Apr. 30, 2024
By Michael Lucas
Utility companies in Wisconsin are monopolies. The state has granted them the exclusive privilege of selling their product within a given area within which no other providers may compete against them. But, in order to prevent practices of monopoly pricing Wisconsin decides the rates that these utilities may charge their customers. While reasonable in theory, in practice, the regulators almost never deny a “rate-change” request from utilities, and actually incentivize them to increase the price consumers pay for utilities. At the very crux of this issue are solar and wind power generators.
There are three kinds of utility providers in Wisconsin: Cooperatives, Investor-Owned Utilities (IOUs) and Municipal Utilities. It is these IOUs that are of particular importance because, together, the five largest IOU providers of residential electricity serve approximately 83% of all Wisconsinites. The largest of these is WE Energies with 39% of the market, then Alliant (WPL) with 16%, WPS with 15%, Xcel Energy (Northern States Power) with 8% and MGE with 5%.
It is no accident that the largest utility providers are all IOUs. IOUs operate differently from their co-op and municipal counterparts in that co-ops are not regulated by Wisconsin’s Public Service Commission (PSC, pg. 13) and municipal utilities can only operate within their municipality. But more importantly, IOUs are private, for-profit companies. Yes, while they are “regulated” by the PSC, this regulation is incredibly beneficial to the shareholders of IOUs. Not only is every IOU listed above publicly traded on the New York Stock Exchange, but Xcel, Alliant and WEC (owner of WE Energies and WPS) are all on the S&P 500 list. Why? IOUs are guaranteed a rate of profit by the Wisconsin PSC. Furthermore, when the PSC decides on a rate of return, they ensure that their rate changes “will not harm shareholders.” This makes IOUs incredibly attractive to investors.
For an IOU to increase its profits, the PSC must approve its proposed rate changes. First, IOUs submit an application called a “rate change” request. Here they detail their expenses, profit rate (“rate of return” or “return on equity”), the amount of revenue required to attain these and an explanation as to why these changes are necessary. The PSC reviews this application and modifies it as it sees fit. After their review is concluded, the PSC does the following (Rate Setting, pg. 13):
- “Sets a rate of return that the utility is allowed to earn on its investment in generating facilities and equipment.” Then,
- “The amount of revenue necessary for the utility to operate, pay debt, and meet its allowable rate of return is determined.” And finally,
- “Prices are set at levels that will generate the company’s revenue requirement.”
In short, the PSC determines utility rates for consumers by reviewing the expenses and desired profit rate of IOUs. You can see examples of this by viewing the rate change requests filed by NSP and WPL and which were approved for this year. For example, the PSC authorized WPL to raise electricity and gas rates by 3.76% and 5.09%, respectively, while also authorizing a 9.8% return on equity.
This method of determining an IOUs revenue and profit is crucial to understanding why renewable energy sources are being built while perfectly functional coal and natural gas sources are being decommissioned. To understand this better, we can express the PSC’s rate-making method as a formula. In effect, an IOUs income looks like this:
Revenue = Expenses + (Value of Property x Profit Rate)
Revenue is the total amount of money that an IOU is entitled to receive from its customers. It’s calculated by the PSC estimating the expenses of the IOU (wages, benefits, supplies, taxes) and then added to the rate of return. It is this second part of the formula that is most important. Let’s look at it in a different way:
Revenue = … + (Gross Value of Property – Depreciation of Property) x Profit Rate
OR
= … + (V – D) x Profit Rate
So, if an IOU wants to maximize their profits, obviously they want to convince the PSC to make the “Profit Rate” as high as possible, but they also want to increase “V” and decrease “D” since the value of “V – D” is then multiplied by the profit rate. How can they do this? Let’s consider an example where a utility has only one coal-powered power plant originally worth $100 million but which has lost half its value over the last 20 years. Let’s also assume their expenses are $1 million and that their profit rate is 10%. The formula would then look like this:
Revenue = $1M + ($100M – 50%) x 10%
= $1M + ($50M) x 10%
= $1M + $5M
= $6M
As a result, the utility is only allowed to receive $6 million from its customers. One million of this will be used to pay its expenses, but the other five million it gets to keep for itself.
Now let’s imagine the utility wanted to increase its profits. Remember that utilities do not care about the level of their expenses because their profits don’t depend on how much money they spend per se. They only make money off the value of their property. So, wanting to increase their profits, the utility decides to tear down their 20-year-old coal plant and put a brand new one in its place that is exactly the same as the original. Let’s assume they still spend $1 million to pay their employees but also pay $1 million to tear down the old plant and $100 million to build the new one. Their profit rate will still be 10% but the depreciation “D” of the new coal plant will now be 0% since it is brand new. Their resulting profit then looks like this:
Revenue = $1M + $1M + $100M + ($100M – 0%) x 10%
= $102M + ($100M) x 10%
= $102M + $10M
= $112M
In this case, the utility is now allowed to receive $112 million from its customers. $102 million of this is used to pay its expenses ($1M in salaries, $1M in demolition costs and $100M in construction costs) but the other $10 million it gets to keep for itself. Their profits have now doubled (!) simply by building a new power plant that is exactly the same as the first.
The incentive for utilities, then, is to build new stuff; not to build better or cheaper stuff; and not to lower prices for consumers. Since Evers’s E.O. #38 seeks to increase the amount of renewable energy, utilities now have the necessary pretext to replace older, yet still functional coal and natural gas plants with new power plants that tend to be wind and solar. This is why We Energies is retiring half of the Oak Creek coal-powered power plant in May (pg. 16) and the other half in 2025, and replacing it with a $1.2 billion natural gas “peaking” facility which won’t be operational until 2028 (pg. 34).
In fact, WE Energies’ plan has prompted Black Mountain Energy (pg. 4) to build $450 million worth of battery storage to offset the inevitable electricity shortage that the early retirement of Oak Creek will create: “When the Oak Creek plant retires, there will be an imbalance in supply that will lead to higher electricity volatility and prices in the greater Milwaukee area.” No doubt, Black Mountain is incredibly grateful to WE Energies for this profit opportunity.
But the plot thickens! Under the direction of Governor Evers, the PSC also now has an incentive to approve the construction of these new power generators so as to satisfy the executive order.
IOUs, the PSC and the Evers administration all have an incentive to overstate the potential of wind and solar to generate electricity. Evers and the PSC do this to sway the public into believing that renewable energy is a good idea; the IOUs do this to pad their bottom line. IOUs accomplish this by stating that the expected lifespan of wind turbines is 30 years, making their depreciation rate only 3.3% per year. But if the actual lifespan of wind turbines is ten years, then the turbine really depreciates by 10% per year. In effect, utilities can increase their profits from renewables even more by misrepresenting the real value of “D”. The example below shows the profits earned by a utility when using a false, artificially lowered “D” compared to the real value of “D”.
Year 1 Profit = … + ($1M – 3.3%) x 10% = $96,000
Year 2 Profit = … + ($.96M – 3.3%) x 10% = $94,000
Year 3 Profit = … + ($.93M – 3.3%) x 10% = $90,000
Total Profit = $280,000
Year 1 Profits = … + ($1M – 10%) x 10% = $90,000
Year 2 Profits = … + ($.9M – 10%) x 10% = $80,000
Year 3 Profits = … + ($.8M – 10%) x 10% = $70,000
Total Profits = $240,000
By using the artificially low “D”, within just three years the utility is able to earn an additional $40,000 in profit—a return that is 14% higher than it otherwise would have been. Furthermore, IOUs can simply choose to retire their power generators before the end of their useful life. This is the case for Oak Creek and other fossil fueled power plants but also for renewables, particularly wind turbine owners who wish to take advantage of the federal Production Tax Credit subsidy (pg. ix, bullet 5). There is no statute in Wisconsin law preventing early retirement. Alas, this is still not the end of our story. The plot thickens once more!
There is a third reason why utilities choose to replace fossil fuel plants with renewables. In short, when utilities “discover” that their wind and solar farms do not produce enough electricity to meet consumer demand, they yet again have cause to build more. Since the current narrative regarding the “sustainability” of the planet is all-important, utilities wouldn’t dream of building fossil fuel power plants to make up for the renewables’ deficits—no, the “responsible” thing is to build more renewables. But how many more? As will be shown in the sections The Problem with Solar and The Problem with Wind, utilities must overbuild wind and solar to achieve the same electricity generation. To summarize quickly, wind turbines, solar panels, coal plants, nuclear reactors—all power generators have a nameplate capacity. Nameplate capacity is how much energy each can produce if operating at its peak output. However, almost none of these actually operate at peak output, and when they do, do not operate at peak output for long.
This brings us to the concept of a capacity factor. A capacity factor is the rate at which a generator produces electricity compared to what it could produce. For example, if a coal-powered power plant could produce 100MW but only produces 50MW then its capacity factor is 50%.
Capacity Factor = Actual Output / Potential Output
Or
50% = 50MW / 100MW
For context, in Wisconsin in 2022 solar had an annual capacity factor of 17%, wind 28%, coal 47%, natural gas 63% and nuclear 96%. In the case of wind and solar, their capacity factors are genuine reflections of their potential—but the same cannot be said for coal, natural gas or nuclear. In 2022 there were many months in which each of these produced more than what their annual capacity factors say they did. This is also true for wind and solar but in the case of coal, natural gas and nuclear, their capacity factors are lower because utilities choose not to run them at capacity. In July of that same year, natural gas reached a capacity factor of 78%. Similarly, coal had a capacity factor of 40% in February and Wisconsin’s one nuclear plant had a capacity factor greater than 100% for eight months out of the year. Given the nature of the fuel used for these three sources, utilities can control how much electricity they generate. This is not the case for wind and solar—a fact which utilities are well aware of.
For our final example, let’s imagine a utility has a 100MW coal plant that it wishes to replace with 100MWs of solar panels. The utility constructs the solar farm and is able to earn greater profits from this (as was shown in our first example) and is also able to increase their profits by exaggerating the lifespan of the solar panels (as was shown in our second example). After some time, the utility “discovers” that their 100MWs of solar panels don’t produce 100MWs of electricity. Instead, they only produce 17% of their nameplate capacity. To make up the difference, the utility must increase the number of solar panels by a factor of 5.88 (!). Whereas one coal plant with a capacity of 100MWs could produce 100MWs of electricity, 588MWs of nameplate capacity are required for the solar farm to produce100MWs. But even this is an understatement. Solar’s 17% capacity factor was the average for the entire year and thus doesn’t tell us what it produces during the winter. If we are to be able to turn on our lights during winter the utility will have to build more than 588MWs of nameplate capacity, even though most of those solar panels will not be needed for the rest of the year. In 2022, Solar’s lowest capacity factor was just 4.9% in the month of December. Consequently, the utility must overbuild solar to account for just this one month. If they do that, instead of the 588MWs of nameplate capacity we previously required for solar, we will need 2000MWs of solar nameplate capacity—twenty times higher than the coal plant requires.
Just as December was Solar’s low point in electricity production for the year, there are also low points in a month and low points throughout the day. Specifically, the deepest low point is between sunset and sunrise (go figure). But even if the sun does shine, Solar’s capacity factor can be 0% in winter if the panels are covered with snow and can suffer performance losses when temperatures are too hot. When seasonal, monthly and daily variations in sunshine are taken into account, utilities, again, have a reasonable pretext for building additional solar capacity. And in the event that solar cannot be depended upon to generate electricity during the night or in harsh weather conditions, not to worry! The utilities can simply supplement their solar farms by building wind turbines with annual capacity factors of 28% and 13% capacity factors in August.
May they be so fortunate as to avoid the German Dunkelflaute.