What is beneficial electrification?

Electrification, or the increased adoption of electric end-use technologies, isn’t a new trend, but the idea is undergoing a renaissance. This time around, the focus has significant though nuanced differences from prior waves of electrification. Each wave has been influential on our culture, economy, comfort, and health, and this fourth wave promises to be no different. The first was the lighting wave, when electricity brought new, clean, and safe lighting to households and businesses. The second was the automation wave during the mid-1900s, when convenience appliances spread like wildfire. Washing machines, TVs, refrigerators, air-conditioning, and all kinds of kitchen gadgets proliferated and industries automated their operations, delivering benefits to households and businesses. Next came the digital wave, starting with computers and then expanding to entertainment, smartphones and other personal devices, Wi-Fi and the web—the list goes on and on, and this wave continues today.

Now we’re entering the fourth wave of electrification, with a focus on reducing the environmental harm we caused through the first three waves. In this fourth wave, we’re also moving electrification into the transportation sector, shifting focus to the reduction of fossil-based transportation fuel. We have an opportunity to make the fourth wave as important as the prior waves, but we need to move quickly and frame our decisions in a manner that will help everyone, while ensuring that businesses, including energy utilities, remain viable and profitable.

Utilities, governments, and other stakeholders view electrification as a means to pursue broader energy, climate, and sustainability goals.

After experiencing rapid growth throughout the 1900s, electricity loads began to taper off and flatten. In recent decades, many states and utilities have instituted revenue decoupling, in which the volume of electricity sales is separated from investor-owned utilities’ (IOUs’) profits. These utilities have had little motivation to increase sales and aren’t hurt when sales decline. Other states and utilities remained in regulatory frameworks whereby increasing sales resulted in greater profits, and their motivations often conflicted with those of environmental intervenors. Overall, nationwide electricity growth has been meager over the past decade.

Today, utilities, governments, and other stakeholders view electrification as a means to pursue broader energy, climate, and sustainability goals. Initiatives that focus on decarbonization or greenhouse gas (GHG) mitigation; electric grid modernization and optimization; and social and environmental equity all call for an increase in electrification as an important strategic element. In this context, practitioners often use the term beneficial electrification. This distinction underscores the ultimate goals of beneficial electrification: to improve social and environmental outcomes for as much of population as possible. This includes:

  • Reduce the costs of energy
  • Reduce GHG emissions and air-quality impacts
  • Improve comfort, convenience, and productivity
  • Manage the electric grid efficiently

Key sectors and applications for beneficial electrification

Modern energy utilities are in a unique position to drive beneficial electrification forward because of their influence over energy supply choices and grid infrastructure, access to customer-funded capital, and decades of experience designing and delivering demand-side management (DSM) programs. Each of these applications, which we detail in this white paper, presents an important area of focus for current or soon-to-be administrators of beneficial-electrification programs:

  • Residential and commercial buildings. Heat pumps, water heaters, and battery storage systems are examples of electrified technologies in residential and commercial buildings. Utilities already have extensive experience with these technologies because they’re common targets for DSM programs.
  • Transportation. Personal vehicles, public transportation, school buses, shipping or freight vehicles, trains, and service or fleet vehicles are just a few applications that can contribute to transportation-electrification efforts. Utilities have a huge stake in ensuring that electric vehicles (EVs) are applied to the grid in ways that keep system costs as low as possible.
  • Industrial processes and material-handling equipment. Industrial process applications often use natural gas or other fossil fuels, so they’re logical targets for electrification. Material-handling equipment such as cranes, forklifts, port equipment, mining equipment, and airport ground-support equipment also hold significant potential for electrification.

Beneficial electrification and DSM

At E Source, we approach beneficial electrification with deep-seated expertise developed over decades of advising clients on DSM programs, technologies, and customer experience. While beneficial in their own right, successful DSM programs also lay an important foundation for the deployment of beneficial-electrification initiatives.

There are few regulatory environments that mandate beneficial electrification in the same way that they mandate DSM.

DSM programs focus on reducing energy bills for consumers and businesses while also lessening environmental impacts and improving the overall resilience of electricity and natural gas distribution systems. In doing so, utilities and other program administrators have developed important expertise across key programmatic elements—including program design and delivery, measurement and evaluation, technology deployment, market research, marketing, and regulatory procedures—that will prove valuable for beneficial-electrification initiatives. This strong foundation, and the ongoing interaction between DSM and beneficial electrification, can help utilities meet their goals around energy savings, GHG emissions reductions, customer satisfaction, and profitability.

It’s also important to consider the differences between DSM programs and beneficial electrification. Understanding the improvements we can make—and when to make them—will help administrators maximize the benefits associated with their electrification programs. There are few regulatory environments that mandate beneficial electrification in the same way that they mandate DSM. In addition, many IOUs have additional shareholder incentives or earnings adjustment mechanisms for their DSM portfolios; they have yet to apply those mechanisms to beneficial-electrification initiatives. We anticipate that electrification programs will quickly grow in importance; following DSM’s lead will help drive that growth.

What are the goals of beneficial electrification?

To date, most beneficial-electrification initiatives don’t claim electrification as the goal. So what exactly are they trying to achieve?

Decarbonizing and improving environments. When paired with low- or zero-carbon electricity generation, beneficial electrification can be an important way to meet carbon-and GHG-reduction goals. The strategy is simple: Electrify end-use technologies and, at the same time, shrink the carbon intensity of the energy supply. More end-use technologies drawing from a cleaner energy grid lead to reductions in carbon dioxide and other GHGs. Reduced emissions from both the power and transportation sectors also improve local air quality in urban or industrialized zones, leading to improved health outcomes for populations that live or work in these areas.

Reducing electric rates and optimizing the grid. Certain electrified technologies, like water heaters and EVs, can help optimize the operation of the electric grid, particularly as more renewable sources come online. These technologies have the added functionality of storing or dispatching energy, so they can serve as flexible grid assets. This enables the storage of electricity while it’s abundant, clean, and cheap to consume, while minimizing the effect of peak demand on the system. The result is increased utilization of the grid, improved load factors, and a reduction of electricity rates for all customers, not just those who adopt new technologies.

Reducing overall energy costs. Beneficial-electrification initiatives can also focus on reducing overall costs to power a customer action. For example, an efficient heat pump could provide heating at a lower overall cost to a dwelling or business compared to its natural gas or electric resistance heating counterpart. Or the cost to drive a mile in an EV might be less than half that of a mile driven in a gasoline-powered vehicle.

It’s important to use precise terminology when describing the aspects of beneficial electrification. We’ve created a straightforward lexicon and framework that explains the constituent parts of beneficial electrification and how their interactions may inform your policy goals:

  • Environmentally beneficial electrification. Defined as moving an end use from a nonelectric fuel to electrification that results in an environmentally superior outcome regardless of cost. You’ll need to decide what “environmentally superior outcome” means for your jurisdiction, but most outcomes focus on carbon reduction.
  • Grid-efficient electrification. Defined as any electrification of end-use applications that lowers electricity rates for all customers by boosting grid efficiency compared to what would have happened in the absence of that electrification. Note that electrification can easily fail on this goal if it contributes to peak demand.
  • Economically efficient electrification. Defined as any electrification in which the consumer sees an equivalent or better end-use result for lower overall costs (without cross subsidies).

Electrification initiatives that focus on revenue generation—growing electric load primarily to improve profitability—miss the mark on meeting these objectives. This narrow focus ignores the most important goals of beneficial electrification and has the potential to put upward pressure on rates, customer bills, and GHG emissions. When beneficial electrification is done in the absence of strategy or equity, there are few winners.

The beneficial-electrification framework

Equipped with a definition for beneficial electrification and set of parameters that identifies what we’re trying to achieve, we can now start to develop the utility beneficial-electrification framework (figure 1). In this section, we dive deeper into the main drivers supporting widespread beneficial electrification, which include decarbonization and grid optimization.

Figure 1: The E Source beneficial electrification framework

This framework illustrates how beneficial electrification can help utilities reduce carbon, lower rates, and produce bill savings.
Venn diagram (copyright E Source) showing that where grid-efficient electrification intersects with economically efficient electrification, you get lower rates and lower bills; where economically efficient electrification intersects with environmentally beneficial electrification, you get less carbon and lower bills; where environmentally beneficial electrification intersects with grid-efficient electrification, you get less carbon and lower rates for nonparticipants; where all three intersect, carbon, rates, and bills are all reduced.

Environmentally beneficial electrification

To date, decarbonization has been the single greatest driver for beneficial-electrification initiatives and best represents environmentally beneficial electrification. States, provinces, cities, and even private companies continue to set carbon- and GHG-reduction goals. During an informal poll at the 2018 E Source Forum, many of our utility members told us that the greatest external driver for beneficial electrification is state and local climate action plans; internally, the greatest driver is load building and revenue generation, followed by carbon reduction (figure 2). Check out the E Source infographic Strategic Electrification: Insights to Spark Your Interests for more data from our members.

Figure 2: Drivers of strategic electrification

None of the utilities represented in our poll cited safety or air-quality regulations as an external driver of their interest in electrification. As for internal drivers, no utilities cited a legislative or policy directive.

External drivers

Bar chart (base of 54 participants at the 2018 E Source Forum; copyright E Source) showing that 63% of respondents said state or local climate action plans was the key external behind their interest in strategic electrification; 17% cited customer preference; 6% cited advocacy groups; 0% cited safety; 0% cited air-quality regulations; 13% said theye had no external driver.

Internal drivers

Bar chart (base of 52 participants at the 2018 E Source Forum; copyright E Source) showing that 35% of respondents said load building was the key internal behind their interest in strategic electrification; 29% cited revenue generation; 21% cited carbon reductions; 13% cited flexible load and grid management; 0% cited a legislative or policy directive.

The Fourth National Climate Assessment (PDF) from the US Global Change Research Program provides a snapshot of current emissions-reduction efforts across the country. It estimates that at least 455 US cities support emissions reductions and 110 US cities have emissions-reduction targets (figure 3).

Figure 3: US emissions-reduction efforts

This US Global Change Research Program map shows the number of state-level climate-mitigation activities as well as cities that are supporting emissions reductions.
Map from the US Global Change Research Program that shows total number of state-level mitigation-related activities (out of 30) by state as well as individual cities that have emissions-reduction plans. Read the Global Change Research Program report for more details.

As a result of this nationwide support, energy utilities have been forced to respond. The Smart Electric Power Alliance’s Utility Carbon Reduction Tracker identifies 44 utilities with emissions-reduction, carbon-reduction, or renewable-energy goals. These commitments underscore the relationship between legislators and energy utilities, described in the Utility Dive article PNM, Avista Commit to Carbon-Free Goals on Heels of State Mandates, with each side acting as a catalyst for decarbonization and GHG mitigation efforts. Moreover, as utilities have set these goals, they’ve identified beneficial electrification as one of the primary mechanisms they’ll use to achieve them.

It’s also important to consider that electricity generation from renewable-energy sources accounts for just 17% of the overall US electricity generation, according to the US Energy Information Administration’s (EIA’s) Short-Term Energy Outlook. That number falls to an unimpressive 10% when the analysis excludes hydro. But the future looks bright for renewables—in its Annual Energy Outlook 2019 (PDF), the EIA predicts that renewables will account for 31% of total US electricity generation by 2050. But it also expects natural gas to continue contributing the largest share of electricity generation in the US, growing to 39% by 2050 (figure 4).

Figure 4: US electricity generation forecast

By 2050, the EIA is forecasting a slight increase in the percentage of the fuel mix comprised of natural gas (from 34% to 39%) and a larger increase in renewables (from 18% to 31%). What this chart doesn’t take into account is the vast number of utilities setting carbon-free goals by 2050 or sooner, and how this will affect the percentage of renewables.
Two area charts from the US Energy Information Administration's 2019 Annual Energy Outlook. The left-hand chart shows electricity generation from selected fuels (reference case). From 2018 to 2050, the administration expects the percentage of electricity generated by natural gas to increase from 34% to 39%; the percentage of renewables to increase from 18% to 31%; the percentage of nuclear to decrease from 19% to 12%; and the percentage of coal to decrease from 28% to 17%. The right-hand chart shows renewable electricity generation, including end use (reference case). From 2018 to 2050, the administration expects the percentage of renewable electricity generated by solar to increase from 13% to 48%; the percentage of wind to decrease from 37% to 25%; the percentage of gerothermal to increase from 2% to 4%; the percentage of hydro to decrease from 39% to 18%; and the percentage of other to decrease from 9% to 5%.

With natural gas projected to generate the greatest share of electricity in the US by 2050, it’s easy to question the near-term decarbonization potential of beneficial electrification. The theoretical calculus behind it—increase electric end-use technologies while adding clean or low-carbon generation—seemingly falls flat without a majority share of renewable-energy sources to power us toward a decarbonized future. The reality, however, demonstrates just how important it is to think about energy consumption and emissions efficiency in broader, more-systemic terms. To achieve carbon reductions through beneficial electrification, you must evaluate it across the entire spectrum of the energy-supply mix to determine which beneficial-electrification programs and strategies best suit your service territory. It’s also imperative that beneficial-electrification efforts coincide with continued renewable-energy growth so we can truly improve emissions efficiency for electricity generation.

Grid-efficient electrification

Electrified end-use technologies such as EVs, water heaters, and even smart thermostats can help utilities and grid operators optimize the use of the electric grid. As another primary driver for increased beneficial electrification, grid-enabled electric technologies have the added capability of serving as flexible grid assets, allowing grid operators and consumers to manage electric load strategically with system peaks, energy supply costs, and emissions efficiency in mind. They can store energy when renewables are abundant (and cheap), like overnight wind and afternoon solar, and dispatch it during times of higher demand.

Electrified end-use technologies such as EVs, water heaters, and even smart thermostats can help utilities and grid operators optimize the use of the electric grid.

Flexible load management with grid-connected devices can also help incorporate clean- and renewable-energy sources and address concerns around their intermittency. With the growing penetration of renewable sources like wind and solar, grid operators have become increasingly aware of their impacts on load shape during specific times of day and year. The concept of net load—the amount of electric load on the grid minus the amount of renewable-energy sources—presents specific challenges to grid operators: overgeneration and ramping, or the need to ramp up conventional supply-side resources as the share of renewable resources subsides. Read more about these intermittency issues in the RAP report Teaching the “Duck” to Fly (PDF).

Figure 5 illustrates the risk of overgeneration during the middle hours of the day when renewable-energy sources are heavily integrated into the resource mix and the resulting net load is low. Then later in the afternoon, the share of renewable resources subsides, forcing grid operators to ramp up conventional resources. This phenomenon, known as the duck curve because of its fowl-shaped silhouette, is of greatest concern for jurisdictions with already-high penetration of solar.

Figure 5: The risks of overgeneration and ramping up

In the morning and afternoon, when solar energy supply is low, conventional resources must quickly ramp down and up to meet load needs, creating operational concerns for utilities.
Chart from the Regulatory Assistance Project showing an example daily load in 2020, with one line for total load and another for load net of wind and solar. The two lines are similar until the middle of the day when there are a lot of renewables available but demand is lower. For details on this duck curve illustration, read the Regulatory Assistance Project report.

In 2013, the California Independent System Operator (CAISO) published its first duck curve, showing a significant drop in midday net load on a typical spring day as the supply of renewable energy increased. This chart has become seminal in discussions about the large-scale deployment of renewable energy in North America. Read the CAISO fact sheet What the Duck Curve Tells Us About Managing a Green Grid (PDF) for more on net load.

Certain grid-enabled beneficial-electrification technologies, like EVs and water heaters, can help mitigate overgeneration and ramping concerns by storing energy when it’s abundant to dispatch during the ramping period later in the day. As one example, the E Source white paper Battery Killers: How Water Heaters Have Evolved into Grid-Scale Energy-Storage Devices describes the benefits associated with grid-interactive water heaters, including intelligent load shifting and traditional demand response.

Adding significant amounts of electrified end-use technologies, and thereby boosting demand, will require significant investment in low- or no-carbon generation and the necessary transmission and distribution infrastructure. To underscore this need, the 2019 Brattle Group report The Coming Electrification of the North American Economy: Why We Need a Robust Transmission Grid (PDF) estimates that by 2030, electrification could increase nationwide US annual energy demand by 5% to 15% (200 to 600 terawatt-hours [TWh]) and by 25% to 85% (1,100 to 3,700 TWh) by 2050 (figure 6).

Figure 6: Projected electrification adoption rates and incremental annual energy demand for two electrification scenarios

Widespread electrification adoption across the residential, commercial, industrial, agriculture, and transportation sectors will lead to significant increases in energy demand. According to the Brattle Group report, “[70 to 200 gigawatts] of new electric generation will be needed to meet the estimated demand growth.”
Two charts from the Brattle Group report that show electrification adoption and electrification energy demand for 2030 and 2050 in both a base case and a high case for three sectors: industrial/agriculture, residential/commercial, and transportation. Even in the base case, demand from all sectors is expected to increase substantially with the adoption of electrification. For specific data, read the Brattle Group report.

Perhaps more important, the report also finds that US utilities will need to make $30 to $90 billion in incremental transmission investments by 2030, with an additional $200 to $600 billion needed from 2030 to 2050. While these investments are significant, additional research by the Brattle Group suggests their overall impact on customer rates will be minimal and perhaps even beneficial. Altogether, the relationship between beneficial electrification and grid optimization mirrors the decarbonization model. Both require planners and policy-makers to anticipate the effects of electrification on the grid as well as the necessary infrastructure to support it.

Economically efficient electrification

Economically efficient electrification highlights the overall economic benefits or costs that might occur from a shift to electrification. Goals might include:

  • Lowering the cost of producing an end-use function such as lighting or driving
  • Increasing the number of jobs or decreasing unemployment
  • Increasing the overall economic efficiency of markets by giving people more disposable income, which creates a multiplier effect

Economic efficiency is an important attribute to consider because money is a key driver of change. Customers cite cost savings as the primary reason for participating in utility programs; however, as we’ve seen in the DSM world, customers don’t always consider life-cycle costs, and up-front capital costs end up being a barrier to adoption. Utilities have a major role to play in offering financing or providing rebates for residential and businesses customers who are interested in electrification.

How to start building your framework

If you’re in the early stages of designing a beneficial-electrification framework, start by engaging with efficiency organizations and utilities in your region to learn about their beneficial-electrification goals. From there, identify stakeholders and additional partners. We’ve highlighted the primary drivers of beneficial-electrification plans, pilots, and eventually programs, but there’s still a lot of work utilities need to do to pave the way for beneficial electrification, including supporting the development of new cost-effectiveness tests and regulatory incentives.

Cost-effectiveness tests for electrification

As previously noted, electrification isn’t inherently beneficial. Therefore, it’s imperative for utilities, regulators, and stakeholders to develop rigorous tools that can assign a value to the benefits—whether environmental, grid-efficient, or economic—and compare them fairly to the costs.

Fortunately, established cost-effectiveness tests used for years in DSM programs offer a template for creating new electrification-specific tests. A well-designed electrification cost-effectiveness test can:

  • Help allocate resources to the most-effective programs and projects
  • Avoid perverse incentives that lead to outcomes in conflict with the policy goals driving electrification
  • Facilitate the creation of effective incentives for utilities and customers alike

The National Standard Practice Manual (NSPM), developed by the National Efficiency Screening Project, provides a helpful framework of universal principles for developing an energy-efficiency resource cost-effectiveness test. According to the NSPM, the universal principals are:

  • Efficiency [or, in our case, electrification] as a Resource. [Energy efficiency] is one of many resources that can be deployed to meet customers’ needs, and therefore should be compared with other energy resources (both supply-side and demand-side) in a consistent and comprehensive manner.
  • Policy Goals. A jurisdiction’s primary cost-effectiveness test should account for its energy and other applicable policy goals and objectives. These goals and objectives may be articulated in legislation, commission orders, regulations, advisory board decisions, guidelines, etc., and are often dynamic and evolving.
  • Hard-to-Quantify Impacts. Cost-effectiveness practices should account for all relevant, substantive impacts (as identified based on policy goals,) even those that are difficult to quantify and monetize. Using best-available information, proxies, alternative thresholds, or qualitative considerations to approximate hard-to-monetize impacts is preferable to assuming those costs and benefits do not exist or have no value.
  • Symmetry. Cost-effectiveness practices should be symmetrical, where both costs and benefits are included for each relevant type of impact.
  • Forward-Looking Analysis. Analysis of the impacts of resource investments should be forward-looking, capturing the difference between costs and benefits that would occur over the life of the subject resources as compared to the costs and benefits that would occur absent the resource investments.
  • Transparency. Cost-effectiveness practices should be completely transparent, and should fully document all relevant inputs, assumptions, methodologies, and results.

What to include in a cost-effectiveness test

We’ve created a list of example costs and benefits for electrification cost-effectiveness tests, modeled after the NSPM’s comparison of costs and benefits for distributed energy resources (DERs). Jurisdictions may include some not listed here and exclude others based on their own policy goals. We also expect the upcoming National Standard Practice Manual for Distributed Energy Resources to include a chapter on electrification, according to the preview table of contents shared in the National Standard Practice Manual for Benefit-Cost Analysis of Distributed Energy Resources: Overview (PDF).


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Example utility system costs

Utility incentives: Performance incentives

Program costs:

  • Measure costs (utility portion)
  • Program and administrative costs
  • Evaluation, measurement, and verification costs

Electric system costs:

  • Increased energy costs
  • Increased generation capacity costs
  • Increased investment in the transmission and distribution system
  • Increased costs to comply with the renewable portfolio standard
  • Wholesale market price impact

Example utility system benefits

Natural gas system avoided costs (for conversions from natural gas to electricity):

  • Avoided energy costs
  • Distribution system impacts
  • Natural gas price suppression

Electric system benefits:

  • Demand-response facilitation
  • Ancillary services provided by installed measure
  • Avoided costs due to load leveling

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Example nonutility costs

Environmental: Increased GHG emissions from additional electric generation

Public: Job losses and economic losses from replaced fuel

Participant:

  • Increased cost of electricity purchased
  • Measure costs (participant portion)

Example nonutility benefits

Environmental: Avoided GHG emissions from displaced fuel

Public:

  • Job creation and economic development from the new measure
  • Air-quality improvements from displaced fuel and related public health savings

Participant:

  • Savings from avoided displaced fuel purchases
  • Lower operations and maintenance costs

A cost-effectiveness test constructed to include the aforementioned elements accomplishes several goals. It:

  • Helps policy-makers determine the value of avoided emissions and other non-energy benefits
  • Supports efforts to reward utilities for developing a low-emissions electric grid
  • Provides incentives for utilities to develop new load in a way that minimizes the need for new investments
  • Demonstrates and quantifies the impacts of beneficial electrification to participants, nonparticipants, and society as a whole

The specific test inputs vary by utility and region, and may even vary based on the location of the measure. Additionally, it’s challenging to quantify some of the inputs and doing so will require stakeholders to compromise on underlying assumptions. Fortunately, research on areas such as load shapes and GHG emissions by a number of research organizations, including the Electric Power Research Institute (EPRI), the Natural Resources Defense Council, the National Renewable Energy Laboratory (NREL), and Lawrence Berkeley National Laboratory have paved the way to start making these estimates.

Your cost-effectiveness test in action

We can illustrate a simplified example of how a test like this could be put into practice, and how it would compare to other tests, by setting up an imaginary program. Let’s assume a dual-fuel utility is planning to promote the sale of 1,000 electric widgets to replace the old, standard fossil-fuel widgets. Figure 7 outlines the details of our widgets and the program. For simplicity, assume all values take into account expected useful life and net present value.

Figure 7: Widget program details

We’ll use these values for our imaginary widgets to run an example cost-effectiveness test.
Table showing inputs for cost-effectiveness testing (copyright E Source). For our example electric widget, here are the inputs we’re using. Measure cost: $1,000 (after rebate); lifetime expected unit maintenance: $50; lifetime cost of fuel to operate (customer): $300; lifetime cost of fuel purchase (utility): $250; expected carbon dioxide emissions: 0.1 tons (based on average load shape and electric grid mix); jobs supported: 1 worth $50,000 per 1,000 units; expected impact on energy price: negligible impact on wholesale prices; expected impact on generation capacity or transmission: none, generally runs during off-peak hours; grid upgrade requirements: $40,000 for distribution-level grid upgrades due to measure locations; localized health impacts: negligible; potential for demand response or ancillary service: none. For our example gas widget, the inputs are as follows. Measure cost: $800; lifetime expected unit maintenance: $500; lifetime cost of fuel to operate (customer): $250; lifetime cost of fuel purchase (utility): $200; expected carbon dioxide emissions: 1.5 tons; jobs supported: 2 worth $50,000 per 1,000 units; expected impact on energy price: negligible impact on natural gas prices; expected impact on generation capacity or transmission: not applicable; grid upgrade requirements: none; localized health impacts: $50,000 in medical expenses per 1,000 units due to indoor air-quality impacts; potential for demand response or ancillary service: not applicable. For the overall program, here are the inputs. Administration and evaluation, measurement, and verification costs: $80,000; utility rebates: $100 per unit; jurisdiction value of carbon dioxide: $100 per ton.

With these sample values, we can evaluate the electric widget program using our proposed cost-effectiveness test and the Total Resource Cost test, commonly used for DSM (figure 8).

Figure 8: Cost-effectiveness test results for electric widget program

The electrification widget passes our example electrification test (A), but fails a more traditional Total Resource Cost (TRC) test (B). The TRC test fails to take into account avoided emissions, public health benefits, and net job losses.

A. Example beneficial-electrification test

Table (copyright E Source) showing the results of our beneficial-electrification cost-effectiveness test for our sample electric widget. Benefits are as follows and sum to $1,090,000. Avoided fossil-fuel costs (utility): $200/unit x 1,000 units = $200,000; net avoided emissions: $100/ton x (1.5–0.1 tons) x 1,000 units = $140,000; net customer maintenance savings: $450/unit x 1,000 units = $450,000; customer fossil-fuel savings: $250/unit x 1,000 = $250,000; public health benefits = $50,000. Costs are as follows and sum to $1,020,000. Program administration and EM&V: $80,000; program rebates: $100/unit x 1,000 units = $100,000; electricity purchases (utility): $250/unit x 1,000 units = $250,000; distribution upgrades: $40,000; customer electricity costs: $300/unit x 1,000 units = $300,000; customer net measure cost: $200/per unit x 1,000 units = $200,000; net job loss: $50,000. The ratio is 1.07.

B. Total Resource Cost test

Table (copyright E Source) showing the results of a traditional Total Resource Cost test for our sample electric widget. Benefits are as follows and sum to $900,000. Avoided fossil-fuel costs (utility): $200/unit x 1,000 units = $200,000; net customer maintenance savings: $450/unit x 1,000 units = $450,000; customer fossil-fuel savings: $250/unit x 1,000 = $250,000. Costs are as follows and sum to $970,000. Program administration and EM&V: $80,000; program rebates: $100/unit x 1,000 units = $100,000; electricity purchases (utility): $250/unit x 1,000 units = $250,000; distribution upgrades: $40,000; customer electricity costs: $300/unit x 1,000 units = $300,000; customer net measure cost: $200/per unit x 1,000 units = $200,000. The ratio is 0.92.

As is the case with energy efficiency, having a secondary test for electrification provides decision-makers with additional insights, enabling them to make more-informed decisions. Here are several common cost-effectiveness tests that can help validate your electrification efforts.

Participant cost test (PCT). The PCT compares postincentive benefits and costs to the participant. It includes other program impacts, such as non-energy benefits and other fuel savings, directly related to the participant. When applied to electrification, the PCT could outline whether the participant will come out financially ahead or behind after participating in the program.

Ratepayer Impact Measure (RIM) test. The RIM test compares all program expenditures and revenue impacts to avoided utility costs. It specifically explores how the program affects rates for nonparticipants. Because electrification increases electric revenues, this test could reveal its benefits for electric customers; however, it will also highlight the program’s implications for remaining natural gas customers, who may be forced to shoulder the burden of stranded assets.

Societal cost test. This test identifies societal externalities not captured in other tests and compares them to program administrator and customer incremental costs. It could be used to value these externalities should electrification stakeholders decide to omit them from the primary cost-effectiveness test.

Program administrator cost test (PACT). The PACT focuses on the costs and benefits to the program administrator. When applied to electrification, the PACT could compare the value of grid improvements (such as load leveling and facilitating demand response) to total program costs.

Recent developments

Several states and provinces have beneficial-electrification programs in place, but none have completely implemented a cost-effectiveness system that’s in line with what we’ve outlined. That said, several jurisdictions are taking steps in that direction.

Massachusetts stands out as one example. Its Three-Year Energy Efficiency Plan: 2019–2021 (PDF) allows incentives for strategic electrification that “result in cost-effective reductions in GHG emissions and minimize ratepayer cost.” While the plan doesn’t give specifics about how administrators determine cost-effective reductions, it lays the groundwork for an electrification resource test.

The California Public Utilities Commission requires fuel-switching measures to be part of a broader portfolio that passes both the TRC test and the PACT, but it doesn’t require individual measures or programs to pass those two tests. However, fuel-switching measures must reduce source energy use and GHGs. The commission outlines the details of this arrangement in its Decision Modifying the Energy Efficiency Three-Prong Test Related to Fuel Substitution (PDF), released August 1, 2019.

Regulatory incentives for beneficial electrification

The question of why regulatory incentives will be important for electrification (and maximizing GHG reductions) isn’t too difficult to answer if we look at the history of incentives for DSM programs. They’ve been instrumental to the growth of energy-efficiency and demand-response programs at IOUs over the past 20 years. These incentives were created to encourage utilities to invest significantly more in their DSM programs and to achieve ever-increasing kilowatt-hour (kWh), kilowatt (kW), and therm goals. Regulators tied other metrics to these incentives, such as maximizing the cost-effectiveness of programs, and created increasingly complex evaluation protocols to ensure that the savings and other metrics established by utilities were proven and reliable.

To date, we’ve found fewer than a dozen utilities that have engaged in discussions with regulators and intervenors about shareholder incentives for beneficial electrification. The ACEEE Beneficial Electrification and Energy Efficiency Policy memo (PDF) outlines these discussions. For example, under the New York Reforming the Energy Vision (REV) strategy, most utilities are proposing energy adjustment mechanisms (EAM) that will serve as the foundation for DSM and beneficial-electrification incentives. As discussed in the Synapse Energy Economics report Earnings Adjustment Mechanisms to Support New York REV Goals (PDF), the New York Public Service Commission is expected to issue an order toward the end of 2019 that will provide specifics on these EAMs.

Beneficial electrification has a significant advantage over energy efficiency because it’s more likely to result in rate reductions, and therefore bill reductions, for nonparticipants.

This lack of incentives is in large part due to divergent views among regulators, intervenors, utilities, and other parties involved in designing the incentives, and it’s reminiscent of when utilities first put in place shareholder incentives for DSM. These incentives started with a simple design and gradually grew in complexity over multiple years of program implementation. It’s common for intervenors, regulators, utilities, and others to reach a consensus on DSM incentives in spite of their different objectives, and this will likely be the case for beneficial-electrification incentives as well. However, beneficial electrification has a significant advantage over energy efficiency because it’s more likely to result in rate reductions, and therefore bill reductions, for nonparticipants. The ACEEE policy memo demonstrates the range of incentive designs utilities are considering.

It’s unlikely that incentives will be put in place in many states until utilities have proved the efficacy of their electrification initiatives through results and rigorous evaluation. To prepare for this debate, it’s important to understand the relative costs and benefits of different cost-effectiveness tests, as we discussed in the Cost-effectiveness tests for electrification section.

Convincing regulators to adopt incentives

To persuade regulators to provide shareholder incentives for electrification, it will be imperative to convince them of the value of electrification and explain how such programs will actually yield projected, measurable results. For example, you’ll need proof that an electrification program will yield projected GHG reductions along with lower overall costs of energy services, and regulators must believe that the evaluation protocols will be rigorous enough to verify savings. Utilities must also convince regulators that incentives are necessary for the utility to achieve its goals. Utilities’ arguments for DSM incentives are a good place to start developing the case for beneficial-electrification incentives.

Utilities’ arguments for DSM incentives are a good place to start developing the case for beneficial-electrification incentives.

Like DSM, electrification will require significant, complex market intervention to encourage utility customers to participate on a scale that will yield any value in terms of carbon reduction. This intervention must be laid out in significant detail, including rebate levels, marketing strategies, equipment selection (for example, specific criteria for eligible heat pumps), and interactions with manufacturers. Because of this complexity, utilities can argue that they should be rewarded for the quality, results, and cost-effectiveness of the service delivery that they execute through electrification. 

Opponents to incentives may argue that electric utilities will already be rewarded for pursuing electrification by the potentially substantial increase in kWh sales they may see as a result of electrification. This increase may be seen as obviating the need for an incentive; however, the substantial effort required to deliver a new service may still justify the need for incentives that reward utilities for their efforts. Furthermore, a major and essential benefit of electrification is carbon reduction. Rewarding utilities for maximizing their carbon reductions should clearly align with the goals of regulators and intervenors, and you should focus on this point when creating an electrification business case. Without a strong business case, you’re unlikely to make progress with regulators. As we see from our Utility DER and Electrification Benchmark, many utilities still need to develop their business cases (figure 9).

Figure 9: Utilities with an electrification business case for their regulatory board, council, or board of directors

Of 14 utilities that participated in our benchmark study, half developed a business case for electrification for their regulatory board, council, or board of directors. Those utilities told us that their business cases include cost-effectiveness, environmental benefits, decarbonization, job creation, increased revenue, reduced customer energy bills, air-quality improvements, adherence to the sustainability implementation plan, and strategic energy-efficiency program rebates.
Pie chart (base of 14 utilities; copyright E Source with data from the 2019 Utility DER and Electrification Benchmark) showing that half of surveyed utilities have a business case for electrification for their regulatory board, council, or board of directors, while the other half does not have a business case.

Structuring incentives

We can credit the initially simple design of DSM incentives with their success. These initiatives were originally based on a small number of metrics such as savings, program cost-effectiveness, and net benefits. They often serve as the foundation for shareholder incentives. Over time, utilities included additional metrics in incentive mechanisms. For example, when utilities introduced market-transformation programs to DSM portfolios, regulators rewarded them for promoting new technologies. As these technologies achieved increasingly greater penetration, regulators deemed the markets transformed and terminated the incentives.

Having this flexibility with incentives gave utilities the ability to achieve more-complex and ambitious goals. Flexibility in incentives for electrification would also benefit utilities considerably. Determining exactly how to structure this flexibility will need to wait until utilities experiment with the early stages of their electrification programs. In the early stages, electrification incentives will likely focus on net efficiency gains, cost-effectiveness, and carbon reduction. As programs grow in popularity and magnitude, utilities may begin introducing other metrics (figure 10) such as:

  • Recovery of program costs by including electrification in the rate base
  • Additional profits if rates are reduced by electrification programs; this could include a valley-filling objective, which increases demand at off-peak periods, or an overall load factor improvement objective, which will diminish the average unit cost of the kWh
  • Additional profits for net efficiency gains (for example, reducing the energy needed to complete the same amount of work)
  • Additional profits for boosting the adoption of new technologies, such as EVs
  • Additional profits for meeting environmental goals
  • Performance-based incentives

Figure 10: Electrification incentive maturity

As electrification programs become more widespread, utility incentives can increase in sophistication.
Illustration (copyright E Source) showing a progression of incentive maturity from cost recovery (least sophisticated), net efficiency gains, rate-based expenses, improved grid operation or load factors, hitting carbon-reduction targets, and technology market transformation, to multifactor performance-based incentives (most sophisticated).

Funding your electrification initiative

The two most common methods we’ve seen for funding electrification initiatives are expensing and rate-basing program costs. These are also the methods most frequently used for funding DSM initiatives. Expensing involves placing a surcharge on each unit of energy (electricity or gas) a customer consumes to recover the costs of administering the program. Expensing allows utilities to recover their costs in the year they were incurred based on extensively evaluated results. If evaluations don’t support year-end results, utilities may not be able to earn the shareholder incentives that were originally established for the program. They may also not be able to recover the full cost of the program. To avoid this, strictly adhere to the program specifications required by regulators. As DSM portfolio budgets grew, some utilities shifted to rate-basing their costs instead of expensing them.

Rate-basing—whereby utilities earn a rate of return on investments by rolling up the costs into customers’ energy rate—is gradually becoming a more popular way to fund DSM programs, and it could become a core mechanism for funding electrification initiatives. New York and a few other states are moving in this direction. Utilities traditionally use rate-basing to fund generation, transmission, and distribution investments. This enables the utility to spread the expense over 20 to 30 years, thereby reducing customer costs on an annual basis. Should costs for electrification initiatives become substantial, which we expect to see as electrification grows in importance, utilities may choose to rate-base the funding.

Should costs for electrification initiatives become substantial, which we expect to see as electrification grows in importance, utilities may choose to rate-base the funding.

Another benefit of rate-basing over expensing is that it allows utilities to approach electrification investments as they do almost all other major cost categories, such as generation, transmission, and distribution. With expensing, utilities must consider costs separately. Rate-basing not only makes it easier for utilities from an accounting perspective, but it also allows them to compare their investments on a level playing field.

A third approach to funding electrification is to amortize the expenses over time; 10 years is a common period. Con Edison takes this approach with DSM and has proposed using it for electrification as well. The benefits of this approach vary based on the utility’s accounting practices and financial position.

A fourth method is performance-based regulation (PBR), whereby the utility is rewarded for meeting or exceeding specific goals, such as reducing carbon, keeping rates low, increasing the net economic benefit to customers, or creating jobs and contributing to economic development. PBR has yet to become a common regulatory approach for IOUs.

Of these methods, expensing is the most common for energy-efficiency programs. However, we’re likely to see rate-basing emerge as the dominant method for funding beneficial electrification. In fact, we learned from our 2019 Utility DER and Electrification Benchmark that funding for active beneficial-electrification initiatives comes largely from utility customers (figure 11).

Figure 11: Utility funding sources for electrification

Of the 27 utilities providing data, a majority indicated that they receive some portion of the funding for their electrification efforts from customers.
Bar chart (copyright E Source, data from the 2019 Utility DER and Electrification Benchmark) showing the source of funding for building electrification and electric vehicles. For building-electrification efforts (base of 27 utilities), 12 utilities said the funding comes from utility customers; 4 said government and utility customers; 3 said the federal or local government; 0 said it comes from a low-carbon fuel standard; 1 said other; 2 said not applicable; and 5 said none. For electric vehicle efforts (base of 28 utilities), 9 said the funding comes from utility customers; 8 said government and utility customers; 2 said the federal or local government; 2 said it comes from a low-carbon fuel standard; 1 said other; 3 said not applicable; and 3 said none.

Up until this point, we’ve been discussing definitions, frameworks, and incentives that will help standardize beneficial electrification across the utility sector. Now we’ll present some specific strategies related to beneficial-electrification technologies and marketing that will allow you to plan and execute programs that benefit the grid, consumers, and your utility.

Beneficial-electrification technologies

No one knows what the future will look like or exactly how we’re going to get there, but you wouldn’t know it from reading most electrification studies. Unquestioned assumptions lie at the heart of these electrification initiatives and technical analyses. For example: Since we need to reduce carbon emissions by [this percentage] and increase revenues by [this percentage], we need to deploy [this percentage] of technologies into the market by [this date].

This is how utilities set goals, so most electrification studies focus on EVs and heat pumps because these end-use technologies are widely assumed to have the greatest overall potential to usher in beneficial electrification at scale. What gets glossed over in this approach is just how difficult it is to intentionally transform well-established markets and unseat long-incumbent technologies.

We don’t disagree that EVs and heat pumps should be an important part of your overall solution. But we don’t think they’re a great place to start for every utility, and they’re certainly not the only solutions you should have in your technology portfolio. In fact, we don’t think you should even start talking about which technologies to promote among your customers unless you’ve already developed a deep understanding of your customers, their behaviors, and the markets in which they participate. According to the results of our 2019 DER and Electrification Benchmark, most utilities are approaching electrification technologies reactively rather than strategically (figure 12).

Figure 12: Utilities’ perceived role in promoting electrification technologies

Over half of the utilities we surveyed for our 2018 DER and Electrification Benchmark indicated that they’ll support the adoption of electrification technologies as opportunities present themselves, highlighting a lack of advance planning.
Chart (base of 30 utilities; copyright E Source) showing how utilities view their role in building-electrification technology adoption: 15 utilities said they will support the adoption of building-electrification technologies as opportunities present themselves; 5 said they will play a major role in helping customers and businesses adopt building-electrification technologies; 4 said they don’t know; 3 said they won't intercede in the development and expansion of building-electrification technologies; 2 said none of the above; 1 said other.

New technologies are exciting, making them an easy focal point for conversations about electrification, but starting with technologies instead of customers can lead to spending a lot of money and seeing few results. It’s easy to establish consensus within your organization about the need for a new technology by demonstrating how it’s better than an old technology, but a better approach is to first consider how technologies are diffused into markets and how your actual customers are using them. By doing so, you can begin to understand what benefits your customers derive from these technologies, what problems these technologies solve for them, and how they can be motivated to change their technology buying and usage behaviors.

Developing an electrification roadmap is an important step in moving your electrification initiative forward.

Developing an electrification roadmap is an important step in moving your electrification initiative forward. A roadmap draws from high-level utility and group goals and helps to make them tangible. Without one, it can be difficult to keep track of where you are, where you’re headed, how you expect to get there, and even how you should communicate your progress internally or to the outside world. During our June 2019 web conference Building an Electrification Strategy and Roadmap, we discussed the potential benefits of creating and refining an electrification roadmap. Using a customer-focused approach when developing your electrification strategy can be the difference between a mediocre program and an exceptional one.

A robust roadmap involves more than picking technology winners; it requires understanding all of the industry stakeholders and how they operate and interact. You could read the existing electrification studies from research groups like EPRI and NREL, and place your bets on technologies like EVs and heat pumps as the main drivers of electrification and market transformation. While that’s not necessarily a bad strategy, it’s unquestionably the long game. To capture more benefits for your utility and customers in the near term, build a more diverse technology portfolio that includes niche market actors and customer segments. A conscientious roadmapping effort will help you determine and track exactly which customers and technologies to microtarget (and retarget).

Electrification through the customer’s eyes

As industry support for electrification grows, it’s sobering to consider that the success or failure of electrification depends on consumers’ purchasing decisions. The term electrification is meaningless to customers; in fact, the whole concept is irrelevant to them.

Electrification efforts will flop unless:

  • Consumers see value in purchasing an EV over a vehicle with an internal combustion engine and an electric appliance over a fossil fuel–powered one
  • Property owners and managers see value in replacing their fossil fuel–powered HVAC, water-heating, and cooking systems with electric ones and in installing EV charging infrastructure or if they receive enough demand from their renters to do so
  • Small, midsize, large, and industrial businesses see value in purchasing electric systems and vehicles over alternatively fueled ones

People respond to messages that connect the dots between a product’s value and their lives. Utilities’ hopes for electrification will only become meaningful and relevant to customers when they leave the utility’s priorities out of the conversation and clearly speak to the value that electric technologies offer over existing alternatives.

The psychology behind why people see value in one offering over another is complex, and numerous electric technologies have compelling attributes, but cost is the primary driver of residential and business customer participation in utility programs.

Why product cost-competitiveness matters

People are rarely willing to put their own, their family’s, or their business’s finances in jeopardy to help society decarbonize power generation and transportation. For consumers, property owners, or businesses to choose an EV, appliance, or system over an alternative, the electric product must be cost-competitive with the alternative and deliver the same or better functionality. Decades of DSM programs have taught us this lesson.

According to the E Source Residential Customer Insights Center, of the 29% of Americans who participated in an energy-related program or service from May 2017 to May 2018, 47% said they participated because of cost savings. For the 19% of small, midsize, and large businesses that participated in a utility energy-efficiency program in 2018, the top three reasons for doing so were rebates or financing (52%), return on investment or payback (47%), and to reduce maintenance (41%), according to the E Source Business Customer Insights Center.

If the up-front or ongoing costs of an EV, appliance, or system are slightly higher than an alternative offering, only consumers with motivations beyond cost savings—whether comfort, environmental stewardship, social status, performance, or something else—will make the purchase. If this is the case with your offering, it’s critical to segment your customers and target your marketing.

How to design electrification value propositions and messaging

When faced with the choice of an uncommon product, like an EV, over a common one, people will only choose the uncommon one if they envision their life being better because of it.

With this in mind, an effective way to market EVs might be, “Driving electric means fueling up in the comfort of your home and spending a third of what you do on gas.” A heat-pump promotion might go something like this: “Choosing a heat pump means saving two-thirds on your home heating costs and getting a built-in air conditioner.”

Lead with terms and phrases that resonate with everyday people when you talk about the value of going electric on your website and in your advertising.

Lead with terms and phrases that resonate with everyday people when you talk about the value of going electric on your website and in your advertising. If your messaging is too technical, customers will tune you out—for example, if you’re explaining the role electrification plays in the decarbonization of the economy. Take a commonsense approach to developing your value propositions and messaging, and test your concepts with real customers.

In 2015, we asked utility customers whether they perceived 24 common terms and phrases utilities use in their communications positively, neutrally, or negatively. The top five most positively perceived terms and phrases were reliability, energy efficiency, solar, conservation, and green. Shape your value propositions and messaging for electrification around these concepts.

The branding potential with electrification

People rarely see utilities as leaders and environmental stewards. More often, they see utilities as laggards and polluters. The branding implications of utility efforts to electrify and decarbonize are serious when you consider that 41% of Americans said they have personally experienced the effects of global warming, according to Yale University’s and George Mason University’s March 2018 Climate Change in the American Mind study—a 10% increase since March 2015.

This is your chance to win customers over with a new business model that creates cheaper, cleaner solutions. And customers want those solutions—65% of Americans agreed in 2018 that their utility should source more renewable energy, according to the E Source Residential Customer Insights Center.

To connect the dots for customers through your brand communications, we recommend using commonsense language like, “When you choose electric, you connect your commute, your home heating and cooling, your cooking, and your business to our increasing supply of renewable energy. By choosing electric, you’re living a better life powered by our shared renewable resources: the sun, wind, and water.”

Next steps for utilities

Electrification is a complex but worthwhile endeavor, considering the opportunities it can deliver to customers, the grid, and the planet. Plus, utilities already have experience in virtually every facet thanks to decades of work on DSM. But the success of your initiative relies on proper coordination and planning.

Engage stakeholders within and outside of your utility. In the early days of DSM, collaborative workshops allowed multiple stakeholders to not only be heard, but to also codesign programs, goals, and initiatives. This is also a good model for electrification endeavors.

Establish an overall set of objectives for your electrification strategy. What goals are imperative and agreed upon by management and stakeholders? What are the environmental goals? What are the regulatory constraints? Without specific goals, determining which electrification programs to develop will be problematic.

While there are certainly winners and losers in electrification, if done correctly it offers huge potential benefits for consumers and the environment.

Analyze grid effects and optimization. The devil is in the details when it comes to how electrification technologies will influence the grid, the need for additional infrastructure, and the impact on rates. Dynamic modeling and forecasting can help you identify the technologies and controls that will enable electrification to maximize net benefits to consumers.

Convince regulators that electrification can benefit everyone. While there are certainly winners and losers in electrification, if done correctly it offers huge potential benefits for consumers and the environment. Partner with outside groups to encourage regulators to establish utility profit or revenue incentives to reward excellent, aggressive implementation.

Create an electrification potential roadmap. Rather than starting with electrification technologies, create a methodology for electrification potential studies that prioritizes human factors, market acceptance, and policy or regulatory influences as dominant drivers of change. Use your experience with DSM potential studies to propel your efforts.

Create programs that customers actually want. Use design thinking and collaborate with customers to identify and understand their wants and needs. Designing your electrification initiative to meet only your utility’s needs will lead to low participation and won’t enhance your brand.

Deliver on your beneficial-electrification plan. Utilities are in a unique position to intervene in the marketplace for electrification. Use decades of DSM failures and successes to jump-start consumer and trade ally engagement. For example, installing EV charging stations won’t help you meet your beneficial-electrification goals if you don’t help boost demand for EVs in your jurisdiction.

Contributing Authors

Senior Analyst, Customer Energy Solutions

Kevin Andrews provides research and consulting services on demand-side management, distributed generation, and beneficial electrification to energy...

Senior Data Analyst, Customer Energy Solutions

Gabe Cuadra updates and draws insights from E Source’s demand-side management tools and databases, in particular the E Source...

Associate Director, Customer Engagement Solutions

Luke Currin leads E Source’s Customer Engagement Solutions team, which covers marketing, communications, customer experience, and...

Associate Analyst, Customer Energy Solutions

Steven Day researches distributed energy resources, specifically electric vehicles and solar energy. Before joining E Source, he worked for...

Senior Manager, Customer Energy Solutions

Bryan Jungers conducts research on emerging, energy-efficient, and distributed energy resource technologies. His main areas of expertise lie in...

Chief Instigation Agent

Bill LeBlanc focuses on helping utilities understand the intersection between the customer and the utility’s products and services, specializing in...

Lead Analyst, Customer Energy Solutions

Ryan Odell provides research, analysis, and consultation to members on issues related to DSM and demand-response programs, with a particular focus on...

Board Member, Senior Fellow

Jay Stein is focused on expertise development, research skills development, quality control, new product development, and technology assessment....

Senior Advisor

Tim Stout, a senior advisor working across the Consulting, Strategic Relations, and Research departments at E Source, has extensive experience in the...

Associate Director, Customer Energy Solutions

Courtney Welch provides research, analysis, and consultation to members on energy efficiency, renewable energy, and DSM policy and program issues,...