Under the present rate structures in U.S. energy markets, utilities’ revenues depend on the amount of energy they produce and deliver to consumers. This type of system makes utilities averse to conservation and efficiency measures because their implementation ultimately cuts into profits by decreasing sales and therefore revenues. “Decoupling” removes the pressures placed on utilities to sell as much energy as possible by eliminating the relationship between revenues and sales volume. Under such a compensation scheme, revenues are “decoupled” from sales and are instead allowed to adjust so that utilities receive fair compensation regardless of fluctuations in sales.
Decoupling can be applied in both electricity and natural gas markets. To date, more states have implemented decoupling policies for natural gas than for electricity. This overview of decoupling explains the general issues associated with revenue decoupling in energy markets using electricity-specific examples.
Utility costs can be broken down into two main components: fixed costs and variable costs. Fixed costs can be thought of as the capital costs utilities face, such as those associated with the construction of a plant, while variable costs are those that vary with production, like the costs associated with the purchase of fuels.
In traditional, regulated markets, large utilities act as natural monopolies and regulatory bodies such as Public Utility Commissions establish the rates customers pay based on an estimated revenue requirement submitted to them by the utility in a proceeding called a “rate case.” The revenue requirement allows utilities to recover both fixed and variable costs and earn a fair return on investment. This amount is then divided by the projected amount of electricity the utility is expected to sell to determine the rate consumers will pay to the utility per unit of energy sold. These rates are often called ‘volumetric’ because they are based on the amount of electricity used by the customer, usually expressed in $/KWh.1 These established rates will apply until the utility petitions for or the regulator initiates a new rate case because of changing market conditions or increased costs from new infrastructure.
Actual utility revenue equals the established rate multiplied by the actual amount of sales. If actual sales are larger than the amount of sales projected in the rate case, the utility keeps the extra revenue as additional profit. This creates an incentive for the utility to maximize the “throughput” across their wires—there is often a significant incremental margin on incremental sales. Thus, a traditional ratemaking system does not promote the efficient use of energy because utilities need to recoup costs, and earn profits, but they can only do so by maximizing the amount of electricity they sell.
The more a utility sells, the more they profit until, in the case of electricity, more capacity is needed to meet the growing customer demand. As such, supply continues to increase, new facilities continue to be constructed, and the system continues to expand because there are no incentives to counter growth.
When sales volume decreases from efficiency measures, utilities are not only at risk of losing some of their profit, they also may lose the ability to recoup a portion of their fixed costs. This amplifies the disincentive for efficiency programs.
The throughput incentive also exists in restructured energy markets. In restructured markets, vertically integrated, monopolistic utilities are typically dismantled into generation, transmission, and distribution utilities in order to promote competition. In restructured markets, transmission and distribution utilities continue to be regulated monopolies, whereas electric generators operate in competitive markets.
Electric generators will always try and recover their variable costs, but they will also try to recoup fixed costs through sales, particularly during peak hours of demand when the price of electricity is higher. These utilities compete with one another for market share; they do so by trying to sell as much electricity to consumers as they can at the highest attainable rate, with rates being established by competitive bidding systems.
Consequently, efficiency and conservation measures conflict with utilities’ profits in a restructured market in a similar way to a traditional market because they decrease the volume demanded by and therefore revenues collected from their customers.
Decoupling removes throughput incentives by providing stable revenue for utilities regardless of sales volume. In the case of regulated electricity markets, this may be applied to all of the integrated utility’s short-run fixed costs (generation, transmission and distribution), whereas in restructured markets only transmission and distribution utilities will have their revenues decoupled from sales volume.
Under decoupling policies, a state regulatory commission determines the revenue requirement for a given utility based on a “test year” using traditional regulatory methods; but in a departure from traditional regulation the utility is then allowed to collect that revenue regardless of actual sales volume. One approach is to connect revenue to the number of customers instead of quantity of sales: revenue per customer is fixed and an automatic adjustment to the revenue requirement occurs with any new or departing customers. Periodic adjustments are made to ensure that the utility is not under- or over-collecting. Thus utilities are no longer incentivized to maximize sales volume and those that reduce costs (fixed or variable) through efficiency measures will see an increase in short-term profits because the revenue stream is largely fixed.
Performance targets or efficiency incentives are typically also included in a decoupled compensation scheme, thereby incentivizing the reduction of energy demand by encouraging the utility to improve the efficiency of its infrastructure and employ demand side management practices.2
In sum, decoupling eliminates the current tie between utility sales volume and profitability. In doing so, it makes efficiency measures not only palatable, but profitable to utilities, and eliminates one of the drivers that has catalyzed growth in the production and consumption of energy.
Decoupling is not the only policy mechanism that has been used to encourage energy efficiency; a number of other options also exist and have been proposed or implemented in different states. While these mechanisms may stimulate certain energy efficiency measures, they often do not address the throughput incentive.
Single Fixed Variable (SFV) rates match the fixed costs more closely with fixed charges. This allows utilities to recover fixed costs without dependence on sales.. SFV, unfortunately, also has the effect of decoupling customers from their own consumption because they will pay the same amount for fixed cost recovery regardless of their energy usage.
Lost Revenue Adjustments [or Recovery] compensate utilities for revenues lost because of efficiency measures. Utilities can collect a charge from customers to account for these revenue losses. This mechanism does not address the throughput incentive because only certain efficiency measures are included in the mechanism; utilities therefore retain an overall incentive to increase sales through means that aren’t included in the Lost Revenue Adjustment.
Revenue-neutral Energy Efficiency Feebates (REEF) establish an allowed amount of energy consumption for customers. Customers that use more than the allowed amount have to pay an extra fee; these fees are then rebated to customers that use less than their allowed amount. REEFs can also be used in combination with SFV pricing.
Creating a level playing field for demand response programs, through capacity auctions, for instance, can reduce the need for new generation capacity. For example, ISO New England allows demand response programs to compete with energy suppliers through auctions in which the utility determines the least-cost resources for meeting their energy needs. Cost-effective demand reductions can therefore replace or slow the need for new supply.
H.R.1, the American Recovery and Reinvestment Act of 2009 conditions a State’s receipt of Energy Efficiency Program funds ($3.1 billion allocated to this purpose) on the state’s creation of policies to align utility incentives with efficiency goals. Governors must assure the Secretary of Energy that the appropriate regulatory authority for each gas and electric utility will seek to implement a policy that encourages this alignment and sustains or enhances customers’ incentives to use energy more efficiently.
In California, Massachusetts and Connecticut, all electric utilities must have some form of decoupling program in place, or include a decoupling plan in their next rate case. California’s policy combines the revenue decoupling program with performance incentives for meeting or exceeding energy efficiency targets. In Connecticut, the type of decoupling is assigned on a utility-by-utility basis. Massachusetts determines the target revenues on a utility-wide basis that can be adjusted for inflation and capital spending requirements.
In other states, including Wisconsin, Vermont, Oregon, New York, Maryland, and Idaho decoupling programs have been approved and are beginning to be implemented for at least one electric utility.
For more information regarding individual state actions on electric and gas revenue decoupling, please click on the states in the map on the previous page .
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1. Energy markets are regulated at the state level; different states have different kinds of markets and rate structures vary widely. Residential customers frequently pay only volumetric rates while industrial and commercial customers sometimes pay volumetric and fixed rates, the latter of which are designed to recover some of the fixed costs and do not vary with use. To learn more about the different kinds of energy market structures, see the Natural Gas Supply Association’s Industry and Market Structure  and the Energy Information Administration’s Electric Power Industry Overview 2007 .
2. Demand side management practices are measures designed to curb consumer energy usage such as consumer energy efficiency measures; rate structures designed to increase the cost of use during high demand periods; and structured contracts that give utilities the ability to control a portion of the load at energy intensive consumer facilities.