Category: State Updates

Featured States Using the NSPM: Michigan and Maryland

Featured States Using the NSPM: Michigan and Maryland

(Continued from NESP News, November 2023)

The table below summarizes each state’s approach in applying the NSPM framework. The key distinction is that in Maryland, a workgroup process is informing the development of its jurisdiction specific test (JST). Whereas in Michigan, the utilities developed a proposed JST at the direction of the commission, which stakeholders then commented on in response to a set of questions from the commission. While both states use the NSPM 5-step process, the Maryland approach involves stakeholder input throughout the multi-process, allowing for discussion of key BCA issues and with a goal of reaching consensus on which costs and benefits to include in the resulting jurisdiction specific test. Maryland’s process to date has taken longer than Michigan’s, primarily because it first updated cost tests for EVs and EE before opening the UBCA Docket 9674. Generally, however, the approach used by each state has taken (or will take) about two years from NSPM introduction to final commission orders adopting a consistent BCA test for all DERs.

1. NESP presentation to Commission staff and stakeholders about NSPM BCA framework in the context of distribution system planning (DSP)1. NESP presentation to Commission and stakeholders about NSPM BCA framework
2. Commission staff make recommendation to the Commission to use the NSPM to develop a consistent BCA test for all DERs2. Commission directs utilities to develop BCA approach for EVs through stakeholder process, guided by NSPM
3. Commission issues order for utilities to develop BCA for DER pilots guided by the NSPM. Utilities retain a consultant to develop BCA using NSPM multi-step process and files proposal with commission, recommending the proposed MI jurisdiction specific test (JST) be applied at scale.3. NSPM principles are applied to inform development of BCA for EVs and then to EE (EMPOWER programs). Commission approves a MD-EV JST (2021), and separately a MD-JST for EMPOWER programs (2022). Commission staff recommend that the Commission open a docket to develop a UBCA test for all DERs
4. Commission invites public comment on the utilities’ proposed BCA, focusing on key questions including impacts to include in a consistent BCA test, methodologies to account for impacts, and whether to develop a transparent BCA spreadsheet tool.4. Commission opens docket (Jan 2022) to develop a UBCA for all DERs in range of regulatory contexts using NSPM, building on EV and EE BCAs. Requests public comment and issues order convening workgroup and issuing RFP for facilitation services.
5. Interested stakeholders file comments responding to Commission’s set of questions.5. Commission staff select consultant to facilitate a workgroup using NSPM multi-step process, comprising up to 8 workgroup meeting (four have been completed as of mid-November)
6. Commission issues order adopting a benefit-cost test based on the utilities’ proposed JST with modifications per stakeholder comments, ensuring alignment with Michigan’s energy goals.6. Based on workgroup input, consulting team to develop UBCA straw proposal for workgroup review and modifications, Commission staff to submit UBCA to Commission for approval (Q1 2024)
Timeframe: Fall 2021 – Fall 2023Timeframe: Spring 2021 – Winter 2024 (anticipated)

More detail on each state process, key issues raised, and a final determination (for Michigan) is provided below.


Case U-20898 – In the matter… to commence a collaborative to consider issues related to implementation of effective new technologies and business models. To recap previous NESP News, the Michigan Public Service Commission’s (MPSC) issued a July 2022 Order requiring the utilities to develop a Michigan specific benefit-cost test for pilot DER programs, guided by the NSPM. DTE Electric Company and Consumers Energy submitted (with support from a consultant) a joint Proposed Requirements and Further Guidance on Benefit-Cost Analyses for Pilot Initiatives using the NSPM five-step process to develop a jurisdiction specific test (JST). The MPSC requested public comments—via an April 2023 Order—focusing on six questions about the proposed utilities’ plan. Comments were submitted by utilities, the Michigan Energy Innovation Business Council (MEIBC), the Midwest Energy Efficiency Alliance (MEEA), and the American Council for an Energy-Efficient Economy (ACEEE).

The Commission issued an October 2023 Order largely adopting the utilities’ proposed BCA test, but with changes based on intervenor comments. A summary of the BCA impacts to include in Michigan’s approved BCA JST (which the commission also refers to as the “Societal Test”) is provided in the table below, highlighting which impacts were added to ensure alignment with Michigan’s applicable policies (consistent with NSPM principles), as well as direction on methodologies for accounting for impacts—whether monetization, quantitative or qualitative. The Commission also decided on a societal discount rate from 0-3%, rather than a weighted average cost of capital (WACC), as the utilities had been ordered to develop a test based on societal impacts, rather than the impacts on a utility (for which the WACC would be more appropriate)—again, consistent with NSPM guidance.

Finally, the MPSC ordered the development of a flexible and transparent spreadsheet-based tool to measure the cost-effectiveness of DER programs, through a collaborative process including commission staff, utilities, and stakeholders. It also supported the use of additional resources such as NESP’s Methods, Tools and Resources (MTR) Handbook and forthcoming guidance on conducting a Distributional Equity Analysis (see separate article).

Commission April 2023 Order Questions:*

  1. Are necessary elements missing from the BCA proposal? Are there additional impact categories which should be considered? 
  2. Are the utilities’ proposed treatment (monetized, quantitative, and qualitative) for each BCA impact appropriate?
  3. Is the utility proposal’s assumed after-tax WACC the appropriate discount rate to use?
  4. What, if any, changes to the BCA proposal are required in order for natural gas utilities to make use of the BCA proposal for pilots?
  5. Do stakeholders find value in the development of a spreadsheet-based tool for both the Staff and utility personnel to utilize?
  6. Are there regulatory examples of JST or BCA developments in other states that could be instructive for use in Michigan?


Michigan’s Jurisdiction Specific Test


The Commission opened the Unified BCA docket (Case No. 9674) in early 2022, and then convened a workgroup (Order 90212) directing utilities to issue an RFP on its behalf to retain workgroup facilitation services. E4TheFuture and its project team (comprising Energy Futures Group, Rábago Energy, Steven Schiller Consulting, and AnnDyl Policy Group) was contracted to provide facilitation and technical services to support the UBCA workgroup process. Four workgroup meetings were held from July to October 2023. The kick-off meeting reviewed the NSPM 5-step process and the commission’s directive on a UBCA framework, per its Order 90212, including that:

  • “A UBCA will better align energy efficiency, demand response programs, and long-term infrastructure planning with State climate and equity efforts and encourage programs that fulfill the needs of the grid and the goals of the State.
  • A UBCA framework may also assist the Commission and stakeholders to identify the least-cost means to achieve Maryland policy goals…
  • The purpose of the UBCA is to better inform stakeholders and the Commission about available choices that will promote the realization of State goals and policies.
  • A UBCA should also increase transparency and efficiency in the assessment of energy resources.
  • The UBCA should not be designed to substitute for the utilities’ independent, experienced judgment as to how to maintain safe and reliable service on utility systems.
  • The goal of developing a consistent framework does not mean that the test must be identical across different DERs and utilities. There may be impacts (benefits or costs) that are unique to a given DER. Likewise, there may be impacts (benefits or costs) that are unique to a given utility.
  • Additionally, the Commission does not intend to surrender its discretion by adopting an inflexible mathematical formula that would mandate the approval or rejection of a given project.”

The workgroup reviewed a preliminary list of policies (building upon policies that informed Maryland’s development of a Statewide EV BCA Methodology and EMPOWER Maryland JST for energy efficiency), and were asked to identify priority policies that should be used to inform the development of a UBCA for all DERs, as well as any missing policies.

Maryland’s Initial List of Applicable Policies

–Clean Transportation and Energy Act of 2023 (Chapter 98 / HB 550)
–Maryland Sustainable Buildings Act of 2023 (Chapter 586 / HB 6)
–Climate Solutions Now Act of 2022 (Chapter 38 / SB 528)
–MD PSC Order No. 90261
–MD PSC Acceptance of EV BCA Framework in Case No. 9478 – PC44 ML# 238013
PC44 Transforming Maryland’s Electric Grid
–Utility Regulation – Consideration of Climate and Labor (Chapter 614 / House Bill 298 of 2021)
MCCC Building Energy Transition Plan (November 2021)
–The Shirley Nathan-Pulliam Health Equity Act of 2021 (Chapter 750 / SB 52)
2030 GGRA Plan (February 2021)
–Energy Savings Goals for State Government – 2020 (Chapter 289 / HB 662)
2020 Annual Report of the Commission on Environmental Justice and Sustainable Communities
–Clean Energy Jobs Act of 2019 (Chapter 757 / SB 516)
–Energy Storage Pilot Project Act of 2019 (Chapter 427 / SB 573)
2020-2024 Maryland WIOA State Plan
–Greenhouse Gas Emissions Reduction Act (GGRA) of 2016 (Chapter 11 / Senate Bill 323)
–MD PSC Order-No.-87082 from 2015
–MD Code, Public Utilities § 7–211(b) EmPOWER Act
–MD Code, Public Utilities § 7-213
–MD Code, Environment § 1-701

The second and third workgroup meetings reviewed utility system impacts, current BCA practice, and the applicability of impacts to different types of DERs. The table shows the collective feedback of the workgroup and how they characterized the applicability of impacts. Facilitated discussion helped to clarify key differences.

This process helped to illustrate that a consistent BCA for all DERs does not mean the same impacts apply across all DERs, but rather that the full range of utility system impacts should be part of a BCA, with transparency about which apply or do not apply, or are considered immaterial to include.

The fourth workgroup meeting reviewed non-utility system impacts (non-USIs) – i.e., other fuels, host customer, and societal impacts – and their relevance to Maryland’s applicable priority policies and to specific DERs. Discussion included the applicability of host customer (participant) impacts to different DER types, and the importance of ensuring symmetry (NSPM Principle #3) in the accounting of both host customer costs and benefits – recognizing the challenge of monetizing certain benefits – should the workgroup decide to include host customer impacts in a proposed UBCA to the commission.

The workgroup was polled on the relevance of non-USIs to the inventory of priority policy goals using the key criteria noted above; the results of workgroup feedback—with NSPM guidance—are informing a draft straw proposal being prepared by the consulting team for review and further workgroup input in December.

States using the NSPM: Washington

States using the NSPM: Washington

(Continued from NESP Quarterly February 23, 2023)

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.

Next Steps:

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:

  1. 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.
  2. General feedback on utility system impacts (electric and gas), and questions regarding specific definitions for and accounting for environmental compliance and renewable portfolio impacts.
  3. General feedback on non-utility system impacts, including Other Fuels, Host Customer Impacts and Societal Impacts.
  4. Treatment of highly impacted communities or vulnerable populations and associated impacts as a separate category relative to low-income customers.
  5. Definitions for applicable societal impacts, including GHG emissions, Other Environmental, Public Health and Energy Security impacts.
  6. Treatment of Risk, Reliability and Resilience, and appropriate definitions and relevance to utility system, host customer and societal impacts.
  7. Application of the WA Test, and whether it should be formal or informal.
  8. 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.

How Are States Using the NSPM?

How Are States Using the NSPM?

(Continued from NESP Quarterly October 5, 2022)


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:

  1. Develop Utility System Impacts values and document how factors are calculated and incorporated into BCA modeling.
  2. Develop Non-Utility System Impacts values and document how factors are calculated and incorporated into BCA modeling.
  3. 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.
  4. 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.

To learn more about the Minnesota’s experience applying the NSPM BCA framework, read our previous newsletter coverage and see MN NSPM workshop materials


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.

States Using the NSPM: New Developments

States Using the NSPM: New Developments

(Continued from NESP Quarterly June, 2022)


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.


The PSCO is required by Commission rules (Proceeding No. 20R-0516E) to file a DSP every two years, including consideration of NWAs for major distribution grid projects. Public Service submitted its DSP on May 2, including a separate appendix (ZDP-5) on its proposed benefit-cost methodology for NWAs developed by ICF.

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.

What’s in Store for 2022?

What’s in Store for 2022?

(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.

Companion Resources to the NSPM

In our October NESP Quarterly (pg. 6), we shared a flavor of two forthcoming NESP publications:

Methods Tools Resources handbook cover
  • 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

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.

See the entire February 2022 NESP Quarterly.