Author: nespE4

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.

Revisiting Lost Revenues and Cost-Effectiveness Testing in a World of Expanding DERs

Revisiting Lost Revenues and Cost-Effectiveness Testing in a World of Expanding DERs: Lessons from the Frontlines of Benefit-Cost Analysis

by Karl R. Rábago, Rábago Energy

There are few topics in modern rate regulation more controversial than the ongoing debate about the growth in deployment and operation of distributed energy resources, or “DERs” and the associated potential of lost and/or gained utility revenues, and how to treat them in rates, program design, and program evaluation. DERs are energy resources deployed at the distribution level of the utility grid and include distributed generation, distributed storage, energy efficiency, demand response, electric vehicles, and energy management. Lost revenues represent the money that a utility expected to collect from customers under approved rates that it will not collect—at least until, and if, a regulator approves changes in rates or charges—because the DERs resulted in a reduction in use of energy. The reverse applies in cases where a utility may “gain” revenues from, e.g., building or transportation electrification.

As brief and tidy as these definitions are, the issue of lost or gained revenues impacts associated with DERs has become a hotbed of argument, confusion, frustration, and not just a few controversial regulatory pronouncements and decisions. To this frequent trainer, debater, and expert witness on the topic, it seems time to address the topic again, and with hope that more of us will approach the issue from a position of more common understanding.

Framing the issue – the basics

First, it is important to frame the issue and not just define the terms. Regulated utilities live on the recovery of revenue requirements. Revenue requirements in turn reflect the return of and on investments made by utilities to provide utility service. Revenue requirements are determined primarily in rate cases, though sometimes also in associated or alternative regulatory proceedings, such as formula rate adjustments, tariff adjustment mechanisms, riders, and performance-based regulation decisions.

For example, if a utility invests $1,000,000,000 to build a new substation, and that substation is used and useful in the provision of electric service, and that spending is approved by a regulatory authority, then the utility will be entitled to recover the money spent plus a return on or profit on the investment. That return will be spread out over the expected useful life of the substation—say 40 years. If the utility spends $100,000 paying for miscellaneous consulting services and the spending is likewise approved, the utility will be entitled to recover that cost, though generally not with a profit, because consulting fees are an operating expense and not a capital investment. Both the annual share of the cost of the substation and the consulting fees will be included in the revenue requirement for the utility. And the utility is entitled—as a matter of U.S. Constitutional law, no less—to a reasonable opportunity to earn its revenue requirement. These and other amounts are the cost of electric service, and the approach I just described is known as cost-of-service regulation.

How the utility recovers or collects its cost of service is referred to as “rate making,” that is, the apportionment of the costs to the customers that use or benefit from the service provided. And the mechanism for cost recovery is dividing approved costs—approved revenue requirement—by the number of energy units the utility expects to sell in the time following the approval of rates.

So, if our example utility has a $27,350, 000 annual revenue requirement (1/40th of $1,000,000,000 for the substation, plus, say, 9% profit on the annual amount, plus $100,000 for the consulting fees), and it expects to sell 273,500,000 kWh of electricity at a single uniform rate, then it will be authorized to charge its customers 10 cents per kWh by the regulators. And if the utility sells exactly 273,500,000 kWh of electricity, it will recover its revenue requirement exactly.

Of course, this is a highly simplified example. There are many kinds of costs that the utility incurs to provide electric service, and there are many kinds of customers rates and charges that a utility uses to recover its cost of service. And there are many reasons why the actual level of sales that occur after rates are approved will not match the forecasts—the weather and economic conditions being chief among them. It is also possible that the forecast itself was simply wrong, for whatever reason.

These deviations from planned revenue recovery seldom move in the same direction. A particularly hot summer could drive sales higher due to increased use of air conditioning but could also motivate some customers to make significant changes in how much energy they use, such as by adding insulation or getting a more efficient air conditioner.

Generally speaking, utilities take the ups with the downs and get pretty close to meeting their approved revenue requirement. And if their earned revenue is consistently lower, or higher, than the approved revenue requirement, many adjustments/fixes are available.

Enter Distributed Generation (DG) – increased costs vs. lost revenues

Just like energy efficiency, personal conservation habits, and/or changes in household makeup—which can persistently change usage levels and patterns—customer-sited distributed generation (DG) can permanently change the usage in a particular customer home or business. Generally, sales to customers with onsite generation go down, especially during the sunny hours of the day if the generation is solar-powered. Sales go down with efficiency and conservation, but could go up due to demand response programs, building electrification (e.g., air source heat pumps), EV adoption, and use of distributed storage.

In the case of DG—which is the focus hereafter—if the utility did not forecast, or underestimated, the adoption of customer-sited DG in its last rate case, sales will fall below the forecast level (all other things being equal). When those sales fall, and if nothing else happens, the utility will face a revenue shortfall as compared to revenues assumed in that last rate case.

So, if the utility does not earn as much as it expected due to the unexpected or underestimated installation of distributed generation, why does that matter? And is that a cost?

DG can provide benefits to the utility and non-DG customers. Overall, reduced use of the grid and utility generation as a result of DG operation can save everyone money over both the short and long term. Transformers wear out faster on hot sunny days when they operate at or above the upper limits of their design. Hot summer weather causes peak demand for energy across entire regions, which in turn requires provision of the most expensive generation and increases overall system stress and can be counteracted by local distributed generation. These are beneficial impacts of distributed generation that, among others, should be accounted for in evaluating whether the utility system and society benefit from distributed generation.

But what about the cost to the utility of distributed generation? Utilities can incur costs related to distributed generation. High concentrations in particular locations can require spending on system upgrades. These added, incremental costs of distributed generation are typically charged to customers seeking to interconnect their generation systems to the grid. But if the utility incurs costs that it does not pass back to the generator, then it faces a cost. And if the utility did not plan for that cost in its last rate case, it could have an earnings shortfall.

The reduction in sales, however, is not by itself a cost. A cost is an added financial burden associated with a particular event or action. Not selling as much electricity as planned is not an added cost of serving customers, even for the customer who installs the distributed generation. The reduction in sales does not increase the cost of service.

“Not selling as much electricity as planned is not an added cost of serving customers, even for the customer who installs the distributed generation. The reduction in sales does not increase the cost of service. The operation of an interconnected distributed generation does not add a cost to utility operations just because expected sales are reduced. So, in the business of performing a benefit-cost analysis, lost sales have no place. Lost revenues, by themselves, are not a cost or a benefit of distributed generation.”

The operation of an interconnected distributed generation does not add a cost to utility operations just because expected sales are reduced. So, in the business of performing a benefit-cost analysis, lost sales have no place. Lost revenues, by themselves, are not a cost or a benefit of distributed generation.

If lost revenues are not a cost or a benefit for including in a BCA, what are they?

Lost revenues due to sales reductions could have an impact on the utility and other customers. The utility could have a revenue shortfall and be forced to reduce spending or find new sources of revenue to do all the things it planned. One of the sources of new revenues could be other customers who do not have generators of their own, or to seek increases in rates—in the next rate case—for all customers, including those with generators.

This raises the oft cited and inaccurately named concept of a “cost shift.” The notion behind cost shift concerns is that if a utility does not earn its planned and approved level of earnings, even after trying to forecast for such impacts in the last rate case, due to self-generation, then the recovery of the costs that the utility would otherwise recover from customer-generators will be shifted to other customers without generation.

The cost shift argument, therefore, expressly assumes that the utility is entitled to all the money it would have made on a customer, even if that customer pays less due to self-generation. Often, the argument speaks in terms of customer-generators paying their “fair share” of utility sunk costs. And far too often, the argument does not include an evaluation of the net benefits and costs of distributed generation.

If a utility is subsequently allowed to recover lost revenues, and the distributed generation customer continues to use less of utility services, three important questions arise.

  • First, did the self-generator reduce utility costs by using less electricity, and to what extent?
  • Second, does a redistribution of those reduced costs to other customers amount to fair, just, and reasonable rate making for non-generator customers?
  • Third, does the redistribution of costs to non-generators have distributional impacts that unjustly burden non-generator customers?

Answering these questions is the stuff of rate impact analysis, whereas BCAs answer the question: Which resources have benefits that exceed costs and therefore merit utility acquisition or support on behalf of their customers?

“Taken together, we can see that the best course is to fully evaluate the costs and benefits of distributed generation in terms of impacts on the utility and other customers, and on society as a whole [. . .] Then, and in parallel, undertake a rate impact analysis to determine whether an actual cost shift will arise, whether the utility should be authorized to collect lost revenues, and whether that collection will have unacceptable impacts, net of benefits, on non-generators.”

Taken together, we can see that the best course is to fully evaluate the costs and benefits of distributed generation in terms of impacts on the utility and other customers, and on society as a whole (to extent applicable to a jurisdiction’s articulated societal policy goals). Then, and in parallel, undertake a rate impact analysis to determine whether an actual cost shift will arise, whether the utility should be authorized to collect lost revenues, and whether that collection will have unacceptable impacts, net of benefits, on non-generators.

Doing a rate impact test without a BCA ignores the long-term and system-wide benefits that distributed generation can bring. And as distributed generation markets grow, evaluating rate and distributional impacts is essential to ensuring just and reasonable utility service rates for all. This evaluation should align with NSPM principles, especially in accounting for the full range of utility system impacts, and, where consistent with jurisdictional policy goals, also in accounting for host customer and societal impacts.

What if rates increase? If the potential level or distribution of rate increases for non-generators is unacceptable, the regulator and the utility have options. They can limit distributed generation with system-wide caps or by imposing charges on distributed generation that makes customer investments in generation less attractive. They can also work to expand the pool of customers that can benefit from self-generation, such as with special incentives for target customers (which can add a cost) or with support for community or shared generation programs. They can seek to maximize the value of installed self-generation with “Value of DER” rates that encourage siting and operation to maximize locational and temporal benefits of distributed generation. And they can include customer-hosted distributed generation in non-wires solutions programs aimed at avoiding or deferring specific and imminent infrastructure costs. Finally, because distributed generation and other distributed resources enjoy economies of deployment scale—they get less expensive with higher deployment rates—they can target programs to accelerate distributed generation deployment. Though this last option sounds counterintuitive, more affordable distribution generation means deployment rates won’t suffer if rates for self-generators are adjusted to increase the amount that these customers pay to the utility even after self-generation.

Closing Thoughts…

Despite all-too-common misperception, utilities are not guaranteed their income or their profits for shareholders. Well-established law provides that they are only entitled to a reasonable opportunity to recover their investments and money spent providing utility service, and to earn an allowed level of profit on some of that spending associated with capital—long-lived investments. So, the regulator and the utility are faced with a series of questions when customer-sited / customer-owned generation is installed and operated. These questions include:

  • What does jurisdictional policy say about distributed generation? Is distributed generation part of the state’s plan for decarbonization?
  • With all the other things that impact revenues, is dealing with distributed generation impacts on revenues a policy priority?
  • Did the utility anticipate the installation and operation of the distributed generation? (if the generation is in the forecast, the lost sales are already accounted for)
  • Were the sales and earnings impacts material to the utility’s ability to recover its revenue requirements? (hot day – increased sales and solar generation)
  • What else happened with sales and earnings to offset or compound the earnings impacts the utility has seen?
  • Should distributed generation revenue impacts be treated similarly or differently from all the other things that affect sales and earnings?
  • Are there already mechanisms in place, like revenue decoupling, which will adjust earnings for unanticipated shortfalls?
  • Will limits on distributed generation, or changes in distributed generation rates reduce or preclude the system-wide benefits that distributed generation can provide?

The issue and treatment of lost revenues versus benefit-cost analysis is critically important to understand, not only for regulators and utilities, but also the stakeholders interested in the merits and impacts of utility DER investments.

As the deployment and operation of DERs continues to grow, with many customers deploying more than one DER at a time, a BCA framework that aligns with the National Standard Practice Manual principles, coupled with rate impact analysis (Appendix A of the NSPM), is essential to avoid rate and revenue surprises and unfair burdens. And a clear understanding of the different purposes and methods of benefit-cost analysis and rate impact analysis is essential.

DSP: NEI and GHG Impact Comparisons

DSP: NEI and GHG Impact Comparisons

(Continued from NESP Quarterly February 23, 2023)

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.

Access the DSP and the new comparison tables here.

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.

Monetizing Societal Health Impacts in BCA – Guidehouse Shares Illinois’ Methodology

Monetizing Societal Health Impacts in BCA – Guidehouse Shares Illinois’ Methodology

(Continued from NESP Quarterly October 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:

  • premature death,
  • 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. 

Methodology for Monetizing Societal Health NEIs

To measure societal health NEIs and incorporate them into ComEd’s TRC values, Guidehouse developed a methodology for monetizing societal health NEIs using two tools developed and maintained by the US Environmental Protection Agency (EPA): AVoided Emissions and geneRation Tool (AVERT) and CO-Benefits Risk Assessment (COBRA).

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.

Figure 1. Guidehouse Methodology for Estimating Societal Health NEIs

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.  

ProgramIllinois TRC Test (without Societal NEIs)Illinois TRC Test (with Societal NEIs)
Appliance Rebates2.353.16
Elementary Energy Education6.528.74
Residential HVAC4.005.55
Single-Family Assessment2.643.80
Residential Behavior6.5211.51
Lighting Discount5.277.99
Multi-Family Assessments1.372.08
Residential Total3.875.82
Business Grocery6.597.71
Business Instant Discounts3.886.06
Business Telecomm1.732.98
Facility Assessments0.260.55
Incentive – Custom + Standard1.662.45
Industrial Systems + Industrial Energy Management1.382.42
LED Streetlighting2.143.57
Non-Profit Retrofits1.382.25
Non-residential New Construction2.073.20
Public Buildings in Distressed Communities1.181.65
RetroCommissioning + VCx4.367.98
Small Business3.254.19
Small Business Kits3.774.79
Strategic Energy Management2.475.12
Business Total2.453.56
Affordable Housing New Construction0.811.23
Food Bank-LED Distribution8.5413.02
Product Discounts – [Lighting Discounts + Appliance Rebates – IE]6.5410.13
Multi-Family Retrofits – IEMS + IHWAP0.841.07
Public Housing Retrofits0.610.93
Single Family Retrofits – CBA + IHWAP0.460.95
UIC-ERC Income Eligible Kits7.9911.14
Income Eligible Total4.226.28
Voltage Optimization2.573.99
Building Operator Certification2.664.60
Efficient Choice0.991.53
Electric Homes New Construction0.631.00
ENERGY STAR Retail Products Program0.100.17
SEM Water Savings13.8313.83
Upstream Commercial Food Service Equipment1.392.29
Pilot and VO Total2.373.66
Res and Business Total2.523.69
Portfolio Total (w/ IE, Pilot and VO)2.623.89
Table 1. CY2021 ComEd TRC Results with and without Societal Health NEIs

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.

Guidehouse’s methodology represents a relatively low-cost approach to reflect societal health benefits in BCA. To learn more about Guidehouse’s societal NEI research and methodology, read their ACEEE Summer Study paper and societal NEIs evaluation study.

For more information on state energy efficiency program cost-effectiveness testing practices, including which states include NEIs, please visit the Database of Screening Practices (DSP).

Database of Screening Practices- Refreshed!

Database of Screening Practices- Refreshed!

(Continued from NESP Quarterly June, 2022)

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.

Refer to the DSP for more information and definitions.

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

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.

States Using the NSPM

States Using the NSPM: MD, DC, WA

(Continued from NESP Quarterly February 14, 2022 – with one updated link below for Maryland, since newsletter publication date)


maryland map

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).

Chris Neme (Energy Futures Group) served as technical advisor to the commission staff on behalf of the NESP. He presented on the Maryland EV WG process and development of the MD-EV JST – with Amanda Best of the Maryland PSC – at a SEEA webinar in December: Electric Vehicle Programs: How to Strike a Balance Between Excitement and Execution. Mark Warner (Gabel Associates) presented on the MD-EV JST and consideration of non-energy impacts at the NARUC Center for Policy Innovation webinar 1/20/22.

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.

Washington, D.C.

washington dc map

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.

Washington State

washington state map

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.

See the entire February 2022 NESP Quarterly.

Energy Equity and BCA

Energy Equity and BCA

(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[1] 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:

In the meantime, we welcome your thoughts and feedback on this conceptual framework and invite your comments at

See the entire February 2022 NESP Quarterly.

[1] 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.