We analyze the impact of electrifying low- and medium-temperature process heat across Oregon’s chemicals, pulp & paper, and food & beverage sectors, which account for 59% of the state’s large-facility industrial emissions. Electrifying nine large Oregon manufacturing facilities can cut 11.5 million metric tons of climate pollution through 2050, deliver $390–$520 million in health and economic benefits, and reduce onsite fossil fuel emissions from process heat by up to 52%.
Oregon is home to a robust manufacturing sector, producing everything from paper products to frozen french fries. It also has one of the cleanest electric grids in the country and robust decarbonization goals, which puts Oregon in a unique position to lead on industrial electrification.
The industrial sector is responsible for 22% of statewide greenhouse gas (GHG) emissions.1 About 59% of emissions from large industrial facilities comes from the chemicals, food & beverage, and pulp & paper sectors.2 These facilities burn fossil fuels to create heat for manufacturing processes, primarily in gas boilers that produce steam. There are commercially available technologies to electrify this heat today, making industrial electrification a significant opportunity to reduce emissions and air pollution across Oregon.
Building on our national-scale engineering models, this report identifies how electrifying manufacturing can generate long-term economic benefits for Oregonians, provide cleaner air for communities, deliver cost-effective emissions reductions, and help Oregon reach its climate goals.3 We also recommend near-term actions that policymakers can take to accelerate deployment of clean industrial technologies.
The industrial sector is a major source of pollution in Oregon, accounting for just over 22% of statewide greenhouse gas (GHG) emissions annually.10 Among Oregon’s most polluting manufacturing facilities, about 52% of emissions come from the pulp & paper sector, 5% from the chemical sector, and 2% from the food & beverage sector (Figure 1). This amounts to 2.9 MMT of GHG emissions in Oregon annually, equivalent to ~680,000 gas-powered vehicles driven for one year.11
Many of the emissions in these sectors come from combusting fossil fuels for low- and medium-temperature (LMT) process heat (<300°C, Figure 2). LMT process heat generally takes the form of hot air, hot water, and especially steam. Steam is a key input for many industrial processes. It is easy to distribute and capable of delivering precise heat for everything from cooking food products to driving chemical reactions or sterilizing equipment. In Oregon’s manufacturing sector, LMT process heat delivers thermal energy for activities like paper drying, frozen fruit and vegetable processing, and nitrogen fertilizer production.
Oregon has statewide emissions reduction goals of 45% below 1990 levels by 2035 and 80% below 1990 levels by 2050.12 This makes tackling emissions from LMT process heat a crucial ingredient of any roadmap to meet these targets. Fortunately, technologies delivering electric LMT process heat are currently available and deployed in industries around the U.S.13 Industrial electrification policy is thus one of the most actionable near-term pathways to make progress towards Oregon’s climate commitments.
Beyond emissions reductions, modernizing Oregon’s manufacturing can generate long-term economic benefits. Energy and transportation have been transformed by advancements in technologies like electric vehicles, solar panels, and batteries.15 The industrial sector is not far behind, with the emergence of commercially available clean heat technologies such as air-source high-temperature heat pumps (HTHPs) and thermal energy storage. Electrifying LMT process heat will help “future-proof” Oregon’s manufacturing and ensure that goods made in Oregon remain competitive in global markets. In 2025, Oregon reported $3.4 billion in exports to European Union (EU) member states.16 These exports are now subject to the EU’s emissions trading laws. The EU Carbon Border Adjustment Mechanism (CBAM) went into full effect in January 2026, covering sectors like fertilizers, cement, and steel.17 It is expected to expand to cover key subsectors like paper and chemicals.18 Lowering the carbon intensity of Oregon’s manufacturing will make these exports more competitive.
Additionally, sourcing technology solutions made by American manufacturers will help support the growth of resilient, domestic clean energy supply chains and high-quality jobs for American workers. A recent study estimated every dollar invested in electrification could result in around $1.85 in total economic activity in the United States over the next decade.19 In Oregon, the study found that industrial electrification can support 26,500 jobs and add $2.7 billion to the state’s GDP from 2026-2035.
In our national-level report, The Clean Heat Climate Opportunity, we simulate the direct electrification of LMT heat at 798 large manufacturing facilities across the country, spanning 32 manufacturing subsectors. Here, we downscale this analysis to Oregon, covering the following 6 manufacturing subsectors and 9 large manufacturing facilities. Below, we describe how we model process heat electrification.
| Chemicals (325) | Pulp & Paper (322) | Food & Beverage (311-312) |
|---|---|---|
|
|
|
Our analysis focuses on four electric technologies, already deployed at U.S. facilities, that together can meet the heat demands of large industrial plants.
Pass electric current directly through water to generate steam, with high efficiency and minimal maintenance compared to combustion boilers. A mature, proven technology.
Source: Cleaver-Brooks
Use electricity to “upgrade” ambient heat, producing 1.3–2 times as much heat energy as the electricity they consume (COP 1.3–2). An early-stage technology with promise for lower costs over project lifespans.
Source: AtmosZero
Electric ovens replace gas-fired baking and curing, delivering precise, uniform heat for food, ceramics, and coatings.
Source: Sveba Dahlen
Electric resistance and infrared dryers replace direct-fired drum and tunnel dryers, removing combustion at the dryer entirely.
Source: Lessine
Optimizing heating systems and reducing steam-transmission losses cuts total energy consumption at a facility — a “win-win” that saves money and reduces emissions. Waste-heat-recovery heat pumps can deliver up to 5.3× more heat than the electricity they use.
Source: Permapipe
Industrial emissions are often labeled “hard-to-abate,”21 but for LMT process heat, many clean technologies are already commercialized and ready to deploy. Electrode boilers, air-source HTHPs, waste heat recovery heat pumps (WHRHPs), electric resistance ovens, and electric resistance dryers can be used to modernize industrial facilities, improve efficiency, and cut emissions. In particular, electrode boilers and air-source HTHPs can meet the primary steam demands of large-scale industrial facilities and have already been deployed in U.S. manufacturing facilities.
Electrode boilers use electric current passed directly through water to generate steam, offering high efficiency and minimal maintenance compared to combustion-based alternatives.
Air-source HTHPs use electricity to power a mechanical vapor compression cycle that harvests and “upgrades” heat. By pulling heat from an external source like the air and/or a waste heat stream, an HTHP can supply even more heat than the electricity it uses.22 Across 9 Oregon industrial plants, we estimate that an air-source HTHP can achieve a “coefficient of performance” (COP) of around 1.3 to 2, meaning it can produce 1.3 to 2 times as much heat energy as electric energy consumed.23
Geothermal systems tap underground thermal energy for steam generation. Thermal batteries can store thermal energy for hours to days, allowing a facility to take advantage of cheap electricity at off-peak times. While we do not model these technologies in this set of results, they are also potential clean heat solutions that should be considered for policy support.
Geothermal systems circulate fluid underground and draw energy from the subsurface, providing a clean, firm source of heat. Today, these systems are mainly used for space heating (via ground-source or geothermal heat pumps) or to generate electricity. Notably, the Portland International Airport completed renovations in 2026 that include a groundwater heat pump system, contributing to a 90% reduction in fossil fuel usage.24
But these systems are also capable of supplying hot water or steam to industrial facilities. This allows manufacturers to use clean heat without adding load to the grid or paying high electricity prices. Our earlier report, Unlocking Next-Generation Geothermal Heat for Industry, explores how geothermal energy can be harnessed for industrial process heat.25
Some industries in Oregon already use geothermal energy, including a milk processing plant that started operating on geothermal heat in 1945 and saved the company roughly $76,000/year in today’s dollars.26 The Klamath Basin Brewing Company was also the first brewery to run on geothermal energy.27 Geothermal energy has been heating buildings in Klamath Falls since the 1960s and saves the Oregon Institute of Technology an estimated $1.4 million in annual energy costs.28 In 2010, the university built Oregon’s first geothermal power plant.
Oregon has abundant potential for further geothermal development, particularly in eastern and central Oregon. The Oregon Energy Strategy identified geothermal as the most cost-effective emerging resource and an area for further development.29 Oregon is also expected to have some of the lowest costs for developing enhanced geothermal electricity generation in the country.30 This makes Oregon a strong candidate for piloting geothermal applications for industrial process heat, either near geothermal power plants or industrial parks.
Thermal energy storage systems (also known as thermal batteries) offer flexibility by decoupling heat production from electricity consumption. Similar to electric batteries, these systems can charge using electricity from the grid at one time and discharge the energy as heat at a later time (as well as charge and discharge simultaneously). This enables operators to shift electricity use to off-peak periods and mitigate strain on the grid. When coupled with access to wholesale market electricity prices, this also allows facilities to concentrate load when renewable electricity is plentiful and electricity is cheapest, lowering operating costs.
Some thermal batteries work by storing energy in “hot rocks,”31 while others store energy in chemical bonds.32 These systems are capable of delivering heat at high efficiency (~98%) across a wide temperature range – not just LMT – supporting diverse industrial applications.
Example Diagram: Thermal Energy Storage
However, deployment challenges remain for each of these technologies. Upfront costs, facility retrofits, and space constraints limit adoption. Targeted pilot programs, workforce training, and utility demand-flexibility incentives could help overcome these barriers. We discuss these measures in the policy recommendations section below.
To capture the complexity of manufacturing processes, we develop process system archetypes for 6 manufacturing subsectors in Oregon (see Table 1). These archetypes model energy and mass flows for a representative plant in a given subsector, allowing us to assess how process heat electrification affects energy use, costs, and direct and indirect emissions.33 Using these archetypes, we model electrification of process heat in the LMT range that does not rely on combined heat and power (CHP) or byproduct fuel combustion.34
CHP units combust fuels to generate both steam and electricity simultaneously for onsite use. It is not possible to replace CHP steam with steam from an electric heat technology without also affecting the CHP unit’s electricity output, which could change both the technical and economic viability of the unit. As such, our models do not electrify CHP units. This affects 4 Oregon pulp & paper facilities that have CHP units.
In the pulp & paper sector, byproducts such as wood waste and black liquor are often combusted in both standalone and CHP units to create steam. Black liquor combustion also supplies pulping chemicals for reuse in other parts of the process. If these byproducts were to be replaced by electrification, they would need to be stored or sold, in which case they would likely still be combusted. This makes the economics of electrification more challenging, so we exclude byproducts from our electrification modeling as well.
This is particularly important for Oregon, as the pulp & paper sector makes up around 52% of emissions from Oregon’s large manufacturing facilities (Figure 1). Future work should explore options for CHP system retrofitting and alternate pathways for byproduct fuels. Even excluding byproducts and CHP, there is still a large opportunity to electrify process heat in the pulp & paper sector, as we show below.
We also model energy efficiency improvements. Often considered the “first fuel,” these upgrades can reduce total energy demand, ease grid impacts, and improve project economics. Waste heat recovery using WHRHPs is a key efficiency measure already deployed at many U.S. facilities.35 Across Oregon facilities with opportunities for WHRHPs, we estimate COPs between 3.8 and 5.3, meaning WHRHPs can produce up to 5.3 times as much heat as electricity consumed.
We simulate five technology scenarios, summarized in Table 2.
| Scenario Name | Process Heat Steam Source | Direct Process Heat Source | Energy Efficiency Measures | Notes |
|---|---|---|---|---|
| “Baseline” | Natural gas boiler36 | Direct Combustion Units | No | Business as usual, process heat (steam and direct-fired units) generated via fossil-fuel combustion |
| “Drop-In Electrification” | Electrode boiler | Electric resistance ovens and dryers | No | Business as usual facility, steam is generated via electrode boilers, direct-fired units electrified |
| “Drop-In Electrification (Max Efficiency)” (EE+) | Yes | Steam and direct process heat systems optimized for efficiency; steam is generated via electrode boilers, direct-fired units electrified | ||
| “Advanced Electrification” | Air-source high-temperature heat pump | No | Business as usual facility, steam is generated via air-source HTHPs, direct-fired units electrified | |
| “Advanced Electrification (Max Efficiency)” (EE+) | Yes | Steam and direct process heat systems optimized for efficiency, steam is generated via air-source HTHPs, direct-fired units electrified |
We estimate that 503,120 t of onsite GHG emissions in 9 Oregon facilities stem from readily-electrifiable LMT heat. Across these 9 facilities, this represents 52% of process heat emissions from fossil fuel combustion covered by the Oregon Climate Protection Program (CPP) and 15.6% of total emissions from process heat.37 Figure 3 captures how manufacturing emissions break down across categories.
Industrial electrification cuts 52% of emissions covered by the CPP across 9 emissions-intensive trade-exposed (EITE) facilities. The CPP establishes a declining cap on GHG emissions from large industrial facilities to help Oregon meet its decarbonization goals.38 For each sector, Figure 4 shows reductions in CPP-covered emissions through 2050 in the Advanced Electrification (Max Efficiency) scenario. Electrification of LMT process heat would significantly reduce covered emissions (the program excludes emissions from Scope 2 and biogenic fuels).
Electrifying LMT process heat starts cutting emissions immediately, with larger climate benefits as the grid gets cleaner. With the technologies in the Advanced Electrification (Max Efficiency) scenario, we estimate that electrifying Oregon’s LMT heat today would eliminate ~1.9 MMT of CO2e emissions at these facilities by 2030. This amounts to an 11.6% reduction in total CO2e emissions from process heat in our target subsectors.39 By 2050, we estimate that electrifying LMT process heat today leads to 11.5 MMT CO2e emissions avoided in the Advanced Electrification (Max Efficiency) scenario – a 14.3% decrease compared to the Baseline scenario. Figure 5 shows how these emissions savings accumulate over time.
Oregon’s electricity grid is relatively clean, ranking 7th lowest in carbon dioxide emissions per GWh of electricity (primarily due to the state’s extensive hydropower resources).40 Nonetheless, while Drop-In Electrification also yields cumulative emissions reductions, it could lead to short-term emissions increases due to the continued presence of fossil fuels on the grid, especially natural gas (see Figure 5).41 To maximize pollution reductions – and meet Oregon’s target of reducing economy-wide greenhouse gas emissions by 80% from 1990 levels by 2050 – the state’s power sector must be decarbonized in parallel.42
Electrification also reduces harmful air pollutants. Natural-gas-fired boilers and heaters release nitrogen oxides (NOx), which have direct respiratory impacts and contribute to the formation of ground-level ozone (O3) and secondary particulate matter (PM2.5). Other fossil fuels release PM2.5, a pollutant that is linked to asthma, cardiovascular disease, and premature death.43 In the pulp & paper sector, the burning of biomass and black liquor also contributes to sulfur dioxide (SO2), NOx, and PM2.5 emissions.44
These pollutants place the greatest burden on communities located near industrial facilities. Across the U.S., industrial sites are more likely to be located near Black, Hispanic, and other communities of color, reflecting decades of racial segregation and inequitable siting practices.45 As a result, people of color and low-income households are consistently exposed to higher levels of PM2.5, NOx, and ozone, even after decades of air-quality improvements.46 Layered on top of existing socioeconomic challenges, these unequal pollution burdens leave marginalized communities facing more illness and greater health risks.
Oregon has a health-based air toxics regulatory program called Cleaner Air Oregon (CAO) that requires certain facilities to report emissions and assess their associated risk to local communities. The Oregon Department of Environmental Quality (DEQ) “calls in” facilities to join the program based on potential risk from the facility and proximity to sensitive populations. If emissions exceed health risk benchmarks, then facilities must reduce the risk from their emissions.47 All 9 facilities in this analysis have been called into the CAO program to evaluate their emissions and the emission impacts on local communities.
We find that full electrification of LMT process heat in 9 of Oregon’s high-emitting manufacturing facilities would remove ~2,800 t of NOx and ~240 t of PM2.5 through 2030. These reductions add up over time, reaching ~16,100 t of NOx and ~1,300 t of PM2.5 through 2050. Most of the reduction is in NOx, because the natural gas being replaced emits relatively little PM2.5 or SO2. SO2 emissions rise slightly through 2030, as added electricity demand draws on a grid that still includes fossil generation, before reaching a net reduction of ~280 t by 2050.
These air quality improvements translate into meaningful health benefits for Oregonians, as well as communities in neighboring states. Fewer residents will suffer from asthma and lung disease. Fewer children will miss school due to asthma and fewer workers will call out sick. Ultimately, electrification in Oregon will prevent premature deaths from chronic pollutant exposure. Much of this benefit comes from reduced ozone formation as NOx emissions fall. Table 3 summarizes our estimates of these health benefits.48
| Health benefits in the form of fewer… | In Oregon | Other U.S. states |
|---|---|---|
| …Asthma Symptom Days | 20,000 | 36,000 |
| …Emergency Room Visits | 40 | 70 |
| …Premature Deaths | 25 - 35 | 35 - 47 |
| …Lost Workdays | 1,100 | 1,400 |
| …Lost School Days | 9,800 | 19,000 |
| Cumulative Health and Economic Benefits | $390M - $520M | $560M - $720M |
Note: Avoided on-site pollution is calculated using EPA’s 2020 National Emissions Inventory records for each boiler and dryer being electrified (covering 92% of in-scope fuel use), with peer-facility or EPA standard emission rates filling gaps. Avoided emissions are subtracted from each facility’s reported total, so pollution from unelectrified equipment remains. Air quality impacts and health benefits were then modeled using EPA’s CO-Benefits Risk Assessment Health Impacts Screening and Mapping Tool (COBRA).
For one example of how industrial electrification could benefit Oregon communities, we can look at Lane County. The Eugene-Springfield area of Lane County is an EPA maintenance area, having had high carbon monoxide and PM10 levels in the past. Lane County as a whole ranks in the 96th percentile nationally for PM2.5.49 As a result, the community faces a high health burden, ranking in the 94th percentile nationally for asthma.50 There are 4 facilities in Lane County that have completed the CAO program and another 4 called in (or soon to be called in) to the CAO program.51 One of the facilities called into the CAO program is a large pulp & paper mill that is included in this analysis.
Electrifying these factories would meaningfully reduce air pollutants and improve health for Lane County residents. We estimate that full electrification of LMT process heat in 9 of Oregon’s high-emitting manufacturing facilities would result in $54 million to $66 million in cumulative health and economic benefits through 2050 in Lane County alone.52
Reductions in pollution and emissions mean better health and a safer environment for Oregonians. But first, industrial facilities must be willing to invest in clean heat technologies. We analyze which technologies and sectors present the most cost-effective opportunities for electrification and assess how policy support can help.
Industrial electrification delivers high-value pollution reductions across the board in Oregon. Figure 6 shows the marginal abatement cost – the cost per ton of avoided emissions over a project’s lifetime – across sectors for CO2e in the Advanced Electrification (Max Efficiency) scenario. Wider bars correspond to greater emissions reductions; shorter or negative bars represent lower-cost emissions reductions.
The costs of abatement are well below the Biden Administration’s estimate of the social cost of carbon, which was $190/ton in 2023.53 The chemicals and pulp & paper sectors deliver emissions reductions at the lowest cost for Advanced Electrification, making them prime targets for first movers.54 The results are broadly similar for Drop-In Electrification (Max Efficiency).
Next, we consider the economics of electrification from the perspective of industrial facilities. Figure 7 shows total project costs (upfront + operating) over equipment lifetimes by technology scenario, broken out by cost component.
Electricity and fuel make up the bulk of lifetime costs, meaning that fuel and electricity prices are a primary driver of project economics. While there is variation across individual service agreements, on average, electricity for industrial consumers is 3.3 times more expensive than natural gas in Oregon.55 Because electricity is more expensive than natural gas per unit of energy – known as the “spark gap” – electric technologies must be more efficient (i.e., use less energy) to be cost-competitive.
Figure 7 shows that although electric technologies are more energy-efficient than conventional combustion equipment, Oregon’s spark gap is large enough to undermine those efficiency gains on a cost basis. Using average assumptions, lifetime costs for supplying LMT process heat increase across the four technology scenarios. The spark gap between the price of electricity and the price of natural gas is thus a central challenge.
The high electricity-to-heat conversion efficiency of HTHPs still reduces operating costs over the project lifetime. As a result, the lifetime project cost is the smallest for “Advanced” electrification with an air-source HTHP and energy efficiency measures. But the difference across technology scenarios is relatively small. Given the lower upfront costs and comparative ease of retrofitting an electrode boiler, this makes “Drop-In Electrification” a particularly competitive pathway in Oregon.
It is important to note that this modeling does not capture all of the economic benefits of electrification. With faster start-up times than fossil-fired equipment, electric heat equipment can increase throughput (the quantity of goods produced per hour) at a facility. Electrification can also improve workplace safety by eliminating open flames, reduce permitting and regulatory compliance costs, and attract environmentally conscious buyers and investors.56 While quantifying these impacts is beyond the scope of this analysis, accounting for these “non-energy benefits” improves the economic competitiveness of electrification.
Next, we identify “hot spots” – the most cost-effective opportunities for electrification in Oregon (Figure 8). We also show cost results under “Optimistic” and “Conservative” assumptions to show a range of possible outcomes. The Optimistic case assumes that parameters such as equipment efficiency, capital costs, and fuel prices land favorably for electrification in the range of feasible values, while the Conservative case assumes the opposite.57
Using “Optimistic” assumptions, we estimate that Advanced Electrification (EE+) can be cost competitive with natural gas technology in the pulp & paper and chemicals sectors today (Figure 8). With highly efficient steam generation from an air-source HTHP and efficiency measures lowering overall energy demand, efficiency gains with clean heat technologies are enough to overcome the “spark gap.” In the pulp & paper sector, electrification is close to cost competitive in the optimistic Drop-In Electrification (EE+) scenario as well. Overall, the pulp & paper sector also stands out as a high-value sector with the most significant emissions reduction potential.
Non-cost barriers such as technology risk and design complexity still matter.58 But this suggests that the best electrification opportunities in Oregon – where “Optimistic” assumptions come closest to capturing the facts on the ground – could approach competitiveness on a cost basis.
The impact of electrification on operating costs and overall manufacturing costs can be minor. Fuel is just one of many costs that go into making a product and usually represents a relatively small share of total costs (though this varies by product). Only a subset of those fuel costs goes towards generating process heat – and, only a portion of that process heat falls in the in-scope LMT category that is electrified in our analysis. As a result, a substantial increase in operating costs for LMT process heat could translate into a small impact on prices, even if all of these costs were passed on to buyers.
Figure 9 shows how LMT process heat electrification could impact product prices for three products that are manufactured in Oregon. We estimate the share of “Fuel” costs that goes towards LMT process heat in the Baseline scenario. That portion gets converted into “Electricity” costs in the Advanced Electrification (Max Efficiency) scenario, showing how this change would impact prices if all costs were passed on to consumers. Because of data restrictions, this exercise does not capture the additional capital costs of electric heat equipment. But, this can still illustrate the effect of the operating cost increases that are the primary driver of higher lifetime costs from electrification.
For french fries, the implied change in price is just 3 cents per 28-oz bag, a 0.5% increase. The change for ethanol is similarly small: about 1 cent per gallon, also a 0.5% increase. For containerboard (a product where a higher proportion of costs come from fuel), the implied change is greater, $9 per short ton – but still just a 0.9% increase.
Importantly, every dollar counts for facilities in trade-exposed sectors operating on tight margins. Again, this exercise does not account for additional upfront capital costs. Nonetheless, this suggests that it is possible for facilities to electrify and remain economically competitive, especially with policy support and accounting for “non-energy” economic benefits.
Policies to bring down upfront costs or industrial electricity rates improve the financial incentives for manufacturers to electrify.
Figure 10 shows the effect of policy support on project economics. “Capex” captures the effect of upfront cost support such as grant funding or an investment tax credit. “Elec” represents the effect of a beneficial tariff that reduces the cost of electricity for clean heat equipment. Because electricity constitutes the largest portion of total costs, policies to reduce the cost of electricity have the greatest effect on cost competitiveness. By a similar token, the most effective policy is a $10/MMBtu production tax credit (PTC). A PTC brings down operating costs by providing a tax rebate per unit of clean heat produced, bringing lifetime costs close to Baseline.
Concentrating electricity demand at times when prices are lower is another pathway to lowering operating costs that we do not capture in this analysis. Thermal energy storage systems can charge during times when electricity is cheaper. We discuss how rate policy can support these systems in Section 4.
This does not mean that upfront cost support is unimportant. The near-term, one-time expense of a large capital investment often weighs more heavily in spending decisions than fuel costs in the distant future. Raising capital can thus be a barrier to adoption of clean heat technologies. Capex policies such as grants or an investment tax credit could bring upfront costs into a range that is more competitive with natural gas technology.
Meanwhile, the upfront costs of Drop-In Electrification with electrode boilers are comparable to natural gas equipment. For facilities with shorter time horizons, this lower upfront cost might make Drop-In Electrification more appealing.
Accelerating load growth, particularly from large loads like data centers, may strain Oregon’s grid. The Oregon Energy Strategy projects electricity demand to double by 2050, with data centers as the near-term driver.59 Electrifying industrial process heat will add more electricity demand to the grid. Meeting this increasing demand will require careful resource planning from Oregon’s utilities and the Oregon Public Utility Commission (OPUC).
We estimate that electrifying all of the LMT process heat in our nine in-scope facilities would increase industrial electricity consumption by ~1.7–2.3 TWh annually, depending on the technologies deployed (Table 4). To put this in context, planned data center projects in the state are projected to add 4 GW of total load,60 equivalent to ~26 TWh per year if fully built out.61 While industrial LMT electrification would meaningfully increase electricity demand from industrial facilities, it represents a modest addition compared to projected data center demand.
Oregon has taken steps to address data center load growth with the 2025 Protecting Oregonians with Energy Responsibility (POWER) Act, which directs the OPUC to create a new rate class for data centers that use more than 20 MW of power. A proposal from Portland General Electric to raise rates for large data centers by nearly 30% was approved in July 2026 in alignment with the POWER Act.62 The POWER Act only applies to data processing facilities (NAICS: 518210), meaning that industrial manufacturers will be excluded from this tariff.
But with electricity bills posing a burden for many households, policymakers are right to consider the effects of additional demand that industrial electrification places on the grid. In Section 4.3, we discuss ways that rate policy can be designed to ensure that industrial electrification does not raise bills for other rate classes. This can mean incentivizing energy storage and “smart” devices to ensure that industrial electrification does not add to peak loads. With appropriate planning and responsible investments, regulators can ensure that clean industrial heat benefits Oregonians.
| Total Annual Oregon Industrial Grid Demand (2023, Baseline) = ~14,434 GWh63 | ||||
| Scenario | OR Chemicals* | OR Pulp & Paper* | OR Food & Beverage* | Scenario Total |
|---|---|---|---|---|
| Drop-In Elec | +184 GWh (+1.3%) | +1,631 GWh (+11.3%) | +455 GWh (+3.2%) | +2,271 GWh (+15.7%) |
| Drop-In Elec (EE+) | +144 GWh (+1.0%) | +1,529 GWh (+10.6%) | +422 GWh (+2.9%) | +2,095 GWh (+14.5%) |
| Adv Elec | +104 GWh (+0.7%) | +1,353 GWh (+9.4%) | +342 GWh (+2.4%) | +1,799 GWh (+12.5%) |
| Adv Elec (EE+) | +84 GWh (+0.6%) | +1,272 GWh (+8.8%) | +317 GWh (+2.2%) | +1,673 GWh (+11.6%) |
Note: *Sector groups only reflect 6 OR subsectors included in study (Table 1). Percentages represent change from the total industrial grid demand in Oregon (2023).
The same data center buildout adding demand to the grid also creates an opportunity. Data centers require extensive cooling to prevent servers from overheating. Rather than releasing the excess heat that servers generate into the atmosphere, this heat could be recovered for use in industrial processes (as well as for district heating, agriculture, and more).64 Data center waste heat reuse projects have already been deployed around the world, including in Seattle where data center heat can provide the equivalent of 11 MW of heat for three large Amazon headquarter office buildings.65
The temperature of waste heat from a data center depends on the cooling system. Air-cooled systems yield waste heat at 25-35°C and water-cooled systems at 50-60°C.66 These temperatures are high enough to be used in some lower-temperature process heat applications, such as paper stock preparation.
For other manufacturing applications, the waste heat must be upgraded with an HTHP. In these cases, using waste heat would still lower costs and improve emissions savings from electrification. Because data center exhaust is substantially warmer than the ambient air that an air-source HTHP would otherwise draw from, using data center waste heat as the source can theoretically improve the unit’s COP and reduce electricity use, resulting in lower costs.
Data center waste heat can be part of industrial symbiosis efforts, as industries exchange materials, energy, byproducts, and/or heat to improve efficiency. The Oregon Energy Strategy has identified industrial symbiosis as a potential tool for industrial decarbonization and energy efficiency. Additionally, the Oregon legislature passed HB 4086 in 2026 to encourage industrial symbiosis, develop a roadmap for action, and allocate $900,000 for four industrial symbiosis pilots.67 Oregon’s policymakers should leverage this opportunity to encourage data center waste heat for industrial symbiosis.
Oregon has already taken important steps to encourage industrial decarbonization. The Climate Protection Program (CPP) sets declining emissions limits for Oregon’s largest industrial facilities, and is currently undergoing a rulemaking to determine the stringency of those emissions reduction requirements. The 2025 Oregon Energy Strategy includes recommendations for industrial decarbonization. The City of Portland is also leading industrial decarbonization through its $20 million Clean Industry Initiative for projects to reduce carbon emissions and create substantial community benefits.68
These actions are a good starting point. But more policy support is needed to make industrial electrification both practical and economical. Policymakers should take a diversified approach to helping manufacturers overcome capital, operating cost, technical, and market barriers. Additionally, as agencies develop implementation plans, they should identify opportunities to advance industrial decarbonization through investment, electricity rate policies, and enhanced grid capacity.
To help Oregon reach its statewide GHG reduction goals, Oregon’s CPP establishes a declining cap on GHG emissions from natural gas utilities, suppliers of gasoline, diesel, kerosene, and propane, and large industrial plants. The CPP sets a goal of reducing covered emissions 50% by 2035 and 90% by 2050, from a 2017-2019 average emissions baseline.69 The program does not include Scope 2 emissions or biogenic fuel combustion emissions.
The Oregon DEQ is currently engaged in a rulemaking process to determine how emissions-intensive trade-exposed (EITE) sources will be regulated.70 EITE sources are those deemed vulnerable to competitive trade and to relocation out of state. In Oregon, 36 sources have been designated as EITE entities, including pulp & paper, chemicals, and food & beverage facilities.71
As part of the rulemaking, DEQ is developing GHG emissions intensity benchmarks. The benchmark is a starting value against which a given facility will be evaluated for compliance with the program.72 From this starting benchmark value, DEQ will determine the amount of free compliance instruments distributed and an emissions reduction schedule to meet reduction targets.
Other states and countries with emissions reduction compliance programs have undergone a similar process to determine what initial emissions intensity benchmark to set for EITE sectors: the European Union used the average emissions of the top 10% most efficient producers in the sector; California set a benchmark for emissions at 10% below the average emission per product; and New Zealand used average emissions in the sector.73
DEQ should set uniform sector-based benchmarks that advocates note “can strengthen comparability, ensure fairness and rigor, and reinforce a consistent signal across the sector.”74 Setting sector-wide benchmarks ensures that standards are based on what is achievable across an industry sector, rather than highly specific facility-specific benchmarks that measure a source against itself. Sector-based benchmarks encourage less-efficient facilities to reduce emissions, while also rewarding early actors that have already taken steps to reduce emissions. Benchmarks should also be set using standard baseline data years for consistency.
Additionally, DEQ should set meaningful and uniform emissions reduction schedules. A reduction schedule of 1.5% per year75 beginning in 2030 is not strong enough to encourage the rapid decarbonization needed to reach Oregon’s emissions reduction targets. DEQ should maintain a minimum reduction schedule of 2.5% per year, or 5% every two years, as follows the current reduction schedule outlined in Table 8 of Oregon Administrative Rule 340-273-9000.76 2.5% a year from 2030 yields a 50% reduction in emissions (scaling linearly) through 2050, which is still well below CPP’s target of a 90% reduction by 2050.
Gradual electrification of LMT process heat would allow facilities to achieve such a target. We estimate that full electrification of LMT process heat in the pulp & paper, chemicals, and food & beverage sectors would eliminate 52% of EITE CPP-covered emissions today at 9 large manufacturing facilities.77 Across sectors, electrification at these 9 facilities eliminates 48% of covered emissions in pulp & paper, 38% in chemicals, and 100% in food & beverage.
Electrification of LMT process heat is also a cost-effective way for facilities to meet CPP emissions reduction requirements. For both Drop-In Electrification and Advanced Electrification, the marginal cost of reducing a ton of CO₂ is below $136, the price facilities pay to earn Community Climate Investment (CCI) credits under the CPP.78 These results suggest electrification is a cheaper compliance option than paying contributions to earn CCI credits.
In its Natural Gas Fact-finding Investigation docket, the OPUC started to evaluate how gas utilities can meet state climate goals while also managing risks to ratepayers as gas demand declines. The investigation closed in January 2023 but did not fully consider line extension policy.79 The Oregon legislature should direct OPUC to further consider line extension policy for industrial customers. One potential reform would require new industrial users to pay for some or all of the costs of line extension, thereby “unsubsidizing” gas use. OPUC could also require utilities to demonstrate consideration of industrial electrification before approving new gas line extensions.
While Oregon has typically aligned with federal baselines for heating equipment, state agencies have distinct paths to set higher standards: the Oregon DEQ has the authority to implement stricter pollution and emission controls for commercial boilers, while the Oregon Department of Energy regulates appliance energy efficiency for products not preempted by federal law.80 Oregon could use this authority to require gradual adoption of electric heat equipment.
Starting with rules for smaller, lower-temperature boilers and water heaters—where electrified options are more readily available—can acclimate stakeholders and industrial users to electrification. Regulators could then phase in similar rules on large boilers implemented through Best Available Control Technology (BACT) determinations. For example, California regional air districts are phasing in zero-emissions standards for smaller units, while new rulemaking is underway to address emissions from larger boilers.81
State and federal incentives for electrification technologies through grants, rebates, and low-cost financing can reduce Capex burden and shorten payback periods.
The Oregon Energy Strategy identified an industrial modernization revolving loan fund as key to helping Oregon industry transition to cleaner and more efficient manufacturing processes.82 SB 1526, introduced in the 2026 legislative session,83 would have created a non-profit to fund clean energy and resilience projects across the state. SB 1526 failed to advance in 2026, but Oregon should revive SB 1526 or develop a similar financing mechanism to help industry electrify. Oregon can learn lessons from Portland’s Clean Industry Initiative, as funding and demonstration projects get underway.84
Alternatively, the legislature could fund investments with an investment tax credit. Colorado offers a model: the state recently launched its semi-annual Colorado Industrial Tax Credit Offering (CITCO), providing $168 million in refundable tax credits for industrial emissions reduction projects.85 The program covers a wide range of interventions, including feasibility studies, facility improvements, and equipment installations and replacement. Because the credit is refundable, firms without substantial tax liability can participate.
Clean heat technologies such as air-source HTHPs86 and thermal energy storage87 are proven to work in the field. That being said, risk remains a factor for industrial manufacturers who prize reliability and plant managers who may be unfamiliar with these new systems.
Oregon can support electrification projects by taking on some of the project risk. Revenue insurance and performance guarantees can protect project owners against risk that the technology underperforms or that the economics shift unfavorably. Contracts-for-difference can stabilize project revenues by guaranteeing a minimum return, even if energy prices move against the project. For projects that require debt financing, first-loss capital or state credit support can improve the risk profile enough to unlock private lending at workable rates. Together, these tools allow the state to absorb the portion of project risk that private markets are unwilling to bear, without requiring the state to fund projects outright.
Our results show that while electrification in Oregon could be cost competitive in the best cases, it is often more expensive over project lifetimes because electricity is more expensive than natural gas. This is known as the “spark gap.”
One way to address the spark gap is to simply offer a lower rate to facilities that electrify. Offering special electricity rates as incentives has strong precedent. Industrial facilities often receive economic development rates in exchange for siting in a service territory. This is akin to residential customers who purchase a heat pump, electric vehicle, or battery receiving a special rate. To encourage industrial electrification, utilities could similarly offer a lower per-kWh rate for power that serves clean heat technologies. Our results show just how much this improves the cost competitiveness of decarbonization.
However, this comes at a time when many are concerned about rising electricity bills for ratepayers and load growth from data centers. Utilities, regulators, and policymakers are understandably cautious about adding more load to the grid from industrial electrification. The concern is that additional investments to service new loads could result in higher bills for other rate classes, and a lower rate means less revenue to cover these additional investments.
Fortunately, we can design policies that support industrial electrification without increasing costs for other customers. The main way to do this is by providing industrial customers with time-based price signals, so that the cost of electricity reflects the strain on the grid at a given point in time. If facilities are incentivized to concentrate new demand from electric heat equipment88 at times when there is capacity on the grid to spare, load growth does not need to result in expensive grid investments that could fall to other customers. In fact, utilities could spread the costs of their existing investments over more sales, which could lower rates for other customers.
Below, we outline several ways that Oregon’s tariff policy can be structured to support industrial electrification without taxing the grid. Eight of the nine facilities in our analysis are served by consumer-owned utilities (public utility districts, cooperatives, and municipal utilities) which set their own rates through locally elected or member boards, rather than through the OPUC. The rate designs below can be adopted by both: through OPUC proceedings for investor-owned utilities, and directly by consumer-owned utility boards.
Reforming non-coincident demand charges is a key measure to encourage off-peak consumption. A non-coincident demand charge is a portion of a customer's bill that is based on the maximum power draw during a billing period, regardless of when it occurs. When utilities use this charge to recover transmission system costs, this penalizes customers who are not drawing their peak power when the transmission system is most taxed. Instead, utilities can use a coincident demand charge that is pegged to the customer's power draw during the system peak. This incentivizes facilities to lower their bill by shifting their demand off-peak.
The Oregon Energy Strategy Policy 2b identifies the need for demand response flexibility as a mechanism for large commercial and industrial users to support grid needs.89 Oregon investor-owned utilities also use on-peak demand charges that are based on general peak time windows, rather than the actual system coincident peaks. Oregon can refine this structure to encourage shifting power demands away from system peaks. Consumer-owned utilities can adopt coincident demand charges directly in their own rate schedules.
Industrial customers should be allowed to purchase power on the real-time or day-ahead markets. There are usually ways to do this in deregulated markets, but in vertically integrated markets it is often difficult or impossible for industrial sites or solutions providers to purchase electricity on spot markets.90
With access to the spot market, in exchange for taking on more price risk and volatility, an industrial customer can often substantially lower its cost of electricity per kWh. The savings are even greater when customers concentrate demand during off-peak times when electricity prices are lowest. In this way, customers are incentivized to avoid adding to peak loads.
Through Oregon’s direct access program, nonresidential customers of Portland General Electric and PacifiCorp can buy power from Electricity Service Suppliers and access market-indexed pricing. However, eight of the nine facilities in our analysis are served by consumer-owned utilities, which are not part of this program and largely buy wholesale power from the Bonneville Power Administration. Consumer-owned utilities could offer similar benefits through real-time or time-of-use rates for electric heat equipment, and Oregon could expand direct access for new electrification load in investor-owned utility territory.
The operating times of electric heat technologies can also be pegged to a specific renewable generating resource. In this arrangement, the equipment only runs when there is renewable energy available to meet the demand from the electrified equipment. The Otter Tail Power Thermal Market Energy Pricing (TMEP) tariff, which supported a 5 GWh thermal battery installation at POET Biorefining in South Dakota by Antora, contains this type of requirement.91 Tying the operation of equipment to a renewable resource helps ensure that the new load does not add to grid strain during system peaks, while also relieving local transmission congestion by absorbing wind or solar output that would otherwise be curtailed.
Another measure that can support industrial electrification is capping policy-related riders and nonbypassable charges for new load from electrification. These charges often cover important utility programs like energy efficiency and low-income bill assistance. However, they are assessed on a per-kWh basis over a billing period, meaning that electrification raises the program fees that a customer pays -- even though these program costs do not change with how much electricity a customer uses. Beneficial electrification should be exempted from program fees or have them capped at a certain amount, given that this load growth advances many of the public goals these programs serve. Capping program fees still has the effect of increasing program revenue, when this load would otherwise be unlikely to come online at all.
Last, service agreements can include provisions for additional investments or service costs occasioned by the new load to be partially or completely recovered from the industrial customer. The Otter Tail Power TMEP tariff includes this requirement, and Antora reportedly worked with Otter Tail Power to build a 34.5 kV transmission line to connect its thermal energy storage installation to the grid.92 Passing these costs to the customer provides strong assurance that investments will not fall to other ratepayers. However, these provisions should not be adopted by default and should only be enacted alongside a tariff that produces substantial energy cost savings for the facility. Requirements to bear system costs should not unduly burden facilities or disincentivize electrification, as industrial electrification brings a host of social benefits and should be supported through smart grid investments.
A clean heat production tax credit (PTC) offers manufacturers a fixed tax rebate per MMBtu of clean heat they produce from clean technologies, such as a high-temperature industrial heat pump or thermal battery. Because it is pegged to clean heat output, this policy offers operating cost support for facilities that invest in electrification or other clean heat technologies, such as geothermal. In Oregon, we found a $10/MMBtu PTC has the largest effect of the policy scenarios tested in terms of bringing down operating costs.93
At the federal level, Senator Martin Heinrich’s Industrial HEAT Act offers a model for PTC policy design. Oregon’s state legislature could implement a similar policy so electricity suppliers and regulators are not entirely responsible for bringing down operating costs for facilities.
Many industries do not pursue process heat electrification or energy efficiency improvements even if they are likely to save money in the long run, resulting in an “implementation gap.”94 This highlights how industrial electrification also requires technical assistance, fuel switching incentives, and educational outreach.
Oregon already has strong technical support infrastructure that can help manufacturers evaluate their electrification options and find funding opportunities, such as the Energy Trust of Oregon (ETO) and the Oregon State University Industrial Assessment Center. ETO is a non-profit established under SB 1149 in 1999 and funded by utility ratepayers. It offers incentives and technical assistance for improvements such as energy efficiency upgrades. Expanding these programs to include specialized expertise in industrial HTHPs, electrode boilers, thermal energy storage, and geothermal systems could expose more manufacturers to these technologies and their benefits.
Additionally, ETO’s authority centers around energy efficiency, not explicitly decarbonization. ETO has historically maintained a Fuel Switching Policy where fuel switching from gas to electricity is not incentivized or encouraged. Advocates have highlighted the need for ETO to revoke the Fuel Switching Policy to allow incentivizing and encouraging customers to electrify.95 In 2025, advocates raised this in comments to the OPUC on ETO’s five year plan.96 The OPUC also recommended ETO collect data on electrification and explore electrification and dual-fuel strategies. ETO responded that it is exploring what actions can be taken.97 OPUC should further direct ETO to revoke the Fuel Switching Policy and create clear electrification and fuel switching incentives.
In addition to technical support, education and relationship building with industry is important to gaining industry support and participation. As part of the Portland Clean Industry Initiative, the city has spent time hearing from industry leaders and developing relationships to help encourage participation in upcoming funding opportunities.98 At the state level, similar education and convening efforts with industry, technical support, and government could help facilitate interest from industry and encourage the uptake of electrification.
Oregon can support pilots of emerging clean heat technologies such as geothermal, data center waste heat, industrial symbiosis, and thermal energy storage, all of which can reduce fossil fuel use and lower industrial energy costs. The state is well positioned for this, with strong geothermal potential and a large data center sector that could supply waste heat. Adoption is held back by upfront costs, retrofit needs, and space constraints. To address these barriers, Oregon should build on its industrial symbiosis work to pilot data center waste heat for manufacturing, fund geothermal and thermal energy storage pilots, and support workforce training and utility demand-flexibility incentives.