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Who Will Pay for Legacy Utility Costs?

New Energy Institute paper asks what the “electrify everything” movement could mean for natural gas customers who are left behind.

(Today’s post is co-authored by Catherine Hausman, an associate professor at the University of Michigan.)

The growing “electrify everything” movement aims to reduce carbon dioxide emissions by transitioning households and firms away from natural gas toward electricity. Already many cities in California and beyond have implemented electric-preferred building codes, heat pump subsidies, and other programs aimed at building electrification. 

Our new Energy Institute working paper asks what this energy transition means for the customers who are left behind. Reports have noted that remaining gas customers during the transition could see higher bills. We dig into this in depth. 

Growing and Shrinking Utilities

The current push for building electrification is still in its early stages, so it is too soon for an empirical analysis of how utility behavior responds to this policy push. Instead, we use historical evidence from growing and shrinking utilities as a proxy. Although mostly driven by population change, not building electrification, this evidence is a valuable opportunity to learn what happens when large numbers of customers enter and exit.

The figure below shows residential customer counts for a random set of U.S. natural gas distribution utilities during the period 1997-2019. The utility business is often thought of as stable and predictable, but we show that utilities have experienced a surprisingly large amount of recent change. We observe, for example, 320 utilities that experienced five or more consecutive years of customer growth, and 250 utilities that experienced five or more consecutive years of customer loss.


The shrinking utilities may seem surprising. But even though the total number of U.S. natural gas customers has increased 25% over this time period, many specific regions have lost population. Many utilities have lost customers, especially in rural areas, parts of the Southeast, Rust Belt, and Appalachia. Customer loss is particularly pronounced for small municipal utilities, but we also see it in cities like Philadelphia, PA and Birmingham, AL.

Utility Operations

In the paper we use evidence from these growing and shrinking utilities to understand how utility operations and finances change with customer entry and exit. The single largest asset for these utilities is the pipeline infrastructure. Accordingly, we compile data on the total number of pipeline miles operated by each utility, and we examine how this responds to changes in the customer base.

As the figure below illustrates, we find that when utilities are growing, they add pipelines. A 10% increase  in the  number  of  residential  customers  on average leads  to  a  4%  increase  in  pipeline miles. However,  when utilities are shrinking, they do not remove pipelines. A 10% decrease in the number of residential customers has a precisely estimated 0% effect on pipeline miles.  


Thus, utilities *expand* the distribution network during years of customer growth, but rarely *shrink* the network during years of customer loss. This makes sense. When a gas utility loses a customer, it generally doesn’t retire gas mains because other customers are still on that pipeline.

Utility Finances

We next perform a similar analysis using data on utility revenues. Utilities collect revenue from customers to pay for capital and operating costs, and we want to understand how these revenues respond to changes in the customer base. Part of our motivation for the paper is that many categories of utility expenditures are likely to be “legacy costs” that don’t necessarily disappear as customers leave the system.

This is exactly what we find. Similar to the pattern for pipeline miles, we find an asymmetric relationship between utility revenue and the size of the customer base. A 10% increase in residential customers leads to 10% increase in revenues. However, a 10% decrease in customers leads to only a 5% decrease in revenues. This pattern implies that some costs do stick around after customer exit and that remaining customers make up half the lost revenue through increased rates. 


This same dynamic is likely to play out in response to increased building electrification. During such a transition, it won’t be easy to retire pipelines until everyone in the network has discontinued service. Moreover, in addition to maintaining pipelines, the utility will still need to pay for legacy costs including past capital expenditures, pensions, and ongoing operations and maintenance.

Cost Shift

Finally, we use our empirical estimates to simulate future bill impacts for different levels of building electrification. 

Recent studies assume roughly a 15% reduction in natural gas residential customers by 2030; 40% by 2040; and 90% reduction by 2050. Our estimates imply that customer losses of this magnitude would mean annual bill increases of $30, $120, and $1,600 per remaining residential customer, respectively. 

The figure below summarizes our results. The cost shift starts out modest but then increases sharply as legacy costs become concentrated on an increasingly small number of remaining customers.


Did Somebody Say Utility Death Spiral?

Higher retail prices for natural gas will also accelerate the transition away from natural gas, prompting further customer exits, and thus additional price increases. While these dynamics will not last forever, an energy transition of this magnitude affects a large number of U.S. households and businesses, so it is critical to trace out the implications for both efficiency and equity. Figuring out the right set of policies to provide a path for decarbonization without hurting low-income households or pipeline safety will be challenging, and our paper provides some suggestions for policymakers.

We also see similarities between natural gas and electricity. There is a similar dynamic with electricity in that rooftop solar lowers utility revenues and can push fixed cost recovery onto low-income customers. However, buildings with rooftop solar generally don’t completely leave the grid. The mechanism in natural gas is different — customers depart entirely. Thus the standard rate reforms that are frequently suggested for rooftop solar, which assume that customers stay connected, would not address the fixed cost recovery and equity issues that arise with natural gas.

Fundamentally, cost recovery and natural gas utility operations and investment will need to be rethought so that the electrify everything movement is equitable.


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

Suggested citation: Davis, Lucas and Catherine Hausman. “Who Will Pay for Legacy Utility Costs?” Energy Institute Blog, UC Berkeley, July 7, 2021,

For more details see Davis, Lucas and Catherine Hausman. “Who Will Pay for Legacy Utility Costs?” Energy Institute Working Paper 317.

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 Faculty Research Fellow at the National Bureau of Economic Research. He received a BA from Amherst College and a PhD in Economics from the University of Wisconsin. Prior to joining Haas in 2009, he was an assistant professor of Economics at the University of Michigan. 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.

5 thoughts on “Who Will Pay for Legacy Utility Costs? Leave a comment

  1. I waited until after the webinar to post. I’m glad I did.

    The first solution to finding yourself in a hole is to stop digging. In this case, the “hole” is unamortized utility plant that is no longer used and useful. Here are a couple ideas to avoid making the problem worse that state utility regulators could implement promptly that will make a big difference. My thoughts below assume that the gas distribution utility MUST be retired to meet climate goals. I do not agree with those that think we can repurpose those pipes to carry renewable natural gas or hydrogen. The first has very limited supply; the second has very small molecules that require a different kind of pipe.

    a) Eliminate “free” line extension allowances to new customers. These are based on future expected margin from those customers, and we now know that this will be available for only a shorter period of time than the life of the plant. If developers have to pay the full cost of gas infrastructure, but still ALSO need to install electric infrastructure (under whatever line extension policy the regulatory deems equitable), they will stop installing gas.

    b) Put all natural gas utilities on depreciation schedules that amortize their plant between now and whenever the “net-zero” deadline is for that state. So, 2040 in Oregon, 2045 in Washington. That will slightly increase gas rates, and provide a new incentive for existing gas customers to shift.

    c) Require gas and electric utilities to do joint integrated distribution plans, so that we identify which gas distribution laterals will need to be retired or replaced, and ensure that the electric infrastructure needs to handle the conversion will be available when it is needed. None of us like to spend time planning for our own death, but doing so is very kind to those who will have to clean up our affairs at the end; the same applies to gas utilities.

    Those three items will make a huge difference.

    Now a few ideas on the practical aspects of retiring a gas utility. A gas distribution utility receives gas from a big pipeline, and I won’t comment on anything upstream of that point of interconnection. There are distribution “mains” which are larger pipes (6″ and larger) and distribution “laterals” which go through neighborhoods (typically 2″ to 4″). A “main” may serve several “laterals” of different ages.

    a) Terminate any programs that allow for automatic or accelerated addition to rate base of the costs of main refurbishment until a long-term retirement plan is in place. Many states have “infrastructure trackers” for gas distribution plant to address safety replacement. These should end, in favor of a main-by-main analysis with a regulatory decision of whether the main should be replaced or retired. These are big dollar investments, because they involve digging up and re-paving major streets (we saw a picture of this in the webinar).

    b) Identify the distribution lateral retirement schedule for each lateral, and begin working to help the customers on the laterals to be retired to prepare for the day when service is cut off. Begin with the leakiest laterals. If necessary to make geographic sense where a distribution mains will require retirement or replacement in a few years, accelerate the retirement of newer laterals that may have some longer life in them.

    c) Develop a program to assist consumers with the conversion costs, whether to propane or to electricity. This could use government funds, utility funds, a low-interest government-backed loan program, home equity loans, or some creative financing out of carbon fees or other sources. There are lots of ideas, and this note is not the place to discuss them. These conversions should be “efficiency-first” meaning we FIRST spend money on the building shell to reduce the amount of heat needed, before sizing expensive heat pumps to do the remaining work. We learned that mistake in Texas last winter.

    I’ll leave it there. Three ideas for regulators to do immediately. Three ideas for addressing some of the practical aspects of decommissioning a gas utility.

    Perhaps the best model for how to proceed is the wireline telephone industry. That industry has lost about 70% of its access lines since 1990. It has abandoned about half of its former geographic service territory (mostly rural areas) to cellular and satellite carriers. This was done without exit fees to departing customers, and, with a few exceptions, without catastrophic loss of service before alternatives were in place. Rate increases to remaining customers have been constrained by competitive forces. Accelerated depreciation was one of the tools used. An obligation to get permission to abandon service territory helped avoid loss of service was one of the tools used. The smart telecom companies moved into fiber, internet, television, and home security. The dumb ones have been through a bankruptcy (or two).

  2. Two thoughts:
    (1) “A 10% increase in residential customers leads to 10% increase in revenues. ”
    So much for economies of scale in a cost of service environment. This relationship implies marginal and average costs are equal for this industry. It also implies that we can break these companies into much smaller parts which likely will make electrification easier as we can handle each company is smaller bites. We could target smaller service areas for zonal electrification and retire whole systems in these smaller parts.

    (2) The first step in the equity question is to clearly identify shareholders as bearing a share of that burden. This is not just zero sum debate amongst ratepayers. Utilities try to portray this debate (and the one about solar rooftops) as a question of how to divvy up the costs amongst consumers, but we don’t have that debate in other industries, even in telcom when cell phones started making land lines obsolete. Industry obsolesce is a natural part of our economy (and we only need to look to Eastern Europe to see what happens when a whole system is built on trying to stop that process.) And a fundamental part of capitalism is that shareholders bear the costs of that obsolesce. That’s one of the risk factors that goes into the premium on the discount rate above time preference. How shareholders will share in these costs must be the opening topic because it determines whether and how much ratepayers then must bear.

  3. For many customers, other questions might also be important.

    • What will power heat pumps, as peak demand moves to the winter?
    • How much will heating with electricity cost, compared to heating with gas? (Is winter electricity likely to be generated by gas with CCS?)

    • This paper suggests you can meet load about 95% of the time using wind, solar and hydro. You need to use a fuel of some sort meet the last 5%. This model includes the new projected load from electrifying heating and transportation. Interestingly the team didn’t find a need to significantly expand transmission.

      There are multiple carbon neutral and carbon negative fuels that could meet this last 5%. Technically we could get all of this fuel from our waste streams but we’re likely to end up supplementing waste derived fuels with fuels derived from energy crops, hydrogen or X. Waste water facilities have historically burned the biogas they produce to provide process heat. We’re starting to see these facilities harvest their biogas, upgrade it to methane and inject this fuel into the natural gas network. The same sort of harvest and upgrade approach can be applied to black liquor in the pulp/paper industry.

      The paper that I referenced above didn’t electrify process heat. Once you get electricity costs down below $30/MWh you start to open up opportunities for electrification of industrial processes. It’s too early to tell how it will all play out but there’s a lot of potential for extracting fuels from industrial processes. It’s a shame California is currently burning their biomass/biogas fuels as if these facilities were baseload plants. What they should be doing is storing these fuels and using them to provide peak power – i.e. using them to help cover the last 5%.

      Click to access production-use-renewable-natural-gas-climate-strategy-united-states.pdf

      Saul Griffith has calculated that electrification should end up saving a typical household $1000 to $2500 a year in energy bills.

    • Here’s a better estimate from NREL for the potential of waste to energy (WTE).

      To convert the energy value of waste resources into electricity you divide the energy content by the heat rate. Typical heat rates for combined cycle plants are 6.5 to 7.0 mmbtu/MWh. If you apply this conversion to the NREL estimate of 2.3 quads you end up with 325 to 350 TWh. One caveat to note here is that you can’t convert the 2.3 quads directly into high quality gaseous fuels like methane. So for example only about 50% of the energy content of black liquor can be converted into methane. In practice there would be fractions of the waste stream which could only be utilized at heat rates of more like 10 to 12 mmbtu/MWh. The general point is simply that wastes could technically cover a significant portion of the residual load hours in 100% renewable grid.

      “The total annual energy potential of wet and gaseous waste resources in the United States, including wastewater residuals, animal waste, biogas, and black liquor, is estimated to be more than 2.3 quadrillion British thermal units (Btu) (DOE 2017).”

      Click to access 77166.pdf

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