Setting Utility Rates • Watts Up With That?

Kevin Kilty

Until about a year ago, I thought about public utility regulation as too boring, too far outside my education, and unrelated to my interests and experience to bother with. I was wrong.

Figure 1. The relationships among interest on bonds and dividends to preferred shares (collectively called debt) and return on capital to return to ordinary shareholders (equity)

What prompted my change of view was recognizing that a frontline in the war, if you will, to remake the electric grid will take place not in arguments about the reality of climate change, but when utilities decide to change the way they generate electrical energy and pay for these changes. The permission to make these changes, and how the ratepayer gets hit afterward, are decided in the public service commissions which by law have to make their deliberations substantially transparent to the public. In particular permission for changes are gained in hearings of public necessity and convenience; how the ratepayer gets hit is decided in rate cases. I plan to examine only rate setting in this brief essay.

My principal goal is this. Many of us are pretty certain that pouring more renewable energy into a network makes delivered energy more expensive and less reliable. We often point to a graph that shows costs rising with percent renewable contributions to generating capacity. Yet, our antagonists claim that adding energy from renewables should, and in fact does, reduce utility costs. They have data, too. We strengthen our case by demonstrating specific reasons, or lack thereof, for rising utility bills. The rate setting process ought to make those reasons visible.

I also suspect most people know little about rate setting and are unaware about its complexity. It’s important to understand this bit of the order of battle.

Where I live we are in the middle of a general rate case affecting one-half the state.  It calls for substantial rate increases (21.6% or over $140 million) and has become exceptionally contentious. It resembles rate cases that have been decided or are in progress across the U.S.[1] The application for this general rate case includes thousands of pages of exhibits and appendices.

The Essence of Rate Setting

Long ago people recognized that the delivery of utility services was probably best handled by allowing a private firm to have a monopoly over this service. At the same time people also recognized that the inherently bad effects of monopoly power had to be addressed. The response was to create public utility commissions whose decisions regarding utility expenditures and methods of financing those expenditures would have the force of law.

The basis of utility rates are best explained as follows in two equations.

1. Needed revenue = operating expenses+depreciation+taxes+(rate of return x rate base)

• Then; rates = needed revenue / assumed volume of service.

The usefulness of this organization is apparent. Operating expenses, and taxes are aligned pretty well with the immediate delivery of services. Depreciation is how capital expenses are eventually recovered as assets wear out. Rate of return is necessary to provide access to capital markets where the resources are garnered for construction of assets to provide service.

There is some overlap. For example, some maintenance could be a capital expenditure and depreciated. Nonetheless, this is a pretty clear summary of revenues required to operate.

Equation 2) appears far more simple than the actual situation. What we call rates is actually a large set of tariffs each of which involves many components and which apply to various customers. The tariffs are structured to prevent one group of customers, such as residential consumers, from subsidizing another, say industrial consumers; while at the same time supplying the needed revenue of Equation 1). The “assumed volume of service” category is actually a guess at the volume of sales. It occasionally happens that the utility over-estimates its sales volume and cannot reach its proposed revenue requirements – a case of volumetric risk.

The goal is to arrive at revenues allowed by the Commission and a structure of tariffs that are “just and reasonable”. The standard of “just and reasonable” became a governing standard through a couple of Supreme Court cases in the 1920s to 1940s.[2] It means, in effect, that customers are truly paying for the value of the service they receive while the utility can earn enough money to stay in business and maintain access to capital markets; all the while the service that results being affordable and reliable. The most contentious aspect of any rate case is justifying and ordering the rate of return on equity.

There is another standard which serves as a worthy goal but which is rarely mentioned in my experience of reading documents and attending meetings. This is “used and useful” which is where the value of a net-zero grid becomes doubtful. It is allowed through Wyoming Statute (Wyo. 37-2-119) but which might be missing in the enabling statutes of other states. The idea is that prudent planning and expenditures should be useful to the delivery of service and actually used in the delivery of service. Stuff falling outside this domain, such as excessive compensation or excess labor or poorly justified projects are the very definition of unnecessary and unjust, unreasonable expense. Dispatchable versus non-dispatchable generation without dedicated backup cannot be viewed as equally “used and useful”. The standard of “just and reasonable” has trouble weighing the differences.

Two other things are important. First, there is dreadful asymmetry with regard to knowledge between the utility and practically all other parties to the rate case. The president of the utility verified this when he said that there are no parties who know more about the topic or the rate case than the utility company itself. This standpoint is entirely reasonable, but it unwittingly also makes the point that since parties are biased toward their self-interest, the greater knowledge of the utility must come with skepticism about their claims.

Second, proof of the reasonableness of the proposed costs, revenues and tariff adjustments is made by applying them to a test year to show how they would work in practice. Traditionally the test year was a historical year for which almost all the data involved, except the new tariff structure, were known quantities. About 15 years ago the utilities began making a case that a future test year (FTY) was more appropriate because it would reduce the regulatory lag between identifying shortfalls in revenue and new tariff structure. Wall Street endorsed this view also. However, having utilities and Wall Street, who both stand to gain by shifting their risks, endorse this new model should raise a flag of caution.

The FTY contains unknown quantities; inflation, capital markets, economic activity, volume of service, demographics changes, and so forth have to be guessed at. Combined with the asymmetry of knowledge, the uncertainties in using a FTY serve not only to make expenses obscure,[3] but potentially reduce market discipline. Regulatory lag aided market discipline by making the utility responsible for costs during their “naked” interval. Lack of market discipline leads to overcapitalization and bloated O&M.

A Current Rate Case

How the simple picture painted above of utility regulation departs from practice is well explained by our rate case. The rate case in question was born on March 1, 2023 when the utility sent its application and all supporting appendices, which amounted to thousands of pages, to the Public Service Commission. A historical year running from mid-2021 to mid-2022 provided a data gathering period to project into the FTY which is 2024. The order resulting from this hearing must be rendered by January 1, 2024 when the new tariffs become effective.

The utility makes its case for rate increases in the application thusly:

(1) continued capital investments including, the Gateway South, Gateway West Segment D.1 transmission lines and the Rock Creek I wind project, along with the Foote Creek II-IV and Rock River I wind repowering projects, which are required in order for the Company to meet its obligation to serve its customers and includes an associated rate of return of 7.60 percent on all capital investments; and (2) NPC.

So, there are three categories of costs; (1) capital expenditures which are recaptured through depreciation, (2) cost of capital which involves the debt involved (bonds and preferred stock), and return to common stock (see Figure 1), and, (3) net power cost (NPC) which catches the rest of Equation 1).

The first two categories are, in my view, relatively clear in their cost of power implications. New capital expenditures will enter a depreciation schedule and the rate structure will directly reflect those depreciation charges. What has to be determined is, on a per kW capacity basis, do renewable energy assets cause larger depreciation charges than the thermal assets they replace? I think the answer is yes for two reasons. First because the average capacity factor for renewables is far lower than thermal assets, the capital cost to replace thermal assets is going to lead to a larger book value to depreciate. I’d say at least 50% larger first cost for equivalent capacity.

Second, renewable assets have shorter depreciation schedules (20 years is widely quoted) than thermal assets (40-50 years is widely quoted). Treated as a perpetuity of sorts, renewables are decommissioned and replaced twice as often. A complication in this instance is that while coal assets are being abandoned (early in some instances), there are some new gas-fired assets that are needed largely as backup for non-dispatchable assets. These will have useful lives much shorter than typical thermal assets (15 years if the schedules in the typical integrated resource plans (IRP) are followed). Even if these plants have utility left in them by the time they are decommissioned, the remaining value will enter some sort of account that will be amortized on an accelerated schedule.

The impact on cost of capital follows similar thinking. There is a differential cost on an equal capacity basis which the rate structure will deliver a return on capital, dependent on the utility’s capital structure and interest rates on debt, but which is typically 7-8%. Let’s just take a wind plant as an example. For wind with an annual capacity factor of one-third to deliver energy like a coal-fired plant with annual capacity factor of 0.85 would require building 2.55 times as much wind plant (0.85/0.33). A quick estimate of the differential first cost would be $825 per kW of nameplate. The impact across rates would be around $100 per kW per annum of additional depreciation and return on capital. In fact, the overbuilding might be much larger. Xcel Energy advertises net dependable power of non-dispatchable sources as needing an overbuild relative to dispatchable coal being three to six.[4]

One could analyze many other new assets the same way. For example, some new transmission lines would not be built if not for the need to gather widely dispersed wind or solar energy. There may be some offsetting savings in debt because of an ESG preference for valued assets versus thermal derived energy, but considering the planned investments in renewables and the enabling transmission lines there cannot be but growth of rates from depreciation and return on capital.

Keep in mind that people might confuse depreciation with return on capital, but they are very separate and additive – one provides for recovery of capital expenditures the other affords access to capital markets.

The complications of NPC

Now we come to that place where the story becomes hazy – net power cost (NPC). The term NPC isn’t clearly related to any single item in Equation (1). The legal definition I have placed in the notes.[5] Its definition seems to open the door to all sorts of things.

Moreover, NPC is not directly determined from accounting entries which is what Equation (1) implies. Instead, in our rate case, it results from modeling. In our case, a sophisticated modeling and optimization program, “Aurora”, has input to it all the assumptions and projections (and uncertainties) of the FTY plus the known characteristics of generating, transmission and distribution assets. In working to find a least-cost solution to the problem of delivering specified power to all customers, it also produces a detailed projection of the components of NPC for the test year. I won’t remind readers of WUWT about the pitfalls of modeling future outcomes vis-a-vis desires.

In our rate case one witness produced a detailed picture of NPC factors affecting policy and operations. Examples are:

• Taxes; including a direct $1/MWhr wind tax in Wyoming to an indirect $24.75/MWhr carbon tax (the CCA) in Washington State levied against a natural gas plant that probably does a lot of balancing wind and solar.
• Abandonment of hydroelectric plants on the Klamath River.
• Market purchases of 1) Day Ahead/Real Time (DA/RT) purchases, 2) summer shortages of thermal plant capacity, 3) Coal to gas conversion requiring temporary market purchases. The utility claims these costs of market purchases of power have risen 200%. What causes this market price inflation?
• Environmental concerns such as the Ozone Transport Rule (OTR) and NOx emissions.

Thus, many factors that could fall under a category like “environmentalism” have substantial impacts on NPC.[6] Even a small factor like net power purchases or feed-in tariffs from residential wind and solar have the effect, one witness said, of increasing rates across all classes of customers. Perhaps the rising NPC and adoption of wind generations are simply both correlated with the endless stream of environmental demands.

Our utility claimed in multiple instances that wind energy saved customers $85 million because it has no fuel cost. A person would really like to see the cost accounting that substantiates such a claim. However, in absence of such data we could ponder Feynman’s dictum that “if you start a [classical] argument in a certain place and don’t carry it far enough, you can get any answer you want.”[7] Carrying far enough in this case means saving customers even more money by adopting 100% wind energy right now which is what the Sierra Club and a majority of voters apparently want.[8] Figure 2 shows this to be patently impossible.

Figure 2. Generation data from EIA in the PacifiCorp East balancing authority area this past week.

What Figure 2 shows first, is that wind disappears routinely. In fact, October 2023 has delivered four separate wind droughts in the EIA Northwest region; one of which was a full week long. More important, though, is to note the anticorrelation between wind or solar and coal thermal energy in Figure 2. Coal is 70% anticorrelated with solar and 50% anticorrelated with wind. Coal is balancing both with some limited help from natural gas. The amplitude of the total adjustments in coal output are as large as 3,000MW; sometimes more than once a day. It would not be remotely possible to run PacifiCorp East (PACE) on wind energy without coal or its equivalent. Moreover, the indicated capacity factor of coal plants is 51% and wind is 27% in Figure 2.

No one in their right mind designs a coal thermal plant, especially a base-load plant, for 50% capacity factor. Instead coal design should figure 100% at maximum demand and some reserve and running capacity at about 80% or even higher.[9] What has happened to the capacity factor?

Figure 3. Trend of U.S. thermal plant capacity factor. Data from EIA. Figure for 2023 is based on January through August with estimates for the balance of the year.

Figure 3 perhaps supplies an answer by illustrating a trend. The capacity factor of coal plants in the U.S. has been on a long decline commensurate with adoption of more renewables. This same tendency of declining capacity factor is true of all networks worldwide and especially among coal thermal plants but is true of renewables as well.[10] In other words, a universal consequence of adding renewable energy to networks is more costs devoted to delivering less energy per unit of investment.

People try to explain this observation in ways convenient for their worldview but I see a simple explanation.[11]

Renewable generation took the best locations early and as more is added these less capable locations reduce overall capacity factor. The variations in renewables, clearly visible in Figure 2, grow larger with more renewables. Thus, the balancing dispatchable source of energy, typically thermal, has to supply larger power levels for the worst cases of renewable shortfall, but has to be curtailed to accommodate the occasional large contribution from renewables. Thermal plants can only be curtailed so far but any curtailment leads to a reduced capacity factor.[10,12] The limited ability to curtail thermal plants inevitably leads to more curtailment of renewables which lowers their capacity factor further. The two very different generating sources walk one another to lower and lower capacity factors.  Eventually capacity factor declines to whatever source dominates the grid.

The utilities and environmentalists might contemplate how forcing thermal plants to accommodate and balance non-dispatchable energy, with its poor capacity factor and wild swings of output, leads to: 1) reduced efficiency of thermal plants, 2) increased maintenance costs, and 3) shortened asset life.[12] Perhaps someone could quantify these factors and apply them to the cost of delivering “free” wind energy just to humor us skeptics. Yet, the answer doesn’t matter. No matter how the costs are accounted for, the consequences demand higher rates.

Conclusions

Engaging in happy talk about wind energy saving customers money and garnering the approval of the ESG obsessed will never substitute for reliable operation. Whining about thermal assets being inflexible and preventing full adoption of wind and solar is simply PR. Someone must admit the realities that Figures 2 and 3 show.

References and notes:

1- Minnesota PUC cut Xcel Energy’s request of 22% to 9.9% in June 2023.  The New York State PSC cut rate requests by NYSEG and RG&E by about 50% in October 2023.

2-These are referred to as Bluefield Waterworks (1923) and Hope Natural Gas Co. (1944). However many other early decisions could serve just as well. See for example, Herman Trachsel, Public Utility Regulation, Irwin Publ., 1947. I’m not sure why these two cases seem to have exerted the most influence.

3- One consistent feature of testimony of the utility and the intervenors, both written and oral, is to seemingly forget that the NPC is for a test year which is in the future. There is a tendency for the utility witnesses, when asked to justify some driver of NPC, to immediately begin discussing some event of the recent past or the present rather than their effects in the FTY and especially not into the uncertainties of their projection.

4-American Experiment, June 20, 2023,  Minnesota’s energy transition threatened after Xcel’s reduced rate increase. Online at “Minnesota’s energy transition threatened after Xcel’s reduced rate increase.pdf” If a person considers storage to replace dispatchable thermal assets, then the amount of overbuild expands greatly.

5-From Lawinsider.com the definition of NPC:

Net Power Cost means, for any period, the cost during such period of purchases by Power Marketing of Deficit Station Power, increased by (i) the amount of any transmission or other costs incurred by Power Marketing during such period in delivering Deficit Station Power to the point of sale, (ii) the amount of any state or federal Taxes paid or required to be paid by Power Marketing with respect to the purchase of Deficit Station Power or otherwise with respect to the performance of its obligations hereunder, and (iii) the amount of any other costs paid by Power Marketing during such period in connection with the purchase of Deficit Station Power, including an arms-length, commercially reasonable allocation of overhead and administrative expense.

6-As of this morning I received notice of a hearing on continuation of a 0.3% per month surcharge on all billing statements to establish a Carbon Capture Use and Storage (CCUS) portfolio standard – currently deferred but which the deferred balance accumulates interest at the allowed cost of capital.

7-Feynman’s Lectures on Physics, Vol II, Chapter 34 Section 6.

8-The Sierra Club actually believes PacifiCorp could abandon thermal assets immediately and claim that depending on thermal assets was always a “risky” proposition. A survey indicates that voters in Utah want more solar and wind generation by a majority of 8:1.

9-The factor includes some down-time for turnaround maintenance and additional curtailment because of variations in day/night demand.

10-Natanael Bolson, et al, 2022, Capacity factors for electrical power generation from renewable and nonrenewable sources, PNAS, 119, 52, doi:10.1073/pnas.2205429119

11-Such excuses include the idea that thermal plants were overbuilt through poor projections of energy demand. Some decline might be related to aging of plants with underinvestment in maintenance.

12-The lower limit of curtailment depends on many factors but could be 30-70% of maximum. Generally, the lower the limit on curtailment the worse the efficiency of fuel use and aging of plant.

13-IRENA, 2019, Innovation landscape brief: Flexibility in conventional power plants. International Renewable Energy Agency, Abu Dhabi. Available online at www.irena.org/publications