PacifiCorp's argument that the meaning of "the previous year" should be the year prior to the filing of the CEIP ignores that the calculation solves for the "average annual incremental cost," and therefore an "increase … above the previous year" is a reference to the prior year for each year within the implementation period, not the year before the implementation period began.54

113 Public counsel argues that the statute does not require CETA-related cost increases from one year to be carried over into the following years. Furthermore, public counsel argues that "[i]f the statute intended the incremental cost calculation to carry cost increases over to the next year, it could have unambiguously stated that requirement."55 In fact, as we have discussed above, the legislature did unambiguously state that requirement in requiring the calculation to reflect the utility's revenue "above the previous year." However, even assuming there is ambiguity, the converse of public counsel's argument is equally true, i.e., that the legislature would have unambiguously stated that the cost of investments only be considered during the first year the investment is made.

114 Utilities do not typically pay for large investments in a lump sum up front. Rather, the standard practice is for large investments to be financed over the period in which the asset is in service. Public counsel appears to take the position that ongoing costs incurred during subsequent years of an implementation period should not be counted as a directly attributable cost. This would severely undercount the actual directly attributable costs of implementation due to the way utilities pay for large investments.

115 We find that the calculation and methodology in the proposed rule is consistent with the statutory language and legislative intent, more so than the proposed alternatives. RCW 19.405.060 (3)(a) states that "the average annual incremental cost … equals a two percent increase … above the previous year." We interpret each word to have meaning; none are superfluous.56 Here, the words "increase" and "above" do not make sense if the interpretation is that the average annual incremental cost equals two percent of the year prior to filing the CEIP. We agree with the comments of PSE, Climate Solutions, NWEC, and Renewable Northwest that the legislature intended for the amount that the utility spends each year toward compliance to increase.57

116 Our colleague's interpretation, and the respective alternative calculations proposed by public counsel, Avista, and PacifiCorp, not only misinterpret the statute, but focus on the least amount of spending feasible at the expense of pursuing the statutory requirements.58 The inconsistency with the statute should not be understated. Public counsel's and Commissioner Balasbas's proposal results in a one-time two percent increase over the WASR for the year preceding the CEIP, followed by small annual increases that equal 0.04 percent of the WASR in each of the following years. Further, Avista's and PacifiCorp's proposals do not allow for these smaller annual increases – they argue for a one-time two percent increase over the four-year period. These calculations do not increase the incremental cost threshold by two percent per year, despite our colleague's claims to the contrary in his dissent.59 We do not believe that these interpretations reflect the legislative requirement for annual two percent increases in the spending threshold above the previous year, which build year over year. Next, PacifiCorp contends that the commission's calculation is incorrect because the utility cannot know what that exact "cost cap" is until several months after the CEIP period. PacifiCorp argues this is inconsistent with the statute and erodes the value of the "cap" as a customer protective measure. PacifiCorp further asserts that the draft rules ignore CETA's requirement that the CEIP be "consistent" with the "cost cap" by relying on a projection of WASR.

117 We disagree with each of PacifiCorp's points. First, as previous[ly] stated, the incremental cost of compliance is a compliance pathway, not a strict cap.

118 Second, PacifiCorp's interpretation is tied to its argument that the commission should determine that a utility may use the compliance pathway when it files its CEIP. PacifiCorp's argument assumes, incorrectly, that the statute implies that the calculation is based upon "projected" revenues. As outlined above, the statutory language is based upon actual, directly attributable costs used to determine compliance, not projections. The calculation for determining the compliance pathway should use actual WASRs. We thus require utilities to use the WASR for each year of the CEIP when each utility files its compliance report, at which time the utility may seek to use the compliance pathway.

119 Relying on projections from the beginning of the implementation period to determine compliance would not be consistent with statute. RCW 19.405.060 (3)(a) states: "All costs included in the determination of cost impact must be directly attributable to actions necessary to comply with the requirements of RCW 19.405.040 and 19.405.050." Reliance on a projected cost that the utility may never actually incur would not be consistent with this requirement. The same is true for the baseline portfolio. The baseline portfolio is described as "an alternative lowest reasonable cost portfolio of investments that are reasonably available."60 Again, relying on a projected cost of an investment that in fact may not be reasonably available during the implementation period would be inconsistent with the statutory description of the baseline portfolio.

120 Third, the proposed rules ensure the CEIP is consistent with the incremental cost of compliance pathway. The commission will not determine if the utility may use the incremental cost of compliance pathway until the company has filed its clean energy compliance report and demonstrated that its spending equaled or exceeded the threshold. Proposed WAC 480-100-660(4) requires utilities to file a projected incremental cost with their CEIPs. When a utility files its CEIP it will not have perfect foresight for the next four years, but the utility should rely on reasonable assumptions of key underlying inputs (revenue, load growth, capex spending, power costs) to make appropriate estimates. Planning for a future with some risk is a fundamental condition of any business, nonprofit, or government. The commission expects that a utility's incremental cost of compliance estimate would be consistent with its recommended specific actions, specific targets, and interim targets that it submits to the commission for approval. Accordingly, the specific actions, specific targets, and interim targets should not require the utility to spend an amount that approaches its incremental cost estimate; to the contrary, as we stated above, CETA requires utilities to meet the statutory requirements at the lowest reasonable cost. However, the commission will not determine if the utility equaled or exceeded the incremental cost of compliance based on "projected" costs, but rather on the actual costs filed in the utility's compliance report.

121 We share the concerns expressed by Avista, AWEC, PacifiCorp, and public counsel related to the potential rate impacts to customers should a utility rely on the incremental cost compliance pathway. However, as we note above, the incremental cost is an alternative, not the primary, pathway for compliance, and is not a strict cost cap. Utilities should be planning to meet the statutory requirements at the lowest reasonable cost, not relying on the incremental cost of compliance pathway as the default method of compliance. The legislature found that meeting those requirements would be feasible while maintaining stable and affordable rates.61

122 Fourth, proposed WAC 480-100-660 (5)(c) requires each utility to update its verifiable and material inputs in the alternative reasonable cost and reasonably available portfolio when it files its clean energy compliance report. PSE contends that requiring utilities to update the baseline using the portfolio optimization model has numerous flaws, including requiring the commission to make periodic and successive determinations of what the utility would have implemented absent CETA. AWEC, Avista, and PacifiCorp argue that a retrospective review puts too much risk on the utilities. AWEC asks the commission to judge if "the utility's forecasts and assumptions were reasonable at the time it made them in the CEIP, just as a utility's prudence is determined based on what it knew when it made the investment decision."62

123 We disagree that requiring the utility to update its inputs is a flaw. Utilities regularly update inputs of previous analysis within a commission proceeding, such as when a utility refiles its power cost baseline during a general rate case.

124 Additionally, although an after-the-fact review creates uncertainty for the utilities, the commission cannot remove all uncertainty. Rather, the commission must strive to balance the needs of the utility and the public, and we believe this decision strikes an appropriate balance. The commission can only determine whether a utility actually met the spending requirements to use the incremental cost compliance pathway with a baseline portfolio that includes, to the extent possible, an accurate representation of what the utility's portfolio would have cost.

125 Although calculating the incremental cost of compliance is not a prudence finding, many of the same facts will be at issue when the commission reviews prudency. In both prudency review and the incremental cost calculation, sensible regulatory oversight demands that we evaluate the utility's actual actions – not its plan.

126 As stated above, CETA requires a cost to be actually incurred in order to be considered directly attributable. The reasonableness of the decision to make the investment is not evaluated when determining incremental cost. Because the utility will be reporting its actual costs based on observed inputs (such as the price of natural gas) to identify the actual incremental cost most closely, the utility should update the inputs and assumptions it made in the baseline when it filed its CEIP. The rules require the updates to be both verifiable and material. The commission, of course, retains its discretion to determine if an input is both verifiable and material during its review of the clean energy compliance report.

127 Directly attributable costs: The commission received comments on if and how SCGHG should be used for calculating the incremental cost of compliance. Avista, PacifiCorp, and PSE argued throughout the rule making that the inclusion of SCGHG in the baseline portfolio inflates the rate impact to customers. Climate Solutions, NWEC, and Renewable Northwest have countered that the inclusion of SCGHG in the law is in sections outside of RCW 19.405.040 and 19.405.050, and therefore should be included in the alternative portfolio used as the counterfactual in the incremental cost.

128 We require the utilities to include SCGHG in the baseline portfolio for calculating the incremental cost of compliance in RCW 19.405.060(3). CETA uses the phrase "lowest reasonable cost" throughout chapter 19.405 RCW but does not define it. That term is defined in the IRP statute, RCW 19.280.020(11), which requires utilities to include "the cost of risks associated with environmental effects including emissions of carbon dioxide."63

129 We find that including SCGHG in the baseline portfolio is required by statute.64 Under RCW 19.280.030 (a)(i) and (iii), a utility is required to include SCGHG as a cost adder when "selecting and evaluating" intermediate and long-term resource options, as well as conservation policies, programs, and targets. Because these subsections would still be statutory requirements but for RCW 19.405.040 and 19.405.050, SCGHG must be included in the baseline portfolio.

130 We do note that the requirement for utilities to ensure all customers are benefiting from the transition to clean energy, as well as the other requirements set out in RCW 19.405.040(8), are explicitly part of the costs to implement RCW 19.405.040 and should be considered a directly attributable cost of compliance. Accordingly, these costs are not included in the baseline portfolio.

131 While the phrase "selecting and evaluating" in RCW 19.280.030 (a)(i) and (iii) could be read to mean selection only within IRP and not in actual investment decisions, RCW 19.280.030 (a)(ii), which states that SCGHG should be included when developing IRPs and CEIPs, contradicts that interpretation. Given that context, if RCW 19.280.030 (a)(i) and (iii) were in fact merely intended as planning requirements, not required for actual investing decisions, then RCW 19.280.030 (a)(ii) is redundant. We decline to so construe the statute. Consistent with our interpretation of the legislature's intent, we include SCGHG in the baseline portfolio's definition.

132 In enacting CETA, the legislature both amended chapter 19.280 RCW and created chapter 19.405 RCW. The IRP and CEIP processes are closely interrelated. The most reasonable statutory interpretation is that the term "lowest reasonable cost" has the same general meaning in both statutes.65 Finally, although the phrase "social cost of greenhouse gas emissions" appears only in RCW 19.280.030, the calculation of cost for greenhouse gas emissions, including the effect of emissions, applies throughout CETA.66 This is yet another indication that SCGHG was intended to have implications outside of IRP. The proposed rules, therefore, define the baseline portfolio's reference to "lowest reasonable cost" to include SCGHG in the same manner required under chapter 19.280 RCW.67

G. Public Participation.

134 A utility's consultations with staff and advisory groups, and opportunities for public participation, are essential to the development of effective IRPs, two-year progress reports, CEIPs, and biennial updates. As a matter of policy, the commission prefers that utilities engage the public in the resource planning processes currently reflected in WAC 480-100-238, adopted in 2006, and prior versions of IRP rules, which these rules replace.68 Meeting the standards of RCW 19.405.040(8)69 requires community engagement to determine how utilities will ensure that all customers are benefiting from the transition to clean energy, with particular emphasis on the needs of highly impacted communities and vulnerable populations.

135 We recognize that utilities have different service territories, varied customer needs, and particular public involvement processes, and that the administrative aspects of utilities' public involvement efforts will be different from company to company. However, the rules we adopt in this order are intended to ensure that utilities administer their individual processes with a similar overarching ethos—one of accessibility, transparency, responsiveness, and clarity. It is in the best interests of utilities, customers, and stakeholders to work collaboratively and proactively through the difficult challenges ahead in implementing CETA. The proposed rules provide a framework for utilities to apply those processes while offering flexibility to fit their particular needs and circumstances.

1. Advisory groups: WAC 480-100-630, 480-100-655.

136 Proposed WAC 480-100-630, 480-100-625 and 480-100-655 rely on the use of advisory group input in the development of, and reporting on, IRPs and CEIPs, as well as associated updates. As previously stated, this process is designed to meet the standards for customer benefit established in RCW 19.405.040(8) in addition to existing expectations for public participation in IRP planning. Throughout this rule making, the commission heard from utilities and stakeholders alike on the benefits and challenges associated with advisory group structures.

137 The benefits of advisory groups include opportunities for deeper conversations with a variety of interested stakeholders on important topics. This provides opportunities to address potential issues and concerns with a plan prior to the utility submitting it to the commission, potentially reducing the need for future adjudication. The challenges include, but are not limited to, the administration of groups; gatekeeping membership to advisory groups; the lack of sincere engagement some group members may see in utilities' efforts; the lack of sincere engagement some utilities may see in some group members' efforts; arguments about how much advisory group input should be reflected in final decisions presented in plans; and lack of trust and transparency in the advisory group process.

138 The comments reflect such challenges, which stakeholders and utilities have experienced in varying degrees. But these challenges do not discount the benefits that can be realized by meaningful and inclusive public engagement through an advisory group process.

139 Utilities and advisory group members alike will need to work on and through these challenges as we implement CETA.

2. International Association for Public Participation Framework: WAC 480-100-630, 480-100-655, 480-100-610, 480-100-625.

140 In efforts to address the challenges of advisory groups, some commenters, including Western Grid Group, Sierra Club, Vashon Climate Action Group, NWEC, and WEC, have advocated that the commission include in its rules all or parts of a public participation framework developed by the International Association for Public Participation (IAP2). For example, commenters have recommended adopting IAP2-specific definitions for the words "inform," "consult," "involve," and "collaborate." Some commenters have also suggested requiring utilities to orient their planning practices to one of the IAP2-defined planning levels, such as "involve" or "collaborate."

141 We appreciate commenters' desire for clarity around minimum expectations for utility and public interaction, as well as clarification regarding how public input can or should influence a utility's decision. We nevertheless decline to adopt the IAP2 framework and definitions in the proposed rules. The commission views IAP2 guidance as one of a number of tools utilities can use to advance their efforts in public involvement.

142 IAP2 can provide helpful guidance to utilities in determining public involvement needs for individual decision points in their planning processes. However, IAP2 definitions should not be used as blanket promises of participation levels without considering the specific decisions that the responsible entity must make. Selecting an appropriate level of participation for a particular decision requires careful consideration by the decision-maker. Further, IAP2 guidance is not the only public participation framework available, and we decline to elevate one framework over others without a thorough evaluation of all options. Finally, direct adoption of IAP2's definitions of words such as "inform," "consult," "involve," and "collaborate" would unnecessarily affect the meaning of these otherwise common terms and restrict the commission's ability to use them in other parts of the rules.

143 Proposed WAC 480-100-630(1) and 480-100-655(1) provide the minimum expectations for a utility's public involvement with its advisory groups. Utilities must consider public input, for example, through modeling scenarios and sensitivities suggested by advisory group members. Additionally, utilities must document how they use public input, which means communicating how public input was considered and addressed both to the commission and to those who provided it. Utilities may use this specific advisory group guidance as a starting point for other types of public participation.

144 The decisions regarding how, where, and when to incorporate public input in plan development are largely the prerogative of the utility, with the exception of developing customer benefit indicators around, for example, energy and non-energy benefits as discussed in proposed WAC 480-100-610 (4)(c). Utilities are ultimately responsible for defending a plan's reasonableness before the commission. Given the commission's strong preference that utilities engage the public in the plan development process, we expect that plans will demonstrate that a utility took appropriate actions to sufficiently solicit, document, and consider public input. To a large extent, we view advisory groups as an appropriate venue for early resolution of issues that later come before the commission in adjudicated proceedings.

145 Utilities are required in proposed WAC 480-100-630(2) to provide advisory group members with completed presentation materials no less than three business days in advance of each advisory group meeting discussing an IRP. This requirement ensures advisory group members, some of whom may participate in a nonprofessional capacity, have sufficient time to digest meeting materials and can participate effectively in meetings. We recognize that advisory group members may have differing levels of experience with utility planning and may have different barriers to participating in the planning process. Utilities should strive to provide members of their advisory groups with informational materials as far in advance of meetings as necessary to allow for meaningful discussion of those materials.70

146 The commission offers the public involvement process in proposed WAC 480-100-625, 480-100-630, and 480-100-655 as a guiding flexible framework for utilities to use in outlining their own plans. With the exceptions noted in this order, the commission generally declines to adopt prescriptive requirements in the proposed rules for the administration of public involvement, methods of consensus building, or requirements for how public involvement impacts final decision-making. These decisions are for the utilities to make and to defend. However, in these rules, we require utilities to clearly document and communicate decision-making on these issues to both those participating in the advisory group process and the commission.

3. "Public" vs "advisory group member": WAC 480-100-630, 480-100-655.

147 Several participants in this rule making have responded to the proposed rules with concerns about a perceived reduction in public participation elements, particularly where those rules have substituted the term "advisory group member" for "public" in prior drafts. We clarify that these rules do not reduce the role of public participation in either the CEIP or IRP. Rather, the proposed rules clarify the roles of advisory group processes and other forms of public engagement. Additionally, the proposed rules set expectations regarding how utilities consider input from advisory groups and communicate utility consideration of that input.

148 We understand a utility's primary method of engaging the public and stakeholders in IRP development is through the utility's advisory groups. Proposed WAC 480-100-625 and 480-100-630 clarify our expectations of utility engagement with IRP advisory groups. Proposed WAC 480-100-655(1) extends those expectations to advisory groups required for the CEIP development process. These clarifications in no way prohibit utilities from engaging the public in different, additional ways, which the commission encourages.

149 Advisory group public input processes, such as those in proposed WAC 480-100-625, 480-100-630, and 480-100-655, are inherently limited to selected or self-selected representative members of the public. Loosely termed as "advisory group members," these representatives are differentiated from the wider public made up of all utility customers, community members, and others who may be interested in a utility's business. Advisory groups often include representation from stakeholders who regularly engage with the utility, such as public counsel and staff, but the distinction between the wider public and members of an advisory group is otherwise fluid. Participation in an advisory group is predicated largely on a group or individual's interest and willingness to commit time and effort to an advisory group process.

150 The proposed rules focus on advisory groups through the outline of an IRP's public process in proposed WAC 480-100-630; the creation of an equity group to advise utilities on equity issues in proposed WAC 480-100-655 (1)(b); and the inclusion of existing and new advisory groups in the CEIP process in proposed WAC 480-100-655 (1)(a). These provisions, however, do not discount the importance of involvement from the wider public. Nor do the proposed rules indicate a preference for gatekeeping the membership of an advisory group. Advisory group membership should be broadly available to the public-at-large. The general public should always have the ability to watch and listen to conversations taking place in advisory groups, if not directly participate in them.71

151 Utilities will ultimately determine the membership, agenda, and workplan for an advisory group, but we direct utilities to ensure they are responsive to outside input. Membership of the advisory group must be broad and representative of the various individuals and formal and informal organizations interested in utilities' plans. We expect utilities and stakeholders to manage issues within the advisory group without commission intervention. This includes matters regarding access to information, the behavior of the utility or stakeholders, obstruction of conversation on the part of a utility or stakeholder, incivility or disruptiveness, and participation by unrepresented groups or individuals with an interest in plan development. The commission expects all participants to work together cordially and constructively.

4. Public participation plan: WAC 480-100-655, 480-100-625.

152 Utilities' efforts to encourage and facilitate broader public engagement must be outlined in their public participation plans required in proposed WAC 480-100-655(2) and may be included in the IRP workplan described in proposed WAC 480-100-625 if specific to the IRP process.

153 The commission anticipates that engagement in IRPs and CEIPs will likely begin to overlap as public involvement in planning continues. The CEIP public participation plan covers a two-year period for CEIP development and implementation, during which time utilities will also be engaged in IRP development. In time, the CEIP public participation plan may begin to include elements for integrated resource planning, particularly as they relate to equity needs. We view the public participation plan as inherently flexible—it will both document work conducted during the period before submission of the plan and outline forward-thinking efforts for public involvement through the period. We expect the utilities and stakeholders to work together in the coming years to further refine public participation plans.

5. Comment summaries: WAC 480-100-625, 480-100-630, 480-100-655.

154 Proposed WAC 480-100-625, 480-100-630, and 480-100-655(1) establish minimum expectations for utilities to work with the members of their advisory groups. This order and the proposed rules promote advisory group access to the public-at-large. A key element of engagement is communicating and responding to public inquiries or suggestions.

155 We expect utilities to respect advisory group members' investment of time and resources to IRP and CEIP development by fully responding to the merits of group member suggestions, but we also understand the need for efficiency. When responding to comments identified in form letters or emails on a particular topic, it is reasonable for utilities to respond with a single, complete response, identifying the number of such contacts. Similarly, it is reasonable for utilities to respond to similar, nonform suggestions with single, complete responses to each topical element as provided in proposed WAC 480-100-620(17), 480-100-625 (5)(d), and 480-100-655 (1)(i), but identifying the groups or individual providing comments.

156 Maintaining advisory group input and responses for integrated resource planning on a public website, as proposed WAC 480-100-625 (5)(d) requires and as some utilities already do, will provide stakeholders and the public-at-large with a clear understanding of decisions the utility has made or topics the advisory group considered. We understand this is how PacifiCorp typically handles its communication of public input on integrated resource planning, and we find this model reasonable for all investor-owned electric utilities to track and respond to public input on integrated resource planning. In keeping these records in a condensed and organized space throughout the process, utilities will have done a large part of the administrative work needed to submit comment summaries with their IRPs, as required by proposed WAC 480-100-620(17). While final plans are utility documents and it is up to utilities to demonstrate their reasonableness, the effort of tracking and responding to public input will assist the commission in determining whether and how a utility's plans meet requirements of the rules and promote the public interest. We find that documentation demonstrating how a utility plans to meet or respond to customer needs, including numerical counts of form letters, will aid the commission in determining whether to acknowledge or approve final plans.

157 In total, the efficient management of documenting and considering public input is a reasonable expectation of any public involvement opportunity, especially one involving utility customers.

158 While proposed WAC 480-100-655 (1)(i) requires utilities to submit with their CEIPs and biennial updates a summary of advisory group comments and utility responses, that proposed rule does not require utilities to track and respond to CEIP public input on their websites. CEIP development may become more complicated, with multiple public input processes beyond just the advisory group structure. For example, WAC 480-100-655 (2)(a)(i) requires engagement specifically with vulnerable populations and highly impacted communities for the creation of and updates to customer benefit indicators and weighting factors for compliance with RCW 19.405.040(8). This type of engagement has a specific focus and will be targeted to specific communities with differing communication needs. While the commission does not require this input and engagement to be recorded on a utility's website, the utility may choose to use its website as the appropriate forum, and we expect utilities to clearly communicate to customers engaged in these efforts how their input was or was not used.

6. Equity advisory group: WAC 480-100-655, 480-100-625.

159 The commission has supported and continues to support public engagement in utility planning on topics ranging from low-income issues to conservation planning.72 Equity concerns addressed by RCW 19.405.040(8) are cross-cutting, complicated issues that will require specific focus and attention by the commission, utilities, their customers, and stakeholders. Because compliance with RCW 19.405.040(8) is context-dependent, it requires engagement with communities, including highly-impacted communities and vulnerable populations, so that utilities are ensuring an equitable distribution of benefits. Therefore, the commission finds it reasonable that utilities create and engage with an advisory group on the equity components of implementing CETA in IRPs and CEIPs.

160 Creation of group: An early discussion in this rule making centered around whether the equity advisory group discussed in proposed WAC 480-100-655 (1)(b) should exist at a state-wide level to discuss compliance with RCW 19.405.040(8), whether individual utilities should create their own groups, or whether equity should instead be represented across all existing, individual utility advisory groups without the creation of a new standalone group. The commission has determined that individual utility equity advisory groups would best address the varying issues and needs across utility service territories.

161 We understand that utilities are continuing to discuss whether they can comply with the requirements to create an equity group by merging the equity group with existing groups or otherwise incorporating equity across existing groups. A key consideration of the commission's approval of any proposal is representation: The requirements of developing an equity group or incorporating equity in existing groups would not be appropriately met if the representation of equity interests is diluted in such a proposed merged group. We encourage utilities and stakeholders to establish equity advisory groups to focus specifically on equity concerns, and to include equitable considerations in the work of utilities' other advisory groups. The work of the advisory groups should not be exclusive, but complementary, and utilities may find that holding meetings with all of a utility's advisory groups together to discuss interrelated or general issues is appropriate.

162 Some stakeholders, including Front and Centered and Climate Solutions, expressed concerns about placing the mandate for the creation of equity groups in the CEIP rules, saying that this placement might hamstring the usefulness of the group if, for example, it delayed its creation or engagement until the end of a planning cycle. To the contrary, we clarify that the creation of an advisory group is only a starting point for the group's work. Proposed WAC 480-100-625 (2)(b) pulls the new equity group into a role for IRP planning. Further, we encourage utilities to approach the role of equity groups broadly and to quickly begin forming and engaging with equity groups. We anticipate that the work of the newly established equity groups will be significant as utilities, customers, stakeholders, and the commission begin to implement CETA's equity mandates.

163Invite versus encourage and include: In CR-101 comments, PSE recommended that the commission change the phrase "encourage and include" to "invite" related to the process of utility outreach in establishing equity advisory groups in draft WAC 480-100-655 (1)(b). The commission declines to make this change in the proposed rule. The decision to use the words "encourage and include" in the rule language was deliberate. Throughout the course of this rule making, we have heard from stakeholders regarding the important role community participation plays in the development of outcomes meant to address specific community needs, as well as certain social and economic barriers that, in the past, have limited the engagement of highly impacted communities and vulnerable populations. The word "invite" implies that only those organizations or individuals that a utility specifically requests may participate in the advisory group, implying that the utility may exclude others. Further, if a utility invites a group or individual to participate in an equity advisory group and the utility's invitation is declined or unanswered, the utility will need to reorient its efforts to develop community-specific guidance. By using the words "encourage and include" to describe the process of forming an equity advisory group, we intend that utilities will proactively reach out to a variety of community voices and reduce barriers to participation.

164 Equity group or intervenor funding: Public counsel and several other commentors have requested various funding mechanisms to ensure individuals or groups representing vulnerable populations and highly-impacted communities have the financial resources to engage in commission or utility processes. Most recently in its CR-102 comments, public counsel urged the inclusion of "basic requirement language in rule" as we adopt these rules with details of funding mechanisms and program design to be discussed with more deliberation among stakeholders and a commission policy statement. Public counsel's specific recommendation in its CR-101 comments suggested the commission require utilities to provide funding for both community-based organizations and individuals to participate in the equity advisory group process and that the commission administer this program. Other commenters including NWEC, Climate Solutions, Front and Centered, One America, Puget Sound Sage, Spark Northwest, Sierra Club, Audubon et. al., El Centro de la Raza, and Washington environmental council have recommended similar equity-focused funding or spending requirements such as requirements for intervenor funding, requirements for utilities to contract with community-based organizations, and requirements for funding mechanisms specifically focused on equity-related public participation, including advisory groups. At the outset, we have questions [about] whether the commission has authority to require such funding. We also have questions about how to determine levels of funding, which organizations would be eligible, which organizations would be excluded if funding is limited, and how any funding mechanism would be administered. We remain interested in additional conversations on these issues, but we decline to require any specific funding mechanism in these proposed rules.

165 Proposed WAC 480-100-655 (2)(b) requires utilities to reduce barriers to participation in utility processes, including those related to economic needs. In the future, as additional information comes forward during rule implementation and as conversations on these issues evolve, the commission may consider issuing additional guidance.

7. Draft IRP and progress report as part of public engagement: WAC 480-100-610, 480-100-620, 480-100-625, 480-100-630, 480-100-655.

166 Providing a draft IRP plan is a critical part of the public participation processes set forth in proposed WAC 480-100-625, 480-100-630, and 480-100-655. To ensure transparency, it is also important that the modeling and portfolio analysis leading to the draft IRP be as complete as practicable before filing to allow the public to comment on the company's presentation and provide meaningful public input on the draft IRP.73 Advisory group participation during the IRP development process, where specific issues are often discussed individually, does not substitute for a thorough review of a substantially completed draft. Only once the plan is substantially complete can advisory group members understand the interactions between the different inputs to the IRP, and determine whether certain elements of the IRP are not sufficiently addressed. Thus, we expect the draft IRP will be substantially complete, containing to the extent practicable the preferred portfolio, CEAP and supporting analysis, and all scenarios, sensitivities, appendices, and attachments. We also find it reasonable to expect the draft plan and modeling to provide an accessible, clear, and transparent view of a utility's plans. A substantially complete draft will allow the public to effectively comment on the long-range IRP solution.

167 As outlined in proposed WAC 480-100-620(17), the final IRP should address appropriate points and public input received after the utility files its draft IRP, including those received through the commission's open meeting public comment process.

168 In its comments related to the 2021 IRP cycle, PSE asserts the IRP is being developed on a schedule that does not allow for all IRP analyses to be completed in time for the draft submittal, with certain modeling components still in development. As outlined in proposed WAC 480-100-620 (11)(a), for the utility to determine its preferred portfolio, the utility must complete the modeling necessary to meet the clean energy transformation standards in WAC 480-100-610 (1)-(3) at the lowest reasonable cost. Lowest reasonable cost is defined in RCW 19.280.020(11), but in its essence, it addresses the utility's obligation to balance cost and risk. The utility must complete modeling and analysis to properly address market-volatility risks, demand-side resource uncertainties, resource dispatchability, resource effect on system operation, the risks imposed on the utility and its customers, public policies regarding resource preference adopted by Washington or the federal government, and the cost of risks associated with environmental effects, including emissions of carbon dioxide. We understand the 2021 cycle is unique and the first under CETA directives, with accompanying modeling and timing challenges. We will provide flexibility in the first round of submissions. Looking ahead to future IRP cycles, the utility must consider the risks outlined in the statutory definition of lowest reasonable cost in its portfolio analysis and selection of the utility's preferred portfolio identified in its draft IRP. Further, after the 2021 cycle, the utility will have a few years to adjust its internal timelines to meet the new IRP schedule, including the draft IRP.

169Two-year progress report. WAC 480-100-625(4). In response to the first discussion draft of the IRP rules released in November 2019, NWEC, Front and Centered, Climate Solutions, WEC, Vashon Climate Action Group, Sierra Club, Invenergy, and Northwest and Intermountain Power Producers Coalition (NIPPC), signaled opposition to the requirement of waiting four years in the utility planning process for the utility to file an updated IRP. Stakeholders voiced concerns that utility data may lag behind the best available technology and pricing.

170 In response to these concerns, proposed WAC 480-100-625 requires each electric utility to file an IRP every four years after the 2021 IRP, with a two-year progress report updating key inputs and outputs and accounting for significant changes to economic or market forces. However, the commission elects to retain the proposal to lengthen the time from two years to four years in between full IRPs. First, the IRP and CEAP inform the CEIP, necessitating alignment of the various plans. Second, the IRP will be a key input dictating the direction of the utility's CEIP, which is an action plan with greater significance than any such plan utilities have previously provided to the commission. Providing additional time between IRPs will allow utilities to continue to refine analyses and gain additional modeling expertise. We thus find it reasonable to reduce the regulatory burden on utilities by requiring less frequent filings. However, to address the parties' concern that resource cost data will become stale, proposed WAC 480-100-625 (4)(a)(iii) requires the utility to update its resource costs during the two-year progress report.74

171 Proposed WAC 480-100-625(2) outlines requirements for utilities to file workplans that include any expectations of work for a two-year progress report. Utilities are not required to file full workplans for two-year progress reports. Instead, utilities are directed to update their workplans, as discussed in WAC 480-100-625 (2)(g), if they anticipate significant changes. Utilities, staff, and stakeholders should work together to refine the two-year advisory group process as these proposed rules are implemented and as any issues arise with this process.

8. Data availability: WAC 480-100-630, 480-100-655, 480-100-620, 480-100-640, 480-100-650.

172 In plan and report filing: A utility is required to include appendices containing its data input files in native format when it files its IRP, two-year progress report, CEIP, and clean energy compliance report.75 This requirement increases the transparency of the utility's plans and reports. RCW 19.280.030(10) supports increased transparency in the IRP process,76 and these sections of proposed rules closely match the statute as well as the commission's current rules regarding confidential information.77

173 A basic requirement of utility regulation is that the utility make available the inputs, data, and assumptions it uses when making its decisions or submitting proposals to the regulator. The commission, staff, public counsel, and other parties with a substantial interest must be able to understand why a utility took the actions it did, or proposed to take certain actions, and to determine independently whether those actions are in the public interest and represent the lowest reasonable cost option.

174 When a utility marks certain information as confidential under RCW 80.04.095, initially that information is only available to the commission and the attorney general's office. During an adjudicated case, other parties to which the commission has granted intervention also may gain access to that information through protective orders. RCW 19.280.030(9), however, authorizes the commission to acknowledge, but not approve, a utility's IRP, meaning the IRP is not subject to adjudication. Accordingly, the commission lacks the legal authority in the IRP process to compel a utility to share confidential information with interested persons other than staff and public counsel.

175 A utility may also designate as confidential certain information contained in its CEIP and clean energy compliance report. Again, only the commission and attorney general's office have immediate access to that information. Unlike an IRP, however, the commission may adjudicate a CEIP or clean energy compliance report. In any such adjudication, parties the commission allows to intervene may gain access to the confidential information under the terms of a commission protective order.

176 The commission strongly encourages utilities to minimize the amount of information designated as confidential in a IRP, CEIP, and clean energy compliance report to allow interested persons access to as much information as possible related to those filings.

177During plan development: Proposed WAC 480-100-630(3) and 480-100-655 (1)(h) lay out expectations for data availability to advisory groups during the development of IRPs, CEIPs, and their associated updates.

178 All nonconfidential information relevant to these plans and updates must be available to advisory groups, in an easily accessible format, on request and provided expeditiously throughout the advisory group process.

179 If a utility relies on confidential information during the plan development process, the utility must make this information, including data inputs and files, available to the commission in both native file format and in an easily accessible format.78 Compliance with this element requires that the utility ensure that the commission can manipulate the data and the modeling files in analyzing the utility's actions. This may require the utility to provide cloud access to data and discuss access to modeling software, similar to prior arrangements.

180 During this rule making, stakeholders including Sierra Club and Vashon Climate Action Group asked the commission to require utilities to offer non-disclosure agreements (NDAs) with parties and advisory groups to share confidential information during the development of the IRP and after its submission to the commission.79

181 While the commission does not compel utilities to sign NDAs, we recognize that this is an option for utilities to consider. The designation of confidential information is governed by statute.80 Regardless, these provisions do not preclude utilities from volunteering NDAs to parties or advisory groups to facilitate discussions on sensitive issues in a timely manner, and the commission would support utilities in their choice to use such agreements as a tool to facilitate discussion with interested persons.

182 While plans are utility documents, it is in both the public interest and the utility's interest for the utility to be as transparent as possible. An IRP may not be adjudicated, but the inputs and assumptions used in the IRP will likely be key inputs and assumptions in a CEIP. A utility may elect not to share confidential information with advisory groups or parties in the IRP process that may have a substantial interest in the CEIP, update, and clean energy compliance report. However, utilities should recognize that withholding that information increases the likelihood that the subsequent filing will be adjudicated because parties to an adjudication have access to confidential information under the terms of a commission protective order.

183 We view the public involvement efforts contained in this rule as a minimum standard. Utilities can and, in certain circumstances should, make efforts to incorporate customer and stakeholder input that go beyond these requirements.

184 The commission anticipates the need for additional, flexible guidance as utilities navigate public involvement, the creation of new advisory groups on equity issues, and the iterative, cross-topical nature of resource planning under CETA. This guidance may be developed in the coming months as specific issues are further discussed and addressed in upcoming workshops.

185CHANGES FROM PROPOSAL: The commission makes the following changes to the proposed rules in the text noticed at WSR 20-21-053:

WAC 480-100-605 "Indicator" definition and all uses of "indicator" in the rule: WAC 480-100-640 (4)(c) and (5)(c), 480-100-650 (1)(d)(i) and (1)(e), 480-100-655 (1)(b), 480-100-665 (2)(a)(i) and (2)(a)(ii), before indicator add "Customer benefit." Note that change in term requires moving the definition due to alphabetical order.

WAC 480-100-620 (11)(b), add "power" after "purchases, and" and delete "power" after "purchase."

WAC 480-100-620 (12)(h), insert citation "RCW 19.405.040 (1)(b)" after "under" and delete "RCW 19.405.090."

WAC 480-100-620(14), insert "and in an easily accessible format" after "RCW 19.280.030 (10)(a) and (b)" and before "as an appendix."

WAC 480-100-625 (2)(f), move (f)(i)-(iv) to a new subsection (5) titled "Publicly available information"; delete "a website managed by the utility" after "a link to" and before ", updated in a timely manner"; insert "the utility's website" after "a link to" and before ", updated in a timely manner"; delete "the following information:" after "makes publicly available"; insert "information related to the IRP, including information outlined in WAC 480-100-625(5)." after "makes publicly available."

WAC 480-100-630(1), insert citation "WAC 480-100-625(5)" after "and consistent with" and before ", the utility must communicate with advisory groups"; delete "WAC 480-100-625 (2)(f)" after "and consistent with" and before "the utility must communicate with advisory groups."

WAC 480-100-630(3), insert "used to develop its IRP" after "all of its data inputs and files" and before "available to the commission"; insert "nonconfidential" after "supporting documentation as well as" and before "data inputs and files"; insert "in an easily accessible format" after "advisory group member review" and before "upon request."

WAC 480-100-640, rename section as "Content of Clean Energy Implementation Plan."

WAC 480-100-640 (3)(b), insert "and in an easily accessible format" after "native format" and before "as an appendix"; delete ", as required in WAC 480-100-655 (1)(h)," after "native format" and before "as an appendix."

WAC 480-100-640 (4)(c), after "reduction of cost," add "reduction of risk."

WAC 480-100-640(5), after "must meet" add "and be consistent with."

WAC 480-100-650 (1)(k), insert "and in an easily accessible format" after "native format" and before "as an appendix"; delete "per WAC 480-100-655 (1)(h)" after "native format" and before "as an appendix."

WAC 480-100-650 (3)(e), insert "(e.g.," after "they were used" before "voluntary renewable programs"; delete "(i.e.," after "they were used" before "voluntary renewable programs"; delete "(, etc.)."

WAC 480-100-655 (1)(g), insert "(g) The utility must make available completed presentation materials for each advisory group meeting at least three business days prior to the meeting. The utility may update materials as needed." after "CEIP filings before the commission," and before "The utility must make all of."

WAC 480-100-655 (1)(h), substitute "(g)" for "(h)"; insert "used to develop its CEIP" after "data inputs and files" and before "available to the commission"; insert "as well as non-confidential data inputs and files" after "supporting documentation" and before "must be available for advisory group review"; insert "in an easily accessible format" after "advisory group member review" and before "upon request."

WAC 480-100-655 (1)(i), substitute "(h)" for "(i)."

WAC 480-100-660 (6)(b), insert citation "RCW 19.405.040 (1)(b)" after "under" and delete "RCW 19.405.060 (3)(a)."

186COMMISSION ACTION: After considering all of the information regarding this proposal, the commission finds and concludes that it should adopt the rules as proposed in the CR-102 at WSR 20-21-053 with the nonsubstantive revisions listed above. We accept staff's explanations for changes as stated in Appendix A of this order. The following explains the remaining revisions.

187 The commission modifies proposed WAC 480-100-605 "Indicator" definition and all uses of indicator in the rule: WAC 480-100-640 (4)(c) and (5)(c), 480-100-650 (1)(d)(i) and (1)(e), 480-100-655 (1)(b), 480-100-665 (2)(a)(i) and (ii). General comments regarding confusion around the definition of "indicator" generated the change to further clarify the use of the term and allows for other types of indicators to be easily understood in the future.

188 The commission modifies proposed WAC 480-100-620 (11)(b) as a clarifying edit.

189 The commission modifies proposed WAC 480-100-620 (12)(h) to correct a statutory citation.

190 The commission modifies proposed WAC 480-100-620(14) to clarify the requirements and to make all data disclosure requirements consistent within the rule.

191 The commission modifies proposed WAC 480-100-640 to clarify the content of the section and to provide consistency with WAC 480-100-620 Content of an integrated resource plan.

192 The commission modifies proposed WAC 480-100-640 (4)(c) to correct an oversight of statutory requirements. The modifications require at least one customer benefit indicator for each element in RCW 19.405.040(8).

193 The commission modifies proposed WAC 480-100-640(5) to integrate "consistent with" CETA language found in multiple parts of the IRP and CEIP rules.

194 The commission modifies proposed WAC 480-100-650 (3)(e) to clarify examples.

195 The commission modifies proposed WAC 480-100-655 (1)(i) to accommodate rule reorganization of WAC 480-100-655 (1)(g).

196STATEMENT OF ACTION; STATEMENT OF EFFECTIVE DATE: After reviewing the entire record, the commission determines that WAC 480-100-600, 480-100-605, 480-100-610, 480-100-620, 480-100-625, 480-100-630, 480-100-640, 480-100-645, 480-100-650, 480-100-655, 480-100-660, and 480-100-665 should be adopted to read as set forth in Appendix B, as rules of the Washington utilities and transportation commission, to take effect on December 31, 2020, as required in RCW 19.405.100(9).81

Number of Sections Adopted in Order to Comply with Federal Statute: New 0, amended 0, repealed 0; Federal Rules or Standards: New 0, amended 0, repealed 0; or Recently Enacted State Statutes: New 12, amended 0, repealed 0.

Number of Sections Adopted at Request of a Nongovernmental Entity: New 0, amended 0, repealed 0.

Number of Sections Adopted on the Agency's own Initiative: New 0, amended 0, repealed 0.

Number of Sections Adopted in Order to Clarify, Streamline, or Reform Agency Procedures: New 0, amended 0, repealed 0.

Number of Sections Adopted using Negotiated Rule Making: New 0, amended 0, repealed 0; Pilot Rule Making: New 0, amended 0, repealed 0; or Other Alternative Rule Making: New 12, amended 0, repealed 0.

197 The commission adopts WAC 480-100-600, 480-100-605, 480-100-610, 480-100-620, 480-100-625, 480-100-630, 480-100-640, 480-100-645, 480-100-650, 480-100-655, 480-100-660, and 480-100-665 to read as set forth in Appendix B, as rules of the Washington utilities and transportation commission, to take effect on December 31, 2020.

198 This order and the rule set out below, after being recorded in the register of the Washington utilities and transportation commission, shall be forwarded to the code reviser for filing pursuant to chapters 80.01 and 34.05 RCW and 1-21 WAC.

DATED at Lacey, Washington, December 28, 2020.

Washington Utilities and Transportation Commission

David W. Danner, Chair

Ann E. Rendahl, Commissioner

1 Today's order concludes a nearly eighteen-month process focused on implementation of CETA. I agree with my colleagues that the commission has fulfilled its statutory obligation under RCW 19.405.100 by adopting rules prior to January 1, 2021. I also support several provisions of the rules. However, I respectfully disagree with my colleagues and oppose adoption of one part of proposed WAC 480-100-605 Definitions, the entirety of proposed WAC 480-100-660 Incremental cost of compliance, and the entirety of proposed WAC 480-100-665 Enforcement. These sections of the rules run contrary to the legislature's intent and explicit direction to simplify utility compliance with CETA,1 as well as accomplishing the goals of the law while maintaining safe and reliable electricity to all customers at stable and affordable rates.2

2 A new addition to the rules, proposed WAC 480-100-605 defines the "Alternative lowest reasonable cost and reasonably available portfolio."3 Further defining this term beyond the statute is a necessary part of developing a methodology for calculating the incremental cost of compliance.4 The term enables utilities to show a comparison of a CETA compliant resource portfolio and a non-CETA compliant resource portfolio (baseline portfolio). However, the definition in the rules (and therefore the portfolio comparison) becomes meaningless by including the social cost of greenhouse gases (SCGHG) in the baseline portfolio.

3 Statute now requires utilities to use SCGHG as a cost adder for evaluating conservation strategies, developing the IRP and CEAP as well as evaluating and selecting intermediate and long-term resource options.5 What is not clear, is whether the legislature intended to include SCGHG in the baseline portfolio. All three utilities and AWEC persuasively argued in their comments throughout this rule making that including SCGHG in the baseline portfolio lacks statutory support and will needlessly lead to higher costs for ratepayers.6

4 The term "lowest reasonable cost" is not defined anywhere in chapter 19.405 RCW and is only defined in RCW 19.280.020(11) and again in proposed WAC 480-100-605. The language in both places requires a utility IRP analysis to consider in part "the cost of risks associated with environmental effects including emissions of carbon dioxide." While my colleagues used this language to justify a requirement for utilities to model SCGHG in their preferred portfolios in 2017 IRP acknowledgment letters, the plain words of the statute are not the same as SCGHG, which is a specific calculation outlined in RCW 80.28.405 enacted in 2019. Even the references to SCGHG in RCW 19.280.030 (3)(a) do not list the incremental cost calculation as an area where a utility must incorporate it as a cost adder.

5 Aside from the lack of statutory support, I believe the correct interpretation of statute shows that SCGHG is a "directly attributable" cost of complying with CETA. When using the incremental cost of compliance pathway, utilities must demonstrate that any costs be "directly attributable" to compliance with RCW 19.405.040 and 19.405.050.7 SCGHG is a component of the 2045 planning standard in RCW 19.405.050 as demonstrated by AWEC's analysis of reading the requirements of RCW 19.280.030 (3)(a) and 19.405.050 together.8 Including SCGHG in the baseline portfolio thus contradicts the intent and meaning of the statute and the first step toward weaking the incremental cost of compliance mechanism.

6 The current commission calculated SCGHG shows a cost of $68 per ton in 2020, increasing to $102 per ton in 2040.9 This cost artificially inflates the baseline portfolio and the costs of non-renewable resources. Requiring inclusion of SCGHG in the baseline portfolio will ultimately lead to higher than necessary costs for ratepayers through the selection of more expensive resources. The inclusion of SCGHG in the baseline portfolio also makes a comparison to a CETA compliant portfolio meaningless, as the only real difference in the two portfolios is whether equitable distribution of benefits is included or not.

7 Turning to proposed WAC 480-100-660 Incremental cost of compliance, I am extremely disappointed and frustrated by the commission's action with this section of the rules. The sole purpose of the incremental cost provisions of CETA is to protect ratepayers from large cost increases to achieve CETA's goals of one hundred percent clean energy by 2045. Specifically, the incremental cost of compliance statutory language says:

"An investor-owned utility must be considered to be in compliance with the standards under RCW 19.405.040(1) and 19.405.050(1) if, over the four-year compliance period, the average annual incremental cost of meeting the standards or the interim targets established under subsection (1) of this section equals a two percent increase of the investor-owned utility's weather-adjusted sales revenue to customers for electric operations above the previous year, as reported by the investor-owned utility in its most recent commission basis report."10

8 The legislative sponsors of CETA referenced the incremental cost provision several times in floor speeches during legislative debate in 2019. The incremental cost provision was also described as a "cost cap" to protect customers from unreasonable rate increases to achieve the policy goals of the bill. A sampling of floor speeches from 2019 shows the importance of the incremental cost provision to the legislature and bill proponents:

"In doing so we want to be extremely cautious about the potential of any modest increase in rates."11

"… the second challenge we took on is protecting our customers, our constituents, our ratepayers, to make sure that they were not bearing the brunt of transitioning off of coal, transitioning off of gas, and moving into a renewable clean energy grid and so we have protections in this policy to ensure that cost caps are in place that we are protecting ratepayers from shots to the system."12

"… we wanted to be sure that whatever law that we passed could be implemented without cost to ratepayers and that's why there's a strong cost cap in the bill …"13

9 Clearly, the legislature intended the incremental cost provision to protect ratepayers from unnecessarily large rate increases and provide rate stability due to enactment of CETA. When read in the full context of CETA's goals, the incremental cost of compliance pathway directly implicates customer rates. Further bolstering this conclusion is the highly unlikely circumstance that the commission would exclude from rates utility spending on CETA compliance.

10 The commission and commerce were charged with the task of adopting a methodology for calculating the incremental cost and thus implementing the legislature's intent to protect ratepayers.14 I fail to understand how the methodology specified in proposed WAC 480-100-660 reflects legislative intent and therefore a correct interpretation of the statute.

11 Sadly, the commission's methodology in these rules makes neither logical nor mathematical sense. The methodology in the rules incorrectly compounds the two percent WASR by adding an extraneous multiplier. I agree that the language implies some level of compounding, but the formula in the rules defies any method of compounding that I was taught in school. There is no mathematical way to justify this kind of compounding formula.

12 The math yields a spending threshold of over five percent per year instead of two percent per year. In other words, to claim compliance with the clean energy goals using the incremental cost pathway, a utility must increase CETA related spending (and therefore rates) by five percent per year to claim that it spent two percent per year. I struggle to understand how requiring utilities to spend more than double what the legislature specified makes any sense. Public counsel also correctly observed in their comments this methodology improperly inflates the incremental cost calculation.15

13 On one hand this methodology may make sense to those who want to see as much utility spending as possible on clean energy. On the other hand, the typical utility ratepayer could now see rate increases of more than five percent per year on top of normal utility spending for safety and reliability of existing electric service infrastructure before the commission would entertain any kind of rate relief to achieve the clean energy goals in statute. This is not only irresponsible, but it renders the incremental cost of compliance pathway useless to the utilities and ratepayers. My colleagues believe utilities will end up spending less than the threshold amount for CETA.16 I hope they are correct, but I am not optimistic that will be reality.

14 To illustrate the magnitude of the likely rate increases due to this methodology, Table 3 below shows a hypothetical calculation of PSE's incremental cost threshold under a straight two percent formula and the calculation in proposed WAC 480-100-660 using the company's 2019 commission basis report weather adjusted sales revenue (Year 0):

Over four years, the two percent calculation adds up to an eight percent increase while the commission rule calculation is an increase of over twenty-one percent. Under either calculation, the amount of utility spending on clean energy will increase significantly. For additional context, PSE's 2019 electric conservation program budget was just under $84 million. These spending amounts are significant and will create burdens for ratepayers.

15 Ratepayer bill impacts of the commission's methodology are even more stark as shown in Table 4 below, which compares the bill increase for a residential ratepayer using 1000 kWh of electricity in a month if rates increased by two percent versus just over five percent:

Using PSE as one example, bills could increase at minimum just over $2 per month or as high as $5.50 per month for compliance with CETA. These bills also do not include any additional rate increases just to maintain the current electric system. The incremental cost formula under proposed WAC 480-100-660 will lead to unnecessary and significant increases for ratepayers due to a flawed mathematical methodology and statutory interpretation. If the legislature wanted utilities to spend more than two percent annually or amounts higher than their annual conservation budget to be considered in compliance with CETA, they would have stated that in the statutory language.

16 A correct reading of the incremental cost statute yields a simpler and mathematically proper methodology that also respects legislative intent and validates the commission's role to protect ratepayers. The commission could have adopted the following methodology to calculate the incremental cost:

CEIP Incremental Cost Calculation = (WASR0 × 2%) + (WASR1 × 2%) + (WASR2 × 2%) + (WASR3 × 2%)

Where: WASR0 = Commission Basis Report from most recent complete year prior to CEIP start date and WASR1 = (WASR0 × 2%) which this same formula applies to WASR2 and WASR3

This formula appropriately adds two percent per year over the four-year compliance period (compounded) and gives utilities a better sense of what their minimum CETA spending amount would be to achieve compliance. It represents a consistent and reasonable reading of the incremental cost statute giving effect to the phrase "above the previous year." Further, it reflects PSE's recollection during legislative consideration of CETA of how the formula would work in practice.17 Although this still has significant ratepayer impacts over time, it at least gives meaning to CETA's ratepayer protection provision.

To illustrate this alternative methodology, Table 5 shows a hypothetical PSE example using WASR from its 2019 Commission Basis Report:

17 I agree with my colleagues that utilities are expected to achieve the clean energy goals at the lowest reasonable cost without defaulting to reliance on the incremental cost pathway. However, the aggressive clean energy goals contained in statute will require significant amounts of new spending (and rate increases). It is not unreasonable to expect utilities to rely on the incremental cost pathway for compliance, especially if spending will lead to rate increases of more than two percent per year.

18 PacifiCorp correctly observes that implementation of CETA must contain meaningful cost containment.18 Unfortunately, my colleagues' interpretation of the statute is not in the public interest. The incremental cost of compliance rule fails to achieve any meaningful cost containment and will force ratepayers to absorb unnecessary rate increases. We could easily have avoided this outcome by taking the time to work with the parties and develop a simple, reasonable methodology that gives meaning to the two percent ratepayer protection provision in statute. There is ample evidence in the record to support this work. Several parties including Avista, PacifiCorp, public counsel and AWEC all noted at the December 9, 2020, adoption hearing they would support additional process to get this methodology right.19

19 Finally, the enforcement provisions contained in proposed WAC 480-100-665 send the wrong signal to utilities about how the commission will view utility compliance with the various requirements of CETA. Although many of the enforcement tools listed in the rule are restatements of existing commission authority, by including explicit provisions in this package of rules, right out of the gate the commission is taking an aggressive and unnecessary adversarial stance on utility compliance with CETA. The enforcement language also implies the interim targets proposed in utility CEIPs are binding. This is not consistent with the specific statutory enforcement provisions in CETA and limits utility flexibility to achieve the clean energy goals at the lowest reasonable cost to ratepayers.20 Utilities pointed this out numerous times in their comments and this provision is unnecessary.

20 The commission already has broad enforcement authority under its authorizing statutes and through its orders.21 If the commission wants to condition its approval of a utility CEIP it can do so in the final order in that proceeding. The commission can also initiate penalty actions before or after a hearing.22 Commission orders make the enforcement section in these rules redundant and superfluous.

21 I recognize and appreciate the extraordinary amount of work that my colleagues, staff, the three electric utilities and all the stakeholders have put in to reach this point. In examining the record in this proceeding, legislative intent, and the statutory provisions of CETA, I cannot in good conscience support sections of these rules that eviscerate and render the ratepayer protections included as part of CETA useless and meaningless.

22 The definition of "alternative lowest reasonable cost and reasonably available portfolio" in proposed WAC 480-100-605, 480-100-660 Incremental cost of compliance, and 480-100-665 Enforcement, will harm ratepayers with larger than necessary rate increases to achieve the clean energy goals in CETA while also contravening legislative intent and misinterpreting statute. I find these sections of the rules are not in the public interest and therefore should not be adopted.

Jay M. Balasbas, Commissioner

WAC 480-100-605 Definitions.

WAC 480-100-610 Clean Energy Transformation Standards.

WAC 480-100-620 Content of an integrated resource plan.

WAC 480-100-625 Integrated resource plan development and timing.

WAC 480-100-630 Integrated resource planning advisory groups.

WAC 480-100-640 Clean energy implementation plan.

WAC 480-100-645 Process for review of CEIP and updates.

WAC 480-100-650 CEIP reporting and compliance.

WAC 480-100-655 Public participation in a CEIP.

WAC 480-100-660 Incremental cost of compliance.

WAC 480-100-665 Enforcement.

Miscellaneous.

OTS-2679.2