Just, non-discriminatory, and economically sound are three qualities electric utilities often strive to achieve when setting electricity rates. Assuming they are reasonably successful, the rates U.S. residents actually pay for electricity indicate that these qualities can translate into vastly different monthly bills depending on geography – from just over $40 in Maine to nearly $170 in the state of Hawaii. From levies to fund local public policies to weather, a diverse set of factors contributes to the differences. Generation and transmission costs, however, are by far the biggest drivers of price divergence.
Generation costs refer to the cost of procuring electricity. Utilities generate their own electricity or, more frequently, buy (only about a quarter of all U.S. utilities own generating assets) from wholesale electricity markets like PJM, a large market that coordinates the movement of wholesale electricity in much of the Middle Atlantic and Midwestern regions. Regardless of the source, fuel is generally the single largest factor that determines what utilities must pay for the electricity that is delivered to their customers. Of particular importance is the generating fuel of the power plant that sets the price of electricity most frequently, ie, the dominant marginal fuel of the region. Regions where the primary fuel of electricity generation is both cheap and plentiful usually enjoy the lowest electricity rates in the country. This includes the Pacific Northwest, where hydroelectric dams supply most of the electricity, and the Midwest and Southeast regions where coal reigns supreme. In 2010, average residential electricity rates in Idaho and Washington were 8 cents/KWh; in Kentucky and Utah, two heavily coal dependent states, 8.6 cents/KWh. By contrast, residents in New York and New Jersey paid, on average, over 16 cents/KWh for their electricity.
Transmission constraints are the second big reason why electricity rates differ significantly from one region to another. Constraints lead to congestion on transmission lines, which show up as congestion charges in electricity prices. They tend to occur in regions that have both high population densities and lots of economic activity. Not surprisingly, the bicoastal states, and in particular the northeastern economic corridor from Washington to Boston, have some of the highest electricity rates in the nation. These areas have high overall electricity demand but relatively limited transmission capabilities. As a result they are unable to import large amounts of cheap electricity from outside the region. This means their electricity rates suffer on two counts in the event of congestion.
First, to maintain system reliability and keep lights on, power plants located within the region and thus not dependent on the transmission system, must be run. But existing spare generating capacity in regions of high demand tends to be made up of older, small oil- and gas-fired steam units. These are highly inefficient and consume far more fuel to generate the same amount of electricity than larger newly built baseload plants. And since these areas are densely populated land scarcity and public health concerns make the permitting process for any new power plant difficult and time consuming. Second, fuel must be imported and a transportation premium paid. This is because the bicoastal states are far from any significant sources of primary generating fuel. The impacts of these factors on electricity prices are most strikingly observable in New York City and in the eastern half of the PJM electricity market, two prime examples of transmission constrained areas in the country. This chart provided by the EIA shows that spot prices of electricity in these two transmission constrained regions can be many times higher than in the rest of the system. Real time price maps for PJM and New York are available here and here.
While generation and transmission costs, by and large, drive the differences in electricity prices across the country, system characteristics and market structures can ameliorate or amplify their impacts to a large degree. Foremost among them are the ability to import power during an emergency (ie, unplanned generator outage) and weather diversity, a proxy for which is the overall size of the market. For example, in February and August of this year, due to extreme cold and hot weather respectively, Texas’s electricity market, a relatively small and isolated system with very limited import capacity, faced shortages of about 4 GW. This caused spot electricity prices in Texas to soar from about $40/MWh to about $3,000/MWh. By contrast, when an earthquake in August knocked out almost 3 GW of capacity in PJM, a much larger and better connected system, electricity prices were barely affected, rising from about $35/MWh to about $60/MWh for about an hour.
In short, electricity, although a commodity in economic terms (traded without any qualitative differentiation on open and competitive markets), is ultimately a network dependent product of some other form of primary energy (ie, fuel). Differing electricity rates across the country simply reflect the fact that costs of electricity production and delivery vary because the inputs are different.