Emerging Cost and Affordability Challenges in Time of Transition

Utility investment is a constant in traditional, rate-of-return regulatory constructs. It builds rate base and provides reliable and affordable electric and related services to customers. End-user costs of electricity have been relatively stable over at least the past decade.

Increased wholesale competition, consolidation (with scale economies), and low natural gas prices along with an increasing proportion of energy provided by gas-fired generation, among other things, have given U.S. customers abundant, low-cost electricity. Price moderation has also been assisted by the introduction of zero-marginal-cost energy from renewable resources. Moreover, electricity prices have moved in relative sympathy with broader, moderated inflationary trends.

By and large, low fuel costs (and related low purchased power costs) have helped stabilize customer bills and avoid significant rate impacts even as increasing capital expenditures on initiatives such as grid modernization have been added to rate base. Looking ahead, however, over the near to medium term, it is unclear whether and when a return to a low fuel cost regime may occur.

Increasing Investment Ahead

Utilities, however, are expected to significantly grow investment in all elements of the electricity value chain to reflect changing customer needs, public policies, increased operational risk from climate- and cyber-related events, and new technologies.

• In distribution, electric utilities will invest in accommodating building and vehicle electrification, rooftop solar, modernizing the grid (e.g., smart meters, distributed energy resource management systems), adding energy storage and other non-wires alternatives, as well as expanding efficiency and demand response programs.
• In transmission and system operations, capital is needed for expanding regional footprints, interconnection of renewables, resilience and safety (e.g., wildfire reduction) investments, load growth in growing regions, electrification, and investments in resource adequacy and flexible resource procurement.
• In generation, utilities and merchants will be adding new resources (both dispatchable and variable and emitting and non-emitting), increasing gas interconnections, and piloting new technologies (hydrogen, advanced nuclear, carbon capture, utilization and storage).

With controversy over further hydrocarbon development and geopolitics and global LNG playing a larger role in demand for hydrocarbons, low fuel prices may no longer offset rising capital investment costs. This comes at a time when fundamentals that have underpinned utility ratemaking in recent decades are also shifting:

• The industry has long relied on volumetric charges; this becomes a potentially less appropriate model as programs like energy efficiency, demand response, and resilience and system hardening are more demand or reliability based rather than usage driven.
• After a long period of relatively modest cost increases for utility spending, higher inflation (especially for commodity and labor costs), may increase investment requirements.
• After a decade of low to near-zero Federal Reserve policy rates, a higher interest rate environment, along with expected higher expected returns, could increase financing costs.

What Does It Mean for Customers and Utilities?

An emerging concern is about energy affordability or “energy burden”—i.e., the share of household income needed to pay home energy costs. Regulators will be sensitive to affordability (as are utilities) and will be monitoring and managing effects on households as investments in modernization and decarbonization/transition increase. In particular, utilities can expect more attention to affordability metrics, assistance programs or alternative rates, non-rate public sources of funding, and the impacts of cost allocation.

Rate design may need to evolve as more fixed, non-volumetric-driven costs are introduced into the system. For example, while more zero-marginal-cost resources are introduced into the power system, potentially higher-cost decarbonized and dispatchable flexible resources may also be required to accompany them as stand-by resources.

Grid investment will continue to grow to accommodate distributed energy resources, enable resiliency, and provide flexibility. Energy efficiency and demand response will likely become even more valuable, making load more fungible in response to intermittent generation resources. The investments to make the grid flexible enough to manage new sources and loads are critical; they also introduce the question of how best to recover and pay for them.

Utilities, regulators, and stakeholders needs to strike a balance between investment needs and affordability concerns. For example, electrification of large parts of the economy (especially transportation) will require hundreds of billions, perhaps trillions, of dollars in incremental investment. Given some ambitious goals—for example, Biden Administration goal of U.S. EV share of automotive sales of 50% by 2030 or the recently announced California goal of 100% of new vehicle sales by 2035—could require electrification at a pace at which it will hit a “cost wall” that cannot be easily absorbed by electricity customers. These “balancing” discussions need to occur before significant spending to ensure expectations are aligned.

Finally, the pace of investments will need to consider funding of the investment. Some of this funding will be in the form of higher utility bills, subject to affordability concerns. In addition, higher cost of electricity makes customer adoption of electrification (a public policy objective) more challenging. This may manifest itself as a pushback to transition, as some customers may question its cost effectiveness. Another potential outcome is a revisiting of utility “death spiral” concerns as bill impacts could make self-supply, or at least partial requirements, more attractive.

Some Potential Relief?

The recently enacted Inflation Reduction Act of 2022 is seen as a game changer in both government dollars allocated to new energy infrastructure as well as the scope of sectors affected. The cost of some utility investments may now be defrayed by the availability of federal dollars.

Another option to temper rate increases may be for utilities to seek public sources of funding to meet public policy objectives, in order to align of public policy objectives and funding sources.

Regardless of the effects of the IRA or other public funding sources, utilities and their regulators will need to monitor closely the amount and pace of utility investment and its effect on customer bills. To avoid frequent rate cases, “rate shock,” and regulatory lag, some mechanisms such as infrastructure surcharges and cost trackers may be considered. And all stakeholders will need to consider the pace and prioritization of utility capital plans. As such, the energy transition may become a measured trot rather than a sprint.