Kevin Kilty
An Integrated Resource Plan (IRP) is a roadmap of sorts showing a contemplated electrical energy delivery system. The steps to build one are: 1) project likely future demand; 2) determine resources that meeting such demand requires; 3) cataloging what resources are available; and 4) propose how the utility can meet this demand over the current planning period (20 years). Utilities are required to present an updated plan every two years.
In Wyoming we recently formalized the IRP process which now requires the utility to make a formal application to submit their plan followed by a public hearing. The Public Service Commission (PSC) will then decide to accept, acknowledge or reject the plan. I attended the formal hearing last week. It involved only three intervening parties and only three additional members of the public who made statements. I was one, of course.
Interestingly, the standpoint of one intervenor (a large environmental organization) and that of one member of the public coincided and prompted me to ponder the ramifications of their advice which was to reject this IRP. I paraphrase their argument as:
“We are disappointed that this IRP does not propose more solar and wind resource opportunities. This exposes the rate payers to the risk of volatile fuel prices and higher utility bills. We advise the PSC to reject this deficient IRP.”
Of course I objected to this line of reasoning in my commentary. I have reviewed each of the last four IRPs (2019, 2021, 2023, and 2025), and see this current one as the most rational and reasonable of the group. I’d submitted an 11 page dissection of the IRP a year ago. Thus, I may return to the specifics of this IRP once the Commission decides on the fate of this current (2025) plan, because there are interesting things to report.
However, the immediate topic here is to explore this idea that adoption of wind and solar protects rate payers from price increases, zero fuel costs notwithstanding.
Does Adoption of Wind and Solar Protect or Expose Rate Payers to Rate Increases?
No one paying attention can have failed to note that as utilities adopt more wind and solar energy, claiming that the zero fuel cost will save rate payers money, rates nevertheless climb rapidly. Why is this so?
Roger Caiazza, writing as the Pragmatic Environmentalist of New York, has shown that the ideas behind adoption of renewables in New York State will necessarily foist some system costs onto ratepayers in the form of adoption of new appliances. Francis Menton, writing as the Manhattan Contrarian, has emphasized the enormous storage demands to make a renewables dominated grid reliable no matter where it occurs. Many other people make similar arguments.
In brief, the idea of using a levelized cost of energy (LCOE) analysis as the basis for choosing low cost generating resources is flawed. While looking at generating technologies individually seems like a way to optimize costs to rate payers, this is only true for technologies that possess similar operating characteristics. LCOE, unfortunately, compares generating sources individually without recognizing that 1) thermal generating sources and renewables behave very differently, and 2) that not recognizing the LCOE flaw leads to making thermal generating stations slaves to renewables which end up absorbing some of their costs.
Figure 1, from reference [1], shows that LCOE measures of the cost of a generating resource are similar across the spectrum of possible choices with renewables being modestly less costly than other choices. However, a full system cost, as advocated by Robert Idel (reference [2]), diverges markedly between thermal and renewable choices. The reference from which Figure 1 came provided no vertical scale, but it appears to be dollars per MWhr of energy.
Some time ago I wrote a brief essay about estimating battery storage using Hurst’s algorithm for estimating reservoir volume behind dams.[3] My method arrived at a horrifying cost for the needed battery storage.[4] However, as I said in that essay
“Maybe I could get a lower cost by adding solar energy and reducing wind. Maybe not. …”
In other words, there is a possibility of finding a lowest cost system implied here. Not long after producing this essay I corresponded with Joe Born about his efforts to do the same, but Joe actually worked to optimize a solution, in Ercot I recall, by trading an overbuild of renewables against storage. Moreover, Emblemsvag tried to estimate full system cost by simply looking at costs of a solar generating system augmented with battery storage.[5]
Gathering all these efforts together, I decided to look at the PacifiCorp East (PACE) balancing authority area, which is essentially the utility involved in the recent IRP hearing and determine what rate customers would see if the entire system were converted to renewables only. Do the rate payers see a rate shock or not?
EIA data used to simulate PACE in summer 2023
To estimate rates what a person needs first is the volume of revenue producing generation (for PACE this is around 51 million MWhrs per year). Currently the season shortest of generation is summer, when air conditioning demand in Utah is high. Thus I focussed my attention on the half-year from May 1 to October 31. Since I had full data for 2023 at my disposal I settled for using it.
In the relevant time period the amount of renewable generation available appeared to be approximately 3900MW of wind and 1700MW of solar. Using these figures I found that the capacity factor for wind in the relevant half-year is 19.7% and that of solar is 35%. These seem very reasonable for the season involved.
Since the simulation is for a completely renewable electrical grid, I eliminate all other generating sources and scale wind and solar in their 2023 ratio (69.6% to 30.4% respectively) up to being able to supply 6362MW which is 110% of average area demand. This translates into 26,505 MW of renewables in my imaginary thermal-free grid. I also provided 1.5 million MWhr of battery storage completely full on May 1. The history of how storage behaves in this system is shown in Figure 2.
Figure 2. This hypothetical system fails and is unbearably expensive to boot. The system needs more generating capacity.
The result of running the PACE area with this system is that battery storage is completely exhausted in early September. One sees that the PACE area, despite having great solar resources in western Utah and what are considered excellent wind resources in Wyoming, is so becalmed during the summer season that once the summer becalming appears, renewables cannot ever fill the batteries again until the wind returns.
This becalming is a characteristic of the entire continental U.S. during the summer. It is not unusual to find that the entire fleet of wind resources across the U.S. operates at 10%. In a PSC hearing I stated that in PACE presently there are probably 120 periods in each year, lasting from 1 to 15 hours, in which both wind and solar operate below 10% capacity factor – i.e. less than 400MW trying to supply nearly 6,000MW of demand. Luckily we have lots of coal and gas generation to fill in at present.
Let me reiterate that the system costs here are two-fold. There is first the great amount of overbuild caused by the poor capacity factor of renewables. When thermal sources are available on a grid, the renewables can externalize their poor capacity factor by enslaving thermal generation to back them up. In a renewables-only network this becomes an explicit cost. Second, battery storage, which is essential to running a grid without other dispatchable power sources available, is very expensive.
Overbuilding the Renewables
What to do from here is obvious. Battery storage is so expensive that one must overbuild renewable generation to reduce the need for it. Running the same simulation, but with renewable resources scaled up by 20% to 27,550MW, again at the wind to solar ratio as of 2023, shows that one could reduce storage by ⅓ to 1 million MWhr. Figure 3 shows it.
Figure 3. Trading more renewable generation capacity allows one to reduce expensive battery storage.
The run is a success. We come close to running out of storage, though – 200,000MWhr is a day and a half of average demand. Of course, how probable is it that one would be looking at only average demand? Well, the answer to that is 50% probable. Averages are the basis of bad designs.
The decline in the battery storage required in Figure 3, suggested an overbuild that might let me minimize battery storage. A system overbuilt by a factor of 1.76, including 42,500 MW of renewable energy, allows the system to reach a state of minimal energy storage. Once again, this is 42,500MW of renewables to supply an average demand of 5,800MW. This system also included a reserve of 24 hours worth of battery storage – 140,000MWhr. No one in their right mind would neglect having some amount of reserve despite whatever excess renewable energy might be available. Twenty-four hours worth of reserve is probably inadequate, but might be close to what is needed.
Figure 4. Storage history with a renewables overbuild of 76%. Even in this extreme case we constantly use battery storage and even drop below 10 hours of remaining storage reserve.
Figure 4 shows how the battery storage performs. There are innumerable short periods, at most several days at a time, when this system still draws upon battery storage. In fact, in a season of 4416 total hours there are 1284 hours in which batteries must supply some part of demand. In the worst period storage has fallen below 10 hours of reserve. Is this an adequate reserve? One might examine many historical summer’s worth of data to answer this, though the EIA data only goes back to 2019.
One other interesting observation is that the annual curtailed energy in this system is 38.8 million MWhr which is 76% of the delivered revenue energy. Now, in addition to poor inherent capacity factor and expensive storage to provide a dispatchable backup, there are obvious opportunity costs involved also.
Estimated Service Rates
The calculation of rates involves many complications as PACE crosses into various jurisdictions with different tax structures and PUCs that set different rates of return on rate base. However, we can get a reasonable estimate by using the rate on rate base current allowed by the Wyoming PSC (7.65% on rate base [5]), ignoring taxes which are minor, ignoring decommissioning costs for thermal plants, and ignoring some adjustments for new bulk electrical system transmission lines and ignoring that industry make up about 60% of the load in Wyoming and are lower than residential rates. All things considered, the estimate is thus low.
Using either recent cost estimates for wind plant applications in Wyoming, or published construction rates for solar plants, and costs for battery storage for a recent 3MWhr facility, the total construction costs are $54.1, $19.3, and $51.4 billion USD for wind, solar and batteries, respectively. Since we should think of the power system as a perpetuity, there will always be this level of invested capital involved. The rate base will not decline.
The return on rate base is then 7.65% x 124.8 = $9.54 billion USD.
Annual depreciation will be, using a straight line method and twenty years duration,
5% x 124.8 = $6.24 billion USD.
And O&M costs, using published figures of O&M being around 2% of capital investment, are $2.39 billion USD.
Using the equation common to simple explanations of required utility rates the result is:
Rate = Costs/Volume of Service = 18.5 Billion USD/51 million MWhr = $356 per MWhr.
As my current rates exclusive of Net Power Costs (NPC)[6] are roughly $75.9 per MWhr (7.59 cents per kWhr) this represents a cost approaching five times present – even greater than EIA published average rates for California.
Interestingly, if one uses Figure 1 to guess the rates of a weighted average wind/solar system using a Texas benchmark, it works out to $328 MWhr. Though the full system cost in Figure 1 is not exactly the same as utility service rates which include taxes and fees, this estimate turns out to be closer than I might have guessed in advance.
Power service rates of this magnitude should wreak havoc on all Wyoming industries. China will out compete Wyoming in Trona production. Farms will have unbearable irrigation costs. Every other utility one can name has electrical power as an input. Finally, some 40% of Wyoming petroleum production comes from stripper wells that depend on low-cost coal powered electrical energy.
Other Externalities
Before one says “Yes. Expensive. But doable and we must do so.” Look at the other externalities.
At the current Wyoming rate of 100 acres per MW of wind plant, the wind portion of this power system will take 3 million acres. Views, birds, bats, big game animals, and tourism are all likely to suffer. The solar energy portion of the system will take 300,000 acres. One would hope they build sufficient alleyways for large birds to take off when they land in the solar farms thinking they are landing near or on water bodies.
Conclusions
Hopefully this analysis has revealed some of the reasons for rising utility rates when incorporating renewables into the electrical grid despite the renewables having no fuel costs. It also shows why these cost drivers are present but not apparent in a network containing sufficient dispatchable thermal sources of energy. Analyses done on an asset level insensitive to costs of interaction among generating plants will likely never explain the mystery.
References:
1- Jan Emblemsvåg, Rethinking the “Levelized Cost of Energy”: A critical review and evaluation
of the concept, Energy Research & Social Science, 119 (2025)
2- Robert Idel, Levelized Full System Costs of Electricity, Energy, Volume 259, 15 November 2022
3- – Hurst, H.E., Long-Term Storage Capacity of Reservoirs, Transactions of the American Society of Civil Engineers Archive, Vol. 116, No. 1, January 1951.
4 – I’ve decided that all storage systems containing a stochastic element behave the same. Whether we are storing water, food, energy, products in inventory (like munitions for the military) stochastic I/O makes needed storage difficult to calculate and produces a storage history with worryingly long periods of decline and curtailments. Even my refrigerator contents behave like this.
5- J. Emblemsvåg, On the levelized cost of energy of solar photovoltaics, Int. J.
Sustain. Energy 40 (2021), https://doi.org/10.1080/14786451.2020.1867139.
6 – Return on Rate Base is calculated from the capital structure of the utility.
Return on Rate Base = Interest on borrowed capital x fraction of borrowed capital + Return on equity x fraction of equity capital
The PSC sometimes adjusts the capital structure of a utility to reduce costs to rate payers.
7- Net Power Costs are defined as any expenses incurred as a result of inadequate station power. Many things can fit in this category. My Net Power Costs at present are over 3 cents per kWhr. They will change most likely in each successive general rate case.
