We have three comments based on these results, following a caveat on our method. We also have two important institutional considerations, which may affect the sufficiency and sustainability of the outcome, but these will appear with concluding remarks in Part 3 in the next issue of Public Utilities Fortnightly.

The caveat relates to our use of transmission structure miles as a proxy measure of generalized transmission capacity. This might overstate how much transmission plant is required to hit the 2030 and 2050 PNZ targets, particularly if total structure miles are mostly lower voltage structure miles in local distribution circuits.

Based on Form 1 historical national average, the majority of total structure miles are in the upper subtransmission and transmission voltage ranges. That is, about eighty-two percent of structure miles are 51 kV+; sixty percent of structure miles are 72 kV+ voltages; and forty-one percent of structure miles are 132 kV+ voltages.

It is safe to say that the grid transformations required to move large amounts of electricity into lower voltage local circuits for total building and transportation electrification will depend on voltages 72 kV and above. Although there may be some loss of generality by using the total structure mile proxy in our approach, it is a good first approximation until refinements are available.

Turning back to comment on Figure 1, our first comment is that sustained growth of electrical infrastructure and its operating expense at this rate and magnitude would be unprecedented, as would be the necessary increases in the price of electricity to pay for it. With very few exceptions over several decades, electricity rate increases have not kept up with the Consumer Price Index (CPI) (Mitnick, 2024).

If our transmission cost growth approximations here are reasonable, the possible increases in electric rates might exceed the general rate of price inflation experienced by consumers. Rate growth of this magnitude is certain to be contested in state jurisdictions in rate cases and before FERC in challenges to formula rates filings where possible.

Both regulators and legislators should not forget the lessons from use of billing moratoria imposed during COVID, or the use of rate freezes for up to ten years by some states to hold off rate hikes twenty years ago. Customer bill moratoria and rate freezes postponed but did not eliminate recovery of prudently incurred costs owed to the service provider.

Moreover, ratepayers and regulators have heard for a decade that renewables and the grid transformation will bring savings and will be affordable. These expectations could become discontents merging with others related to facility permitting, fairness of cost allocations, and insufficient attention to social equity. These discontents can easily undermine commitments to long-term policy prescriptions.

Our second comment relates to unfamiliar project risk faced by financial markets. The financial markets and the rating agencies need to get it right, because the amounts involved and lingering reminders of the 2008-2009 Great Recession are not easily forgotten.

Financial markets have gotten utility markets wrong before (Enron, MCI-Worldcom). There is considerable potential for guessing wrong about future outcomes by developers and lenders, as well as the federal and state governments, because of technological complexities, regional and state differences, human behavior, and the passage of time.

Lenders who look at the risk exposure and the new opportunities created by the Inflation Reduction Act (IRA) have moved off their market optimism of early 2023 and now express caution at developments in financial markets.

To counter this, the 2023 IRA allowed DOE to serve as a transmission line "anchor customer" by taking up to fifty percent ownership in firm transmission capacity for up to forty years. This is in addition to other derisking measures to reassure financial markets, such as loan guarantees and tribal incentives for siting.

These derisking steps for financial markets are similar to the measures taken by the federal government during the 2009 GM bankruptcy, although the GM financing of thirty-three billion is a tiny fraction of the amounts required for the transmission transition discussed here. Whether and when the federal government could extract itself profitably from transmission ownership commitments like the way the Treasury Department unwound the GM stock commitment is another consideration.

Our last observation relates to the headlong pace and what may be an absence of transparency about requirements and cost. Indeed, the questions unanswered led the authors to this research.

We are faced with complex models and discussions of which model is better at one aspect or another of prediction, but there is something about the quantitative style that gives the illusion of exactitude about the future. As Vaclav Smil and many others have noted, forecasts made so far into the future are worthless.

We are making a commitment to a transmission system makeover for which no one has a very convincing grasp of the economics of implementation, deployment, and operation. As an example, cost estimates from various expert sources and sophisticated modeling tools are widely different.

This reminds the authors of the spiral or concurrent development concept sometimes used in major public acquisition programs. For example, large complex undertakings are initiated before the technology or manufacturing capability exists, in the hope these capabilities will be developed at some point after the project is underway.

As the U.S. Government Accountability Office has demonstrated in repeated studies of government procurements, these situations are recipes for cost and schedule overruns and lowered performance of the eventual product.

In the present context, one example is affordable utility-scale long-term battery storage. It is absolutely essential for a grid built around intermittent generation sources to integrate with large amounts of storage.

Affordable storage in sufficient quantity offers grid support that replaces fast ramping fossil-fueled generators and provides reliability and system resilience. The reality is that current implementations of larger scale long-term battery storage are exorbitantly expensive and lack performance except in brief intervals. Much development work remains to be done.

Supposing that affordable utility-scale storage finally arrives, it is likely that other parts of the overall transformation may already be in service. This results from the headlong pace set by the target dates with little regard for the economics or maturity of the necessary technology.

This is the risk within the false promise of spiral or concurrent development: when the needed technology or method eventually arrives, there is often wasted effort, retrofit and rework, because other systems could not be held up waiting for one or more laggard technologies or manufacturing capabilities.