Pre-Approval of Large Capital Expenditures: More Questions

[A colleague from another nation, advising a client in yet another nation, asked me a series of questions about pre-approvals of major capital expenditures.]

Dear Scott,

I am advising a regulatory client in XX that is considering, amongst other things, how to deal with network capex expenditure in any five-year period that is greater than the amount approved in setting the price cap (or revenue allowance) for that period. They are aware that in the U.S., capex is typically not approved in advance (though it can be for major projects), but rather does not enter the rate base until it has been proved used and useful.

The foregoing statement about what is “typical” in the U.S. is no longer true.  A growing number of states are “pre-approving” major capex.  My co-authored paper (with Scott Strauss) on pre-approval describes and organizes many examples.  In addition, the recently enacted Illinois statute that is the subject of my recent testimony is a “frontier” example of the combination of both pre-approval and formula rates.  There are other states, especially in our Southeast region, that combine these concepts, but Illinois seems to have extended the concept to all costs—and added an obligation to spend more. 

A related question is:  To what extent do these devices—pre-approvals and formula rates—reduce the utility’s cost recovery risk?  And how does a regulator reflect that risk reduction in the authorized return on equity?  I addressed that issue in "Riders, Trackers, Surcharges, Pre-Approvals and Decoupling: How Do They Affect the Cost of Equity?"

The regulator has asked me whether this process works satisfactorily in the U.S.  From their perspective, I think the question is whether to automatically accept what the company built and spent, on the basis that it must have been necessary, or whether to have some kind of ex post check, which could increase regulatory risk and cost.

In the U.S. there is a range of views.  I am concerned that pre-approval causes the regulator to make decisions without a context.  The risk is that the utility controls the expertise and information, and uses that advantage to lead the regulator into approvals that might otherwise not be forthcoming.  The core regulatory issue is:  Who should bear the risk of bad luck?  On the other hand, I believe that private capital should have some sense of the parameters of risk before making a major investment.  So the old days of expecting the utility to commit $1 billion but not knowing until project completion whether that expenditure will be recovered were not optimal.  The answer, for me, is closer regulatory involvement, with close-in reporting, risk assignment and off ramps.  The pre-approval paper discussed these matters generically, but my testimony in Illinois applies those general principles to a direct example.

What are your thoughts and experience?  I assume that the U.S. policy works tolerably well because I don't hear much grumbling about it these days.

Consumer advocates are troubled by the pre-approvals.  The bottom line is that we don’t know yet how well it will work because we are at the front end of much large spending.

For large projects debated and approved in advance, I assume that is costly and time-consuming but may reduce risk? 

As discussed in my Illinois testimony, the answer depends on how one defines “risk.”  Project risk—the risk of a project coming in over-budget, or becoming unneeded due to changed circumstances—is unaffected by how one assigns the burden of cost recovery.  Well, not exactly, because if you assign the risk of bad luck to the utility, the utility might take fewer chances, it being its own money it is risking. One point I made in the Illinois testimony is to distinguish risk from uncertainty.  I think the goal must be to reduce the cost of capital and the likelihood of poor decisions.  Those things can be affected by how one assigns business risk.

But does it do more than approve in principle—is there a later process to prove that the actual capex is indeed used and useful?

Very important point:  it all depends on what is “approved” by the pre-approval.  The co-authored study addresses this point in detail.  One can approve a decision without approving the associcated cost.  What “approval” does is bind the regulator, i.e., it prevents the regulator from changing the initial decision retroactively.   So a regulator could say “Your decision to build Project X is the decision we approve, provided that it costs less than $2.4 billion.  Any cost above that, the consequences are XYZ.”  There are many ways to write that sentence.

For projects not approved in advance, I assume they are noted in the next rate case and this is where the company makes the case. My impression from the cases we looked at over the last year or two is that this is not a particularly big deal. Does any substantial proportion of actual capex get turned down?

In the nuclear era, early 1980s, regulator disallowed billions in cost overruns.  Some utilities were badly damaged.  But consumers also paid a lot of these overruns.  Today, not much capex gets turned down after the fact.  But that is because utilities are seeking pre-approval.

In either case, is there much ex ante discussion of these issues between company and users? i.e., company asking users what they want built, or responding to users asking for improved facilities?

Excellent question.  Most states had, in the 1990s and the aughts, “integrated resource plan” processes whereby the utility engaged in present plans that would guide later project proposals.  So a project proposal for pre-approval was considered in the context of a longer plan.  There has been some backing off of this IRP process, especially in states that enacted retail competition processes or ordered their utilities to divest generation.  I am concerned that we have insufficient plans now, so that we lack context for project analysis.  I address this point in the Illinois testimony.

In all this, would transmission be significantly different from distribution?

Very different because of the jurisdictional difference.  As you know, in much of our country the transmission-owning utilities have transferred control of transmission to regional transmission organizations.  The RTOs are FERC-regulated entities, whereas distribution owners are largely state-regulated.  FERC in its important “Order 1000” has ordered all utilities to engage in regional planning processes for transmission.  The problem is that FERC does not yet say what a “plan” does; that is, there is no known link yet between a plan and cost recovery.  You can get a download of the NRRI teleseminar on Order 1000 by contacting www.nrri.org.

Finally, I see that AEP Texas initiated a series of discussions with Texas PUC about ways to streamline the traditional rate setting process, especially to address the regulatory lag between incurring costs and recovering them. One mechanism under discussion is the ability of a company to update its capex annually and adjust its rates according to the previously approved ROE, with reconciliation at the next full cost of service review. Is there anything of that kind elsewhere, either existing or in prospect?

I am not familiar with the TX example but what you describe is similar to the situation in Illinois.

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