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When Managing Electric Usage, Peak Demand Is Key To Savings

By Lindsay Audin - October 2013 - Energy Efficiency


The proportion of a bill that is related to peak demand varies based on the $/kW rate and on when and how a facility uses power. The overall average electric rate for commercial facilities in the US in 2011 was about $.103 per kWh, with a range of about $.06 to $.25/kWh. Within those averages, charges for peak demand may account for 10 percent to 70 percent of the total annual bill. The highest percents occur for accounts having high daytime peak demands but low kWh usage (e.g., inefficiently air conditioned offices). Higher $/kW rates are often seen in urban areas where overall electric rates are high. In the past, such impacts have been localized, but they are now being seen regionally and may soon be felt nationally.

Up to the late '60s, most cities were supplied by nearby generation. Over time, the increased need for reliable power fostered interconnected grids called power pools or, more recently, Independent System Operators (ISOs). Since 1992, those grids have become wholesale marketplaces where power is traded every hour, like a stock market but with greater volatility. Utilities shield customers from price swings through regulated rates ("tariffs") overseen by government agencies. In deregulated states where customers can choose their power supplier, such costs may be rolled into fixed supply pricing, or appear as a separate line item. Demand charges for power delivery, however, remain regulated and unavoidable.

In the last decade, several factors have begun challenging that price stability. Some are now combining to shift the proportion of electric bills that is dedicated to paying for peak demand. They include:

  • The price of natural gas, which sets wholesale $/kWh (but not $/kW) prices, has dropped by more than 60 percent.
  • New environmental regulations are gradually forcing retirement or alteration of coal-fired power plants. As that capacity is reduced, wholesale auctions bid up the value of each remaining kW of generation. In some grids, capacity prices for the coming year (or longer) have recently doubled or tripled. Utilities may pass on such costs as higher demand charges.
  • Increased demand for power reliability requires large utility investments in transmission and distribution systems.
  • Due to their variability, expanded supply from renewables (mainly wind) requires intermittent backup generation, and expanded transmission systems to deliver that power.
  • Five years of a slow economy has seen retirement of aging power plants but, due to chronic low grid demand, few new ones have been added. As recovery occurs, demand rises much faster than new plants can be built, driving up short-term capacity pricing.
  • New power plants, while more efficient, cost more per installed MW to build than those they are replacing.
  • Energy efficiencies by large energy users have cut kWh usage more than kW demand.

The end result is to increase utility fixed costs while reducing kWh revenues.

A general rule of ratemaking is that rates reflect true costs of service while ensuring sufficient utility revenue to maintain reliability. When a facility uses fewer kilowatt-hours by, for example, turning off lights at night, but its daytime peak demand does not also drop, a utility must re-design its rates so it is able to recoup its costs for supplying both kWh and kW.

Doing so may encourage further cuts in kWh usage, beginning what some call a "death spiral." Increasing $/kW demand rates, however, better reflects rising fixed costs, and cutting peak demand is more difficult for customers. When customers succeed, however, that may be welcomed by utilities since it helps them avoid future fixed cost investments.





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