6. Host Customer Impacts

The term “host customer” is used to refer to a utility customer that installs a DER in their home, business, or other type of property. The host customer might be a participant in a DER program, a customer who installs DERs with the assistance of a third party, or a customer who installs DERs in response to price signals.

Host customer impacts should be accounted for in a jurisdiction’s BCA if they are relevant to the jurisdiction’s energy policy goals, consistent with NSPM 2020 guidance. If accounting for host customer impacts is required, then ensuring symmetry in the treatment of host customer costs and benefits—even where hard to quantify—is critical to ensuring unbiased treatment in valuing any one resource relative to others. This includes accounting for host customer impacts for the full study period of the BCA. This chapter provides guidance on how to account for the range of host customer impacts, including hard-to-quantify impacts, for host customer energy and non-energy impacts.

6.1. Host Customer Energy Impacts

Examples of the main types of host customer energy impacts are provided in Table 54. These impacts can be either benefits or costs, depending on the situation or use case. In most cases, the host DER costs, any transaction costs, and any interconnection fees will represent costs to the host customers. For some of the impacts listed, such as risk or reliability, the impacts can be either a benefit or cost. See the NSPM 2020 for further guidance on when an impact may be a cost versus a benefit for different DERs and use cases.

Table 54. Host customer energy impacts

Additionally, there may be cases where an energy-related benefit or cost is experienced by the owner of a DER, as opposed to the host customer. For example, some distributed PV systems are owned by a PV third-party developer and leased to the host customer. In other instances, the DER is owned by a commercial or residential landlord, but the energy utilities are paid for by a tenant who is the host customer. In these cases, some or all of the costs or benefits of the DER are passed on to the host customer through some mechanism (e.g., lease payments, higher rent, lower energy bills, increased reliability, etc.). Consequently, a portion of the costs or benefits that are technically experienced by the third-party developer or landlord can be attributed to the host customer.

6.1.1. Host Customer DER Costs

6.1.1.a. Definition

Host customer costs include the incremental costs incurred to plan for, install, operate, and maintain a DER project. These are the costs of the DER incurred by the host customer relative to the cost of a standard measure or alternative consumer choice (referred to as the baseline costs or Reference Case) and after accounting for any utility or other incentives.

For example, in the case of some energy efficiency or electrification measures, the new technology replaces a less efficient, or fossil-fuel based option that the host customer would have obtained in the absence of the DER program or intervention. Here, the incremental cost of the measure is the difference in price between the DER and the baseline option.

In some cases, the incremental cost may be the total cost of the DER. For example, for a host customer who installs a new generation resource, such as solar PV, the baseline is often no new generation resource. In this example, the incremental cost of the DER is simply equal to the total cost of the DER.

For all DERs, any financial incentive provided to the host customer should be subtracted from the incremental DER costs for use in cost-effectiveness tests.

The incremental DER cost should include all costs throughout the BCA study period that are associated with planning and procuring the DER relative to the baseline option. Host customer costs can also occur in the form of a subscription cost that is paid over time to a third-party owner of a DER, as is often found with community solar projects.

Table 55 lists examples of costs to consider when calculating host customer DER costs. The cost elements apply to both DER and baseline options. Ideally, cost escalation should be considered for any ongoing costs, as relevant.

Table 55. Types of costs to consider when calculating host customer DER costs

6.1.1.b. Methods for Calculating Host Customer DER Costs

Conceptually, the host customer DER cost is calculated by simply subtracting any financial incentives from an electric utility (see Section 3.5.1) or other source from the incremental cost of the DER. However, in practice, determining the Host Customer DER cost can be a complex exercise for some types of use cases. Complexities relate to several factors, including the following:

• Collecting data for all of the cost elements in Table 55, especially for the baseline case since that represents the action not taken by the customer
• Taking into account escalation, cost of money (financing), and differences in project lifetimes between the DER and the baseline case
• Understanding and applying state- and jurisdiction-specific costs and incentives

Estimating costs is generally easier for DERs that are an add-on to a property than for DERs that substitute alternative energy technologies.

DER as “Add-On”

As described above, there are some DER use cases where the incremental cost is simply equal to the total DER project cost including any utility infrastructure or customer electrical upgrades over the lifetime of the DER. These special cases include installation of solar PV and/or battery storage at a host customer site for which there is no alternative distributed generation or storage option currently installed or being considered. They could also include demand response-enabling controls that are added to existing equipment.

DER as “Substitute”

For installation of demand response-ready technologies (e.g., grid-integrated water heaters) or implementation of energy efficiency or electrification measures (including electric vehicles, distributed generation, and distributed storage systems that displace fossil fuel-fired counterparts), determining the total incremental cost is much more complicated.

All of these examples substitute an alternative option with a DER, rather than introducing a new, add-on DER. A homeowner may be faced with a choice to purchase an efficient or inefficient refrigerator, but they are unlikely to opt out of owning a refrigerator altogether. Given this distinction from the add-on use case, the total incremental cost of a DER in the substitute use case is the total incremental cost above a baseline (i.e., Reference Case) option.

Incremental Cost Studies

The methods for preparing incremental cost studies can vary depending on the DER in question. In general, incremental cost studies often involve the following components:

1. Conducting in-depth interviews with installers, manufacturers, retailers, and other industry experts to:
   • Confirm the baseline option;
   • Define the DER boundaries (e.g., is ancillary equipment essential to the “typical” installation?);
   • Define the typical installation or more complex installation;
   • Identify any other special characteristics that might impact costs; and
   • Gather data on typical costs from the interviewees, as available (see Table 55 on costs elements to consider).
2. Collecting available DER cost data from program administrators, implementation contractors, and/or directly from host customers (if possible). Available data may be in the form of database extracts that compile costs for a group of customers, or it may consist of equipment invoices or purchase orders. For complex construction projects, more detailed unit pricing may be available. (Unit pricing involves preparing a “takeoff” listing of every element of the project from the project drawings and then itemizing material and labor costs.)
3. Estimating baseline cost data—and any missing DER cost data—using cost estimation resources. Some resources have data that show changing rates over time and geographical variations. Examples of sources include:
   • RSMeans data website (see RSMeans)
   • National Construction Estimator (see Pray 2021)
   • Grainger website (see Grainger)
   • U.S. Bureau of Labor Statistics (see U.S. BLS)
   • Associated General Contractors of America (see AGCA)
4. Verifying costs or filling in gaps using other publicly available resources:
   • Manufacturer and distributor websites
   • Cost studies (see U.S. EIA 2018, NREL 2021, and PNNL 2019)
   • Technical reference manuals (some include measure costs)
   • Measure work papers (e.g., from the California Public Utilities Commission)
5. Compiling and normalizing the cost data to provide a single analysis platform for each DER

In practice, jurisdictions often ‘borrow’ or use incremental cost data from other jurisdictions that have invested in studying incremental costs. Some examples of such studies are:

• Massachusetts’ MA19R18: Residential New Construction Incremental Cost Update (see NMR 2020 MA19R18)
• Massachusetts’ RLPNC 17-14: Mini-Split Heat Pump Incremental Cost Assessment—Final Report (see NMR Group. 2018)
• CPUC’s Measure Cost Studies guide (see Itron 2015)
• Navigant’s EM&V Forum Incremental Cost Study (see Navigant 2015)

The same general methods used to calculate host customer costs for traditional energy efficiency and demand response measures can be applied to electrification measures. A key difference is that the baseline technologies relative to the new electrification measures are likely to be non-electric measures (e.g., the baseline technology for evaluating electric heat pump water heaters is likely to be a natural gas- or propane-fueled water heater). Nonetheless, the incremental costs and subsequent host customer costs should be treated consistently based on the program delivery approach.

The total incremental cost of a “substitute” DER measure varies by program type and status of the alternative option because these factors will impact the definition of the baseline condition, and therefore the incremental cost. The standard practice for calculating the incremental cost is summarized below for the most common program types and baseline conditions: new construction and major renovation, replace on failure, early replacement, and retirement and removal.

New Construction and Major Renovation

For new construction and major renovation projects, the incremental cost of a DER is defined as the cost of the DER above what is required by building code or appliance standards (i.e., the baseline technology). For states without building codes or with outdated codes—or where common practices (standard industry practices) exceed codes, the baseline technology may be developed through market surveys. New construction programs are designed to encourage builders and developers to go above and beyond what is required by codes and standards or to exceed common practice.

Replace on Failure

The replace on failure baseline occurs when a customer needs to replace their old equipment due to its failure or the fact it has reached the end of its useful life. It mostly applies to energy efficiency and electrification projects but could also apply to replacing distributed generation or storage equipment. In this situation, the customer must choose between purchasing a DER that is more efficient and/or has a lower carbon footprint than the alternative options on the market or purchasing one of the alternatives. Replace on failure programs are typically designed to move host customers to adopt more energy efficient or greener DER technologies. To capture this situation, the incremental cost should represent the cost of the new DER above the cost of the alternative equipment that the customer would have purchased in the absence of the subject program. Depending on the measure and jurisdiction, the baseline would either represent an applicable code or standard, or common practice.

Early Replacement

DERs that replace existing, functional equipment before the end of the equipment’s useful life are defined as early replacement measures. Establishing the incremental cost of early replacement measures is complex for two reasons:

• Early replacement changes the timing of costs relative to when they could be incurred in the baseline scenario (i.e., absent the early replacement)—at least in cases where a jurisdiction chooses to include participant benefits and costs; and
• That change in timing can lead to the need to account for multiple baseline assumptions (assumptions that change over time) for both costs and savings.

The NSPM 2020 provides guidance on how to calculate the incremental cost of early retirement measures (see NSPM 2020, Appendix H2).

Retirement and Removal

Some utility programs encourage customers to remove their old equipment without replacement. For example, some program administrators offer refrigeration recycling programs where an incentive is offered to remove the old appliance. In this situation there is no incremental cost.

The calculation of the host customer cost for this type of program depends on the program’s financial incentive. It is common for program administrators to pay 100 percent of the removal cost for this type of offering. In this situation there are no host customer costs. In the case where the program administrator does not cover 100 percent of the removal cost, the customer cost would be calculated by subtracting the utility incentive from the cost to remove the equipment.

6.1.2. Host Transaction Costs

6.1.2.a. Definition

This includes the transaction costs associated with the acquisition and installation of DERs. These costs can include time spent collecting information, obtaining quotes from multiple vendors, filing paperwork, and completing applications for rebates and other financing mechanisms. This impact will always be experienced as a cost for the host customer.

6.1.2.b. Method for Estimating Host Transaction Cost Impacts

Host transaction costs can be estimated on the basis of the host customer’s “lost time,” which can be valued using the hourly wage of the host customer, in the following steps:

6.1.3. Interconnection Fees

6.1.3.a. Definition

Interconnection fees are the costs associated with the utility and/or ISO/RTO interconnection process paid for by the host customer or a third party. Interconnection fees can include costs associated with permits, studies, grid upgrade costs assessed to the customer, or inspections.

Interconnection costs can be designated as a flat fee, a cost per installed capacity, or as a variable cost (e.g., $/MW) pending an assessment. Small DERs are more likely to have streamlined interconnection processes, whereas large projects may require detailed studies and extensive grid upgrades.

Interconnection costs may vary based on system size, whether the system is set up to export back to the grid, or whether multiple systems interact (e.g., PV plus storage).

6.1.3.b. Method for Estimating Interconnection Fee Impacts

Interconnection fees for DERs are set by the state, utility, and/or ISO/RTO. This information is best obtained through one of these entities, or a third party such as an installer that may pay for the costs on behalf of the customer. The DERs to which interconnection fees are the most applicable are solar PV and battery storage.

Solar PV

Most states have fixed application fees for small to mid-sized PV systems, while larger projects are more likely to be assessed on a $/MW basis. Table 56 below shows several examples of interconnection fees by state.

Table 56. State examples of interconnection fees for solar PV

Several states, including California and Colorado, require pre-application reports upon request that could lead to additional costs associated with interconnection.

Battery Storage

Battery storage systems are highly flexible grid resources that act as both sources of energy and consumers of energy. Battery storage can be installed as standalone systems or can be paired with solar PV. Many states have yet to define a specific interconnection procedure for battery storage. Depending on the state, battery storage systems may be categorized under the same set of regulations as solar PV and consequently have corresponding interconnection fees or be viewed as separate resources.

6.1.4. Risk, Reliability and Resilience

Host customer impacts from DERs can include direct benefits (or costs) with regard to risk, reliability, and resilience—depending on the DER(s) installed and the use case being evaluated. These impacts are addressed separately in Chapter 8 (Reliability and Resilience) and Chapter 10 (Risk).

6.1.5. Tax Incentives

6.1.5.a. Definition

Federal, state, and local tax incentives are sometimes available to host customers to defray the costs of some DERs. Tax incentives are deducted from a host customer’s annual income tax and are typically presented as a percent of total project costs or as a fixed credit.¹³

The NSPM 2020 Appendix F (Table F-5) applies criteria to determine when tax incentives should be included in a cost-effectiveness test. If tax incentives are not an offsetting impact, they should be included. Based on the criteria, tax incentives should be included in the Total Resource Cost Test and Participant Cost Test as a benefit to the host customer, but they should not be included as a benefit or cost in the Utility Cost Test or Societal Cost Test. In jurisdiction-specific tests that include host customer impacts, tax incentives can be included as a benefit to host customers if that is consistent with the jurisdiction’s energy policy goals.¹⁴

Federal Tax Incentives

Federal incentives for DERs vary between years. Incentives may decrease from year-to-year as market adoption increases or disappear altogether with changing federal priorities. Applicable federal tax credits for DERs may be obtained from the office of Energy Efficiency and Renewable Energy at the U.S. Department of Energy (See U.S. DOE O&M 2018). Table 57 reflects federal tax incentives for DERs at the time of this publication.

Table 57. Federal tax incentives

State Tax Incentives

Host customers may qualify for tax incentives offered by their state in addition to or independently from federal incentives. This can take the form of income tax incentives, sales tax holidays, and property tax incentives. Table 58 contains examples of state tax incentives available at the time of this publication.

Table 58. State tax incentives

6.1.5.b. Methods for Calculating Tax Incentive Impacts

Federal Tax Incentives

Federal tax credits reduce the amount of federal income tax owed by a host customer. Federal tax credits are either offered as a percent of project costs or as a fixed credit that does not vary based on the initial customer investment. For example, the federal solar energy investment tax credit (ITC) is based of a percentage of the cost of a solar PV system, while the federal electric vehicle tax credit provides up to a $7,500 credit for qualifying battery electric vehicles. See Figure 29 for a summary of methods to estimate impacts from federal tax incentives.

Percent of Total Project Cost Method for Federal Tax Incentives

The percent tax credit should be multiplied by the project costs, as shown in Table 59. Applicable project costs include equipment costs, labor costs, and sales tax. Under most circumstances, utility incentives or rebates should be removed from the total project cost (see U.S. DOE Tax Guide).

Table 59. Steps to calculate federal tax incentives using the percent of total project cost

These steps are summarized in the following formula:

Federal tax incentive = (total equipment costs + total labor costs + sales tax – utility incentives) * (percent federal tax incentive)

State tax credits should not be factored into this calculation.

Fixed Tax Credit Method

Fixed tax credits are more straightforward because they do not differ with project cost. The total federal tax credit should simply be set to the fixed tax credit.

State Tax Incentives

The methods for calculating state tax credits largely mirror the methods for calculating federal tax credits. State tax credits, like federal credits, are either offered as a percent of project costs or as a fixed credit that does not vary based on the initial customer investment.

The methods for federal and state tax credits diverge slightly because of the interplay between federal and state taxes. By claiming a state tax incentive, a customer effectively increases their total income reported (by reducing the taxes owed). Consequently, the customer now reports a higher income to be taxed at the federal tax rate. This interplay modifies the calculation methods, as displayed in Figure 30  (See DOE Tax Guide 2021).

Percent of Total Project Cost Method for State Tax Incentives

The calculation method for a state tax credit that is presented as a percent of project costs is nearly identical to the federal tax credit method, with the exception that the total tax refund is reduced by the federal tax rate. Table 60 describes those steps.

Table 60. Steps to calculate state tax incentives using percent of total project cost

These steps are summarized in the following formula:

State tax incentive = (total equipment costs + total labor costs + sales tax – utility incentives) * (percent state tax incentive) * (1 – federal tax rate)

Fixed Tax Credit Method

The fixed tax credit method is modified identically.

State tax incentive = (fixed tax credit) * (1 – federal tax rate)

Federal and state tax credits are additive.

6.1.6. Energy Cost Impacts

6.1.6.a. Definition

DERs typically result in energy bill savings for the host customer. In some cases, such as electrification, the DER might increase the host customer’s electricity bill but decrease the costs of other fuels such as natural gas or gasoline.

6.1.6.b. Application

Host customer bill impacts associated with the utility conducting the BCA should not be included as a benefit or cost in the BCA. Those host customer bill savings would overlap significantly with the utility system benefits, which are already accounted for in the utility system impacts in BCA tests. As such, including them in a BCA would double-count some of those impacts.¹⁵ Further, host customer bill savings result in lost revenues, which can contribute to rate impacts, which should be analyzed separately from cost-effectiveness analyses (see NSPM 2020, Chapter 2, Section 4.4.3, and Appendix A).

However, for DERs that have interactive effects with other types of energy sources, it is appropriate to include bill impacts for the changes in consumption of the other energy sources. There are many examples of such DERs, including efficient lighting projects that increase the costs for oil heating, demand response programs that defer or increase back-up generation, distributed generation projects that require alternative fuels such as combined heat and power, building electrification, and electric vehicles). In these cases, the changes in consumption of the other energy sources should be accounted for as other fuel impacts (see Chapter 5).

In the case where a Participant Cost Test is used to help inform program design and financial incentive levels, host customer bill savings should be included. This is because the Participant Cost Test is designed to represent the actual impacts on host customers, including bill impacts from all relevant energy sources. In the Participant Cost Test, the energy cost savings are the primary benefits of DERs, but the utility system benefits are not included at all, thereby preventing double-counting.

6.1.6.c. Method for Estimating Host Customer Bill Impacts

Host customer bill impacts can be calculated by multiplying the DER energy impacts by the corresponding energy prices. For host customers with time-of-use rates, the DER’s hours of operation should be mapped to the hourly time-of-use rates. For host customers with demand charges, the DER demand savings or generation (in kW) should be applied to the demand charges (in $/kW), in addition to applying the DER savings or generation to the energy charge. Ideally, the energy prices should be escalated through the life of the DER, or the length of the BCA study period.

6.1.7. Resources for Calculating Host Customer Energy Impacts

Associated General Contractors of America website. n.d. (AGCA). www.agc.org/.

Energy Sage. 2021. “Solar battery incentives and rebates.” energysage.com website. www.energysage.com/energy-storage/benefits-of-storage/energy-storage-incentives/. September.

Gordian. n.d. (RSMeans). “RSMeans data.” rsmean.com website.

Grainger website. n.d. W.W. Grainger, Inc. www.grainger.com/.

Itron. 2015. Measure Cost Studies: A Key Ingredient in Your Energy Efficiency Portfolio’s Success. Prepared for California Public Utilities Commission. www.itron.com/-/media/feature/products/documents/brochure/measure-cost-studies.pdf.

Maryland Energy Administration. 2021. (MEA 2021). “Maryland Energy Source Income Tax Credit – Tax Year 2021.” energy.maryland.gov website. energy.maryland.gov/business/Pages/EnergyStorage.aspx.

Navigant Consulting. 2011. (Navigant 2011). Incremental Cost Study: A Report on 12 Energy Efficiency Measure Incremental Costs in Six Northeast and Mid-Atlantic States. Prepared for the Evaluation, Measurement, and Verification Forum, chaired by Northeast Energy Efficiency Partnerships. September 23.

Navigant Consulting. 2015. (Navigant 2015). Incremental Cost Study: Phase Four Final Report

–A Report on Six Energy Efficiency Measure Incremental Costs in Six Northeast and Mid-Atlantic States. Prepared for the Evaluation, Measurement, and Verification Forum, chaired by Northeast Energy Efficiency Partnerships. June 15. neep.org/sites/default/files/resources/ICS4%20project%–20report%20FINAL%202015%20June%2015.pdf.

New York State. Updated 2019. (NYS 2019.) “Solar Energy System Equipment Credit.” tax.ny.gov website. www.tax.ny.gov/pit/credits/solar_energy_system_equipment_credit.htm.

NMR Group. 2018. RLPNC 17-14: Mini-Split Heat Pump Incremental Cost Assessment—Final Report. Prepared for the Massachusetts Electric and Gas Program Administrators.

ma-eeac.org/wp-content/uploads/RLPNC_17-14_MiniSplitCost_27NOV2018_Final.pdf.

NMR Group. 2020. (NMR 2020 MA19R18). MA19R18: Residential New Construction Incremental Cost Update–Final Report. Prepared for Massachusetts Electric and Gas Program Administrators. https://doee.dc.gov/sites/default/files/dc/sites/ddoe/publication/attachments/DCSEU%20FY2019%20Performance%20Benchmarks%20Report%20-%20FINAL%2006012020%29%281%29.pdf

NMR Group. 2020. (NMR 2020 DCSEU). Performance Benchmark Assessment of FY2019 DC Sustainable Energy Utility Programs. doee.dc.gov/sites/default/files/dc/sites/ddoe/publication/–attachments/‌DCSEU%20FY2019%20Performance%20Benchmarks%20Report%20-%20FINAL%2006012020%29%281%29.pdf.

Rocky Mountain Institute 2019. (RMI 2019). Reducing EV Charging Infrastructure Costs. Nelder, C. and E. Rogers. rmi.org/wp-content/uploads/2020/01/RMI-EV-Charging-Infrastructure-Costs.pdf.

U.S. Bureau of Labor Statistics. n.d. (U.S. BLS). bls.gov website.

U.S. Department of Energy. 2018. (U.S. DOE 2018 O&M). How to Determine and Verify Operating and Maintenance Savings in Energy Savings Performance Contracts. www.energy.gov/sites/prod/files/2018/03/f49/om_savings_guidance.pdf

U.S. Department of Energy. n.d. (U.S. DOE Tax Guide). “Homeowner’s Guide to the Federal Tax Credit for Solar Photovoltaics.” energy.gov website. Office of Energy Efficiency and Renewable Energy. www.energy.gov/eere/solar/homeowners-guide-federal-tax-credit-solar-photovoltaics.

6.2. Host Customer Non-Energy Impacts

Non-energy impacts (NEI) of DERs are real or perceived, financial or intangible, impacts not directly associated with energy production, transmission, distribution, or use. In some cases, the lines are blurry between what constitutes as an energy impact versus a non-energy impact. Therefore, NEI analysis may also be used to capture impacts that are not commonly recognized or quantified as energy impacts, even if they are associated with energy supply and demand (e.g., impacts on other fuel types, renewable energy credits, or power quality).

While often more difficult to quantify than direct energy impacts, there are multiple sources and methods for determining NEI values. On balance, researchers have found that NEIs have positive impacts for utility systems, consumers, and society, and they sometimes represent substantial benefits—for example, with respect to air quality and public health. Even from the lens of just the host customer, the impacts can be significant and may even equal or exceed the energy bill impacts. Moreover, those customer-level impacts can have a ripple effect throughout the economy, crossing over to areas far beyond just energy.

Considering whether and how to include NEIs is an important component of cost-benefit analyses—to the extent accounting for host customer impacts is a stated policy in a jurisdiction. Some NEIs are easier to quantify than others. Examples of more measurable impacts include water savings and reduced O&M costs, while harder to measure impacts include increased comfort and convenience. Nevertheless, it is better to use the best available approximation for a material impact than to assume it does not exist or that its value is zero.

6.2.1. Definition

DERs can create a variety of NEIs for host customers that are separate from the energy saved or produced by DERs. Table 61 presents a summary of host customer NEIs that might potentially be created by DERs. These impacts can sometimes be in the form of benefits and sometimes costs. NEIs can represent one-time benefits to participants, annual benefits to participants, or benefits based on total savings.

Table 61. Examples of host customer non-energy impacts

The presence, direction, and magnitude of these impacts will depend upon many factors, including the type of DER (e.g., energy efficiency, demand response, distributed generation, storage, electrification, electric vehicles), the specific DER technology (e.g., energy efficient lighting versus energy efficient building conditioning), the type of host customer (e.g., low-income, residential, commercial, industrial), whether the host customer values the impact, and the role of the host customer, potentially relative to a landlord or third-party developer.

NEIs for energy efficiency are much more thoroughly analyzed and used than NEIs for other DER types. NEIs for other DER types are still novel and often have limited supporting documentation. The following methods for calculating NEIs apply to all DER types but have historically been implemented for energy efficiency.

6.2.2. Methods for Calculating Host Customer Non-Energy Impacts

Host customers experience NEIs to varying degrees, and importantly, have varied perceptions of the exact benefits or costs of those NEIs. As with other estimates of DER and non-DER costs and benefits, regardless of the method used, some level of uncertainty will remain as to whether the chosen method accurately estimates the value of the NEIs experienced by customers. Both the accuracy and precision of NEIs vary based on the estimation method selected.

NEIs can be applied at the measure, measure-type, end-use, program, sector, or portfolio level. The more granular the assessment level, the more likely the NEIs are to accurately represent impacts experienced by participants.

Although some jurisdictions apply NEIs at the portfolio-level (as a percent adder), this fails to capture the variability of measure mix or customer types. For example, water savings apply only to measures that impact water use. If water benefits are applied at the portfolio level as an adder, they could be overstated for a project that has no connection to water savings, such as a large commercial lighting project. Applying NEIs at a more granular resolution reduces this risk.

Figure 31 summarizes several options for estimating NEIs. From a generalized perspective, the order of accuracy decreases from left to right. The calculation methods for each option are outlined below.

Some NEI values would not be expected to vary by jurisdiction—for example, comfort. However, states use different methods, inputs, and assumptions to derive NEI values, and regulators exercise independent judgment in finalizing NEI values. Often, the NEI value represents a unique set of circumstances and cannot be directly transferred. The studies, however, usually provide methods that can be replicated. These methods range from relatively simple lookups of region-specific rates or costs that can be applied to the amount of energy, water, or resources saved, to conducting sophisticated studies or running sophisticated models that consider economic patterns and wages (see LBNL 2020 NEI).

Option 1: Jurisdiction-Specific Studies

Rigorous jurisdiction-specific studies on DER impacts potentially offer the most accurate approach for estimating and monetizing relevant impacts. Jurisdiction-specific studies are conducted specifically for the geographic region and market in which the DER program operates. As such, NEIs calculated using this option benefit from location- and market-specific inputs, direct feedback from participants, or other factors that improve the accuracy and precision of the results. There are two primary methods for jurisdiction-specific studies: customer surveys and NEI algorithms with jurisdiction-specific inputs.

Customer Surveys

Customers surveys are one approach evaluators use to estimate the value of a host customer NEI. These surveys often use a “relative valuation” method, by which surveys can ask host customers to estimate the dollar value of a series of NEIs as well as their annual bills savings to the best of their abilities. The bill savings can be used as a method to normalize the dollar values assigned to each NEI, given the potential for variability in responses (see Tetra Tech, NRM Group 2011).

A slightly modified approach is for participants to report added benefits as a percentage on top of bill savings. Utility-estimated bills savings may be appropriate to compare with customer-reported bill savings (see APPRISE Incorporated 2018). If studies find that a large portion of participants place little or no value on any particular NEI, that NEI should be discounted accordingly (see Tetra Tech, NMR Group 2011).

Table 62 below presents a simplified example of a relative valuation survey that could be used to estimate NEIs experienced by a single customer. In this example, the survey form asks a customer to estimate their bill savings from two distinct DERs (rooftop solar and a heat pump). Then the form asks the customer to estimate the impacts (in dollars) of two NEIs (comfort and empowerment/control) as a result of those measures. The estimated NEI as a percent of the estimated bill savings are calculated for each DER and NEI.

Table 62. Simplified example of relative valuation survey for estimating non-energy impacts for single customers

Another approach to customer surveys is the “willingness-to-pay” method, which asks customers to assign a dollar value to the amount they would be willing to pay for each NEI. This approach typically yields more conservative estimates for NEIs. Surveys sometimes include a hybrid approach with both the relative valuation and the willingness-to-pay methods to gain a more complete understanding of how customers value various impacts. One caveat with applying willingness-to-pay studies with low-income customers is that their values may be lower because their capacity to pay is lower, skewing results to appear as if they value benefits less than general customers.

For NEI surveys to be analyzed in aggregate, the surveyed population group should all have received the same measure type(s) in order to isolate the benefits. For example, if a study intends to quantify an NEI for hot water measures, the participants should have all received hot water products (see APPRISE Incorporated 2018). In many cases, participants may have received more than one measure from the program administrator.

If participants received more than one measure type, they should be separated into a distinct group that received the same measure types. Surveys can be distributed to a sampling of program participants who are meant to represent the total population served. The larger the number of participants, the more statistically viable (see APPRISE Incorporated 2018).

It is important to note that responses from these types of customer surveys are often associated with high uncertainty—and the uncertainty itself is also difficult to quantify. But, as noted earlier, using even approximations to estimate the impacts is better than assuming they have no value. Further, surveys should be conducted on a periodic basis in order to capture the most up-to-date opinions.

NEI Algorithms

Jurisdictions can develop or repurpose algorithms to calculate NEIs based on territory-specific inputs. Not all NEIs are well suited to algorithms, such as changes in comfort. But others may have clear and jurisdiction-specific inputs.

Two common examples are natural gas and water impacts from electric efficiency measures; these are both relatively easy to quantify and often prescribed with algorithms in technical reference manuals. The value of the energy and water impacts can be quantified by multiplying them by applicable utility rates.

Some other examples include (see Skumatz et. al. 2019):

Reduction in allergy symptoms

Reduction in allergy symptoms = (number of children with environmentally attributed asthma) * (direct medical cost of asthma in children) * (estimated reduction in asthma from program for host customers)

Fewer fires

Fewer fires = [(average property loss from fires per incident) * (percentage of incidents resulting from products offered in the portfolio) * (estimated percentage of incidents that could be fixed with new equipment) * (percentage of households receiving relevant equipment) * (percentage of fires eliminated based on program’s efforts)] + [(average number of injuries/deaths per household) * (percentage of incidents resulting from products offered in the portfolio) * (value of loss of life) * (percentage of households receiving health and safety measures) * (percentage of fires eliminated based on program’s efforts)]

O&M impacts from repairs and repair costs

O&M savings/costs = (average number of appliances that could experience a change in O&M costs) * (appliance repair rate) * (change in repair frequency from the newer equipment)

In cases where the equation inputs are not well defined or not readily available, DER program administrators may need to rely on a blended approach to quantifying NEIs in which the inputs to the calculations are based on survey results.

Low-Income NEI Considerations

Customer surveys and NEI algorithms can also be used to determine low-income NEIs. For both approaches, it is important that the study represent only the low-income population as defined by the program. For customer surveys, this relates to the sample population surveyed. For the NEI algorithms, this relates to the inputs.

Option 2: Transfer values from Other Jurisdictions

Some NEI values or methods may be transferred between jurisdictions under the right circumstances. This option allows jurisdictions to benefit from detailed studies conducted elsewhere without having to fund the studies themselves. The applicability and ease of transferability varies by NEI and differences between jurisdictions. This process to determine whether an NEI can be transferred from another jurisdiction should start with a literature review that explores different values and methodologies used in the source jurisdictions’ analyses (see LBNL 2020 NEI).

In some cases, precise values can be transferred from one jurisdiction to the next. This requires that the inputs used to calculate the NEI do not vary by jurisdiction. Exercise caution with inputs that relate to average home size, average income, average fuel costs, climate, or other variables that are likely to fluctuate based on location or market. In general, studies from nearby jurisdictions are more likely to be a good fit, given the relationship to weather that exists for many DERs (see LBNL 2020 NEI).

In cases where a value cannot be suitably transferred due to jurisdictional differences, a jurisdiction could replicate a particular method while updating just the inputs that vary by jurisdiction.

Low-Income NEI Considerations

The option of transferring values from other jurisdictions can be used for low-income NEIs, but it is important to account for any differences between jurisdictions in the low-income populations that might affect the NEIs.

Option 3: Proxies

Proxies are simple, quantitative values that can be used as indirect indicators for values not monetized by conventional means. They can be applied to any type of benefit or cost that is hard to monetize and is expected to be of significant magnitude.

Proxy values should ideally be based on the best, most quantitative information currently available regarding the specific NEI and how it will be affected the DER being evaluated. Even with the best information available, however, it is sometimes necessary to rely upon professional judgment to make a rough estimate. In many cases, these rough estimates are then negotiated among relevant stakeholders to determine a reasonable proxy. Steps include:

1. Review literature on the NEI.
2. Quantify the NEI to the extent feasible.
3. Review proxy values in other jurisdictions.
4. Consider the conditions specific to the jurisdiction where the proxy will be applied.

Several types of proxies can be used to account for impacts:

• Percentage “Blanket’” Adder: A percentage adder approximates the value of non-monetized impacts by scaling up all impacts that are monetized. For example, the percent adder could be multiplied by the total resource benefits. This type of proxy is the simplest and easiest to apply but is a blunt tool. Several states apply this approach.
• Energy Savings Multiplier ($/MWh or $/MMBtu or X%): A savings multiplier approximates the value of non-monetized benefits or costs relative to the quantity of energy savings. For example, increasing value of benefits by 50 cents per MWh saved or by 10% of the value of the energy savings.
• Customer Adder ($/customer): A customer adder (or subtraction) approximates the value of non-monetized benefits relative to the number of customers served by a program.
• Measure Multiplier ($/measure):A fixed dollar amount adder—for example, $X.X per PV system.

Proxies may be used to reflect several types of NEIs at once. However, proxies will be more accurate if they are determined separately for each type of NEI.

Similarly, proxies can be applied at the portfolio, sector, program, or measure level. They will be most accurate if they are applied at the most granular level possible, to reflect the different magnitudes of NEIs at different levels.

The proxy method is the most commonly used approach for calculating NEIs (see DSP 2021). This is due more to the simplicity of the method than the accuracy. Other more comprehensive methods can be complex and expensive.

Low-Income NEI Considerations

The use of proxies also applies to low-income NEIs. Low-income proxies tend to be higher than those for non-low-income customers. This is because low-income customers typically experience higher benefits from DERs due to higher levels of energy burden, the condition of low-income housing stock, and social-equity-related concerns. See additional considerations on accounting for energy equity in Chapter 9.

Additional low-income benefits can exist for individual DERs as well.

Option 4: Use Non- Dollar Values for NEIs

This option allows DERs with benefit-cost ratios of less than one to be deemed worthwhile based upon qualitative considerations of NEIs (see NSPM 2020, Appendix C). These qualitative considerations need to be described in order to justify the cost-effectiveness of the DER.

This approach requires a qualitative explanation as to why the relevant NEIs are large enough for the DER to be deemed cost-effective despite a low benefit-cost ratio. In some regards, this makes for a more transparent accounting of the NEIs. In general, this flexible approach is highly subjective and rarely applied on a portfolio-wide scale.

Accounting for non-monetary impacts involves several steps:

• First decide whether to include impacts in cost-effectiveness tests based on the relevant policies, goals, regulations, and relevance of specific NEIs. Then decide separately how to value or otherwise account for the impacts.
• Provide as much quantitative evidence as possible.
• Establish metrics to create quantitative data for future analyses that can result in quantitative values.
• Provide as much qualitative evidence as possible.
• Decide on the implications of the quantitative and qualitative evidence.
• Non-monetized impacts are presented alongside monetary impacts so regulators can compare the monetized, quantitative, and qualitative factors and evidence to decide whether a program is appropriate.
• Document and justify the decision.

Low-Income NEI Considerations

Qualitative assessment of non-monetary impacts is commonly used for low-income NEIs. This option can be used to justify low-income programs that are not deemed cost-effective when it is difficult to quantify and monetize NEIs. As noted above, qualitative considerations require a more transparent accounting of the low-income NEIs.

Option 5: Alternative Thresholds

Alternative thresholds are another option for addressing hard-to-monetize impacts. They allow DERs to be deemed cost-effective at pre-determined benefit-cost ratios that are less than one (See NSPM 2020, Appendix C). Applying a proxy value can essentially have the same effect as using alternative benchmarks.

Alternative thresholds are, by design, a simplistic way of recognizing that the hard-to-monetize impacts are significant enough to influence the cost-effectiveness analysis. The primary advantage of this approach is that it does not require the development of specific monetary or proxy values. The disadvantage is that it might not eliminate DERs that are more costly than necessary. This disadvantage can be mitigated through sound DER program design.

Regulators should ensure that alternative thresholds are as transparent as possible and are established prior to the cost-effectiveness analysis. Ideally, regulators should articulate which resources the alternative thresholds can be applied to, what the threshold is, and the basis for the threshold chosen.

Low-Income NEI Considerations

The alternative thresholds option is often used for low-income NEIs. In the case of low-income NEIs, a benefit-cost ratio threshold of less than one can be used to account for the non-energy benefits of DERs hosted by low-income customers. Some jurisdictions that place a high priority on protecting low-income customers do not require low-income DER programs to be subject to a BCA, which is essentially equivalent to dropping the benefit-cost ratio threshold to zero (see NESP 2021 DSP).

6.2.2.a. Summary of Methods for Calculating Host Customer Non-Energy Impacts

The advantages and disadvantages of the different methods available to estimate host customer impacts is provided in Table 63.

Table 63. Advantages and disadvantages of methods for estimating host customer non-energy impacts

6.2.3. Resources for Calculating Host Customer NEIs

Lawrence Berkeley National Laboratory. 2020. (LBNL 2020 NEI). Applying Non-Energy Impacts from Other Jurisdictions in Cost-Benefit Analyses of Energy Efficiency Programs: Resources for States for Utility Customer-Funding Programs. Sutter, Mitchell-Jackson, Schiller, Schwartz, and Hoffman. https://naseo.org/Data/Sites/1/media/documents/topics/nei_report_20200414_final.pdf

Malmgren and Skumatz. 2014. Lessons from the Field: Practical Applications for Incorporating Non-Energy Benefits into Cost-Effectiveness Screening. www.aceee.org/files/proceedings/‌2014/data/papers/8-357.pdf

Murphy, L., and L. Pelchen. 2021. “Solar Tax Credit 2021 By State: What You Need to Know.” Forbes, Sep 27, 2021, www.forbes.com/advisor/home-improvement/solar-tax-credit-by-state/.

National Energy Screening Project. Updated 2021. (NESP 2021 DSP). Database of State Efficiency Screening Practices. www.nationalenergyscreeningproject.org/state-database-dsp/.

National Renewable Energy Laboratory. 2021. (NREL 2021). U.S. Solar Photovoltaic System and Energy Storage Cost Benchmark: Q1 2020. D.Feldman, V. Ramasamy, R. Fu, A. Ramdas, J. Desai, and R. Margolis. www.nrel.gov/docs/fy21osti/77324.pdf.

NMR Group. 2020. (NMR 2020 DCSEU). Performance Benchmark Assessment of FY2019 DC Sustainable Energy Utility Programs. https://doee.dc.gov/sites/default/files/dc/sites/ddoe/publication/attachments/DCSEU%20FY2019%20Performance%20Benchmarks%20Report%20-%20FINAL%2006012020%29%281%29.pdf

Northeast Energy Efficiency Partnerships. 2017. (NEEP 2017). Non-Energy Impacts Approaches and Values: An Examination of the Northeast, Mid-Atlantic, and Beyond. June. https://neep.org/sites/default/files/resources/NEI%20Final%20Report%20for%20NH%206.2.17.pdf

Pacific Northwest National Laboratory. 2019. (PNNL 2019). Energy Storage Technology and Cost Characterization Report. U.S. Department of Energy HydroWires Initiative. K. Mongird, V. Fotedar, V. Viswanathan, V. Koritarov, P. Balducci, B. Hadjerioua, J. Alam. PNNL-28866. energystorage.pnnl.gov/pdf/PNNL-28866.pdf.

Pray, Richard (editor). 2021. 2022 National Construction Estimator, Craftsman Book Company.

Skumatz, L. D. D’Souza, M. Santulli, M. Podolefsky, J. Minor-Baetens. 2019. Non-Energy Benefits and Non-Energy Impact (NEB/NEI) Study for the California Energy Savings Assistance (ESA) Program. Prepared by Skumatz Economic Research Associates and Navigant. https://pda.energydataweb.com/api/view/2289/ESA%20NEB%20Study%20Draft%20Report%20Volume1.pdf

Tetra Tech, NMR Group. 2011. Massachusetts Special and Cross-Sector Studies Area, Residential and Low-Income Non-Energy Impacts (NEI) Evaluation. Prepared for the Massachusetts Program Administrators. https://ma-eeac.org/wp-content/uploads/Residential-and-Low-Income-Non-Energy-Impacts-Evaluation-1.pdf

Three Cubed. 2020. Non-Energy Impact (NEI) Analysis for Xcel Energy’s Low-Income Programs. B. Hawkins, B. Tonn, M. Marincic, E. Rose. Prepared for Xcel Energy and Energy CENTS Coalition. http://www.threecubed.org/uploads/2/9/1/9/29191267/non-energy_impacts__nei__analysis_for_xcel_energys_low-income_programs.pdf

U.S. Energy Information Administration. 2018. (U.S. EIA 2018). Updated Buildings Sector Appliance and Equipment Costs and Efficiencies. www.eia.gov/analysis/studies/buildings/equipcosts/pdf/full.pdf

¹³ Many factors can influence the final monetary benefit of a tax incentive, including but not limited to individual or corporate tax liability, federal/state tax interplay, and refundable and non-refundable incentives. Program administrators may have to make some simplifying assumptions to capture the most likely final tax benefits to host customers.

¹⁴ It is sometimes argued that, from a societal perspective, the benefit of the tax incentive is exactly offset by the cost to the taxpayers for the incentive, and therefore neither should be included in the BCA. While it is true that this benefit to the host customer is equal to the cost to the taxpayers, that does not mean that the tax incentive should be netted out against the cost. The tax incentive itself was clearly motivated by the policy goal of promoting the DER. If a jurisdiction shares that policy goal, then the tax incentive can be included in the BCA as a benefit to host customers. Otherwise, netting out this benefit will defeat the policy goal underlying the tax incentive.

¹⁵ Host customer bill savings are driven by the rates that the customer pays for generation, transmission, and distribution, which are typically based on historical embedded costs. Utility system benefits are based on future, incremental generation, transmission, and distribution costs. While embedded costs can be very different from incremental costs, there is nonetheless considerable overlap between the two.