• Like most states, Louisiana’s electricity utilities operate as monopolies, meaning customers don’t choose their electricity provider.
  • To mitigate risks of future outages and higher costs, utilities submit plans to regulators that lay out demand forecasts and supply plans.
  • Recent plans indicate a risky transition away from dispatchable natural gas plants and towards solar and wind production in Louisiana to make up for future deficits.
  • Utilities’ plans will directly impact the rates that electricity users like you pay because they will determine the costs that utilities incur. Under the regulated monopoly model, utilities pass their costs directly on to consumers.
  • Regulators, known as Public Service Commissioners in Louisiana, should explore allowing differentiated service options to customers to mitigate risk of higher costs and rates in the future.


The purpose of this blog post is to introduce you to Integrated Resource Plans (IRP) which are reports that regulated utilities submit to public service commissions every few years, and to discuss some implications of those plans. Most states in the United States operate under a regulated monopoly model for electricity provision which gives a utility the right to be the sole provider of electricity in its service area. There are costs and benefits to this model, and it is a continuously debated issue.

One risk of the regulated utility model is that households and businesses within a given utility’s service area are dependent on a single utility: if that utility faces outages or high costs, there is relatively little those individuals and firms can do outside providing their own backup power with emergency generators or batteries. IRPs are one way that public service commissions like the Louisiana Public Service Commission (LPSC) mitigate this risk. Public service commissions require utilities to submit IRPs so they, and the public and ratepayers, can understand how the utility plans to meet electricity demand in the future.

Based on a changing national regulatory environment and social pressure related to the use of fossil fuels for energy, many IRPs submitted in recent years reveal plans to replace fossil fuel plants, e.g., coal fired power plants and natural gas fired power plants, with renewable generation, e.g., solar and wind. This is important in Louisiana as the vast majority of electricity in Louisiana is currently generated using natural gas,[1] and abundant natural gas production in the region keeps natural gas prices and electricity prices low. Towards the end of this post, I will introduce some of the implications and risks of a transition towards relatively higher proportions of renewable generation in the mix after explaining some key concepts related to electricity markets. Finally, I hint at potential solutions to this conundrum.

Preliminary Descriptions and Energy Jargon

In order to better understand the rest of this blog post (and future posts), I will start with some preliminary descriptions.

Electricity Demand Planning

Utilities make predictions about future electricity demand, or “load” in energy industry jargon. They use factors like current electricity demand, estimated population growth, estimated economic growth, etc. to make these demand predictions. Utilities need to plan to have enough electricity generation capacity for their estimated “peak load,” or maximum energy demand at any given point in time in the future. In Louisiana, this is likely to occur on hot summer days when a large number of households and businesses use air conditioning.[2] If the utility failed to meet the peak load, power would need to be cutoff or reduced for at least some customers. Utilities are obligated to avoid the possibility of such “outages” by planning to have enough electricity generation capacity for peak load plus a “reserve margin.” The reserve margin serves as a buffer to avoid service disruptions if some power plants are offline or demand is higher than predicted.

Dispatchable versus Renewable Electricity Generation

The production of electricity, or “electricity generation,” can occur at “dispatchable” power plants and “intermittent” power plants. Dispatchable power plants include those powered by natural gas, coal, and nuclear. These types of plants can adjust the amount of power they are generating to match current demand to a greater extent than intermittent plants, which is important to the proper functioning of the power system. Natural gas plants are especially flexible in terms of their ability to generate more or less power and fire up quickly.

On the other hand, intermittent power plants like solar and wind plants are not dispatchable because the amount of power produced is at least partially determined by natural factors such as cloud cover and wind speed. This inherent intermittency can be mitigated to some degree by storing power generated from wind and solar, or from backing those generation units up with dispatchable ones.

Power plants do not produce power all of the time. Dispatchable power plants need to go down for maintenance, while solar panels do not produce power at night, for example. Operators may also choose not to operate a dispatchable power plant when fuel, e.g., natural gas, is relatively expensive. The “capacity factor” of a power plant measures the power the plant actually produces as a percentage of the amount of power it could produce if it ran at maximum capacity all the time. The formula for the maximum potential production in a year from a power plant is:

Max Production = (Capacity) × (Number of hours in year).                      

So, a 10 MW power plant could produce 87,600 MWh of electricity if it operated a maximum capacity all year (in a non-leap year). The average capacity factor at combined cycle natural gas plants was 56.6% in 2022 and 12.9% at gas turbine plants. The former are much more efficient than the latter, so they are less costly and operated more for economic reasons. A 10 MW combined cycle gas plant would be expected to produce about 0.566 × 87,600 = 49,582 MWh in a year. The vast majority of new natural gas plants are combined cycle natural gas plants.

The average capacity factor for solar plants is approximately 25% and the average for wind is approximately 35%, but these numbers vary a great degree by location so applying the average to new plants is risky. Importantly, the main driver behind capacity factors for solar and wind are natural intermittency, e.g., random variation in wind speed and cloud cover, while the main driver for natural gas and other dispatchable plants is economic choice.

Future Generation Deficit

IRPs submitted by utilities to public service commissions like the LPSC often include a chart like Figure 1. If you look at IRPs submitted to the LPSC in Louisiana, you are likely to observe very similar charts, but they will often have more granular information about the types of planned capacity and the types of power plants that will go offline in the future. It is not surprising that an energy deficit exists in these plans as is almost always the case. The key to these reports is understanding how the utilities plan to make up for such deficits.

Figure 1: Integrated Resource Plans submitted by utilities to public service commissions like the LSPC often include charts like this. (This chart uses made up numbers, but the pattern shown is very common.) The “Load + Reserve Target” line shows the utility’s estimated future demand, while the “Existing + Planned Capacity” shows how much electricity generation the utility will have from currently existing plants plus those that they have solid plans of building. The distance between the two series represents the generation deficit faced by the utility.

The first thing to note is the reason the “Existing + Planned Capacity” series decreases over time. Power plants have a limited operational life. Utilities estimate when their current plants will shut down. For example, natural gas power plants usually have a lifespan of between 30 and 40 years. Power plants might shut down if they become uneconomic due to inefficiency, or they might shut down if regulations change. For example, many oil power plants have shut down over the years because oil is relatively expensive compared to coal and natural gas due to its value in the transportation sector. On the other hand, coal plants have shut down as air quality regulations have become more stringent. Utilities need to work both of these possibilities into their assumptions to estimate the “Existing + Reserve Load” capacity line. Utilities often have specific short-term plans which is why I’ve shown a generation surplus in the first few years in Figure 1. However, as the time horizon gets longer, the impact of plants shutting down overtakes planned capacity additions, and a deficit begins and widens over the planning horizon.

Risks of Higher Costs

Electricity generation deficits faced by utilities in Louisiana pose a significant challenge. Many utilities’ current plans, under the regulatory guidance of the LPSC, is to replace dispatchable natural-gas generation with intermittent solar and wind resources. This requires assumptions about how much power the intermittent sources will generate and how their generation will align with demand. If it is windier at night when demand is low, then utilities will need to invest in storing power in batteries in order to match production with demand, or back up intermittent sources with dispatchable plants.

Utilities’ plans will directly impact the rates that electricity users like you pay because they will determine the costs that utilities incur. Under the regulated monopoly model, utilities pass their costs directly on to consumers and consumers cannot seek lower prices from competitors like they can in free markets.

One constraint embedded in the regulated utility model of electricity markets is that all the utilities’ customers are treated as though their energy consumption is similar, but this is certainly not the case. Small residential customers like me use electricity primarily for things like air conditioning, doing laundry, and charging my cellphone. Although my electricity bill varies from month to month, my habits around these activities do not change that much. On the other end of the spectrum are large industrial electricity users who use electricity in the process of producing other goods like petrochemicals at large factories. Large consumers like that would like to manage their consumption of electricity around short term variation in electricity prices. In other words, such users would like to manage their consumption around short term variation in electricity supply conditions. It appears that some customers would be better matched with renewable generation that can provide very low cost but is relatively unpredictable while other customers would be better off with dispatchable plants.

In most markets, we see companies specialize in serving different types of customers even though they are fundamentally buying the same good. Federal Express’s claim to fame is differentiating between customers who valued extremely fast delivery and those who would prefer to wait and pay lower prices. This differentiation allowed it to successfully compete with the extremely large, and government-supported, U.S. Postal Service. Similar opportunities for differentiation across customer types exist in electricity markets in Louisiana

[1] In 2022, 68% of electricity in Louisiana was generation from natural gas. See https://www.eia.gov/state/analysis.php?sid=LA

[2] For example, peak load on Entergy Louisiana’s system occurred during the week of June 20 in 2022. See www.lpsc.lousiana.gov.