public comments due November 6

This is my second submission, on behalf of American Experiment, to the energy affordability investigation by the Minnesota Public Utility Commission (MN PUC). Public comments are due by Friday 4:30pm on November 6, 2026 via [email protected] or online form.

The MN PUC seeks written comments on five questions listed further below. The most relevant background can be found in the following links:

Note that I have been the Energy Policy Fellow with the Center of the American Experiment since June 1, 2026. I am an economist by trade; policy, regulatory and pricing. My public utilities related experience is mainly from Australia and the UK, between 1997 to 2019, including working at the Queensland, Australian and Scottish versions of the MN PUC.

Question #1

Riders, fuel clauses, and incentive to manage costs. Riders and the fuel clause give utilities timely recovery and may lower financing costs, but they arguably weaken the incentive for rate-regulated utilities to manage costs between rate cases.

a. What evidence is there, in Minnesota or elsewhere, that these mechanisms have raised or lowered total costs to customers?

b. What, if any, reforms would preserve rate mechanisms’ benefits while further improving cost discipline?

The PUC’s website has a page devoted to “Rider Filings” including the following key points:

• Transmission Cost Recovery (TCR) – Minn. Stat. § 216B.16, subd. 7b: “… allow for the cost recovery of facilities and planning investments that support grid modernization efforts.”
• Renewable Energy Standards (RES) – Minnesota Statute § 216B.1691: “… allow for the automatic adjustment of charges to recover prudently-incurred investments, expenses, or costs associated with facilities constructed, owned, or operated by a utility to satisfy the RES Statute, provided those facilities were previously approved by the Commission.”

The “RES Statute,” as reinforced by the “RES Rider” and “TCR Rider,” are the prime sources of electricity unaffordability in this state (as is RPS for many other states), in the 21st century:

• University of Chicago (July 2024): “… electricity prices increase substantially after RPS adoption. The estimates indicate that in the 7th year after passage, average retail electricity prices are…11% higher. Twelve years later they are…17%, higher.”
• Pew Research Center (April 2026): A majority of Americans think “solar and wind power” are not cheaper than “most other energy sources” by 61% and 63% respectively.
• Electric Power Research Institute (June 2026): “Observing the capacity expansion of data centers in particular, there does not appear to be a correlation with rising average prices at the state level from 2019 to 2024.”
• KSTP / SurveyUSA (September 2026): “Inflation/Cost of Living” is the most important issue to 37% of Minnesotans as a whole, compared to “Fraud” at 14% and “Health Care” at 12%.
• S&P Global Energy (October 2026): “Capital spending continues to drive rate case activity … grid modernization, system resiliency, renewable energy integration.”

As per my first submission to the PUC on October 15, 2026 regarding energy affordability:

• Wind and solar renewables are still, as of 2024, vastly more costly than nuclear, coal or natural gas reliables (see Chart 1 below).
• Wind has been the dominant renewable in MN in the 21st century, especially since 2004, with solar a distant second even in the 2020s (see Chart 2 below).
• MN renewables went from an afterthought prior to the 21st century to the top generation source nowadays along with natural gas not far behind (see Chart 3 below).
• The growth of MN renewables in the 21st century has far outpaced that of the rest of the midwest (MW) region and the country (US) as a whole (see Chart 4 below).
• Twin Cities (MSP) electricity CPI inflation has thus also far outpaced that of the MW and US in the 21st century (see Chart 5 below).
• MSP electricity CPI inflation has outpaced MSP general CPI inflation throughout the 21st century, as well as overtaking it in the 2010s and 2020s (see Chart 6 below).
• MN electricity rates have inflated by well over 100% in the 21st century for residential, commercial, industrial and total combined customer classes (see Chart 7 below).
• MN’s state rankings on these four electricity rates have sunk throughout the 21st century from almost top 10 for commercial in 2002 to almost bottom 10 for industrial 2022 (see Chart 8 below).
• These heavily inflating MN electricity rates have translated into skyrocketing electricity bills, on average for the three main customer classes combined (see Chart 9 below).
• MN electricity bills inflation is being driven up by increased rates and not by increased uses, noting { Bills = Revenues / Customers } and { Revenues = Rates x Uses } (see Chart 10 below).
• MN electricity uses peaked in 2008 and has sunk since, given the Jevons paradox and Khazzoom-Brookes postulate, strongly suggests not electricity cost efficiency but electricity price inflation (see Chart 11 below).
• This is very much reinforced by comparing MN electricity price inflation to MN natural gas price deflation between 2002 and 2025 (see Chart 12 below).
• This is also reinforced by comparing MN electricity revenues to MN natural gas revenues, the former of which are being pushed up by rates not uses, which in turn are being pushed up by renewables capex not equity returns (see Charts 13 and 14 below).

Chart 1

Chart 2

Chart 3

Chart 4

Chart 5

Chart 6

Chart 7

Chart 8

Chart 9

Chart 10

Chart 11

Chart 12

Chart 13

Chart 14

Question #2

Interim rates and affordability. Minnesota law allows utilities to collect interim rate increases while the Commission reviews a rate case, subject to refund with interest. While interim rates provide rate-regulated utilities timely cost recovery for costs while a rate case is pending, customers must pay higher bills before the Commission has determined the amount of rate increase that is just and reasonable. Even when refunds are issued, they may come too late to help customers struggling with higher bills during the proceeding. On the other hand, interim rates arguably help manage financial risk to the utility, potentially reducing its cost of capital.

a. Does the availability of interim rates affect a utilities’ incentives to control costs, the size of initial rate requests, or parties’ willingness to settle a rate case?

b. Do they have measurable impacts on the utility’s financial risk and cost of capital?

c. How do other states balance timely utility cost recovery with customer protections during rate proceedings, and what can Minnesota learn from their experience?

d. What changes, if any, should be considered to Minn. Stat. § 216B.16, subds. 3 and 4, or the Commission’s implementation of those provisions?

Subd. 4. states “The burden of proof [BoP] to show that the rate change is just and reasonable shall be upon the public utility seeking the change.” This should be supplemented by either a legislative amendment and/or a legal opinion regarding “the standard of proof [SoP].” The three main legal SoP options are as follows:

• The civil case (low) standard of “a preponderance of the evidence.”
• The civil case (medium) standard of “clear and convincing evidence.”
• The criminal case (high) standard of “beyond a reasonable doubt.”

The current implied SoP for the likes of Xcel, for both general rate cases and thus interim rate increases, appears to be the low SoP. To better tackle MN electricity unaffordability, which has been an increasing problem throughout the 21st century, the SoP should be:

• low for matters with no significant affordability impacts, such as administrative or procedural matters;
• medium for general rates cases, especially for multi-year revenue and rate increases;
• high for interim rate increases, such as reasonable threat of bankruptcy or blackouts.

Regardless, transparent SoPs need to be established by the PUC, with or without legislative changes. This is in better keeping with the:

• “Regulatory Compact” or “partnership between the state and utility providers.”
• “Trust, but Verify” mindset that “emphasized the extensive verification procedures that would enable both sides to monitor compliance with the treaty.”
• MN Governor-Elect‘s concerns that “America has a major monopoly and competition problem. Reduced competition can mean higher prices, lower product and service quality, depressed wages, and less innovation. It is a problem that we can no longer afford to ignore. To ensure our future economic prosperity, America must confront its monopoly power problem and restore competitive markets.”

Question #3

Return on equity, capital structure, and the cost of capital.

a. Are there opportunities to improve how the Commission determines utilities’ authorized return on equity (ROE), debt-to-equity ratios, and overall cost of capital to better balance affordability with utilities’ ability to attract investment and maintain financial stability?

b. Should the Commission reconsider how it evaluates these interrelated factors, including the appropriate balance of debt and equity financing, to ensure that customers pay no more than necessary while utilities retain access to capital on reasonable terms?

c. What specific changes should be considered?

Return on equity (ROE), capital structure and the cost of capital are important, but are overemphasized relative to the capital base that ROE is applied to. Especially given:

• Aii found in July 2026 that linear authorized ROE declined over time from slightly above 11% in 2000 to a bit under 9.5% in 2026 (see Chart 14 above).
• S&P found in October 2026 that “The returns on equity [ROEs] requested in the pending cases range from 9.50% to 13.20%, averaging 10.48% in vertically integrated electric rate cases, 10.27% in electric distribution rate cases and 10.52% in gas base rate cases.”
• NYU found in January 2026 total market ROE of 17.6% as well as 95 industry ROEs of: 9.75% for Banks (Regional); 11.06% for Cable TV; 18.25% for Computer Services; 15.9% for Education; 19.74% for Environmental & Waste Services; 50.84% for Hospitals/Healthcare Facilities; 17.79% for Metals & Mining; 9.96% for Oil/Gas (Integrated); 7.01% for Paper/Forest Products; 12.4% for Power; 26.05% for Retail (General); 10.15% for Shipbuilding & Marine; 3.68% for Steel; 19.82% of Telecom. Services; 29.07% for Transportation (Railroads); 10.42% for Utility (General); 10.28% for Utility (Water); plus -12.76% for Recreation, -2.51% for Coal & Related Energy and -7.36% for Green & Renewable Energy.

The criticisms of the both the Weighted Average Cost of Capital (WACC) and the Capital Asset Pricing Model (CAPM) are many and varied, as well as theoretical and practical. I highlight three important ones next in terms of: firm level; risk free; and free markets.

Regarding firm level, HBS observed in a June 2012 paper entitled “The WACC Fallacy” that:

• “Ever since the seminal contribution of Modigliani and Miller (1958), a key result of corporate finance theory is that a project’s cash flows should be discounted at a rate that reflects the project’s risk characteristics.”
• “Discounting cash flows at the firm’s WACC is therefore inappropriate if the project differs in terms of its riskiness from the rest of the firm’s assets.”
• “In stark contrast, however, survey evidence suggests that performing capital-budgeting using a unique firm-level WACC is quite common.”
• “The prevalence of this ‘WACC fallacy‘ implies that firms tend to bias investment upward for divisions that have a higher industry beta than the firm’s core division.”
• “This paper provides a direct test of this prediction using segment-level accounting data. We find a robust positive relationship between division-level investment and the spread between its industry beta and the beta of the firm’s core division.”
• “The prevalence of the ‘WACC fallacy’ among corporations seems consistent with managerial bounded rationality.”
• “It is…logically flawed for a firm to discount a risky project using its own cost of capital.”
• The…use of multiple discount rates within a firm might require the creation of a specific internal process to decide the discount rate appropriate for each project.”

Regarding risk free:

• PortfolioPilot wrote in August 2026: “The risk-free rate is…a key component…CAPM, which uses it to estimate the expected return of an asset by considering its risk. In the US, this is usually tied to Treasury bonds because they’re backed by the federal government, so there’s virtually zero risk of default.”
• Investopedia wrote: “Although termed ‘risk-free,’ no investment is entirely without risk; even T-bills carry minimal default risk and can be influenced by inflation and market conditions. Various factors, including economic conditions and monetary policies, can cause fluctuations in the risk-free rate, making it challenging to use as a stable long-term benchmark. Different countries use different proxies for the risk-free rate, reflecting their unique economic conditions and geopolitical risks, demonstrating that a universal risk-free rate doesn’t exist.”
• Forbes wrote in April 2023: “The risk-free rate (RFR) is a theoretical measure of an investment with zero risk, over a specified period. The risk-free rate is actually the ‘nominal’ RFR, and fails to account for the elephant in the room, inflation. The so-called ‘real risk-free rate’ is computed by backing out inflation.”
• Milton Friedman wrote in January 1963: “Inflation is always and everywhere a monetary phenomenon, in the sense that it is and can be produced only by a more rapid increase in the quantity of money than in output.”

Regarding free markets, the Mises Institute wrote on August 2022:

• “CAPM is an important investment model that describes how investors expect to be compensated for the time value of money and risk. The more risk you take, the more you want to be compensated. In CAPM, only investors’ nominal returns matter, not their price impact [i.e. inflation].”
• “A pure risk-free rate of return does not exist. Any government could print money [i.e. inflation] and ‘safely’ return money. However, in that case, you probably get money with less purchasing power back. For that purchasing loss, a lender wants to be compensated.”
• “In Human Action, Ludwig von Mises explains that an investor’s required return consists of the originary interest rate, a compensation for the risk, and a compensation for an expected increase in the price level [i.e. inflation].”
• “The only way to improve people’s situation in society is to invest time and resources properly. Any investment is meant to have a positive impact and to improve people’s situation in the future.”
• “Three groups are involved in investment: investors, entrepreneurs, and consumers. The investor requires compensation for making money available. The entrepreneur requires a profit for adding value to the items or services bought, by buying cheaply, and selling more expensively over time. The consumers also require a profit.”
• “Without a leap in products or services’ quality, falling prices are beneficial for consumers. If the price decline were sufficiently large, people’s purchasing power would go up. An ongoing general decline goods prices [i.e. deflation] is a form of social profit.”
• “Investors should consider their investments’ price impact. What matters to people is a real improvement in their situation. Taking into account investments’ price impact [i.e. inflation or deflation] could change investment allocations.”
• “If prices go down [i.e. deflation], people’s purchasing power will improve. Lower prices are a form of profit to people in society and a way for everyone to benefit from working and living together.”

WACC and CAPM should inform but not determine cost of capital, capital structure and ROE. The PUC should use best practice economics and best available data as well as sound regulatory judgement on what is “just and reasonable,” as informed not just by “rounding up the usual suspects” in terms of the same old ideas, approaches and stakeholders. Hint hint.

Question #4

Rate design as a cost-control tool, not just an allocation tool. Rate design is often treated as dividing up a fixed revenue requirement. However, well-designed rates and incentives can also send signals to customers and the utility to achieve overall cost savings.

a. To what extent can time-varying rates, demand charges, flexible load programs, or customer-sited resources actually reduce the system costs that need to be recovered, particularly peak-driven generation, transmission, and distribution investment?

b. How can that reduction best be measured?

c. Who bears the risk if those savings don’t materialize, and how should benefits be shared between participating and non-participating customers?

The PUC system of electricity revenues and rates setting has been biased in favor of inflating the capital base throughout the 20th century, but has been biased in favor of doing so through wind and solar renewables throughout the 21st century.

Both the capital bias and the renewables bias will probably require legislative reform, but in the meantime the PUC can learn from, and look to apply, incentive regulation: both domestic and foreign; as well as both academic and applied.

One example of foreign plus applied is the “Demand Management Innovation Allowance Mechanism” of the Australian Energy Regulator (AER). The original 2017 version can be found here. The revised 2026 version can be found here. Highlights from the fact sheet include:

• “We have introduced a demand management incentive scheme aimed at encouraging distribution businesses to find lower cost solutions to investing in network solutions.”
• “The incentive scheme achieves this by encouraging distribution businesses to undertake efficient expenditure on non-network options relating to demand management.”
• “Distribution businesses can manage demand on their networks to reduce, delay or even avoid the need to install, replace or upgrade expensive network assets. [This] can reduce upward pressure on network charges, which make up about half the cost of electricity bills.”
• “Price signals or financial incentives can reward consumers [and] may come in the form of things like cost-reflective tariffs, congestion pricing, and rebates.”
• “Historically,…the regulatory system encourages distribution businesses to prefer network capex over non-network options.”
• “Our incentive scheme is a targeted, achievable solution that forms a bridge between the current regulatory framework and a framework more focussed on efficiently pricing network services.”
• “As the demand management industry advances as a whole, distributors will become better at managing the risks and minimising the costs of these solutions, delivering even more consumer benefits.”
• “In deciding whether a project is efficient, we require distribution businesses to test the demand management services market. This will increase transparency, promote competition and put downwards pressure on electricity prices.”
• “The incentive scheme has three key features: the cost uplift, the net benefit constraint, and the overall incentive constraint.”
• “The cost uplift gives distributors an incentive of up to 50% of their expected demand management costs.”
• “The net benefit constraint [is] the size of the incentive will not outweigh the value (or net benefit) the demand management project delivers across the electricity market.”
• “The overall incentive constraint [is] the total incentive in any year cannot exceed 1% of the distribution business’s allowed revenue for that year.”

Question #5

Priorities for regulatory reform.

a. Looking across the full range of Commission rate setting practices, which two or three changes would have the greatest potential to reduce customer bills or slow future cost increases without compromising safety, reliability, or progress toward Minnesota’s clean- energy goals?

b. What specific changes could the Commission implement under existing authority, what would require legislation, and how should their effectiveness be measured?

As I quoted in October 2026 regarding the Averch-Johnson (A-J) Effect (1962):

• Professor Kenneth Train of UC Berkeley in 1991 wrote: “Averch and Johnson initiated one of the earliest and most influential investigations into the effects of regulation on the behavior of a regulated firm. They argue that the most prevalent form of regulation currently applied to public utilities, rate-of-return regulation, induces the firm to engage in inefficiencies. These inefficiencies are the natural result of the regulation. Furthermore, the aspects of monopoly control that regulation is intended to address, such as high prices, are not necessarily mitigated, and could be made worse, by the regulation.”
• The Federal Reserve in 1987 wrote: “Electric utility regulators attempt to maintain a ‘competitive’ price for electricity by adjusting the rate of return on a utility’s capital. However, there are potentially serious problems with this type of regulation. First, price increases may lower the consumption of electricity, which may reduce earned rates of return below ‘fair’ rates and trigger a price increase, which in turn may lower consumption and trigger another price increase, and so on. Second, utilities may be able to effect price increases by using ‘too much’ capital, that is, by overcapitalizing, which inflates their rate base.“
• Professors Paul Joskow and Richard Schmalensee in 2024 wrote: “The most important intellectual contribution of the Averch-Johnson paper is not the capital bias result, but rather that it got economists thinking about the implications of various regulatory mechanisms for the regulated firm’s costs. In the end, we believe that traditional COSR [cost of service or rate of return regulation] of legal monopolies does lead to inefficiencies, mainly for all of the reasons articulated in the incentive regulation literature.”

I quoted further from Professors Joskow and Schmalensee in October 2026 regarding incentive regulation:

• “There is by now a very extensive and mature theoretical literature on incentive regulation of legal monopolies. Incentive regulation mechanisms have been applied for many years to the regulation of electric utilities in countries other than the US, including Great Britain, New Zealand, Australia, and Canada.”
• “Incentive regulation mechanisms of some type have now been introduced into the electricity distribution regulatory process in a majority of US states. These initiatives are never called ‘incentive regulation’ by regulators and policy makers in the US. The policy phrases used routinely now are ‘performance-based regulation’ (PBR) or ‘alternative regulatory mechanisms’ (ARM).”
• “Massachusetts, Hawaii, Minnesota, Vermont, Rhode Island, and Maryland have adopted MYRPs [Multi-Year Rate Plans] in the spirit of RPI-X. Other states are considering doing so or are in the process of designing MYRP mechanisms, including. North Carolina, Colorado, Connecticut, Nevada, and Arizona.”
• “RPI-X regulation (sometimes called price-cap regulation) [was originally applied] to the newly privatized British Telecom beginning in 1983 and thereafter to all regulated [public utilities] in the UK.”
• “Under this system the rate of growth of a weighted average of the regulated firm’s prices is constrained not to exceed the rate of growth of the RPI (retail price index) minus X [i.e. the efficiency X-factor], set after negotiation by the regulator.”
• “RPI-X regimes provide cost efficiency incentives by adjusting prices or revenues based on external indices of input costs, productivity, and other performance metrics.”
• “It was initially hoped that once X had been set, this system could simply run until competition made regulation redundant, but that did not happen.”

The Australian public utilities regulator for the state of NSW, IPART, wrote about “Incentives for cost saving in CPI-X regimes” in July 2011. Highlights from that paper include:

• “CPI-X regulation involves setting a price-path (price-cap regulation) for a utility, allowing for changes in inflation (the CPI factor) and expected efficiency improvements (the ‘X’ factor).”
• “The ‘X’ factor may incorporate other aspects in addition to the expected improvement in efficiency, such as rewards for improvements in output quality, service levels or demand management actions.”
• “Regulators generally aim to set prices/revenues along a path that will generate sufficient revenue to recover the efficient levels of opex and capex, with a reasonable after-tax return on capital.”
• “The inherent incentives for cost or efficiency savings in the standard CPI-X regime…arise principally because the regime disconnects prices from cost movements after the price path has been set in relation to forecast costs for the period in question.”
• “This delinking of costs from prices creates an incentive for the regulated firm to cut costs early in a determination period because it retains those cost savings until they are passed through to consumers in lower prices.”
• “The delinking also creates a counter-incentive to delay until the start of the next determination period any cost savings that would have been done later in the current determination period.”
• “To preserve the strength of the incentive throughout a determination or control period, both Ofwat and the AER use a carryover mechanism. This mechanism allows utilities to retain, for a period of time at least equal to the length of the control period, the cost-savings that result from improvements in efficiency.”
• “[AER] only apply their carryover mechanism to operating expenditure (opex) savings.
• “Ofwat switched to a menu of choices for capital spending [capex] only…called the Capital Incentive Scheme (CIS).”
• “Ofgem decided to no longer distinguish between opex and capex for the purpose of calculating required revenue. Instead, it treats all expenditure as ‘totex’ and allocates 85% of it to be recouped from depreciation and a return on capital.”

Senator Klobuchar has a web page devoted to Competition Policy that states: “Strong competition policy is necessary to build a vibrant economy that works for consumers, for workers, for entrepreneurs, for local communities, and for companies, large and small.”

I wrote about Australia’s public utilities related Competition Policy in October 2026:

• “Market competition is a means to an end. That end is greater freedom to choose, for consumers and suppliers. The main obstacle to that is government. That includes so called ‘natural’ monopolies and ‘public’ utilities.”
• “Australia tested how ‘natural’ and ‘public’ these really were, between 1995 and 2005, through National Competition Policy (NCP).”
• “NCP reforms involved the following: removing anti-competitive regulation and legislation; separating the non-monopoly from the monopoly parts of large state-owned enterprises (SOEs) and government-sponsored enterprises; ensuring competitive neutrality for non-monopoly SOEs; formalizing oversight of pricing for monopoly SOEs, and using incentive regulation; creating a third-party access regime for monopoly infrastructure, whether SOE or not; extending antitrust laws to all SOEs; and having states and territories apply these reforms to local government.”
• “NCP was directly applied to the following infrastructure industries: electricity (federal and state); natural gas (state); roads (federal, state, and local); and water and sewage (federal, state, and local). It was also designed to indirectly target airports (federal and local), ports (state), postal (federal), rail (federal and state), and telecommunications (federal).”
• “Policymakers implemented NCP through three agreements between the federal, state, and territorial governments. Annual performance-based payments were provided to the states for nine years, some of which the state of Queensland passed on to local governments for five years to incentivize NCP reform at that level.”
• “A small ‘guide-and-watch dog‘ called the National Competition Council (NCC) was established to assess progress and make payments on an annual basis.”
• “Cost-benefit analyses were embedded in every aspect of NCP, including in three major assessments of the economic impacts in 1995, 1999, and 2005. The 2005 assessment found there was a massive net-benefit (benefits over costs) from NCP, i.e. competition performance above competition payments.”
• “The sowing of AU$5.5 Billion in taxpayer payments during the NCP decade conservatively reaped more than AU$1 Trillion in additional benefits for Australians, gained “from productivity and price reductions observed over the 1990s in the electricity, gas, urban water, telecommunications, urban transport, ports and rail freight sectors.” This economic return was of Biblical proportions, well over a hundred-fold!”