U.S. Department of Energy - Energy Efficiency and Renewable Energy

Distributed Energy Program

Utility Tariffs and Pricing Issues

Utility tariffs and pricing structures can have a significant impact on the economic viability of distributed energy systems, especially the type of metering arrangements and charges for standby power that are imposed on the self-generator.

Demand-response programs, in particular those based on differential pricing of electricity, can put a premium on the value of electricity from dispatchable distributed generation while helping to mitigate congestion in the transmission and distribution grid.

Other utility tariffs include public benefits charges and fees to recover stranded investments in electricity infrastructure and programs that are no longer economically viable after the transition to competitive markets.

See the following to learn more:

Metering Arrangements

The Public Utility Regulatory Policy Act of 1978 (PURPA) requires utilities to purchase excess power from certain small, grid-connected generators at a rate equal to what it costs the utility to produce the power itself. Today, the list of eligible generating technologies varies from state to state.

Electric utilities generally implement the PURPA requirement through one of the following metering arrangements:

  • Net purchase and sale — Under this arrangement, two unidirectional meters are installed: one records electricity taken from the grid, and the other records excess electricity generated and fed back into the grid. You pay the higher retail rate for the electricity you use, and the utility purchases your excess generation at its avoided cost (the lower wholesale rate).

    With net purchase and sale, you pay the higher retail rate for all of the grid electricity you use, and are credited at a lower rate for the electricity you generate and feed back to the grid.

  • Net metering — This is the most advantageous arrangement for the owner of a distributed energy system. A single, bidirectional meter is used to record both electricity drawn from the grid and the excess electricity the distributed energy system feeds back into the grid. The meter spins forward when electricity is drawn from the grid, and it spins backward as electricity is fed into the grid. If, at the end of the month, you've used more electricity than your system has produced, you pay the retail price for that extra electricity. If you've produced more than you've used, the utility may pay you for the excess, depending on where you live. Utilities in many states aren't required to pay anything for the net excess power. Others reimburse distributed generators at rates lower than the retail price. Only a handful of states require utilities to reimburse customers at the full retail price.

    With net metering, you are billed (at the retail price) only when you consume more electricity than you generate. The electricity you generate is effectively worth as much as the electricity you consume.

    Some power providers will now let you carry over the balance of any net extra electricity your system generates from month to month, which can be an advantage if the resource you are using to generate your electricity is seasonal. If, at the end of the year, you have produced more than you've used, you typically forfeit the excess generation to the power provider.

For more information, pursue the following links:

Demand-Response Programs

With unbundling of electric services at the heart of deregulation, electric utilities were faced with great uncertainty about their ability to recover stranded investments in electricity infrastructure. As a result, many utilities delayed infrastructure investments in new generation and transmission, leading to local or regional transmission bottlenecks and areas with inadequate generating capacity.

Demand-response programs, which encourage electricity consumers to reduce energy use during system peak periods in exchange for lower electricity bills, can be used to mitigate both of these problems. There are two types of demand-response program.

Load Response

With these programs, a load reduction is called for by a utility company, with little discretion in compliance on the part of the electricity consumer. Utilities that may call for a load response include independent system (grid) operators, load-serving entities, and utility distribution companies.

There are three types of load response program:

  • Direct load-control programs — Primarily for residential and small commercial facilities with equipment, such as air conditioners, that may be "cycled" (turned off) for limited periods of time.

  • Curtailable load programs — Primarily for large commercial and industrial facilities that can reduce at least some of their load with a minimum threshold, such as 100 kW per event. Notification is generally from 30 minutes to two hours before the requested curtailment.

  • Interruptible programs — Primarily for industrial operations that can shed all or major portions of their load. Commercial facilities may also participate, particularly if backup generators can provide large portions of the load.

Price Response

Price response programs operate based on voluntary actions of electricity customers in response to market signals. They typically rely on wholesale clearing prices as a primary signal or method to reimburse customers for their participation. Price-responsive demand helps mitigate spikes in wholesale market prices.

Price response programs include the following:

  • Economic programs — Primarily for large commercial and industrial facilities that can provide a minimum amount of load reduction, such as 100 kW per event. Participants may offer load reductions in certain amounts for certain time periods in response to a proposed price or set of hourly prices in the day-ahead market (or potentially the hour ahead or real time market). Payment is based on the market-clearing price in the day-ahead market bid by the participant and accepted by the buyer for day-ahead programs.

  • Time-of-use rates — Eligible customers may be residential, commercial, or industrial users. Participation may be mandatory or voluntary depending on the jurisdiction. Special meters are installed to measure consumption during peak, off-peak, and in some cases, intermediate hours. Rates vary with time of day, day-of-week (since weekends are generally considered off-peak), and season of year (since winter weekdays may be considered off-peak or intermediate hours). Rates are fixed for each period so the customer knows well in advance what the prices will be.

  • Real time pricing — Primarily for commercial and industrial facilities with the ability to reduce or shift loads. Advanced communication systems allow electricity customers to observe real-time energy usage and forward prices. In one version, customers are provided hourly prices for the next day. Facility managers are free to maintain operations as planned or adjust operations to take advantage of lower rates. "Two-part" tariffs establish a baseline energy usage for each hour of the year. Baseline usage is agreed upon by both parties based on historical use subject to appropriate adjustments, such as changes in operations or weather. Variances in usage from baseline estimates are charged a premium if above, and a discount if below, the baseline using spot market clearing prices. An alternative to the two-part tariff is a "one-part" tariff that links all usage to hourly prices to market clearing spot prices and avoids baseline estimation.

Experience with regional power markets suggests that active demand response is crucial to both power system reliability and market efficiency.

See the following for more information:

Standby Charges

Distributed generators usually require a source of backup power to meet electrical loads during routine maintenance or in case the generator fails.

Utilities typically charge their customers a "standby charge" or "backup charge" to guarantee that grid power will be available when the customer's distributed generator is out of commission. The cost of this standby power affects the economic viability of the distributed generator in instances when the customer cannot, or chooses not to, disconnect from the grid. Thus, standby rates have become a significant point of discussion in barriers to implementation of distributed generation technology.

Most of a utility's cost for providing standby service is associated with the fixed cost of the transmission and distribution system. Generally, a utility customer will pay a tariff in the form of a monthly demand charge per kilowatt. This is in addition to any electrical generation charges for actual electricity used.

In restructured electricity markets, the generation backup charge is negotiated between the consumer and the power provider; the charge to cover access to the distribution system is negotiated with the utility that owns the wires.

The utility perspective on this issue is captured in the following quote from Hawaiian Electric's Karl Stahlkopf, senior vice president for energy solutions, when he was interviewed by Pacific Business News in July 2002:

"If I'm going to provide you standby electricity, I should have capacity in the power plant to serve you, maintain my lines and make sure that the interconnection is up to interconnection standards. There are real costs associated to provide interconnection to your system. It costs Hawaiian Electric real dollars if your generator goes down and you are connected to our system. It costs us money and therefore it costs you money."

In other words, customers who self-generate, yet depend on the grid for backup, should pay their fair share of the fixed costs of providing distribution service and maintaining excess power-plant capacity, in order to avoid shifting costs to other customers.

However, many utilities require a customer to contract for the measured peak electrical output of the on-site generator. Such standby rates are based on the notion that, if there is an unexpected generator failure, grid electricity may be required to replace the entire peak electrical load previously served by the distributed generator. This approach can be inappropriate and prohibitively expensive in applications where the customer would shed a significant portion of the load if standby power was required from the utility. In addition, not all distributed generators connected to a distribution network are likely to experience unexpected outages at the same time, so it may not be necessary to maintain so much excess generating capacity.

An alternative structure for standby charges has been proposed that is built on the principles used in unemployment insurance — charges are initially based on usage typical of similar businesses, and subsequent charges are increased or decreased to reflect actual experience.

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Stranded Investments

Stranded investments are investments in power plants or demand-side-management measures that become uneconomic due to increased competition in the electric power market. Stranded investments can be either costs or benefits.

An example of a stranded cost is an electric power plant that, after deregulation of electricity markets, produces power that is more costly than the market rate for electricity. As a result, the power plant owner may have to close the plant, even though the capital and financing costs of building the plant have not been recovered through prior sales of electricity from the plant.

Stranded benefits are investments by power providers in measures or programs considered to benefit consumers by reducing energy consumption or providing environmental benefits that have to be curtailed due to increased competition and lower profit margins.

Stranded investments are a concern when lower electricity prices resulting from competition reduce the ability of utilities to recover expenses incurred on behalf of their customers under earlier regulatory arrangements. There is uncertainty about who should pay for these stranded costs — utility shareholders, ratepayers, or both.

In another example, electric utilities typically view customer-sited distributed generation as bypassing the distribution system to some extent, resulting in the stranding of distribution assets both at the substation and the distribution feeder levels.

Under many state restructuring plans, utilities are permitted to recover such stranded investments through a per kilowatt-hour charge on the electric bill. But such cost recovery isn't always necessary. In California, for example, two of the larger utility companies (SDG&E and SoCal Gas) found "that overall system load growth may outpace any load loss resulting from distributed generation" resulting in "insignificant" stranded assets.

For more information, see the list of EERE documents on the topic of stranded costs.

Public Benefits Charges

Prior to electricity industry restructuring, utilities were responsible for a variety of programs designed to meet social objectives. Examples of such public benefits programs include low-income assistance, demand-side management, consumer education, promoting energy efficiency, and the development and demonstration of emerging technologies such as renewable energy.

Following restructuring, funding for these programs is typically through a small surcharge ("wires charge" or "system benefits charge") on utility bills.

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Content Last Updated: 05/17/2006

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