3 Scenarios Examine the Future of the Natural Gas Industry in the Context of Decarbonization Policies
NED ALLIS & GREG HERBERT
Addressing climate change has become an increasingly urgent topic of discussion globally, and many countries have moved to reduce their greenhouse gas emissions significantly. In the U.S., the president’s April 2021 announcement of a goal to reduce greenhouse gas emissions to half of 2005 levels by 2030 provides a direction for federal policy. Several states have taken more significant actions, including setting targets for emission reductions by 80% or more in New York, California, and Massachusetts within the next 30 years.
Emission reduction targets may have profound effects on a variety of industries, including transportation, manufacturing, power generation, and residential heating. While it is uncertain how and to what extent each sector will be affected, natural gas utilities could be impacted. Changes could range from modifying distribution systems to incorporate other fuels to the migration of gas customers to other energy sources. These changes will likely affect the price of natural gas delivery.
Modeling Price Impacts
Natural gas distribution companies in the U.S. are regulated monopolies for which prices are established by state jurisdictional utility commissions. One of the most significant factors in establishing a utility’s revenue requirement is depreciation expense (the return of capital). This represents allocating the capital costs of a company’s assets to each period of service over their useful lives. This blog examines three scenarios using different depreciation approaches in the context of state greenhouse gas emissions policies to assess the resultant financial impacts. Each assumes that such policies would result in a 50% reduction in gas demand by 2050 and a similar 50% reduction in the number of gas customers. We note that our analysis is not intended to suggest that such reductions in demand or customer counts are the most likely future state. However, the scenarios below illustrate the impact on gas delivery prices in the event of such outcomes.
Scenario 1: The recognition of the impact of emissions reduction on depreciation expense is delayed. A 45-year average remaining life, consistent with the company’s historical experience, is used initially and then gradually shortened each time a depreciation study is performed and estimates of service lives are updated. The straight-line method is used for depreciation — capital costs are allocated in equal amounts to each year of the service lives of the company’s assets.
Scenario 2: The average remaining life is shortened to 30 years to better align with 2050 carbon emissions targets. The straight-line method is used for depreciation.
Scenario 3: The average remaining life is shortened to 30 years, and the units of production method is used. This method allocates costs in proportion to consumption rather than equal amounts each year.
Long-Term Price Impacts
Figure 1 shows the annual depreciation expense on a per-customer basis through 2050. Due to capital replacements over time and the incremental costs that result from these replacements, depreciation expense increases for each scenario on a per-customer basis. However, both straight-line method scenarios (Scenarios 1 and 2) increase significantly over time, whereas the units of production scenario (Scenario 3) result in a more gradual per-customer increase each year.
Figure 1: Annual Depreciation Expense Per Customer ($)
Scenario 3 results in a higher depreciation expense on a per-customer basis at first, but over time there is a more equal distribution of depreciation expense per customer when the number of customers declines significantly. Scenario 1 shows that delaying the recognition of the impact on depreciation of shorter service lives and declining demand results in lower depreciation expense initially but ultimately results in a sharper increase over time. The cost per customer is highest in 2050 for Scenario 1 compared to the other scenarios, with depreciation expense increasing nearly five-fold on a per-customer basis by 2050.
Figure 2: Average Annual Cost Per Customer ($) – Depreciation Expense and Return on Rate Base
In addition to the annual expense impact on customer rates, depreciation also reduces the “rate base,” or the balance on which a utility earns a return on its investments. Figure 2 illustrates the impact of each scenario on both depreciation expense and the return on rate base in each year. In both Scenarios 1 and 2, the combined cost of depreciation expense and the return on rate base increases significantly on a per-customer basis. This is most pronounced in Scenario 1, where customers in 2050 pay more than twice as much on a per-customer basis as those in 2020. In contrast, Scenario 3 results in only moderately higher costs in 2050 than those in 2020. Because the units of production method allocates costs in proportion to gas consumption, the costs are spread more evenly over the entire 30-year period on a per-customer basis.
Planning for the Future
When there is the potential for significant technology- or policy-driven change, higher costs today can mean lower costs in the future and a more equitable share of costs overall. In contrast, lower costs today can lead to higher costs in the future.
For natural gas utilities in certain states, policy changes will likely result in the need for higher depreciation expense as natural gas assets must be recovered through depreciation more quickly. This does not mean that gas systems will go away, but rather that infrastructure will be either retired or replaced more rapidly than in the past as the usage of a gas system evolves. While higher depreciation expense today has the short-term impact of creating higher prices paid by customers, over the long-term higher depreciation can help mitigate the potential for much higher price increases in the future.
Additionally, delaying the recognition of the impacts of policy and technology changes will not affect all customers equally. Reductions in gas demand and customer counts will impact gas prices and affect cost equity among different generations of customers. Our modeling results suggest that addressing these considerations is best done sooner rather than later to allow sufficient time to implement policy decisions in as equitable a manner as possible and mitigate long-term price increases and potential harm to future gas customers.
ABOUT THE AUTHORS
Ned Allis
Vice President, Sr. Project Manager, valuation and rates
