The search continues for a definitive “smoking gun” responsible for the Northeast’s blackout last year. Absent a clearly defined single cause, analysts turn to the “usual suspects”—issues the industry has been discussing for years. Is the grid large enough? Does it require additional investment? Given that the grid was never designed to handle a competitive industry, is it reasonable to require that it now do so?
At the core of these issues lies the obligation to serve. The grid is sized correctly when the industry can meet that obligation at the lowest reasonable cost.
Defining that obligation, then, is key to blackout prevention. But the electric industry and its policymakers—and the nation as a whole—have yet to reach consensus. Some seek to maintain the status quo. Others believe the obligation should be expanded to include emerging customer needs and niches. Some define the obligation as local. Others have a regional or national view.
A consensus definition of the obligation to serve may be long in coming. In the meantime, the public rightly demands that we focus on near-term blackout prevention. Doing so means acting in the face of uncertainty. But failure to act is not an option.
The Value of Demand Response
Given these circumstances, it makes sense to concentrate first on maximizing the efficiency of the existing grid. Demand response programs clearly fall into that category. While they require complex billing software, that investment is far smaller than are such grid-expansion remedies as more towers, more line, and more rights of way.
Demand response is an updated, flexible, and market-driven replacement for the interruptible rates that have long given grid managers to option to remove large customers from the grid on short notice. Utilities that use the demand response approach instead ask facilities to reduce load during a specific period and reward those that do with financial incentives geared to the length and size of the reduction. While not yet widespread, these programs have proven so valuable in solving some grid constraints that the Federal Energy Regulatory Commission (FERC) has become a strong advocate.
Demand response comes in two varieties.
Within these basic types are dozens of variations. Utilities may place limits or guarantees on length of cutbacks. Customers may have different lengths of time in which to signal their participation. Some programs penalize customers who sign up but fail to participate over a defined period. Some utilities combine the two types of programs: customers specify a price at which they will consider a utility request to reduce demand.
Demand response is a replacement for interruptible rates. And it arrives none too soon. Interruptible rates are increasingly unpopular with all parties. Utilities and regulators are often unhappy about price concessions in place for years in return for cooperation during emergency situations that rarely or never occur. At the same time, the manufacturers and distributors who have traditionally taken advantage of interruptible rates are finding them increasingly unworkable. High-tech and food-processing facilities, for instance, frequently have processes that, if interrupted, result in the massive discarding of raw materials. Suppliers may be hit with penalties when a loss of electricity results in a failure to deliver to just-in-time customers.
Demand response solves these problems. Utilities pay incentives only when they’re needed. And participants have options to determine the timing and extent of load reduction. It’s a win-win approach to increasing grid efficiency and ensuring that utilities meet their obligation to serve.
Software Infrastructure
Fundamental to effective demand response is complex billing software integrated into basic customer care and billing systems. Complex billing (also called “real-time,” “interval,” or “time-series” billing) uses special meters to measure consumption during a prescribed time interval—generally 10 to 60 minutes long for electricity.
In theory, a contract between a customer and a utility could specify different prices, terms, and conditions for each interval. In practice, most customers would find this unwieldy. Measuring consumption in half-hour intervals, for instance, could result in 1500 separate prices per month. Thus, under normal conditions, contracts group intervals into categories similar to the time-of-use categories that have long dominated industrial-customer ratemaking—peak, shoulder, and off-peak rates. With the more sophisticated processing possible with complex billing software, however, these categories are easily expanded to include, for instance, public holidays, traditionally slack periods in the customer’s industry, etc.
Contracts can be set up so that different prices, terms, and conditions apply to specific intervals during a crisis. And these contracts can be dynamically altered as required, given changing grid conditions. A customer signed up for demand response might agree to halve normal demand for a maximum of 12 hours and to pay a penalty for any interval above a specified limit. Toward the end of that period, the customer may agree to an extension, but at a different demand level, and for a different length of time. Utilities can peg the reward for participation to the length and severity of the crisis.
The Addition of Net Metering
Further grid efficiencies result from the addition of net metering options into a complex billing/demand-response program.
While national grid-connection standards have been slow to develop, many utilities have standing arrangements that take advantage of customers’ on-site generation during a crisis. Current arrangements, however, are frequently primitive. When, for instance, the amount of electricity injected is simply subtracted from that month’s consumption, customers may inject amounts that more closely reflect their own needs, not the utility’s.
Adding complex billing to net metering significantly increases their usefulness during high-demand periods. Utilities can, for instance, vary the incentive for injection with the severity of the crisis. They can raise incentives for facilities capable of injecting at key locations. And clear, short-term price incentives permit customers to evaluate whether they are better off using their generation on-site or selling it to the grid.
Additional Benefits
Building your software infrastructure to handle comfortably a variety of complex billing approaches has benefits beyond grid efficiency:
Demand response comes in two varieties.
Conclusion
There’s no evidence that complex billing would have prevented the August blackout. In fact, there is no “magic bullet” that will prevent blackouts going forward. Minimizing the size and frequency of blackouts will likely result from dozens of steps taken by hundreds of utilities over the coming months and years.
Many of those steps will, like complex billing, improve grid efficiency. And identifying those efficiencies involves far more than back-room analyses of grid structure and load profile. Efficiencies will require innovative thinking and partnerships between utilities and their customers.
Complex billing underpins that thinking. It fosters commonsense innovations that, no matter what the future holds, maximize the effective use of current resources and thus hold down the cost of service.
About the Author
Brian Owenson is vice president for product strategy. Owenson is the author of Energy Data Management: Complex Billing and Pricing, available at:
www.splwg.com/main/whitepaper/wpapply.asp.
At the core of these issues lies the obligation to serve. The grid is sized correctly when the industry can meet that obligation at the lowest reasonable cost.
Defining that obligation, then, is key to blackout prevention. But the electric industry and its policymakers—and the nation as a whole—have yet to reach consensus. Some seek to maintain the status quo. Others believe the obligation should be expanded to include emerging customer needs and niches. Some define the obligation as local. Others have a regional or national view.
A consensus definition of the obligation to serve may be long in coming. In the meantime, the public rightly demands that we focus on near-term blackout prevention. Doing so means acting in the face of uncertainty. But failure to act is not an option.
The Value of Demand Response
Given these circumstances, it makes sense to concentrate first on maximizing the efficiency of the existing grid. Demand response programs clearly fall into that category. While they require complex billing software, that investment is far smaller than are such grid-expansion remedies as more towers, more line, and more rights of way.
Demand response is an updated, flexible, and market-driven replacement for the interruptible rates that have long given grid managers to option to remove large customers from the grid on short notice. Utilities that use the demand response approach instead ask facilities to reduce load during a specific period and reward those that do with financial incentives geared to the length and size of the reduction. While not yet widespread, these programs have proven so valuable in solving some grid constraints that the Federal Energy Regulatory Commission (FERC) has become a strong advocate.
Demand response comes in two varieties.
- Reward programs. Utilities ask commercial and industrial customers if they might consider demand reductions at an indefinite time in the future. When a problem arises, utilities request a reduction in use from those signed up to participate. They reward those who implement reductions with a financial incentive geared to the problem’s size and duration.
- Price-based programs, in which customers determine in advance a set price at which they will reduce demand. This gives grid managers a clearer picture of likely demand as wholesale prices vary.
Within these basic types are dozens of variations. Utilities may place limits or guarantees on length of cutbacks. Customers may have different lengths of time in which to signal their participation. Some programs penalize customers who sign up but fail to participate over a defined period. Some utilities combine the two types of programs: customers specify a price at which they will consider a utility request to reduce demand.
Demand response is a replacement for interruptible rates. And it arrives none too soon. Interruptible rates are increasingly unpopular with all parties. Utilities and regulators are often unhappy about price concessions in place for years in return for cooperation during emergency situations that rarely or never occur. At the same time, the manufacturers and distributors who have traditionally taken advantage of interruptible rates are finding them increasingly unworkable. High-tech and food-processing facilities, for instance, frequently have processes that, if interrupted, result in the massive discarding of raw materials. Suppliers may be hit with penalties when a loss of electricity results in a failure to deliver to just-in-time customers.
Demand response solves these problems. Utilities pay incentives only when they’re needed. And participants have options to determine the timing and extent of load reduction. It’s a win-win approach to increasing grid efficiency and ensuring that utilities meet their obligation to serve.
Software Infrastructure
Fundamental to effective demand response is complex billing software integrated into basic customer care and billing systems. Complex billing (also called “real-time,” “interval,” or “time-series” billing) uses special meters to measure consumption during a prescribed time interval—generally 10 to 60 minutes long for electricity.
In theory, a contract between a customer and a utility could specify different prices, terms, and conditions for each interval. In practice, most customers would find this unwieldy. Measuring consumption in half-hour intervals, for instance, could result in 1500 separate prices per month. Thus, under normal conditions, contracts group intervals into categories similar to the time-of-use categories that have long dominated industrial-customer ratemaking—peak, shoulder, and off-peak rates. With the more sophisticated processing possible with complex billing software, however, these categories are easily expanded to include, for instance, public holidays, traditionally slack periods in the customer’s industry, etc.
Contracts can be set up so that different prices, terms, and conditions apply to specific intervals during a crisis. And these contracts can be dynamically altered as required, given changing grid conditions. A customer signed up for demand response might agree to halve normal demand for a maximum of 12 hours and to pay a penalty for any interval above a specified limit. Toward the end of that period, the customer may agree to an extension, but at a different demand level, and for a different length of time. Utilities can peg the reward for participation to the length and severity of the crisis.
The Addition of Net Metering
Further grid efficiencies result from the addition of net metering options into a complex billing/demand-response program.
While national grid-connection standards have been slow to develop, many utilities have standing arrangements that take advantage of customers’ on-site generation during a crisis. Current arrangements, however, are frequently primitive. When, for instance, the amount of electricity injected is simply subtracted from that month’s consumption, customers may inject amounts that more closely reflect their own needs, not the utility’s.
Adding complex billing to net metering significantly increases their usefulness during high-demand periods. Utilities can, for instance, vary the incentive for injection with the severity of the crisis. They can raise incentives for facilities capable of injecting at key locations. And clear, short-term price incentives permit customers to evaluate whether they are better off using their generation on-site or selling it to the grid.
Additional Benefits
Building your software infrastructure to handle comfortably a variety of complex billing approaches has benefits beyond grid efficiency:
Demand response comes in two varieties.
- Complex billing helps utilities address concerns about fairness. Small and mid-size commercial and industrial customers as well as regulators have long expressed discomfort with incentive programs limited to only the largest of industrial firms. But limiting the size of participants is necessary when incentive programs for grid injection or demand reduction must be calculated individually. Complex billing automates the calculation and the underlying contracts. That enables utilities to handle large numbers of program participants. It also enlarges the size of potential demand reductions.
- The interval data routinely produced as part of the complex billing process has multiple uses. It can help facilities identify expensive and unnecessary peaks. It can indicate malfunctioning equipment and permit repairs in advance of breakdown. It can suggest conservation measures. To facilitate these uses, utilities may offer compilation services, such as delivering formatted data to customers on CDs. Utilities can also use the data to offer analytic services that increase facility efficiency while adding to the utility’s bottom line.
- Complex billing permits regulated utilities to offer direct access to wholesale electricity markets. Such programs may ease the concerns of large customers who advocate full retail competition as a way to provide themselves with lower-cost supply options.
Conclusion
There’s no evidence that complex billing would have prevented the August blackout. In fact, there is no “magic bullet” that will prevent blackouts going forward. Minimizing the size and frequency of blackouts will likely result from dozens of steps taken by hundreds of utilities over the coming months and years.
Many of those steps will, like complex billing, improve grid efficiency. And identifying those efficiencies involves far more than back-room analyses of grid structure and load profile. Efficiencies will require innovative thinking and partnerships between utilities and their customers.
Complex billing underpins that thinking. It fosters commonsense innovations that, no matter what the future holds, maximize the effective use of current resources and thus hold down the cost of service.
About the Author
Brian Owenson is vice president for product strategy. Owenson is the author of Energy Data Management: Complex Billing and Pricing, available at:
www.splwg.com/main/whitepaper/wpapply.asp.
Additional Complex Billing Concepts
Historically, in their simplest form, customers’ energy charges have been calculated by multiplying the number of energy units used (typically expressed as a number of kilowatt-hours) by the price per unit. Using complex pricing, the energy charge is calculated by multiplying each interval by the price for that interval, then adding all of the results (products) together.
In practice, however, interval pricing is virtually never this simple. Two frequently used variations are peak-demand pricing and hedging.
Peak Demand Pricing
The ability to control peak demand does not provide utilities with the hour-by-hour control available via direct interval pricing. But it can be an effective tool in helping to prevent overloads or shortages.
Under peak-pricing programs, utilities grant customers an incentive (generally a price concession) to shift the timing of their peaks or to reduce their number and size. The agreement may be accompanied by such negative incentives as:
- Significantly higher prices for energy used during a utility’s peak periods.
- Additional charges for peak demand. In some markets, the rate per peak kilowatt can be two orders of magnitude greater than the equivalent non-peak energy.
- “Ratcheting.” This incentive requires customers who even once reach a specific high peak demand to pay a higher price for all energy used during a specific period, or for all energy used for a specific amount of time into the future. Typically, ratchets are calculated using timeframes of a year to two, but they can be longer. In some markets, ratchets are ongoing from the inception of the contract.
Peak-demand programs do not require interval data meters. Non-interval industrial meters commonly have simple peak-demand registers.However, coincidental peak demand is easily and accurately calculated from interval data meters with sufficiently small interval sizes, say 10-15 minutes.
Hedging
Hedges are financial instruments that insure against price volatility. Hedge sellers collect a fee in exchange for a guarantee to either:
- Deliver a specific amount of energy (the “hedge cover”) to a specific place at a specific price (the “strike price”) during a specific interval.
- Pay the difference between the energy price specified in the hedge (again, the “strike price”) and the price the hedge buyer actually has to pay on the wholesale market for the amount of energy specified in the hedge (again, the “hedge cover”).
In a market economy, hedge sellers set the energy price higher than they expect it to be during that interval. From a seller’s point of view, the ideal hedge involves a customer who pays a fee and is never heard from again. As the time for delivery/payment nears, however, hedges are commonly resold at discounts or premiums that reflect changing market conditions.
Hedges help customers maintain a stable energy price. But only the largest buyers will want to handle them themselves. Some utilities offer and manage hedges. Others arrange them through a third party. In any event, their costs must be factored into the total cost of energy.
Brian Owenson is Vice President – Solution Management for SPL WorldGroup.
