Because regulation has traditionally insulated customers from market pricing, electricity markets have not historically followed standard economic principles. The general paradigm in electric markets has been supply will be built to meet forecasted demand, regardless of cost. And demand is based on demographics, business activities, and weather patterns — again, regardless of cost issues. The other key factor about electricity demand is that time of use is critically important since peak demand drives much of the cost of the system, and capacity must be planned to meet the overall market peak even though that may occur only a few hours out of the year. Some utilities have moderated demand growth through demand side management (DSM) programs that encourage customers to enhance energy efficiency or move demands to off-peak periods. But in general, we have traditionally built power plants and transmission lines in step with forecasted demand increases.
In the long term, supply has historically been driven by demand forecasts. Once a utility’s forecast indicates that a region’s available supply is getting close to demand, the utility will request new resources in its integrated resource plan, regulators will approve either the construction or purchase of new resources, and, voila, supply is increased.
But in the short term, increasing supply is more difficult since it generally takes at least two years (and often much longer) to plan, design, permit, and build a new power plant. Thus there are really two sets of supply/demand issues to consider: long-term issues that relate to decisions to build new infrastructure and short-term issues that determine whether there is enough supply to cover customer needs for today, tomorrow, and this summer.
The way that the balance of supply and demand in a specific market region is evaluated is by looking at the reserve margin. The reserve margin is calculated as the total supply capacity in a region (supply can include generation plus available firm imports) minus the peak demand, divided by the peak demand. For instance, if a marketplace has 12,000 MW of supply and 10,000 MW of peak demand, the reserve margin would be: (12,000 — 10,000) ÷ 10,000 = 20%. Essentially, we are calculating how much extra supply is available to a given region. This is important for extreme weather situations or in the event any of the total supply should suddenly become unavailable.
Although target reserve margins vary by region, a rule of thumb is that markets with reserve margins of less than 15% are considered tight. Those with margins between 15% and 20% are considered balanced, and those with margins greater than 20% are often considered oversupplied. Some regions now use a more sophisticated analysis that employs reliability simulations to determine what level of supply capacity is required so that daily system peak load is not likely to exceed available supply at any hour during the day more than once in a 10-year period.
Short-term supply and demand
The short-term supply/demand balance is driven simply by projected demand and the supply available to meet it. The marketplace will generally look at this on a seasonal and monthly basis (since blocks of power are often traded and/or priced seasonally and monthly) and then again very closely in the day ahead (since this is when the system operator will schedule actual units and transmission lines). In the short term, demands are driven largely by weather (hot weather in summer driving cooling loads and cold weather in the winter driving heating loads) as well as business activity (often determined by the day of the week). Short-term supply is driven by the availability of generation units, transmission, firm power imports, and in some regions storage and flexible loads participating in supply markets.
A number of factors can impact unit availability including maintenance needs, environmental restrictions, fuel availability, and weather patterns (for hydropower and renewable resources such as wind and solar). In a competitive marketplace, additional factors such as contractual conditions, tariff provisions, and the behavior of market participants also come into play. On an hourly basis, unit availability is also impacted by start-up and ramp-up times. Units that haven’t been started may not be available for a given hour if the time it takes to get them online safely is longer than the hour in which they are needed.
Transmission line availability is also an important factor when determining available supply. This is affected by weather (hot weather reduces capabilities), maintenance needs, and use of the lines by other market participants. If supply/demand is tight for a given day or hour both market prices and system reliability may be impacted. Short-term supply/demand factors include:
Long-term supply and demand
In the longer term (greater than one year), demand is driven largely by demographics and business cycles. But also important are energy efficiency improvements and the growth rates of building electrification and electric vehicles. Long-term supply is affected by construction of new units and/or transmission lines, retirement of units, and, in some markets, availability of hydropower (driven by weather patterns) and growth of DERs. Construction of new units can be impacted by capital availability, regulatory decisions, environmental restrictions, willingness of buyers to sign long-term power purchase agreements, and market participants’ perception of future profit opportunities (in competitive markets). Long-term supply/demand factors include: