In the case of host customer NEIs – which are typically difficult to quantify – the Database of Screening Practices shows us that many states use a proxy adder as a methodology to account for various types of NEIs. States like Colorado and Nevada utilize adders to account for the full range of host customer NEIs from their energy efficiency programs, while other jurisdictions utilize adders to account for specific impacts, such as Maryland’s health and safety adder.
The new DSP table summary shows the proxy adder values used by states, ranging from 5% to 25%. However, application of the adders varies: some states apply an adder to only low-moderate income (LMI) program impacts, while others apply broadly to all residential programs; in states that use a proxy adder across residential programs, the value applied to LMI programs may be higher than for non-LMI programs.
In the case of how jurisdictions account for carbon emission impacts in BCAs for efficiency programs, there is considerable variation in the methodologies and values used. Our research shows that jurisdictions often account for carbon emissions as an avoided utility system cost, either embedded into their avoided generation/distribution costs or as an avoided environmental compliance cost.
For states with carbon cap-and-trade systems, such as the Regional Greenhouse Gas Initiative in the Northeast, this value encompasses the cost of compliance with the cap-and-trade system. Other jurisdictions choose to account for carbon as a non-utility system impact (i.e., societal impact). When treated as a societal impact, we found that carbon emissions are often valued higher than when accounted for as a utility system impact. This may be due to the fact that many jurisdictions utilize the Social Cost of Carbon to value societal carbon emissions, which encompasses the full range of damages from carbon emissions that are often not captured as a utility system impact. Some jurisdictions account for avoided carbon emissions as both a utility system impact and a societal impact. This practice allows jurisdictions to account for the avoided impacts of carbon emissions to the utility system as well as other societal impacts, and can avoid double counting when performed correctly. See the MTR Handbook (Chapters 3.2 and 7.1) for guidance on accounting for GHG emission impacts.
The table below lays out the NSPM 5-step process and the associated workshop series and topics, illustrating specific Washington priorities. The first two workshops provided an overview of the NSPM process and served as a forum for stakeholders to discuss applicable WA policy goals, relevant impacts, and current utility BCA practices. During the third workshop, stakeholders reviewed and discussed current utility BCA practice for treatment of utility and non-utility system impacts and identified which impacts should be included in a primary BCA test.
Synapse Energy Economics incorporated feedback from workshops 1-3 to develop a draft straw proposal with a recommended “WA Test” for UTC Staff and other stakeholder review. Synapse presented this proposal and an example application of the WA Test during the fourth workshop.
Key aspects of the proposed WA Test include adhering to the NSPM core principles, such as aligning with WA’s applicable policies, ensuring symmetrical treatment of costs and benefits, accounting for relevant impacts (even if difficult to quantify), and avoiding double counting of any impacts.
Importantly, the straw proposal demonstrates how a primary WA Test would apply across different DERs, where not all impacts are relevant (N/A) or material (N/M) to each DER (or use case). Table 8 from the straw proposal (below) shows how the full range of utility system impacts should be part of the WA Test, but where depending on the DER, certain impacts may or may not be applicable. Similar tables are provided for Host Customer and Societal Impacts.
The fifth UTC workshop provided a forum for the intervenors to ask clarifying questions and provide feedback on the straw proposal. Synapse also described how to account for energy equity as a complementary analysis to BCA. With energy equity as a top policy priority for the state, Synapse is providing technical assistance to WA UTC (via LBNL) to assist with addressing distributional equity analysis (see newsletter information on new DEA project).
Following the last workshop, UTC staff issued a notice of opportunity for written comments on various aspects of the straw proposal and proposed test. Its notice included over 20 questions asking intervenors to comment on the following range of issues:
Whether changes are needed to current BCA practice in WA to ensure consistent evaluation of DERs, and if so, whether a JST is necessary to align with the Commission’s policy goals.
General feedback on utility system impacts (electric and gas), and questions regarding specific definitions for and accounting for environmental compliance and renewable portfolio impacts.
General feedback on non-utility system impacts, including Other Fuels, Host Customer Impacts and Societal Impacts.
Treatment of highly impacted communities or vulnerable populations and associated impacts as a separate category relative to low-income customers.
Definitions for applicable societal impacts, including GHG emissions, Other Environmental, Public Health and Energy Security impacts.
Treatment of Risk, Reliability and Resilience, and appropriate definitions and relevance to utility system, host customer and societal impacts.
Application of the WA Test, and whether it should be formal or informal.
Value of a Phase 2 process to address methodologies for quantifying DER impacts (using the NESP’s Methods, Tools & Resources Handbook); best process for addressing Phase 2 issues.
Formal intervenor comments were due on the straw proposal January 18, 2023. UTC staff are reviewing comments with a determination and/or next steps expected this spring. All docket and workshop meeting materials are posted to the WA UTC website for Docket UE-210804.
The table below summarizes the MN NSPM workshops to date. These are facilitated by the Department of Commerce (DOC) staff with support from the DOC’s lead consultant, Mendota Group, and with technical assistance from Synapse Energy Economics (“Synapse”) on NSPM application (funded by US DOE/LBNL). Stakeholders in the Cost-Effectiveness Advisory Committee (CAC) include utilities, state agencies, and nearly 20 other interested organizations.
The first two workshops, led by Synapse, walked the CAC through the key steps of identifying what impacts to include in Minnesota’s primary cost-effectiveness test. This process informed Synapse’s development of a straw proposal with a new Minnesota Test (MN Test) for stakeholder review. The third workshop focused on stakeholder feedback on the straw proposal. With this input, Mendota prepared a draft Working Group Report that incorporated the straw proposal and stakeholder comments, along with DOC staff’s recommendation for a new Minnesota Test (MN Test) and use of secondary tests, as required by statute.
With the draft MN Test in place, the CAC has moved to the next phase of the NSPM process, which is to identify methodologies to quantify impacts for use in cost effectiveness. As presented by Synapse in Workshop #5, this effort will refer to the MTR Handbook (a companion resource to the NSPM) to guide selection of appropriate methodologies for quantifying various impacts. Identifying methods to account for relevant impacts in this phase will be informed by white papers developed by the utilities and others in the following areas:
Develop Utility System Impacts values and document how factors are calculated and incorporated into BCA modeling.
Develop Non-Utility System Impacts values and document how factors are calculated and incorporated into BCA modeling.
Develop Efficient Fuel-Switching and Load Management Cost-Effectiveness Guidelines, and apply approach adopted for the MN Test to evaluate Efficient Fuel-Switching and Load Management programs.
Determine Discount Rates to use in cost-effectiveness analyses, informed by previous MN guidance.
The DOC anticipates that the CAC will have four more meetings in 2022, with the CAC process concluding by January 2023. Near the conclusion of the CAC process, there will be a formal regulatory process set by Minnesota rules and statute. During this regulatory process, the DOC will develop a written Staff Proposed Decision with recommendations about cost-effectiveness methodology updates, followed by a public comment period. In early 2023, the Department will issue the Deputy Commissioner’s Final Decision filing, which will set the cost-effectiveness assumptions that the utilities will be required to use for their 2024-2026 CIP Triennials.
Since kicking off the NSPM process at its May 10 Workshop in Docket UE-210804, the Washington Utilities and Transportation Commission (UTC) convened stakeholders on August 1 and September 20 to bring cost-effectiveness testing practices into alignment with applicable policies — in particular, related to the state’s CETA statute and Climate Commitment Act – and to support clean energy rule requirements. The summer workshop agendas generally followed the NSPM 5-step process as shown below, while illustrating specific Washington priorities. As it takes steps to review and update its BCA practices, Washington aims to ensure it can meet its policy needs.
Workshop #2 Agenda (August 1, 2022)
Workshop #3 (September 20, 2022)
During Workshop #3, stakeholders reviewed and discussed current utility BCA practice for treatment of utility and non-utility system impacts, using Puget Sound Energy data as reported below (and similar tables for host customer and societal impacts.
The concluding workshop assignment from UTC staff was a request for the utilities to indicate, where utility system impacts are not included in current BCA practice, the reason for exclusion — e.g., due to lack of data, or impacts considered not applicable or not material. In cases where an impact is applicable and material, utilities are asked to recommend a general approach/method for quantifying or accounting for the impact.
Subsequent to Workshop #3 and additional information requested from the utilities, a Straw Proposal will be developed by Synapse Energy Economics (via LBL funding for state technical assistance) and will be circulated to stakeholders for comment and discussion at a workshop scheduled for late October.
Additional workshop topics to be addressed during the NSPM process include use of secondary tests, selecting discount rates, and accounting for energy equity. All docket and workshop meeting materials are posted to the WA UTC website for Docket UE-210804. For more information on the WA process, see our previous newsletter coverage.
Pursuant to Public Law 2021 Chapter 390 (LD 936, An Act To Amend State Laws Relating to Net Energy Billing and the Procurement of Distributed Generation), the Governor’s Energy Office convened the Distributed Generation (DG) Stakeholder Group to issue recommendations that support continued development of renewable energy in Maine through cost-effective distributed generation, including meeting a goal of 750 megawatts (MW) of DG under the net energy billing programs established in 35-A MRS §3209-A and §3209-B.
Per LD 936, the charge of the DG Stakeholder Group is to “consider various distributed generation project programs to be implemented between 2024 and 2028 and the need for improved grid planning.” The DG Stakeholder Group produced an interim report in December 2021 establishing initial areas of consensus and describing a framework and intended design process for a successor program. The areas of consensus included articulating clear policy goals based on legislation, and recognizing the importance of accounting for DG potential benefits to the electric system, as well as to the state — through avoided costs, plus resilience, environmental, public health, and economic benefits.
Synapse Energy Economics will provide technical analysis to fulfill the requirements of LD 936 Section 4 as specified in the RFP, provide technical and program design support for the development of the DG program, and facilitate stakeholder engagement to obtain and incorporate public input.
Monetizing Societal Health Impacts in BCA – Guidehouse Shares Illinois’ Methodology
(Continued from NESP QuarterlyOctober 5, 2022) — In this article, guest writer Patricia Plympton, Associate Director at Guidehouse outlines the methodology used by Guidehouse to monetize societal health impacts for the BCA of ComEd’s energy efficiency portfolio. ComEd was the first IOU to include societal health impacts in BCA tests in alignment with Illinois policies using a relatively low-cost approach applicable to any electric or gas utility.
In 2016, the Illinois legislature passed the Future Energy Jobs Act (FEJA), and with this passage, Commonwealth Edison (ComEd) requested Guidehouse, their independent evaluator, to conduct non-energy impacts (NEIs) research to quantify and monetize NEIs, such as societal health impacts, to include in total resource cost (TRC) tests. This was reaffirmed in 2021 with the passage of the Climate and Equitable Jobs Act (CEJA), which directed the utilities to continue to include societal health NEIs in TRC tests and to report economic NEIs. The CEJA legislation explicitly set forth that:
“The plan shall be determined to be cost-beneficial if the total cost of beneficial electrification expenditures is less than the net present value of increased electricity costs …[including] the societal value of reduced carbon emissions and surface-level pollutants, particularly in environmental justice communities.” “The independent evaluator shall determine…an estimate of job impacts and other macroeconomic impacts of the efficiency programs for that [plan] year.”
Energy efficiency programs result in many benefits beyond direct energy and demand impacts, including those related to public health. Energy generation from fossil fuel sources leads to emissions of several harmful pollutants such as PM2.5, SO2, NOx, and CO2. These pollutants have several implications for public health, including:
chronic and acute bronchitis,
non-fatal heart attacks,
respiratory or cardiovascular hospital admissions,
upper and lower respiratory symptoms, and
asthma, and asthma-related hospital visits.
Although utilities in several states have used one or more categories of monetized NEIs in their cost-effectiveness tests, Illinois is the first state—in alignment with its policies—to include monetized societal health NEIs in their cost-effectiveness tests. Guidehouse recently published an Evaluation of ComEd’s CY2020 Total Resource Cost Test which includes a years-long research project to quantify and monetize the societal health NEIs as a result of ComEd’s energy efficiency programs. Guidehouse’s methodology and the results of incorporating societal health NEIs into their Benefit Cost Analysis (BCA) are described below.
At a high level, AVERT calculates avoided emissions associated with energy efficiency programs based on generation across the EPA-defined Great Lakes/Mid-Atlantic eGRID region for ComEd. COBRA calculates the societal health impacts of chronic and acute bronchitis, non-fatal heart attacks, respiratory or cardiovascular hospital admissions, work loss days, and other impacts associated with improved outdoor ambient particulate matter.
To estimate societal health NEIs, Guidehouse implements the following four-step process:
Step 1: Guidehouse develops the portfolio-level cumulative annual savings values.
Step 2: Guidehouse applies the AVERT model to determine county-level emissions reductions for each pollutant studied.
Step 3: Guidehouse uses the AVERT outputs to execute the COBRA model to estimate the health impacts of reduced pollution exposure over a 20-year period.
Step 4: To be consistent with other TRC testing inputs, Guidehouse discounts each year’s COBRA results to the analysis year using a 0.42% real discount rate.
Figure 1 below shows the process Guidehouse uses to quantify and monetize societal health NEIs. See Chapter 7.2 of the Methods, Tools, and Resources handbook for more information about measuring societal health impacts.
ComEd Cost-effectiveness Test Results
To determine the impact of societal health NEIs on cost-effectiveness, Guidehouse produces annual TRC values with and without societal health NEIs for all of ComEd’s energy efficiency programs and pilots, as shown in Table 1.
As can be seen from the table, ComEd’s portfolio-level TRC score increased by nearly 50% from 2.62 to 3.89 with the addition of societal health NEIs. Additionally, several programs saw their scores increase enough to push them past the 1.0 threshold that typically determines program cost-effectiveness, including Affordable Housing New Construction, Multi-Family Retrofits, Efficient Choice, and Electric Homes New Construction. Societal health NEIs increased the TRC scores for these programs by 25-50%, and while low-income programs are not required to meet the TRC test (per the Illinois Energy Efficiency Policy Manual 2.1), the non-income eligible programs may have been deemed not cost-effective absent accounting for the societal health NEIs.
The Database of Screening Practices (DSP) is an open-source resource that provides energy efficiency cost-effectiveness testing information for all 50 states as well as Washington, D.C. and Puerto Rico. This database contains information about the cost-effectiveness test(s) used in each jurisdiction, including primary and secondary tests, the assessment level used, discount rate, and analysis period. The database also details the specific utility system, host customer, and societal impacts each jurisdiction includes in their primary test. The database includes visualizations in a variety of formats such as tables, charts, and maps.
The NESP team recently researched updates to state BCA practices and refreshed the database with new information and revised/new documents. See below for a few notable updates:
Connecticut: The Department of Energy and Environmental Protection recently approved the new Connecticut Efficiency Test (CTET) that was developed based on NSPM guidelines. Read more about the CTET here.
New Jersey: In 2020, the New Jersey Board of Public Utilities (BPU) Staff released a proposed interim New Jersey Cost Test (NJCT) as the state transitions to the next generation of energy efficiency and peak reduction programs. Staff used the costs and benefits traditionally associated with the TRC as a starting point for the NJCT. The test also includes additional avoided energy benefits (including T&D costs, ancillary services, and demand reduction induced price effects), and non-energy impacts (NEIs) that are relevant to New Jersey’s policy goals (including avoided emissions impacts, a 10% adder to account for benefits to low-income participants, and a 5% adder to account for NEIs such as public health, water benefits, economic development, etc.).
Illinois: Cost-effectiveness testing in Illinois now includes monetized societal health impacts. Commonwealth Edison (ComEd) updated its TRC test in 2021 by adding an estimated reduction in adverse health impacts due to lower PM 2.5, SO2, NOx, and CO2 emissions. To monetize these benefits, they used the EPA’s AVoided Emissions and geneRation Tool (AVERT) and CO–Benefits Risk Assessment (COBRA) Health Impacts Screening and Mapping Tool.
Pennsylvania: While the Commonwealth had previously applied a discount rate based on the weighted average cost of capital (WACC), about 7%, the Commission issued an order that switched the discount rate to 3% beginning in mid-2021. The Commission argued that it is important to consider whose preferences are reflected by the discount rate and that a 3% rate reflects the preferences of the public at large.
Maryland, Minnesota, Puerto Rico, Washington, and Washington, D.C. have recently applied–or are in the process of applying–the NSPM to update their energy efficiency cost-effectiveness tests. New information will be added to the DSP for these jurisdictions when their new tests are approved.
We are planning another round of updates, with more functionality, to the DSP later this year. If you notice out of date or incorrect state information, please contact NSPM@nationalenergyscreeningproject.org.
As part of its Determination on the C&LM Plan, CT DEEP reevaluated the primary test used to assess the CL&M programs by applying the NSPM BCA framework, building on its previous efforts to review cost-effectiveness testing practice including review of applicable energy policies. CT DEEP’s review and update to its current cost-effectiveness testing practice led it to adopt a new Connecticut Efficiency Test (CTET), described in Attachment B of the Determination, and summarized below.
Historically, the Connecticut utilities have used three cost-effectiveness tests to compare the net present value of program benefits with the cost to achieve those benefits.
The Utility Cost Test (UCT), which includes the benefits and costs experienced by the utility system, is the primary test.
A Modified Utility Cost Test (MUCT), which is similar to the UCT but also captures oil and propane savings and the costs associated with achieving those savings.
And a third test, the Total Resource Cost (TRC) test, to inform efficiency program design (but passing the TRC is not required for a program to proceed, except for income eligible programs). The TRC incorporates the UCT and MUCT as well as several additional costs and benefits important from the perspective of program participants, including water savings, non-embedded emissions, and environmental attributes. For the income eligible program, the TRC includes non-energy impacts such as participant comfort, appliance noise, and home value, appearance, and safety.
In its determination, CT DEEP set forth:
Recommendation 1. Create a new Connecticut Efficiency Test (CTET) that applies the principles of the MUCT to all programs and continue the use of the TRC as a supplemental test for income eligible programs.
Recommendation 2. Modify the primary CTET to capture avoided greenhouse gas emissions.
Recommendation 3. Modify the CTET to capture the utility system benefit of reduced arrearages, collection costs, debt write-offs, or administrative costs.
DEEP’s recommendations reflect alignment with the NSPM principles by ensuring the new primary test – the CTET – aligns with the state’s policies, including accounting for GHG emission reductions and other fuels, and to account for certain utility system impacts that previously were not accounted for.
The Determination was informed by a comprehensive public participation process to gather input including public meetings, open comment periods, and a request for information. All materials associated with the Determination can be found here.
In its existing cost-effectiveness framework for the evaluation of its DSM programs, PSCO uses a Modified Total Resource Cost (MTRC) test, which is broader than a TRC as it includes GHG impacts as a societal value stream. Its proposed CBA further incorporates considerations based on NSPM guidance that build on the foundation of the MTRC – specifically by incorporating additional value streams to reflect localized and customer benefits that may be realized by NWAs. PSCO’s proposal aligns with the NSPM symmetry principle as demonstrated by its proposed treatment of the costs and benefits of host customer impacts, where the utility proposes a 10% non-energy impact (NEI) adder for natural gas programs,10% NEI adder for electric programs, and 25% NEI adder for low-income natural gas and electric programs.
PSCO refers to its proposed jurisdiction specific test (JST) as the “Expanded, Modified TRC” (EMTRC). In alignment with the principles of the NSPM, the EMTRC accounts for applicable policy goals including, but not limited to, clean energy and equity goals.
BCA vs Rate Impacts. PSCO considered, in addition to using a primary EMTRC and secondary Utility Cost Test, the use of a Rate Impact Measure (RIM) test. While the NSPM advises not using the RIM test on the basis that a rate impact analysis should be separate from BCA, PSCO recognizes that “rate impacts should not be included in a [primary] JST, and therefore are not included in the EMTRC.” The utility indicates that an NWA can “pass” the EMTRC and still raise customer rates as demonstrated through a RIM test. This provides an additional viewpoint from which the merit of the NWA can be evaluated by both PSCO and the Commission.
NESP plans to develop an illustrative case study using the EMTRC later this year and will share this resource in the NESP Quarterly.
The MN Department of Commerce (DOC or “Department”) process to explore energy efficiency cost-effectiveness testing practices includes convening a Cost-effectiveness Advisory Committee (CAC) and establishing a technical workshop series to apply the NSPM BCA framework, as set forth in a Department 2/11/2020 Cost-Effectiveness Decision. The stakeholder process, supported by technical assistance provided by LBNL via the National Energy Screening Project, builds on earlier work conducted for the DOC in 2018 by Synapse Energy Economics on Updating the EE Cost-Effectiveness Framework in Minnesota. While a stakeholder process began in 2020, it was paused with the passage of the Eco Act in 2021, and restarted in spring of 2022.
In an April kick-off meeting, Department staff reviewed the roles of the Department and the CAC in updating the state’s cost-effectiveness test for its efficiency programs, and reviewed historical testing practices. The DOC addressed key provisions of the Eco Act pertaining to efficient fuel-switching and load management and the need for BCA guidance. Technical advisors Synapse Energy Economics explained the NSPM 5-step process and subsequent workshop topics.
Three workshops covered the following topics:
Workshop 1 (May 4) presented the NSPM core principles, reviewed applicable policy goals, and presented an assignment for stakeholders. Utilities identified what current utility system impacts are accounted for in their test and stakeholders indicated which non-utility systems should be included in the test.
Workshop 2 (May 18) reviewed responses from the utilities and stakeholders from the previous workshop on utility and non-utility system impacts, reviewed a Draft Policy Inventory prepared by DOC, and discussed the mapping of DER impacts to policies. Discussion outcomes and supporting materials were then used by Synapse to develop an initial straw proposal.
Workshop 3 (June 15) focused on the Straw Proposal, which presented a “MN Test,” addressed the implications of including participant impacts (or not) in a primary test, the order of magnitude of different non-energy impacts, and various societal impacts. Next steps were also reviewed, including comments on the straw proposal and a full report to be shared prior to the next workshop on July 20.
At its first UE-210804 Workshop on May 10, the docket’s purpose was reviewed, focusing on: how Clean Energy Transformation Act (CETA) changes the standard practice of using the modified TRC test and UCT as primary and secondary tests; ensuring consistent evaluation of DERs; and following the process and principles described in the NSPM. An overview of the NSPM BCA framework was provided, followed by discussion of the state’s applicable energy policy goals compiled by the UTC staff. The policy review focused on the CETA goals and clean energy rule requirements, including the following provisions:
SB 5116 and HB 1257 incorporate social cost of carbon into cost-effectiveness for electric and gas utilities
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 non-energy benefits and reduction of burdens to vulnerable populations and highly impacted communities;
long-term and short-term public health and environmental benefits;
reduction of costs and risks; and
energy security and resiliency (RCW 19.405.040(8))
UTC staff summarized the following policy goals based on its review of the statutes and rules:
Provide safe, adequate, and efficient services
Support fair, just, reasonable, and sufficient rates
Reduce energy burden of low-income households
Avoiding increased burdens to highly impacted communities
Ensure all customers benefit from the transition to clean energy through the equitable distribution of energy and non-energy benefits and reduction of burdens to vulnerable populations and highly impacted communities
Ensure all customers benefit from the transition to clean energy through long-term and short-term public health and environmental benefits and reductions of costs and risks
Ensure all customers benefit from the transition to clean energy through energy security and resiliency
Maintain system reliability
Develop lowest reasonable cost resources
Enable significant and swift reductions in greenhouse gas emissions
With this first key step of articulating applicable policy goals, the next workshop scheduled for early August will involve utilities reviewing current cost-effectiveness testing practice, and stakeholders identifying what non-utility impacts should be included in a primary test based on the articulated goals.
After nearly a year of meetings, the “PC44” EV Work Group submitted a consensus Statewide EV BCA Methodology Report (“EV BCA Report”) to the Commission for approval 12/1/21. The commission accepted the proposal in a hearing 1/12/22 (Commission Acceptance of EV BCA Framework in Case No. 9478 – PC44; ML 238539).
As background, a working group was formed per commission direction in early 2021 to address deficiencies and concerns around the utilities’ EV Pilot BCA methodology (see Office of People’s Counsel comments). The Commission ordered that: “the PC44 Electric Vehicle Work Group develop and propose for Commission consideration a consensus benefit-cost approach and methodology by December 1, 2021 […] The Commission specifically requests that the EV Work Group examine the National Standard Practice Manual and the existing BCA framework used to review the EmPOWER Maryland programs for best practices in developing an EV BCA methodology.” (Maryland PSC Order 89678 in Case 9645 in BG&E Multi-Rate Plan Section 238).
The EV Work Group convened nearly a dozen times to develop an appropriate cost-effectiveness test for valuing utility EV investments, and it used the NSPM BCA framework to guide the process. The EV BCA Report, developed by Gabel Associates, describes the consensus methodology used to develop the EV BCA framework, including a primary test, referred to as the MD-EV Jurisdiction Specific Test (MD-EV JST).
Meanwhile, the Future Program Work Group (FPWG) is applying the NSPM to develop a BCA test for the EmPOWER Maryland energy efficiency programs. Proposals on the table, with broad stakeholder support, include adopting an EmPOWER Maryland JST. A final proposal and consensus report to the Commission is due mid-April 2022.
As a result of the EV Working Group process to develop an EV BCA framework, the Leader of the EV WG issued a PSC Staff recommendation to the Commission to consider opening a new proceeding. The recommendation suggested use of the Maryland EV and EmPOWER efficiency BCA developments with the NSPM to create a “Unified BCA” methodology across all DERs. The commission opened Case No. 9674 in December 2021 to explore the process of developing a unified BCA methodology, and issued a request for comments due 2/15/22.
The Clean Energy DC Omnibus Amendment of 2018, enacted by the Washington, District of Columbia Council, charges the DC Public Service Commission (the Commission) with evaluating the effects of utility proposals on global climate change and in achievement of the District’s commitments to reduce greenhouse gas emissions. In undertaking its charge, the Commission initiated a proceeding through a Notice of Inquiry (Case No. GD-2019-04-M) and directed that a “Clean Energy Act Implementation Working Group” (CEIWG) be convened. In taking these steps, the Commission sought guidance on appropriate GHG and “carbon footprint” measurement and verification metrics; GHG emissions reporting requirements; standards for quantifying and monetizing impacts; and a “Benefit-Cost Analytical Framework” (“BCA framework”), taking into account best practices from other jurisdictions with similar climate goals, all designed to enable the Commission to assess compliance with the Clean Energy DC Act.
The PSC Staff convened and facilitated the CEIWG from fall of 2020 through October 2021. In its very first meeting, Staff cited the NSPM for DERs in a presentation to stakeholders. Smart Electric Power Alliance (NSPM for DERs co-author) presented at a subsequent CEIWG meeting; thereafter, technical advisor Karl Rabago of Rabago Energy and NSPM project coordinator Julie Michals provided direct technical assistance to the PSC Staff team throughout the CEIWG process to develop a report with a recommended BCA Framework to the Commission. The role of the NESP technical advisors – funded in part by E4TheFuture and Lawrence Berkeley National Laboratory – was to provide objective guidance to the Staff and stakeholders on application of the NSPM for DERs.
Over the course of the year that involved a series meetings, the commission Staff received extensive CEIWG input that informed a 325-page majority consensus report filed by Staff with the Commission for review. Staff’s report laid out the background and process, documented majority and non-majority recommendations, and made specific recommendations to the Commission, including that it:
Adopt “a consistent BCA Framework, based on the guidance of the NSPM-DER, that can organically evolve in a systematic and economically sound manner to assimilate technology, policy, and market/customer changes, as well as to address multi-sited DERs and their interactive effects; multi-sectoral applications; dynamic utility system optimization planning; and coordinated end-to-end utility planning.”
Adopt the NSPM Principles to govern the development and application of the BCA Framework.
Ensure alignment of the BCA Framework with applicable District policies by adopting a societal cost test that aligns with the District’s applicable policy goals.
The report also recommended the Commission approve a Phase II process to address methodological approaches to quantifying the impacts indicated in the report and approved by the Commission, including those impacts that are difficult to quantify. The process for Phase II, whether facilitated through rulemaking, another working group, or a combination of both, is to be determined by the Commission.
The 2019 Clean Energy Transformation Act (CETA) requires significant changes to electric utility planning in Washington state including, among other provisions, a transition to clean energy by 2045. CETA also requires utilities to ensure that all customers benefit from the transition to clean energy through the equitable distribution of benefits and reduced burdens. The 2019 legislation created a new requirement, the Clean Energy Implementation Plan (CEIP).
The WA UTC adopted rules in 2020 to guide investor-owned electric utilities’ planning efforts to meet CETA’s mandates. The Commission’s final rules were adopted 12/28/20, in Dockets UE-190698, UE-191023, and UE-190837. During the rulemaking process, the Commission received stakeholder requests for additional guidance regarding changes to cost-effectiveness test calculations implicit in CETA, in particular concerning distributed energy resources (DERs).
In response to these requests, the UTC opened Docket UE-210804 to investigate cost-effectiveness, with a focus on how CETA necessarily changes the standard practice of using the modified total resource cost test (TRC) and utility cost test (UCT) as the primary and secondary screening tests currently used in the state. The scope of the UTC’s current investigation is to ensure consistent evaluation of distributed energy resources.
The UTC’s Notice of Opportunity to Comment in the cost-effectiveness testing docket states that it will follow the process and principles described in the NSPM for DERs using the NSPM principles. The notice asks a series of questions about the scope and application of the NSPM, to which stakeholders submitted comments in December 2021. In general, the comments indicate that:
Stakeholders are supportive of using the UTC’s proposed NSPM 5-step framework process to review existing cost-effectiveness testing practices.
Key impacts/issues to address, including methodologies to quantify impacts, are: avoided costs of energy capacity (and load shapes used); program overhead costs; customer costs; program incentives; non-energy impacts; measure life; incremental cost, measure lifetimes; environmental and societal benefits; economic benefits; public health impacts, energy equity, accounting for federal subsidies; double counting of impacts; symmetry in treatment of benefits and costs; and how each impact should be weighted in the analysis.
Stakeholders are mixed on whether the docket should evaluate both electric and gas DER cost effectiveness testing, or only electric.
Next steps are to be determined by the UTC staff, based on feedback they received from stakeholders and priority issues to address.
Meanwhile, in December 2021, Puget Sound Energy (PSE) submitted its draft Clean Energy Implementation Plan (Docket 210795) where PSE indicates (pg. 36) that it followed NSPM guidance to evaluate different suites of DERs to create a portfolio that promotes equity, diverse offerings, and minimizes costs. PSE notes the NSPM recommends any BCA should align with the policy goals of the jurisdiction, and thus chose the Societal Cost Test and Participant Cost Test for their primary and secondary cost tests, respectively.
(Continued from NESP Quarterly February 14, 2022) — We first posed the question “How do we account for energy equity in BCAs?” in our June 2021 newsletter. We’ve since further collaborated with organizations to evolve our conceptual framework for how and where energy equity fits within benefit-cost analysis. Below is a summary of this framework, which is a work in progress. With further input and refinement from key stakeholders, our aim is to develop compendium guidance to the NSPM this year.
“An equitable energy system is one where the economic, health, and social benefits of participation extend to all levels of society, regardless of ability, race, or socioeconomic status. Achieving energy equity requires intentionally designing systems, technology, procedures, and policies that lead to the fair and just distribution of benefits in the energy system.”
PNNL: Review of Energy Equity Metrics – Oct 2021
Affirming equity in all aspects of the energy system is key to building a just and clean energy system and is increasingly being identified as a key policy goal by legislatures around the country. Many PUCs, utilities and stakeholders are making strides in addressing energy equity by developing procedural metrics to ensure participation by target populations (e.g., marginalized communities) in program design, delivery and decision making, and setting goals to increase program participation and reduce energy burden for target populations. These efforts are critical to addressing key aspects of energy equity. However, more work is needed to explicitly measure the distributional impacts of DER programs i.e., will program benefits be distributed equitably across all customers, including target populations?
Benefit-cost analysis is used to measure the utility system, host customer, and societal costs and benefits of a DER program or policy on average across the utility system, typically expressed as monetized impacts or benefit-cost ratios (BCR). BCA can incorporate some aspects of energy equity, primarily in cases where a program is designed, implemented and evaluated for a specific target population (e.g., limited income, an EJ community program, etc.). In these cases, both energy and non-energy benefits to host customers can be assessed, or in some cases alternative BC ratio thresholds can be used (e.g., < 1.0). Additionally, transgenerational equity can be captured by using low discount rates (e.g., 2-3%) to calculate the net present value of the impacts: where a greater value is placed on the impacts of DER investments in the long-term versus the short-term. But these aspects of BCA do not fully address the distribution of benefits and costs to target populations.
To address distributional impacts, we offer the conceptual framework in the figure below, where distributional equity analyses (DEA) are conducted alongside BCAs when evaluating programs and policies. This is in addition to, but separate from, addressing procedural and structural energy equity metrics. DEAs can help determine if program benefits will be distributed equitably to target populations, where metrics can include:
Rate (¢/kwh) and bill ($/month) impacts;
Participation rates (% eligible) in programs;
Energy burden (% of income spent on energy bills)
Impacts on health & safety, economic development (job-years), reliability (CEMI – Customers Experiencing Multiple Interruptions), resilience (customer outages, restoration time, etc.); and
Environmental /health and other impacts in specific locations / geographic areas.
NESP is still refining this framework, but we believe it will help provide jurisdictions with a path to explicitly measure and include distributional equity in decision making. Questions and challenges remain regarding the framework’s use, including:
Is distributional equity analysis a part of a broader BCA, or is it a distinct analysis?
How should distributional equity analysis results be presented? How should stakeholders use distributional equity analysis results in decision making?
What customer data must utilities collect in order to conduct a distributional equity analysis, and what challenges are there to collecting this data?
As NESP drafts guidance on this topic, we will continue to collaborate with and seek input from our peers in this space, including key work from the following organizations/companies:
 The extent to which a jurisdiction accounts for host customer and/or societal impacts should depend on the applicable policies in the jurisdiction – consistent with NSPM Principle #2 – and applies to accounting for energy equity in regulatory decisions regarding resource investments.
(Continued from NESP Quarterly February 14, 2022) — This year is off to a busy start! New publications are coming soon, we are providing technical assistance to states applying the NSPM, and we’re gearing up to expand the NSPM to address key topics including guidance on accounting for energy equity.
Methods, Tools & Resources: A Handbook for Quantifying Distributed Energy Resource Impacts for Benefit-Cost Analysis; and
Benefit-Cost Analysis Case Studies – Examples of Distributed Energy Resource Use Cases
While we hoped to publish by now, they are expected in March 2022. These companion documents to the NSPM for DERs will further help guide jurisdictions in their BCA efforts.
The 200+ page Methods, Tools & Resources (a.k.a. “MTR Handbook”) provides a wealth of technical information on how to quantify the full range of utility system and non-utility system impacts of DER investments, with links to resources and tools. Once a jurisdiction applies the NSPM BCA framework to develop or update its primary cost-effectiveness test, the MTR Handbook can guide decisions on what methods to use to quantify the relevant impacts in the jurisdiction’s BCA test.
The BCA Case Studies take the theoretical to application. Informed by real-world use cases but generalized into illustrative examples, they demonstrate applying the NSPM to specific DER technologies and programs of growing interest: residential EV managed charging, commercial combined solar and storage dispatch, and residential grid-interactive and efficient building (GEB) retrofits. The three case studies highlight different jurisdiction-specific tests (JSTs) based on policy objectives for three hypothetical jurisdictions. Each illustrates key BCA considerations for either single or multi-DER use cases and demonstrates different approaches to account for impacts when certain data may be unavailable.
State Technical Assistance in Applying the NSPM
We are providing technical assistance to commissions in applying the NSPM framework. Assistance is in the context of updating BCA practices for DER programs, procurement, and/or broader planning efforts. With support from U.S. DOE via Lawrence Berkeley National Laboratory, we will provide technical assistance throughout the year to select states, budget permitting. If your jurisdiction is interested in such services, please contact NSPM@nationalenergyscreeningproject.org.
Expanding NSPM Guidance
Based on 2021 experience with NSPM application, we are prioritizing areas where additional guidance is warranted to help jurisdictions with BCA practices, such as:
Accounting for energy equity in the context of benefit-cost analyses (BCAs), including developing the concept of a separate but complementary distributional equity analysis.
Applying the principles and concepts of the NSPM to a range of regulatory settings, including distribution system planning, integrated resource planning, grid modernization, time-of-use rates, and more.
Use of discount rates in BCAs, including whether and how to use different rates for different BCA tests and across BCA assumptions (e.g., for the social cost of carbon versus other costs or benefits), and use of nominal vs real rates, etc.
How to treat offsetting impacts (i.e., transfer payments), especially in context of tax incentives.
Treatment of other fuel impacts to consider in BCA, which is particularly relevant and important for electrification measures, programs and strategies.
These updates/expansions to the NSPM are slated for later 2022.