The cost and benefits of energy efficiency are estimated by measure. The analysis attempts to include all quantifiable costs of energy efficiency measures including capital costs, labor and markup, finance costs, maintenance, operations-fuel, non-energy consumables, other quantifiable non-energy costs, and program administrative costs. The net cost is the total cost of the measure less any non-electric impacts. Costs represent an increase in the required financial commitment relative to the baseline and are expressed as positive incremental effects. Benefits represent a reduction in the required financial commitment and are expressed as negative incremental effects.
Costs and non-electric impacts are tallied regardless of which sponsors incurs these costs or accrues the benefits. The details of the inputs are provided here. The following section provides an overview of the calculation methodology and ProCost, the tool used by the Council to estimate NRC net levelized cost.
Calculating Net Levelized Cost
The Council uses a levelized cost to compare energy efficiency resources to supply resources. The levelized cost components described below reflect those used as inputs into the resource analysis. Once the plan’s energy efficiency target is determined, there is a cost-effectiveness methodology that allows stakeholders to determine if a measure is cost-effective relative to the plan findings.
There are many definitions of levelized cost depending on what components are included. The Council uses a Northwest total Resource net levelized Cost (NRC net levelized cost) for its analysis of the cost of energy efficiency measures. This includes all the costs and benefits described in the following sections to reflect the full cost of the measures, regardless of who is paying the costs, as consistent with the definition of system cost in the Northwest Power Act (Section 839a(4)(B)). ProCost is the tool the Council uses to calculate the NRC net levelized cost for energy efficiency measures. Note: the Council formerly used the term “total resource cost (TRC)” instead of NRC, and updated to avoid confusion with other usages of TRC that are not consistent with the Act.
The primary components of the NRC net levelized cost are the net present value (NPV) of the measure costs divided by the annual savings of the measure. Economic costs and benefits are converted to present-value costs and benefits based the financing costs, sponsor cost shares, and discount rates. ProCost uses standard capital recovery factors and present value (PV) factors to calculate PV costs and benefits. Finance costs use sponsor-specific interest rates and terms as assigned by user input to calculate PV of capital costs of measures. Annual costs and benefits that are not financed are counted in the years they occur and discounted to present values using standard present value factors and the global discount rate of 3.75 percent used in all analysis for the 2021 Plan.
ProCost sums all the present value costs and nets out benefits. This net present value is then amortized over the life of the program (20 years) using standard capital recovery factors and the discount rate. The resulting annual “levelized” cost is divided by the discounted annual energy savings adjusted for transmission and distribution line losses to produce a levelized cost per unit energy saved in dollars per kWh.
The NRC net levelized costs are all costs minus all benefits regardless of which sponsor incurs the cost or accrues the benefits. In addition to energy system costs and benefits, NRC net levelized cost includes non-energy, program administration, other-fuel, O&M, periodic-replacement benefits and costs. The ten percent Regional Act Credit is taken into consideration in the Regional Portfolio Model and thus not included in the NRC net levelized costs used in the supply curve inputs. The costs and benefits included in the 2021 Power Plan are summarized in the table below.
NRC Net Levelized Cost Components
|Costs Included||Benefits Netted Out|
|Capital & Labor||Regional Act Credit*|
|Annual O&M||Annual O&M|
|Program Administration||Deferred Resource Investment**|
|Periodic Replacement||Avoided Periodic Replacement|
|Other Fuel Costs||Other Fuel Benefits|
|Non-Energy Impacts||Non-Energy Impacts|
|Deferred T&D Expansion|
*The 10 percent advantage for energy efficiency in the Northwest Power Act is accounted for when comparing energy efficiency and other resources in the RPM rather than in the levelized cost of energy efficiency.
** The value of deferred resource is determined as part of the RPM analysis and is not included as part of the levelized cost input to the RPM analysis.
While not all of these costs and benefits are paid by or accrue to the region’s power system, the Northwest resource cost perspective is used because all costs must be included in resource comparisons and because, ultimately, it is the region’s consumers who pay the costs and receive the benefits. For some measures, NRC net levelized cost is less than zero because electric plus non-electric benefits exceed cost. In addition, the Council’s analysis assumes energy efficiency measures comply with environmental regulations and thus incorporate any cost associated with compliance. All costs are assumed to be nominally constant – meaning, the levelized cost is assumed to remain the same throughout the plan horizon.
The present value cost of energy efficiency is determined in part by who pays for it and how it is financed. The Conservation Resources Advisory Committee (CRAC) was asked to provide recommendations on the anticipated “cost-sharing” between utilities and consumers. Staff also developed estimates of the cost of capital and equity used to pay for energy efficiency based on the mix of consumers in each of the major sectors. These cost shares and finance costs are applied to each cost source for each measure at the time they are incurred.
The table below shows the financial assumptions used in the economic analysis of energy efficiency opportunities in each of the four major economic sectors. The table also provides the utility financial assumptions, where the portion of the initial capital cost is shared between the customer, the wholesale electric provider, the retail electric provider, and the natural gas utility. The Council assumes the natural gas utility will not bear any portion of the cost but is included for completeness. The analysis assumes that end use customers directly pay 50 percent of measure capital cost and all of measure operational and maintenance costs. The cost of capital varies for among residential, commercial, and industrial customers. Financial life is the term over which a sponsor’s share of capital cost is financed. A financial life of one year indicates that portion is expensed, rather than financed. The 2021 Plan assumed the portion of capital cost paid by Bonneville, the wholesale utility, as well as retail utilities do not finance energy efficiency investments, but expense them each year.
A separate Table is provided for the Utility System, where the customer shares are zero.
Energy Efficiency Financial Input Assumptions
|Real After-Tax Cost of Capital|
|Financial Life (years)||12||1||1||1|
|Sponsor Share of Initial Capital Cost||50%||35%||15%||0%|
|Sponsor Share of Annual O&M||100%||0%||0%||0%|
|Sponsor Share of Periodic Replacement Cost||100%||0%||0%||0%|
|Sponsor Share of Administrative Cost||0%||30%||70%||0%|
|Last Year of Non-Customer O&M & Period Replacement||20|
Utility System Financial Input Assumptions
|Real After-Tax Cost of Capital|
|Financial Life (years)||12||1||1||1|
|Sponsor Share of Initial Capital Cost||0%||30%||70%||0%|
|Sponsor Share of Annual O&M||0%||30%||70%||0%|
|Sponsor Share of Periodic Replacement Cost||0%||30%||70%||0%|
|Sponsor Share of Administrative Cost||0%||30%||70%||0%|
|Last Year of Non-Customer O&M & Period Replacement||20|
In addition, this analysis uses a discount rate of 3.75 percent, consistent with all the other resources analyzed in the Plan.
The cost of energy efficiency is based on the incremental cost of the measure compared to the baseline case. The Council also includes a programmatic administration cost, approximated at 20 percent of the incremental cost. In addition to those up-front costs, a measure may have on-going operation and maintenance (O&M) costs (or benefits) compared to the baseline. For example, a heat pump water heater has maintenance costs to clean filters and discharge condensate compared to an electric resistance water heater. The incremental capital and O&M costs are all assumed to be nominally constant throughout the planning horizon.
There may also be periodic replacement costs (or benefits) compared to the baseline. An example of the periodic replacement cost is the replacement of a system component that was not present in the baseline system, like a compressor in a heat pump heating system that replaces an electric baseboard heating system. There may also be other fuel costs, such as additional gas heating required when high-efficiency lighting (that produces less waste heat) is installed. Finally, other quantifiable non-energy costs are also included in the cost calculation if they can be sufficiently quantified. For example, an evaporative cooler might require significant water consumption and associated water costs compared to a vapor-compression system.
Benefits of Energy Efficiency
In addition to the energy saved by energy efficiency, there are several benefits that reduce the cost of energy efficiency. These contributors include: deferred transmission and distribution (T&D) capacity expansion, deferred generation capacity investment, avoided periodic replacement, other fuel benefits, value of non-power system impacts (also referred to as non-energy benefits), and the regional Act credit.
The deferred T&D capacity is estimated from the contribution of energy efficiency on winter peak loads, defined as the average over the hours 7 through 9 am on a weekday in January and February or, for the summer season, as the average over the hours 4 through 6 pm on a weekday in July and August. By reducing the peak load with efficiency, ongoing upgrades or expansions to the T&D system and associated costs are deferred. The Council used data from five transmission utilities and four distribution utilities to estimate this value: $3.08/kW-yr for deferred transmission and $6.85/kW-year for deferred distribution (both in 2016$). These inputs and methodology to calculate are described here. The Council recognizes that potential transmission and distribution systems cost savings are dependent upon local conditions.
There are two types of losses on the transmission and distribution system. The first are no-load/core losses, or the losses that are incurred just to energize the system – to create a voltage available to serve a load. Nearly all of these occur in step-up and step-down transformers. The second are resistive losses, which are caused by friction released as heat as electrons move on increasingly crowded lines and transformers. Typically, about 25 percent of the average annual losses are no-load or core losses, and about 75 percent are resistive losses.
Losses increase significantly during peak periods. ProCost uses the formula for the resistive losses, I2R, where “I” is the amperage (current) on any particular transformer or distribution line, and “R” is the resistance of the wires through which that current flows. While the “R” is generally constant through the year, since utilities use the same wires and transformers all year long, the “I” is directly a function of the demand that customers place on the utility. Thus, resistive losses increase with the square of the current, meaning losses increase as load increases. Depending on the system load shape, the percentage of generation that is “lost” before it reaches loads is typically at least twice as high as the average annual losses on the system. During the highest critical peak hours (perhaps 5-25 hours per year) when the system is under stress, the losses may be four to six times higher than the average.
ProCost uses the system load shape and the energy efficiency measure load shape to calculate the impact of the measure on system losses, accounting for both the core and resistive losses.
Energy efficiency measures also have a deferred resource value, though the economic value of this is derived from analysis of resource strategies in the Regional Portfolio Model rather than fixed as an input. As such, the economic value of a deferred resource was set to zero for the RPM inputs. Instead, the derived economic value of a deferred resource (e.g., deferred generation capacity) is captured in the determination of the plan energy efficiency goals and for setting cost-effectiveness levels for energy efficiency measures and programs. Note that in the Seventh Power Plan, the modeling results showed a clear benefit to EE for deferring a peak capacity resource, while in the 2021 Plan the benefit is needed during the morning and evening ramping periods, so a different deferred resource is valued. The measure cost-effectiveness methodology provides further description.
The other benefits of energy efficiency included in the levelized cost calculation include the periodic replacement, other fuel, and quantifiable non-power system impacts. An example of the periodic replacement benefit is a high-efficiency LED light bulb that has a significantly longer life than a baseline halogen bulb. As such, by installing an LED that has a 12-year measure life, the user avoids replacing the halogen bulb five times (every two years).
The other fuel benefits are savings in natural gas or heating oil from, for example, increased insulation levels. The homeowner who has air conditioning and a gas furnace will save electricity in reduced cooling usage as well as saving gas from reduced heating usage by adding ceiling insulation.
In addition, the Council includes the value of quantifiable non-power system impacts. For example, by installing an efficient clothes washer, the homeowner will use less water than the baseline. The value of this water reduction is included as a benefit in the net levelized cost calculation.
Finally, the Northwest Power Act directs the Council and Bonneville to give conservation (energy efficiency) a 10 percent cost advantage over sources of electric generation. The Council does this by calculating the Act credit as 10 percent of the value of energy saved at wholesale market prices, plus ten percent of the value of savings from deferring electric transmission and distribution system expansion, deferred generation capacity investment, and risk avoidance. This credit is applied in the resource strategy analysis and is thus not included in the NRC net levelized cost input data.
There may be other measure benefits or costs that are not quantified in this analysis. The Council's methodology for determining quantifiable environmental costs and benefits outlines the approach taken to determine if a particular non-energy cost or benefit is included in the analysis. As further described here, care is taken to ensure costs and benefits are applied symmetrically across all resources.
Value of Energy Efficiency with Respect to Time
The energy saved from energy efficiency is generally not constant across every hour of the year. For example, efficient street lighting only saves energy from dusk-to-dawn, the hours of which vary over the year. The figure below shows typical daily savings profile for measures that improve the efficiency of space heating, water heating, and central air conditioning in a typical Northwest home. The vertical axis indicates the ratio (expressed as a percent) of each hour’s electric demand to the maximum demand for that end use during over the course of the entire day. The horizontal axis shows the hour of the day, with hour “1” representing midnight to 1 am.
Illustrative Hour Load Profile for Three Residential End Uses
As can be seen from inspecting the figure above, water heating savings increase in the morning when occupants rise to bathe and cook breakfast, then drop while they are away at work and rise again during the evening. Space heating savings also exhibit this “double-hump” pattern. In contrast, central air conditioning savings increase quickly beginning in the early afternoon as the outside temperature rises, peaking in late afternoon and decline again as the evening progresses and outside temperatures drop. Measure savings can also vary seasonally and by day of the week. As the price of electricity varies by day and by season, the value of the energy efficiency will also vary, depending on its savings shape.
The shape of the savings for the complete set of energy efficiency measures in the supply curve during heavy and light load hours is shown below. Heavy load hours are defined as hours ending 7 pm through 10 pm on weekdays; light load hours are all others. Because light load hours are a high portion of the total hours, the portion of savings is much greater during those times. As is shown, the energy savings are greater during the winter season than summer, in large part due to significant savings from conversion of electric resistance heating to more efficient heat pump technologies and increased use of lighting during the winter period.
Monthly Savings Shape for All Measures during Heavy and Light Load Hours
In addition to the shape by season, the energy efficiency also saves during peak times. Winter peak hours occur from 7to 9 am on a weekday in January or February. Summer peak hours occur from 4 to 6 pm on a weekday in July or August. The peak capacity factor was, in aggregate, around 1.8 in summer and around 1.7 in winter, indicating that energy efficiency measures have a significant impact on peak loads. Of course, each individual energy efficiency measure analyzed has a unique shape, which will affect its value as a resource option and on measure cost-effectiveness. The variance by bin is provided in the Table below, for context; the hourly shape for energy efficiency is provided to GENESYS and is used to calculate the associated system capacity contribution which is how RPM identifies a resource’s ability to meet capacity needs.
Peak to Energy Impact of Measures by Levelized Cost Bin.