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What Matters for Electrification?

Electricity is replacing on-site fossil fuel consumption for U.S. home heating, and energy prices explain why.

Berkeley was the first, but now more than thirty municipalities in California have enacted measures limiting or prohibiting natural gas in new homes.  The list includes San Francisco, San Jose, and most recently, Oakland

Proponents argue that electrifying buildings is critical if the U.S. is to sharply reduce carbon dioxide emissions from the building sector. Critics argue that electric heat costs more per unit of heating, so electrification mandates are expensive.

Mostly missing from this discussion, is that home electrification is nothing new. In a new Energy Institute working paper, I document dramatic growth in residential electric heating over the last seven decades and ask two questions: (1) What explains this increase? and (2) How much would U.S. households be willing to pay to avoid an electrification mandate?


Growth in Electric Heating

Only 1% of U.S. homes in 1950 used electricity as their primary heating fuel. Electric heating has increased steadily since that time, reaching 8% in 1970, 26% in 1990, and 39% in 2018. Electricity is today the dominant form of heating in the Southeast and widely used throughout the West and Midwest.

What explains this increase? The paper proposes and tests five hypotheses. To distinguish between the different explanations, a statistical model is constructed using data on heating choices from millions of U.S. households over the period 1950-2018. There is considerable inertia with home heating decisions, so the model is focused on the initial heating choice at the time each home is constructed. 


Prices, Prices, Prices

The five explanations are shown to collectively explain 90% of the increase in electrification since 1950. But by far the most important single factor is energy prices. U.S. residential electricity prices have fallen over 50% in real terms during this time period, while residential natural gas and heating oil prices have both increased.

Residential Electricity Prices By State

The statistical model reveals a pronounced negative and statistically significant relationship between electricity prices and electrification. The effect is large in magnitude. Everything else equal, going from 21.6 cents per kWh (the current price in Massachusetts) to 9.6 cents per kWh (the current price in Louisiana) implies a 32 percentage point increase in electric heating.

Changing energy prices explains 70% of the increase in electrification since 1950. This is a large share; much more than I would have guessed, frankly. Changes in other factors like where new homes are built, housing characteristics, and climate also matter, but collectively can explain only about 20% of the increase in electrification since 1950.  

Changes in household income have had almost zero impact. Electric heating is convenient and has no on-site emissions, so I had hypothesized that rising incomes since 1950 would help explain the shift. I was wrong. Turns out that higher income households are actually slightly less likely to choose electric heating, but the effect is so tiny that rising incomes over this period can explain essentially none of the increase in electrification since 1950.


Policy Implications

So the big policy takeaway is that energy prices matter for electrification choices. This finding underscores the importance of pricing energy efficiently, a central theme in energy economics and a favorite topic at the Energy Institute blog. 

California is an illustrative example. At the same time dozens of municipalities are banning natural gas in new homes, the state is also continuing to make policy and retail rate design choices resulting in some of the highest electricity prices in the country.  

Energy Institute researchers Severin Borenstein and Jim Bushnell find that the price per kWh in California is two or more times higher than the actual incremental cost of providing electricity. These high prices mean that California households have too little incentive to electrify, and it is no coincidence that electric heating is much less common here than in neighboring states.

Regulators can  mandate and ban natural gas for new buildings. However, without additional policy and rate reform, California’s high electricity prices mean that electrification mandates will raise costs for households. 


Willingness to Pay

How much would U.S. households be willing to pay to avoid an electrification mandate? The working paper next uses a discrete choice model to calculate willingness-to-pay. Households weigh energy prices, climate, geography, housing characteristics, and other factors when making heating system choices and willingness-to-pay is inferred based on revealed preference. 

Willingness-to-Pay to Avoid an Electrification Mandate

Households in warm states are close to indifferent between electricity and natural gas, so a mandate would cost them less than $600 annually, on average. In Florida, for example, most households prefer electricity anyway so a mandate would impose low economic costs.

However, households in cold states tend to strongly prefer natural gas so would be made worse off by $2500+ annually, on average. Households in New Hampshire, for example, use a lot of heating, and by revealed preference would be willing to pay a significant amount to continue having access to natural gas.

The model also reveals considerable variation within states. For example, households in multi-unit homes have lower demand for heating and thus lower willingness-to-pay to avoid mandates. These households thus represent a potential opportunity for electrification.

An important caveat is that the model is estimated using historical data, and thus cannot speak to how the impact on households will be affected in the future by technological change. Probably most importantly, electric heat pumps are expected to continue becoming more energy-efficient over the next several decades. This will increase acceptance of electrification and decrease the costs of a mandate.



One broader implication of the research is that, nationally, it may be a lot easier than is generally believed to encourage electrification. The steady historical trend over the last seven decades means that 50 million U.S. households have already electrified. Moreover, the analysis identifies large numbers of additional households for whom adopting electric heating would impose relatively modest costs.

An important goal for future research is to ask whether electrification mandates pass a societal cost-benefit test. These willingness-to-pay estimates provide a starting point, but they are calculated based on current residential energy prices and thus reflect private, not social, costs. These costs would then need to be compared to the benefits from reduced fossil fuel emissions. At a high enough social cost of carbon, electricity could make sense from a societal perspective even in places where it imposes large private costs. 

Of course the generation mix matters too. U.S. electricity generation has become much cleaner, but emissions vary regionally and there are large parts of the country that continue to rely heavily on coal. The economic case for electrification is strongest in places where electricity generation is relatively green.

Keep up with Energy Institute blogs, research, and events on Twitter @energyathaas.

For more details see Lucas W. Davis, “What Matters for Electrification? Evidence from 70 Years of U.S. Home Heating Choices”, Energy Institute Working Paper.

Suggested citation: Davis, Lucas“What Matters for Electrification?” Energy Institute Blog, UC Berkeley, January 4, 2021,


Lucas Davis View All

Lucas Davis is the Jeffrey A. Jacobs Distinguished Professor in Business and Technology at the Haas School of Business at the University of California, Berkeley. He is a Faculty Affiliate at the Energy Institute at Haas, a coeditor at the American Economic Journal: Economic Policy, and a Research Associate at the National Bureau of Economic Research. He received a BA from Amherst College and a PhD in Economics from the University of Wisconsin. His research focuses on energy and environmental markets, and in particular, on electricity and natural gas regulation, pricing in competitive and non-competitive markets, and the economic and business impacts of environmental policy.

26 thoughts on “What Matters for Electrification? Leave a comment

  1. I wouldn’t count out other heating options entirely. For example, perhaps with clean combustion and catalytic converters pellet stoves could be environmentally acceptable and achieve a low carbon footprint? Some cold areas have a good supply of forestry byproducts, and heat pumps function less efficiently in severe cold. By focusing solely on electric heating to the point of subsidizing it might be closing off some limited alternative possibilities.

  2. By the way, NREL is hosting a webinar with an update on their big Electrification study:

    Join a free #webinar on Thursday, Jan. 14 to learn about the latest findings in the NREL’s Electrification Futures Study! You’ll get insight on the potential evolution and impacts of the U.S. power system with widespread #electrification. Register at

  3. Lucas, electric heating makes economic sense in areas with either or both of the following characteristics: 1) temperate weather, or 2) cheap electricity. The locations shown on your map are all temperate except the Pacific Northwest, where hydropower is abundant and cheap.

    “Berkeley was the first, but now more than thirty municipalities in California have enacted measures limiting or prohibiting natural gas in new homes.”

    Prohibiting natural gas in new homes then heating them with electricity generated at 65%-efficient gas plants (at night, when California solar is generating nothing) makes no environmental sense at all. Until California reverses its trend of both: 1) building new gas plants, and 2) outsourcing emissions to other Western states (via the Western Energy Imbalance Market), electricity customers and the environment are clear losers.

    For those who thought California was closing its gas plants, think again:

    “This year the Stanton Energy Reliability Center, a 98 MW gas-fired peaking plant, has started up. In addition, 1,280 MW of gas-fired generation was added at two AES Southland Development LLC sites to replace banned seawater-cooled plants. In addition, regulators last month extended the operating lives of four coastal plants.

    However, 705 MW of gas-fired peaking generation already approved remains on the drawing board, according to the California Energy Commission (CEC). Last year, 527 MW of gas-fired peaking was brought online as part of another coastal plant site repowering at the Carlsbad Energy Center in San Diego County.”

    Those who thought Diablo Canyon would be replaced with clean electricity can think again, too. The California Public Utilities Commission admitted in November it will need to replace all of Diablo Canyon’s carbon-free electricity with imports – and if it’s anything like San Onofre, it will come from coal and gas plants in Nevada and Wyoming, conveniently re-labeled as “unspecified sources.”

    • Don’t confuse plants used for peaking purposes running at capacity factors less than 5% as being used to power home space heating. As I posted a couple of weeks ago, the EIA (and the CARB) show that natural gas generation has been steadily declining since 2000, even through a recent 5 year drought. The important factor is to focus on the overall long run generation mix. Even if an all electric building is supplied by gas generation this year, that will not be the case in the near future and certainly won’t be with a couple of decades. Given that we will go from 33% renewable to at least 50% renewable over the next decade, the increase in electrification will be served by the incremental new generation–renewables–and not the “marginal” generation supposed reflected in the CAISO markets. (This is why pointing to short run marginal costs and equating that with the added resources is an analytic mistake.) Buildings have a life of at least half a century and longer and it very expensive to retrofit them to a new HVAC technology. So the most cost effective policy is to compel all electric when they are built with the knowledge that the electricity will by carbon free soon.

      I see no gas additions in the CPUC’s 2021-22 transmission planning portfolio:
      I can’t find a citation to the November statement that you reference. Is this what you’re referencing? . (A complaint filed at FERC by your group.) If so, I suspect you’re confusing the replacement of Diablo’s CAPACITY with replacement of its ENERGY. Because Diablo provides no local capacity, it’s system capacity can be replaced with appropriate out of state capacity because the power has to be exported to the Bay Area and Southern California regardless which leaves the same transmission exposure.

      • “Given that we will go from 33% renewable to at least 50% renewable over the next decade…”
        Your “given” has no basis over the next decade, or ever.

        The only economies in the world with more than 50% renewable electricity can be counted on one hand (Brazil, Iceland, Denmark, Colombia?). All four have abundant natural resources – ones that aren’t scalable. The economies of two, Brazil and Colombia, are struggling with the unreliability of hydropower – the most reliable source of renewable energy. Denmark, with the priciest electricity in the EU, also happens to be the windiest country on Earth. Iceland has abundant geothermal power, and the population of Bakersfield.

        “If so, I suspect you’re confusing the replacement of Diablo’s CAPACITY with replacement of its ENERGY.”
        Caps-lock notwithstanding, I have no idea what this statement is intended to mean; it doesn’t make sense. We’ve run into this issue repeatedly in prior discussions.

        “Because Diablo provides no local capacity…”
        Of course it does. Per Wikipedia, it offers 2.3 gigawatts of nameplate capacity, and you can assign to it whatever arbitrary category you prefer (local? system? The designations are equally affected). Because its capacity factor is very near to 100%, it’s virtually always generating 2.3 gigawatts of power.

        “…it’s system capacity can be replaced with appropriate out of state capacity because the power has to be exported”
        More nonsense. Power is the rate of energy transfer; as such it can’t be exported, imported, sold, or painted red.

        “…to the Bay Area and Southern California regardless which leaves the same transmission exposure.”
        I couldn’t begin to imagine what ‘transmission exposure’ is, but it sounds terribly contagious.

        • 50% RPS by 2030 is state law:'s%20RPS%20program%20was%20established,a%2050%25%20RPS%20by%202030.

          I’m not sure why you don’t understand this. Capacity is about reliability which currently is measured at available capacity at the peak load moment. Energy is about the provision of electricity continually over the 24 hour period of the day. Capacity is about an instantaneous moment of demand; energy is about the work of powering and lighting. The FERC complaint that you’re group filed is about capacity requirements, and NOT about energy production from Diablo. If you don’t understand the distinction, then you’re are truly missing what the debate is really about on resource planning in California right now. (And I use caps because we can’t use italics or bold here.)

          Diablo does NOT provide local capacity resources as defined by the CPUC–it provides system capacity. Again, please gain an understanding of the issues that you’re opining on if you are trying to be authoritative. See this website for a definition of these categories.

          You should also try to understand how the state’s transmission system is set up. Diablo sits outside the rings of the Los Angeles Basin and the Bay Area. SONGS sat at a key corner of the Los Angeles and San Diego areas and was considered a local capacity resource. Once a generation resource is outside of these rings, their relative capacity value compared to other remote resources, e.g., PVNGS, is about the same because the transmission lines become the vulnerability rather than the generation resource. The question then is about whether congestion will diminish the capacity value of the resource.

          • “50% RPS by 2030 is state law.”

            And you believe the proponents of SB-100, resting on their natural-gas-financed laurels in retirement, will give a squat when it doesn’t come to pass, do you? Please.

            “Capacity is about reliability which currently is measured at available capacity at the peak load moment.” Very impressive, Richard. But as Stravinsky remarked after seeing The Rite of Spring used as a soundtrack for Walt Disney’s Fantasia: I’m unable to comment on such unresisting imbecility.

            Have a nice evening.

          • The RPS law that will drive reaching 50% renewables includes a fine of $50/MWH on shareholders for failing to reach it. PG&E is already contractually committed to being at 46% renewables in 2030 (and even higher if their customer load declines further) and most CCAs are near or beyond 50% themselves.

            You may consider this widely accepted definition of capacity as an “imbecility” but it is how the nation’s planning, operational and regulatory framework is structured. This is the setting in which utilities operate today. You need to show that’s not the case to prove your point. Otherwise you are irrelevant.

          • The definition of renewables in California doesn’t include large hydro. I have posted on Twitter more than 3 years of CAISO (80% of California and a bit of New Mexico) daily renewables, and will post year end summaries once more CAISO information is posted.

            Not counting rooftop solar, these are the 2020 numbers:
            • solar 13.7%
            • wind 7.2%
            * total renewables 27.5% (includes solar, wind, small hydro, biogas, biomass, and geothermal,)

            To get these high numbers, many times, prices were negative, as CAISO paid other states to take the non-renewables being generated at the same time (at least, I presume CAISO kept renewables and only sold gas).

            Higher numbers for CAISO renewables include renewables built out of state, so they don’t have to be integrated into the CAISO grid.

            All parts of the world getting half or more of electricity from renewables generate a lot of hydro and/or geothermal. (Note: hydro won’t bring California to half, at least not this year.) On the other hand, other countries likely count rooftop solar. (A guess, rooftop solar adds 5-7% to California generation, and 5-7% to California demand, so all generation numbers need to be divided by 1.05 to 1.07.)

            My assumption is that requirements for 50-60% renewables will include lots of renewables bought out of state, eg, wind in Wyoming.

            Wyoming wind appears to be a better match for heat electrification than California wind, although I have not seen daily data, and wind varies by year. (A recent lecture said that El Nino years have less wind. Maybe)

  4. A common weakness in such arguments comes from the fact that an all-electric system cannot currently duplicate the services provided by some fuel-fired appliances, at least in any reasonable way. Heat pump heating, for example, cannot provide the capacity to recover temperature (in a home or a water tank) as quickly or cost effectively as a gas appliance. Despite the improvements in electric cooking due to induction systems, gas still provides more flexibility and options in a cooktop. It takes much less backup electricity to power a gas home in a power outage than an all-electric one.

    While we may all agree that the long-term goal is to drastically reduce FOSSIL fuels, that does not mean that fuels, in general, are a bad thing. Chemical energy (e.g. in the form of fuels like hydrogen or alkanes) has many advantages in terms of storage, transportation and use. It may well turn out to be the optimal match to renewable energy generation’s intermittancy.

    Improvements in technology can certainly lessen the current downsides in full electrication, but that is not necessarily the long-run answer. Technology will certainly advance, but will also do so in areas which would suggest that an increase use of fuels is desirable and we want to make sure we keep that infrastructure in the interim. I am quite sure that the push for electrification is at least too early and too hard and could easily result in the same kind of regrets we had the first time round in both electriciation and conservation. We should not assume we know the right answer as those who are closest to something are often the least able to predict its future.

    ‘There are more things in heaven and earth, Horatio, than are dreamt of in your philosophy’

    • Professor Sherman
      Have you used an induction cooktop? And have you included the environmental costs of gas in your calculation of cost effectiveness for heating water and building space?

      As for power back up, the vast majority of customers do not use back up generators and just ride out a black out. The most cost effective solution to extended blackouts is microgrids versus grid hardening. While storage may not yet be entirely cost effective, we can see the day when that is likely to occur. Remember a decade ago few could envision that solar power would be less costly than gas generation. (I wrote the study for the CEC in 2009 looking at these projections at the time.)

      I’m not sure of regrets in conservation that you bring up. The only one that comes to mind was the premature push for CFLs, but that was largely brought on by the self interest of investor owned utilities who saw my manipulating assumptions about usage and bulb life that they could make an easy profit in the incentives from the CPUC.

    • “Chemical energy (e.g. in the form of fuels like hydrogen or alkanes) has many advantages in terms of storage, transportation and use.”

      Hydrogen has no advantages over gasoline in storage, transportation, or use. A fuel with a ridiculously low energy density, it must be compressed to 8,000 lbs./in², or refrigerated to -212°C, or both, then stuffed into canisters to be usefulfor automotive transportation. Yet lately it’s somehow become all the rage. How?

      Shortly after the General Motors EV1 electric car was introduced in 1997, Chevron, Shell, and other oil majors recognized gasoline’s future was limited. The sober realization 50,000 U.S. service stations would have nothing to sell prompted them to investigate other liquid fuels, and several possibilities were considered before they agreed upon hydrogen. Though made from “natural gas” (methane) using a process that emits vast quantities of CO2, hydrogen offered a unique marketing advantage: all that comes out of a a fuel-cell vehicle’s tailpipe is water vapor. Hydrogen would thus be marketed as a “clean alternative” to gasoline.

      The quest to sell hydrogen to a wary public has advanced in fits and starts ever since. After word got around it was little more than methane with a pretty face, oil majors insisted natural gas would only serve as a fossil fuel “bridge”. In the future, we were told, hydrogen would be produced by electrolyzing water with energy provided by renewable solar and wind. When that glorious day arrives, supposedly, oil companies would shut their doors and call it a day

      As oil companies continue to test market clean-fuel alternatives-that-aren’t, we need to view all sources of clean chemical energy with skepticism. Unless a new carbon-free compound is discovered with energy that can be harvested from its chemical bonds without releasing pernicious byproducts, we’re very likely looking at fossil fuel with another pretty face.

      “I am quite sure that the push for electrification is at least too early and too hard and could easily result in the same kind of regrets we had the first time round in both electriciation and conservation.”

      Agreed. The first step is making abundant, clean electricity, in quantities yet unrealized by wind and solar farms. When it becomes obvious those sources won’t pan out, it’s very possible electrification undertaken now could lock in dependence on methane for decades – a big step backwards, at a time we can least afford to take one.

  5. Two critical variables relevant to this discussion– while California’s energy prices are high, the increase in energy efficiency (and presumably behind the meter generation) has resulted in lower electricity demand than projected by CAISO–so energy cost to California households should be looked at based on total bills, not just price per kWh…
    Secondly for economic modelling, strongly agree with Lucas Davis on importance of including externalized costs and benefits–gas looks “cheap” when direct health and climate costs are excluded.
    I do agree with the takeaway that electricity prices –and total bills–are important in order for “beneficial electrification” (thanks RAP) to succeed. So energy conservation and energy efficiency (esp via codes, as Jim Lazar notes) are crucial to minimize demand from increased electrification.
    Furthermore, an accelerating part of CA investor owned utility revenue requirement (and hence customer bills and IOU/shareholder ROI) is due to transmission infrastructure, as documented in the CPUC annual report to the legislature–increasing 2 to 5 fold over the period 2008-2018, as well as distribution infra-structure. Getting these components “right-sized”, as well as open to third party access for innovation, will be essential to affordable electricity, a responsive grid, and successful electrification.

  6. Jim,

    “Putting out three units of heat for each unit of electricity consumed, modern heat pumps mean that even higher electricity prices may not be a barrier.”

    This is only true when the ambient (outside) temperature is substantially above freezing. Heat pump conversion efficiency falls off as the ambient temperature goes down. When ambient temperature reaches a few degrees below freezing the heat pump is essentially useless, at which point resistance heating kicks in, providing only one unit of heat for each unit of electricity consumed.

    In Northern states that experience cold winters (e.g., Maine or Wisconsin) heat pumps will always have difficulty competing with natural gas or fuel oil.

  7. I have a number of questions:
    • Even if we shift to heat pumps, isn’t it true that there will be days when US heating demand alone is larger than summer grid requirements? Generating capacity will need to expand, a lot. Note: wind is down in most places on especially cold days.
    • Shifting to green electricity is fine, but electricity is greener in the spring, and least green in the winter, except where there is a lot of winter hydropower. What clean generation sources will supply winter heat? I presume that California intends to shift to boucoup gas with carbon capture and storage.
    • How does decarbonizing via electrification of heating compare to replacing fossil gas with hydrogen? The hydrogen would presumably be made by a source of firm capacity.

    • On your last point, the most significant problem is transporting hydrogen significant distances. Hydrogen corrodes the metal used in most existing natural gas lines, and it will have to be compressed significantly to deliver sufficient volume. Instead of replacing the gas infrastructure, it’s probably more cost effective to generate electricity near the hydrogen production facility, and then to use the electricity instead of gas in buildings.

      If small scale electrolysis becomes cost competitive, we might see it used locally, but then again more likely in fuel cells to produce electricity.

    • Karen Street raises important questions about the shift of load causing imbalances in the power system. For the past half-century, the Pacific Northwest and California have been interdependent, with 8,000 MW of transmission connecting us. California was summer-peaking, the Northwest winter-peaking. Power flowed South every summer, and flowed North most winters. It was a synergistic relationship.

      But the Northwest has added a lot of air conditioning load, and has less of a summer surplus. California is adding heating load, and will have less of a winter surplus. Long-term storage, such as hydro, is pretty limited in California, and the trend is to LESS (think the settlement of the Klamath River dispute) rather than MORE large-scale hydro storage. Several studies have showed that if California converts even half of space heating from gas to electricity that the state will become a winter-peaking load. The regional synergy is likely to disappear.

      Hydrogen is unlikely to be much more than a bit player. It requires expensive production facilities and expensive storage facilities. Converting water to hydrogen with electrolysis is only about 50% efficient. Converting that hydrogen back to electricity in fuel cells is only about 60% efficient. So you end up with only 30% of the original electricity, compared with 80% to 90% with battery or pumped hydro storage. Storing the hydrogen seasonally is possible, in underground salt domes, but that is not cheap.

      Using hydrogen directly for space and water heating would require dramatic changes to the pipeline system and appliances. We can blend a little bit into a natural gas system, but that won’t get us anywhere near zero net carbon. And, finally, if hydrogen is produced using non-firm wind and solar, it will be a lower price premium — but also a lower reliability result. Dedicating firm resources to hydrogen production will be very expensive.

      I put hydrogen in the same category as nuclear and geothermal: attractive technologies from a technical perspective, but very expensive. I don’t consider hydrogen to be a big future player — but there are niche uses, such as industrial process heat, where it will be valuable and important.

      The big challenge will be long-term storage. A few hours here and there is easy to do with batteries, which are becoming cheaper year-by-year. But months of storage will be a huge challenge. We must meet that challenge. I look forward to the contributions of others on what those long-term storage solutions will be.

    • Today the cost of producing hydrogen cannot compete with natural gas. However, if we are to get to net-zero, natural gas will need to be phased out so cost (that does not account for externalities) will be less of a barrier.

      But there is a more promising solution: producing hydrogen through electrolysis, then converting it to synthetic methane through a process that extracts carbon from atmospheric CO2. This is a very energy-intensive process but if we have lots of excess renewable energy available during the summer months that energy will be free.

      Numerous studies (by Perez, Jenkins, et al) have concluded that it is more cost-effective to deal with the seasonal variation in renewable energy production by overbuilding the facilities, rather than to rely on seasonal storage.

      One huge advantage to synthetic methane is that it can take advantage of the existing gas pipeline and storage infrastructure and can be burned in existing gas turbines.

      • Robert
        The counterbalancing problem is the leakage in the gas distribution system with methane having such a high global warming effect. It might be possible to use synthetic methane in industrial uses where leakage is less of an issue, but its much less attractive for building use.

  8. Three factors that SHOULD influence people’s preference for electric heating as:
    a) the efficiency of new electric heat pumps;
    b) the efficiency of new buildings, and
    c) the shift of new construction from single-family homes to smaller dwelling units: apartments, townhouses, and condos.

    Putting out three units of heat for each unit of electricity consumed, modern heat pumps mean that even higher electricity prices may not be a barrier. In climates with an air conditioning need (about 90% of new home construction occurs in these areas), a heat pump may be both a lower first-cost option and a lower operating-cost option, compared with separate air conditioner and furnace.

    Another important factor is the greatly improved energy efficiency of new construction. The Washington State Building Code Council just released a new study, comparing actual energy usage in homes built to the 2006 code vs. homes built to the 2018 code. About a 50% reduction in usage for the natural gas heated homes. That’s from a combination of building shell improvements and appliance efficiency improvements.

    What’s interesting is that the usage of newly built natural gas heated homes is now so low, that if the state Utilities and Transportation Commission ever updates the line extension allowance to reflect these figures, builders will be paying the gas utility about $3,000 just to run the pipes to the new homes. At that point, builders might instead choose to spend $2,000 to install a heat pump (over a furnace), and forget about the gas line. The 2021 code will be even more stringent.

    I suspect the same is true in other states that modernize their codes, of which California is a leader. As the building uses less and less energy, it becomes infeasible to support two sets of energy infrastructure to every home. Gas will lose out.

    Housing cost is a part of this. As the cost of housing in many regions continues to rise faster than income growth (and as US household size continues to decline, from 3.33 in 1960 to 2.53 today), people increasingly choose smaller and smaller dwelling units. In small dwelling units, energy usage is so low that the cost of supporting two sets of energy infrastructure for each home becomes economically infeasible. Fire code requirements may also make natural gas installation in apartments a challenge. Indeed, the Washington code study assumes that 100% of new multi-family structures are electric-only. That market segment has grown from about 20% of new housing when I served on the Energy Code Technical Advisory Group a few decades ago (in the sprawl era) to more than 50% of new housing today. It may be that housing type shift is as powerful a driver as energy costs or appliance costs in fuel choice.

    The Washington “2018 Baseline Study” is available at:

    Click to access SBCC%20BaselineStudy%20Revised_inclusive%20Final_2020_Nov6.pdf

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