INTRODUCTION

The robust support for grid modernization (“GM”) from diverse interests should not presume its social desirability and net benefits to utility customers. This Article focuses on electricity distribution, which falls under state regulation in the United States. At odds with the prevailing view, it raises the question of whether utilities should spend more on GM and whether it should be done as quickly as possible.

Regulators should perform their due diligence to determine whether GM investments — which for some utilities amount to billions of dollars — are good for utility customers and society as a whole. Not to be overlooked, regulators should ask whether utilities have an incentive to overspend on GM. In the end, the burden ultimately falls on utility regulators to assure that customers receive the promised benefits to a magnitude that at least offset the costs they pay for GM investments. This exercise requires sound technical investigation as well as good judgment. After all, the benefits are often highly uncertain and sometimes immeasurable, while estimated costs may be unreliable because of unexpected overruns.^[1]

Utility customers should avoid having to bear the burden of undue risk, which arguably is happening with recent capital-cost recovery mechanisms; namely, upfront regulatory commitment and riders/trackers. The moral hazard created by such mechanisms reduces both utility and regulatory accountability and can be a major factor for utility overspending on GM.

THE POLITICAL ECONOMY OF GRID MODERNIZATION

Grid modernization refers to the transformation of the traditional electrical grid into a smarter, more efficient, reliable, and resilient system. It encompasses a variety of technologies^[2] that advance various objectives: the integration of renewable energy, improvement in grid reliability and resilience, enhancement of cybersecurity, and empowerment of consumers.^[3] It involves major upgrades of the transmission and distribution grid that accommodate new technological developments (e.g., renewable energy, storage) and systems, changing market dynamics and shifting consumer preferences. GM reflects both an evolutionary and a revolutionary progression, contingent on the technology and process under consideration.

Most electric industry observers support GM at both the transmission and distribution level.^[4] Advocates of GM comes from diverse quarters: electric utilities, clean air and climate advocates, technology vendors, consultants, labor unions, and state^[5] and federal politicians and bureaucrats.^[6] Wall Street also favors GM when utilities are able to earn at or above their cost of capital on the potentially large expansion in their rate base from GM investments — delivering coveted earnings per share and dividend growth, in addition to the need to issue additional debt and potentially equity.^[7] (Evidence has shown that most electric utilities earn above their cost of capital.^[8]) These advocates generally argue that utilities should be spending more and sooner on GM.^[9]

As a casual observation, proponents of GM in the governmental domain have dominated both skeptics and opponents.^[10] Since GM has the potential to advance a wide array of regulatory and public policy objectives, such as stimulating renewable energy, improving reliability and resilience, reducing operating costs and effectuating more efficient pricing, it places utility regulators in an unenviable position to reject proposed GM investments.

From a public-choice perspective, strong pressure from various interests with political clout can sway utility regulators and energy policymakers to support their positions, even when harmful to the public interest.^[11] As discussed later, utility regulators and consumer advocates in particular should be aware of this possibility, which also arises in others aspects of utility regulation and energy policy.

POTENTIALLY LARGE BENEFITS FROM GM

Sixty percent of the U.S. distribution grid — which carries electricity energy to homes and businesses at the local level — have gone past their 50-year life expectancy. The Brattle Group estimates that $1.5 trillion to $2 trillion will be spent by 2030 to modernize the grid just to maintain sufficient reliability,^[12] which constitutes a huge amount that elevates the importance of utility regulators conducting careful cost-benefit reviews.

GM investments encompass myriad technologies that digitize a utility’s grid. This allows utility operators to improve their ability to monitor grid conditions, examine those conditions with software, and take appropriate action in near real-time (e.g., restore power after an outage). GM has the potential to improve the reliability of the electrical grid, better integrate alternative energy, and enable pricing that reflects the marginal cost of generation. For example, smart grid technology helps operators to better handle fluctuating supply from renewable energy sources.^[13] Design of the present grid occurred when power plants in central locations exclusively controlled a one-way flow of electricity to customers.^[14] A modern grid has the ability to accommodate greater consumer control and two-way flows of power.

Climate advocates are a strong proponent of GM, as they consider GM necessary to satisfy the “net zero emissions” standard.^[15] Some utilities share this view. As expressed by one advocate, the Union of Concerned Scientists:

Grid modernization can deliver greater quantities of zero-to low-carbon electricity reliably and securely, including handling variable renewables like wind and solar power. It can support the electric vehicle revolution and increase grid resilience to withstand climate impacts. It can spread economic opportunity in rural and urban communities through electricity and transportation infrastructure investment and upgrades. And, it can improve system efficiencies and reduce costs by reducing the need for expensive and dirty power plants that only run a few hours per year.^[16]

This view is also consistent with past experience — achieving public-policy goals at an affordable or reasonable cost to society often requires technological and other innovative breakthroughs. Similarly, making the transition to a clean-energy future at an affordable or politically acceptable cost will demand new technologies, such as those rooted in GM.^[17]

New technologies also have enormous potential for improving the performance of public utilities. New technologies can help enhance the quality of utility services, achieve clean-energy goals at a lower cost, reduce the cost of existing services, and advance other regulatory objectives more effectively and economically.^[18] New technologies also play a vital role for advancing long-term policy objectives, like safety, reliability, resilience,^[19] cheaper energy, and energy efficiency.

Who then can disagree that GM is the wave of the future, in which policy makers and regulators should give their unequivocal support for GM investments that ostensibly coincide with the public interest?

THE VALID QUESTION: ARE GM INVESTMENTS IN THE PUBLIC INTEREST?

The strong support for grid modernization (GM) from a wide array of interests, and its potential large benefits, do not guarantee its desirability to utility customers and society. Trying to reconcile the divergence between individual interests and the public interest is an inescapable obligation that commonly besets utility regulators.

Utility regulators should probe whether (1) the total benefits from GM to utility customers exceed the costs^[20] and (2) low-income and other households will overpay, given common ratemaking structures, since higher-income households will mostly benefit from purchases of electric vehicles and rooftop solar systems that GM tries to accommodate.^[21]

Economically, initial investments in GM should have the highest net benefits, with succeeding investments having lower or even negative net benefits. To say differently, this sequence of actions would result in the ratio of benefits to dollars spent decreasing at higher levels of GM investments. The implication is that spending lesser amounts on GM could be cost-beneficial, limiting the size of socially optimal GM spending and potentially extending the horizon over which this optimal GM spending occurs. This condition especially holds when substitutes for GM investments can achieve the same objectives at lower cost.^[22]

Although the economics literature has devoted relatively little attention to regulated firms’ incentive to adopt new technologies,^[23] the standard narrative is that regulation causes utilities to be cautious about innovating and taking risks.

Utilities are often accepting of new technologies, particularly when mandated and are included in rate base and remain in rate base, considered “used and useful” even if all of the promised benefits do not materialize. Otherwise, utilities would have the propensity to underinvest in new technologies, for example when they have high risk relative to their expected return, produce public benefits^[24] or threaten their monopoly status. If a utility has a choice of two technologies, for example, one existing and the other new, where the regulator allows the same allowed rate of return, it will tend to favor the existing technology since inherently it has lower risk.^[25] But there may exist explanations for why this may not hold under certain conditions.^[26]

One example is GM investments where recent regulatory practices can provoke excessive spending on GM. Several U.S. regulators have committed to GM projects that shift risk to utility customers.^[27] While no state utility regulators have guaranteed full cost recovery of a utility’s GM investments, some regulators have allowed a utilities to recoup their costs outside traditional rate cases and preapprove costs not yet incurred. Some analysts have claimed that these actions have weakened regulatory oversight of utilities to control the costs of GM projects, with the increased possibility of customers absorbing imprudent costs from mismanagement.^[28]

WHAT UTILITY REGULATORS SHOULD ASK

Utility regulators face a formidable challenge in ensuring that utility investments in GM advance the public interest.^[29] While state statutes encourage GM, they do not require regulators to approve utility GM plans.^[30] In the state of New Mexico, the Grid Modernization Statute authorizes the state’s Public Regulation Commission (“PRC”) to approve distribution GM projects.^[31] In evaluating utility-proposed projects, the PRC must consider the reasonableness of the project (presumably related to customer net benefits) and whether a project would advance certain objectives, like a reduction in greenhouse gases, facilitation of grid access for renewable and other forms of clean energy, and improved reliability and resilience. Other states have comparable statutes to encourage electric utilities to upgrade their distribution systems.^[32]

Utility regulators must address myriad questions. Neglecting to answer the questions below increases the chances that GM investments will fail tests of reasonableness that underscore net benefits and societal welfare.^[33] Although admittedly difficult to answer, regulators cannot ignore them if they hope to prevent excessive spending on GM, which could (1) involve large sums of money ultimately borne by utility customers and (2) be better spent on other, more economical actions. Failing to answer these questions can also create “equity” problems that jeopardize the public interest. Answers to many of the questions require a combination of judgment and objective information.

The most critical questions are:

1. 1. How much weight should regulators give in their decisions to those benefits that are difficult to quantify and highly uncertain?
   2. What is the best method of cost recovery for balancing utility and customer interests (e.g., riders^[34] and surcharges versus base-rate treatment)? Should regulators commit to GM investments upfront when it limits their ability to disallow costs when found imprudent?^[35]
   3. What is the optimal timing or roll-out of GM investments?^[36]
   4. How can a regulator implement appropriate rate structures to reduce or substantially eliminate a utility’s inherent incentive to overinvest (e.g., the Averch-Johnson effect^[37] or “gold plating”)?
   5. Do the benefits of GM accrue to the same customers who pay the costs? If not, what adjustments should the regulator make to cost allocation and rate design structures to maintain fairness and meet established criteria of a sound rate structure?^[38]
   6. How do the benefits depend upon utility actions in deployment — should utilities be held accountable ex post for achieving the benefits contained in their GM plans?
   7. Should taxpayers pay for a portion of GM costs in situations where benefits extend beyond those of utility customers and are society-wide (e.g., environmental, grid resilience)?
   8. Are there other, more cost-effective ways to achieve the same benefits from GM that are less costly?^[39] and
   9. To what extent, if any, has government subsidies stimulate uneconomical GM Investments?^[40]

CONCLUSION

Several challenges with GM await regulators seeking to maximize the public good while protecting the interests of the utility and its shareholders. A prime one is regulators being sufficiently informed about new technologies embedded in GM to avoid — or at least seek to balance out — the information asymmetry^[41] that inevitably exists between the regulator and the utility.^[42] Reliance solely on information from utilities and other GM advocates fails to safeguard the public interest.

Another task for regulators is to allocate the risk of GM investment costs between the utility and its customers. They must also seek to align utility rewards with utility risks.^[43] An added burden for utility regulators is how to allocate risk between customer classes. When an investment chiefly benefits only a portion of a utility’s customers, regulators should consider the potential responsibility and benefits for each group of customers. Should all customers bear the risk of an investment that benefits only one class of customers? Should all residential customers pay the same costs, even though some users benefit much more than others? Regulators may have to cogitate whether commonly-used cost allocation and rate design structures are appropriate for GM investments.^[44]

Finally, regulators should not outright reject a GM proposal just because it increases electricity rates or be prejudiced against a proposal in spite of the evidence; or accept a proposal just because it will support clean energy and is politically popular, while ignoring the effect on utility customers and other options to achieve similar objectives. One cannot ignore the fact that either of these scenarios can happen and probably already has in some jurisdictions.

• * Kenneth W. Costello worked for a state utility commission for almost ten years (the Illinois Commerce Commission), 28 years at the National Regulatory Research Institute, which was the research, educational and technical arm of all the state utility commissions around the US, and over 6 years as an independent consultant. During his tenure, Mr. Costello conducted research and written on a wide array of topics, including some of those discussed in this article.

  ¹ As noted in a study by Lawrence Berkley National Laboratory (Tim Woolf et al., Benefit-Cost Analysis for Utility-Facing Grid Modernization Investments: Trends, Challenges, and Consideration, (2021) Report for the U.S. Department of Energy’s Modern Distribution Grid, online (pdf): <eta-publications.lbl.gov/sites/default/files/gmlc_bca_final_report_20210202.pdf>

  “For jurisdictional utilities, grid modernization plans pose some new and complex challenges for state public utility commissions in determining whether projects will provide net benefits to customers. Plans typically include multiple grid modernization components that have interactive effects and are difficult to analyze or justify separately. Many benefits are hard to quantify or monetize, making it difficult to compare all benefits and costs. Part of the rationale for some grid modernization investments is to meet state energy goals, which can be difficult to quantify and account for in [cost-benefit analysis]. Equity issues arise when investments may benefit some types of customers more than others” at i).

• ² These technologies can be both in current use and new ones. New technologies fall within the subgroup “innovation.” Other categories of innovation are the creation of better products, more efficient and effective operating processes, and any ideas that enhance a utility’s performance.

• ³ Grid modernization encompasses the often-used term “smart grid” but much more. A smart grid centers on digital technologies that include real-time monitoring, automation, data analytics and two-way communications between a utility and its customers. Grid modernization is a broader concept that covers transmission and distribution physical upgrades. A smart grid may include smart meters, artificial intelligence, Interest of Things, demand response systems, while grid modernization may include storm hardening and replacing or elevating the performance of aging infrastructure. Taking smart meters as an example, they can provide two-way communications capabilities and other functionalities that facilitate the ability of customers to better manage their electricity usage. They can also, although still at a low level but a growing one in the U.S., allow for time-varying pricing. Time-varying pricing can bolster certain new technologies (e.g., energy storage), both inside and outside the home. The slow acceptance of time-varying pricing, so far, may reflect more than anything the preference of customers and regulators for the “stability” feature of average-cost pricing.

• ⁴ One prominent U.S. climate advocacy group, RMI, contends that too much effort has been directed at local, low-voltage projects relative to high-voltage transmission projects. It recommends collaborative actions that the state, local, regional, and federal authorities can take to mitigate what RMI calls a “regulatory gap.” Claire Wayner, “Mind the Regulatory Gap: How To Enhance Local Transmission Oversight” presentation to PJM PIEOUG, (10 December 2024), online (pdf): <pjm.com/-/media/DotCom/committees-groups/user-groups/pieoug/2024/20241210/20141210-mind-the-regulatory-gap-how-to-enhance-local-transmission-oversight.pdf>.

• ⁵ Robert Zullo, “21 states join Biden administration in bid to modernize nation’s aging grid” Washington State Standard (30 May 2024), online: <washingtonstatestandard.com/2024/05/30/21-states-join-biden-administration-in-bid-to-modernize-nations-aging-grid>.

• ⁶ The federal government, under the Biden Administration, has subsidized GM and encouraged its development. The Infrastructure Investment and Jobs Act appropriated more than $65 billion for upgrading the electric grid. The U.S. Department of Energy established the Grid Modernization Initiative to assist in “creating the modern grid of the future.” State organizations like the National Conference of State Legislatures and the National Governors Association also support more spending and aggressive activity on GM. See Glen Andersen, Megan Cleveland & Daniel Shea, “Modernizing the Electric Grid: State Role and Policy Options” (22 September 2021), online: <ncsl.org/energy/modernizing-the-electric-grid>; See also National Governors Association, “Advanced Grid Technologies: Governor Leadership To Spur Innovation and Adoption” (January 2025), online (pdf): <nga.org/wp-content/uploads/2025/01/2025_Advanced_Grid_Technologies.pdf>.

• ⁷ Steve Kihm, Janice Beecher and Ronald Lehr, Regulatory Incentives and Disincentives for Utility Investments in Grid Modernization, Report No. 8 (Lawrence Berkley National Laboratory, 2017), online (pdf): <eta-publications.lbl.gov/sites/default/files/feur_8_utility_incentives_for_grid_mod_rev_062617.pdf>.

• ⁸ Karl Dunkle Werner and Stephen Jarvis, “Rate of Return Regulation Revisited” (2025) Energy Institute at Hass, Working Paper, online (pdf): <haas.berkeley.edu/wp-content/uploads/WP329.pdf>.

• ⁹ According to the American Society for Civil Engineers, current grid “investment trends” will lead to funding gaps of $42 billion for transmission and $94 billion for distribution by 2025. See Glen Andersen, Megan Cleveland & Daniel Shea, Modernizing the Electric Grid: State Role and Policy Options, (National Conference of State Legislatures, 2019) online (pdf): <gridwise.org/wp-content/uploads/2020/01/NCSL_-Modernizing-the-Electri-Grid_112519_34226.pdf> [Modernizing the Electric Grid].

• ¹⁰ When searching the internet, and various articles, reports and other sources to identify the proponents, opponents and skeptics of GM, I discovered that the proponents dominate the other two categories by a far margin. I am confident that the reader will come to the same conclusion.

• ¹¹ See James D. Gwartney et al., Microeconomics: Private and Public Choice,15^th ed (Stamford, CT: Cengage Learning, 2015).

• ¹² See Modernizing the Electric Grid, supra note 9.

• ¹³ Assessing the economics of renewable energy requires adding the costs for new transmission lines and network reconfiguration to accommodate renewable-energy generation.

• ¹⁴ AltEnergyMag, “From One-Way to Two-Way: The Future of Electricity with Smart Grids” (26 June 2024), online: <altenergymag.com/news/2024/06/26/from-one-way-to-two-way-the-future-of-electricity-with-smart-grids/42377>.

• ¹⁵ See Andreas Schierenbeck, “The cost of inaction: Grid Flexibility for a resilient, equitable digital energy future” (20 January 2025), online: <weforum.org/stories/2025/01/grid-flexibility-for-resilient-equitable-digital-energy-future>.

• ¹⁶ Peter O’Connor, “The Equation: What is Grid Modernization – and What’s the Role of Electric Vehicles?” (12 September 2017), online (blog): <blog.ucsusa.org/peter-oconnor/grid-modernization-and-smart-charging>.

• ¹⁷ More broadly, one of this year’s winners of the Nobel Prize in Economics, Joel Mokyr, stresses the importance of new technologies and other innovations to modern economic growth.

• ¹⁸ For the electric industry, a confluence of new technologies has erupted in recent years. The most important ones include solar, wind, battery storage, electric vehicles, fuel cells, small modular nuclear reactors, digital control of the grid, smart technologies, demand-side innovations, and information and communications technologies. Some of these technologies will require a longer time before they become commercialized. Other new technologies that show promise today may never attain commercial success. Initial flaws and high costs of new technologies require an extended period of experimentation, learning and technology development as part of the “innovation” process. Widespread adoption of a technology often follows this extended period during which the technology is iteratively tested, refined and adapted to market conditions. During the initial years, new technologies appear attractive but often too expensive for the mass market. When first entering the market, new technologies are typically “crude, imperfect, and expensive.” They initially assume a market “niche” from their performance and unique features, rather than by their cost competitiveness.

  Firms typically invest in new technologies at different times. The diffusion of a new technology is often slow and highly unpredictable, even after its initial commercial application. Established firms with older capital assets and firms with newly purchased assets face different economic conditions when deciding to scrap old capital assets and purchase new assets that embody state-of-the-art technology. Not all firms should invest in “best practice” technologies at the same time. What is a “best practice” for one firm may not be “best practice” for another firm. Regulators should therefore not expect all utilities immediately to deploy the newest or the same technologies.

• ¹⁹ Measuring the resilience of an electric power system is especially problematic, but critical for decision-making (Henry H. Willis and Kathleen Loa, Measuring the Resilience of Energy Distribution Systems (Santa Monica, California: RAND Corporation, 2015).). According to the National Academies of Sciences, Engineering, and Medicine (National Academies of Sciences, Engineering, and Medicine, Enhancing the Resilience of the Nation’s Electricity System (Washington: The National Academies Press, 2017). “Developing metrics for resilience is extremely challenging because that involves assessing how well we are prepared for, and could deal with, very rare events, some of which have never happened”.

• ²⁰ Few students of utility regulation would dispute the contention that long-term utility customer welfare is one of the least represented interests in the regulatory arena. Utilities focus on their financial interests, consumer advocates tend to take a short-term view, and other stakeholders have their own agenda (e.g., the advancement of clean energy and certain technologies). A gap in adequate representation for the long-term interests of customers becomes evident. Regulators’ main duty, which commonly stated in statutes and court rulings is to advance the public interest, should be to fill that void, notwithstanding the intense pressure regulators face to appease individual stakeholders with substantial political and economic influence.

• ²¹ Under cost-of-service regulation, customers who benefit more from a particular investment should pay a higher share of the costs for the investment. GM would benefit all customers, although grossly unevenly in some instances, when it improves reliability, resilience, operations efficiency and have other positive system-wide effects. Utility regulators generally approve rolled-in pricing when a new investment benefits all customers, or when demand by all customers creates the need for a new investment. (Under rolled-in pricing, the utility would add the costs of GM investments to existing costs with prices to all customers based on this sum; analysts often refer to rolled-in prices as average or embedded cost prices).

  One example justifying rolled-in-pricing is a gas utility investing in new storage capability to accommodate the growing demand of its customers. Because the investment would benefit all customers, it would be appropriate to roll-in the costs into the rates of all customers. They would then be responsible for paying the costs for this investment that the utility made to benefit them. When the utility expands its system dedicated to serving a subgroup of customers, on the other hand, rolled-in pricing becomes less defensible from both an “equity and economic efficiency perspective.

• ²² Paul J. Alvarez et al., “Alternative ratemaking in the U.S.: A prerequisite for grid modernization or an unwarranted shift of risk to customers?” (2022) 35:9 Electricity J 107200, online: <doi.org/10.1016/j.tej.2022.107200>.

• ²³ Studies that examine how regulatory incentives affect new technologies include Stuart Burness et al., “Capital Contracting and the Regulated Firm” (1980) 70:30 Am Econ Rev342-54; Mohammad Harunuzzaman et al., “Regulatory Practices and Innovative Generation Technologies: Problems and New Rate-Making Approaches” (1994) National Regulatory Research Institute at 94–105; and Paul Joskow, “Productivity Growth and Technical Change in the Generation of Electricity” (1987) 8:1 Energy J at 17–38.

• ²⁴ Public benefits are external to a utility and defined by economists as positive externalities. Examples include clean air and national security, which society values but individual utilities in terms of their profitability do not. Investments in new technologies like GM that have the potential to reduce greenhouse gas emissions and lower the risk of harmful climate change can benefit society at large. Absent carbon pricing or similar policies (e.g., carbon trading), no direct financial compensation associated with those benefits exists, which drives a wedge between the private return that a utility realizes from adopting a new technology and the overall social return.

• ²⁵ The reality is that new technologies create more risk than conventional technologies. New technologies can fail economically in a number of ways: low operating performance, high cost overruns in construction, and (for optional demand-side technologies) low penetration or customer acceptance. Assets based on new technologies may have shorter economic lives than those assumed under a regulator-approved depreciation schedule. Overall, new technologies carry higher risk, and unforeseen problems commonly occur.

• ²⁶ Throughout its history, utility regulation has gone through periods where it has given utilities either inadequate or excessive incentives to innovate. The second condition occurred when utilities shouldered little risk from adopting a new technology relative to the benefits they realize.

  As an example of the second condition, during this period (1960-1975) regulators rarely conducted prudence reviews and disallowed cost recovery, while extended regulatory lag allowed utilities to retain the benefits of a new technology over several years. These regulatory practices were one reason why many utilities found nuclear power attractive (See for example, H. Stuart Burness, W. David Montgomery & James P. Quirk, “Capital Contracting and the Regulated Firm” Am Econ Rev): The potential for earning high rates of return from increased sales and the low risks during this period from rare retrospective reviews and cost disallowances. Regulatory lag meant that utilities were able to keep any cost savings or other benefits for a number of years until the next rate case, which occurred infrequently during that period when utilities’ average cost was falling. Instructive for the present time, a price cap or another multiyear rate mechanism could help achieve a similar outcome, heightening the incentive of utilities to innovate. In its purest form, a price-cap regulatory system regulates a utility’s prices but not its profits. Price caps generally allow utilities to earn higher profits. Compared to traditional rate-of-return regulation, a price-cap scheme also imposes higher risk on the utility. The focus shifts from “inputs” to “output,” which tends to improve the utility’s interest in using innovation to serve customers and society. See Ken Costello, “New Technologies: Challenges for State Utility Regulators and What They Should Ask” (2012) 12:1 National Regulatory Research Inst.

• ²⁷ Utilities often see upfront commitment by regulators to a new capital project as a way to minimize risk. Without that kind of commitment, utilities sometimes rightly feel vulnerable to regulatory “hold-up” or “opportunism.” (Economists label this condition “asset specificity.” It includes investments that have an alternative value much lower than their value in its original use.) The regulator, for example, might disallow a utility to recover certain costs because of an outcome that fell short of expectations even though the utility was not at fault. In other words, the utility made a good decision that turned out bad. The tough question for regulators then becomes, how should the cost of the bad outcome be shared between the utility customers and shareholders, or even utility management?

• ²⁸ In some states like Indiana and Kentucky utilities file multi-year modernization plans, which once approved, allow utilities to recover their expenditures unless clearly imprudent. Regulators are more constrained in disallowing imprudent costs than when utilities have to show that the costs they incurred were prudent. Supra notes 7 and 22.

• ²⁹ The public interest is an ill-defined term devoid of any definite metric. Generically, it refers to the “common well-being” or “general welfare.” One idea is for regulators to identify the multiple objectives that coincide with the public interest, assigning weights to those objectives and resolving the trade-offs among them. Of course, trade-offs must recognize the prevailing statutory, constitutional and other checks.

• ³⁰ Since 2021 over 28 states have introduced legislation relating to grid modernization. See National Conference of State Legislatures, “Strengthening the Grid Against Extreme Weather” (4 January 4 2025), online: <ncsl.org/energy/strengthening-the-grid-against-extreme-weather>. In some of the states, legislation requires either the regulator or utilities to evaluate the costs and benefits of GM. In most U.S. states, legislation limits the authority of utility regulators by statute, which typically provides general guidelines from which regulators form their regulations. Regulators have exercised their authority to require studies on the feasibility and economics of grid modernization. (NC Clean Energy, Technology Center, “The 50 States of Grid Modernization: Utilities Pursue Tools for Demand Management and Grid Flexibility in Q1 2025” (24 Avril 2025), online: <nccleantech.ncsu.edu/2025/04/24/the-50-states-of-grid-modernization-utilities-pursue-tools-for-demand-management-and-grid-flexibility-in-q1-2025>.

• ³¹ Gridworks, Investing in a Modern Electric Grid for New Mexico, Report prepared for the New Mexico Public Regulation Commission, (September 2022) , online (pdf): <gridworks.org/wp-content/uploads/2022/11/GW_New-Mexico-Modern-Grid-Report_.pdf>.

• ³² Glen Anderson et al., Modernizing the Electric Grid: State Role and Policy Options, Report prepared by the National Conference of State Legislatures, (22 September 2021), online: <ncsl.org/energy/modernizing-the-electric-grid>.

• ³³ GM investments have often fallen short of achieving the benefits utilities projected in their proposed plans. See Sanem Sergici, “Reviewing Grid Modernization Investments: Summary of Recent Methods and Projects” (4 December 2018) The Brattle Group before the National Electrical Manufacturers Association; Herman K. Trabish, “Duke, SCE, Other Grid Modernization Proposals Faced Big Cost Questions, More Regulatory Scrutiny in 2021” (4 January 2021) Utility Dive; and The 50 States of Grid Modernization: Q3 2022 Quarterly Report, (North Carolina Clean Energy Technology Center, 2022).

• ³⁴ Cost riders account for those costs lying outside base rates by creating a separate cost category, or include specified new costs or true-ups from cost levels that differ from test-year costs. A rider can either provide short-term rate relief for a utility or adjust rates between rate cases based on movements in those costs specified in a rider. Attrition is the fundamental reason for interim rate relief. Attrition refers to the tendency for a utility’s rate of return to decline since the last rate case. Attrition exists when revenue growth falls below revenue requirement increases, eroding the utility’s rate of return over time in the absence of a rate change. See Ken Costello, “How Should Regulators View Cost Trackers?” NRRI 09-13, September 2009.

• ³⁵ Utilities often see upfront commitment by regulators to a new capital project as a way to minimize risk. Without that kind of commitment, utilities sometimes rightly feel vulnerable to regulatory “hold-up” or “opportunism.” (Analysts label this condition “asset specificity.” It includes investments that have an alternative value much lower than their value in its original use.) The regulator, for example, might disallow a utility to recover certain costs because of an outcome that fell short of expectations even though the utility was not at fault. In other words, the utility made a good decision that turned out bad. The tough question for regulators then becomes, how should the cost of the bad outcome be shared between the utility customers and shareholders, or even utility management?

• ³⁶ Uncertainty about future returns creates what analysts call an option value to deferring or postponing investment in the technology. A firm may rationally wait because it wants to acquire new information before making a decision that involves large amounts of money. Real options theory says that when the future is uncertain, it pays to have available a broad range of options and to maintain the flexibility to exercise those options. Applying real options theory to smart meters, a preferred policy might involve a pilot program rather than installation of smart meters in all homes over a designated period of time. An excellent discussion of real options theory is contained in Avinash K. Dixit and Robert S. Pindyck, Investment Under Uncertainty (Princeton, NJ: Princeton University Press, 1994); and Robert S. Pindyck, “Irreversible Investment, Capacity Choice, and the Value of the Firm” (1988) 78:5 Am Econ Rev 969.

• ³⁷ On example is utilities upgrading their grid by building-out rather than adopting grid enhancing technologies (GETs) that would be more costly to customers but more profitable to utilities. Building-out is more capital intensive. GETs also have the advantages of being faster to deploy. GETs include dynamic line ratings, advanced power flow control, and topology optimization software. See Climate XChange, “Enabling ATTs and GETs” (last modified 21 July 2025), online: <climatepolicydashboard.org/policies/electricity/transmission-atts-gets>.

• ³⁸ Since businesses and industrial firms would be the primary beneficiaries of improved resilience (which, to recall, is one benefit of GM), they should proportionately bear the associated GM investment costs. Traditional cost allocation methods may need modification to recognize this reality.

• ³⁹ In a cost-effectiveness calculation, two or more actions assume to have the same or similar benefits with the lowest-cost option being the preferred choice. Unless the benefits of each action are quantifiable, a decision as to which action or actions are preferable becomes an exercise in judgment, which can become adulterated with the decision-maker’s biasness and other undue favoritism toward a particular choice. History has shown that utilities, utility regulators, the state and federal governments and others favor those actions based on a host of factors other than cost. One can then surmise that the investments and other actions taken to improve resilience bear little resemblance to being purely cost-effective. Even though some utility regulators pronounce their adherence to cost-effective actions, in reality their declaration is more rhetorical than real.

• ⁴⁰ The rationale for government subsidies rests with evidence of the social desirability of GM to penetrate the marketplace more intensively and rapidly than occurring under private-market incentives. This rationale is ostensibly the core argument for governmental intervention. Its sentiment presumes that the benefits of GM override any costs that would arise. Subsidies, especially when poorly structured, can be (a) unfair to funding parties (e.g., taxpayers), (b) economically inefficient, and (c) unfair to competing energy sources. Overall, subsidies typically fail a cost-benefit test from an aggregate economic-welfare perspective. See the problems with subsidies in Elizabeth Van Heuvelen, “Subsidy Wars” F&D Magazine, International Monetary Fund, (June 2023), online: <imf.org/en/Publications/fandd/issues/2023/06/B2B-subsidy-wars-elizabeth-van-heuvelen>.

• ⁴¹ The basic problem is that regulators know less than utilities about the availability, cost, risk, and benefit of new technologies. (This “information asymmetry” arises in many areas of regulation). It causes regulators to be uncertain about the commercial and social value of new technologies. Inadequate information might also make it difficult for regulators even to know when they have sufficient information to make a decision as to whether a new technology is in the public interest. Proactive regulators require parties to provide them with objective and adequate information. Especially if a utility regulator is asked to pre-approve a new technology or the associated utility’s expenditures, it should have a thorough understanding of the likely risks and benefits before allowing the utility to pass those risks on to customers.

• ⁴² See Paul L. Joskow & Richard Schmalensee, “Incentive Regulation for Electric Utilities” (1986) 4:1 Yale J on Regulation 1, online: <openyls.law.yale.edu/entities/publication/af9483dd-5fc9-4cfc-8ea8-9806666858af>.

• ⁴³ Economic theory says that all firms will innovate if they receive adequate compensation given the risks they face. This theory applies equally to utilities, although regulated utilities have different kinds of risks and compensation and hence different incentives. Regulatory policies can discourage or stimulate utility investments in innovations, thereby affecting the amount that utilities spend on innovation, the speed at which they innovate, and the nature of the investments (supra note 26). The regulatory tools that affect innovation are ratemaking, mandates, and performance objectives. By placing bounds on utility profits and risk, regulation can affect innovative activity. Regulated utilities face more severe profit constraints than their unregulated counterparts, which generally diminishes their willingness to innovate. On the other hand, utilities generally face less risk than unregulated companies.

• ⁴⁴ See supra note 21.