∫ Economics of Electric Rates

How much you pay for electricity is not as simple as you might think. Rate structures have changed drastically over time and vary substantially between customer classes and utility territories. While the rationale behind the rate that you pay for electricity may not be keeping you up at night, it has important implications for energy efficiency, distributed generation, and is actually pretty darn interesting!

Up until about the 1960’s, utilities wanted to increase energy use as quickly as possible. Technology was evolving rapidly, reducing the price for building and operating new generation capacity. Efficiencies were increasing so quickly that the millions of dollars required to build new generation plants was completely offset by the reduced operating costs of the new plants and each one that came online actually reduced the average cost per unit of energy sold. In order to encourage increased demand, many utilities offered declining block rates, meaning that the more a customer purchased the less they paid per unit – kind of like buying in bulk at Costco. This type of rate structure encouraged customers to use large amounts of energy, and in turn justified the utilities’ continued expansion of generation resources. Utilities received profits based on a percent of their spending – which was large given the construction of so many power plants – and received regulator approval for reducing the cost of electricity.

All this hit a pretty big road block in the 70’s as generators began to approach their theoretical maximum efficiencies and innovations in construction design tapered off; new generators were no longer cheaper to operate than those already in place. Additionally, the increased cost of fuel and more stringent restrictions on siting of new generation plants further complicated the growth model previously pursued by utilities.

With the economics of expansion completely switched around, Public Utilities Commissions across the country found that it was in the public’s best interest to slow or reverse the growth in energy consumption rather than continue to approve the costly construction of new generation plants. Several policies were pursued to encourage this new direction, including deregulation (discussed in a past article) and investment in energy efficiency, leading to the structure of modern utility rates.

Commercial rates (in deregulated markets) are typically broken down into supply and demand charges. The supply charge is related to the amount of energy (kWh) used by the facility, where as the demand charge is based on a facility’s peak rate of energy use (kW – see the article on kWh vs. kW if you need a refresher). The supply charge compensates generators for producing the amount of energy a facility uses and the demand charge pays for the transmission and distribution owner (utility) to maintain the electric grid with enough capacity to meet the system’s needs.

Each of these charges can be broken down further. Energy does not cost the same amount at all times; generators are turned on based on an economic loading order, where the units with the cheapest marginal cost of operation are dispatched first (plus a few geographic restrictions). This means that as demand for energy increases, such as in the afternoon on a hot day, the cost per unit of electricity goes up. A customer’s supply charge must take into account the real cost of the energy they use – either by averaging the cost across all hours or by charging more at certain times than others.

Demand charges are also composed of multiple parts. Utilities are allowed to recover costs for maintaining and improving the transmission and distribution lines. This part of the rate can increase when near-term demand is predicted to increase beyond the capability of the system and a utility is approved to build new infrastructure, or if aging infrastructure needs to be repaired. Load serving entities (i.e. utilities) must also ensure that there will be enough generators to cover the peak demand, so they must pay generators a retainer to keep them waiting in the wings, called a capacity payment. Yet another part comes from congestion costs, which result from dispatching more expensive generation plants that are near the demand instead of cheaper ones somewhere else because the transmission or distribution system is at or above its capacity. All of these charges are spread across all of the users of the system.

Energy efficiency and, even more importantly, demand management by end use customers reduces both the costs to the individual facilities and the system as a whole. For example, in PG&E territory 10% of the capacity of the entire system is only used for 0.6% of the hours per year (2006 Data, see figure below). Those 0.6% of the hours also represent more than 10% of the costs because the plants deployed last are also the most expensive to run. Reducing use during just those 50 hours would reduce average customer costs substantially. Conservation and demand management now can delay or negate the need for costly infrastructure upgrades to meet growing peak demand that end-use customers would be on the hook for paying for years to come.

Source: PG&E presentation at Sacramento State: http://www.ecs.csus.edu/CASmartGrid/lectures/100630_sacstate_lecture_final.pdf?PHPSESSID=4f997875242dc30b275b33728ca04627
Unfortunately, many customers have (or believe they have) a constant rate. If a customer has a constant rate, they may be charged the same amount for each kWh no matter when they use their energy – this results in market signal failures because the cost of supply is not effectively signaled to end users. Thankfully, there are other rate structures, such as time-of-use (fixed prices that vary over the time of day) or real-time rates that expose the end user to some or all of the price volatility. These variable rates send an economic signal that the facility should use less energy when it is most in demand. Properly responding to price signals not only saves the individual customer money, it also reduces the costs for the whole system as described (See the smartgrid article for more discussion of how real-time rates can be used to reduce system costs). And this is why rate structures are so important.

6 Responses to ∫ Economics of Electric Rates

  1. [...] And thus far we’ve left out the financial component as well. Which is very exciting for electric car enthusiasts: • If gasoline costs $3.50/gallon, then a 30 mpg gallon gasoline powered car pays 11.7 cents per mile, and a 20 mpg gas car pay 17.5 cents per mile. • If electricity costs $0.10/kWh, which is the national average and closer to what electricity costs at night even in expensive areas, and a car goes 2.91 miles per kWh, then it costs 3.4 cents per mile to drive an electric car. Less than a third the price of driving a gasoline car. • Plus, while gasoline prices are extremely volatile, nighttime electricity costs should remain relatively low and flat. It is daytime and peak energy costs that are the real driver of electricity price hikes. [...]

  2. A load duration curve, as covered here in the blog, really highlights the importance of reducing the peak operating hours and power demand through a mechanism like efficiency or DR.

    I think it is often interesting to view this through the utility’s perspective. First, by reducing the peaker unit consumption, we are addressing the emissions and energy consumption associated with these less efficient prime movers when in use. Second, by reducing the peak operating hours, the utility has the ability to reduce the number of peaker units on standby/idle.


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