By Sharon Allan, Elster Electricity
Six months after the enactment of the Energy Policy Act of 2005 (EPAct), industry response has been mixed. Some interpret it as calling for specific action, while others question its significance. Nevertheless, the language of EPAct gives U.S. utilities specific directives to make available time-based rates and demand response programs. EPAct states that it is the official U.S. policy to encourage demand response and the adoption of advanced metering technology to enable it. State commissions must conduct investigative proceedings into demand response and advanced metering within one year of the enactment of EPAct 2005, completing it within two years.
At this time, many state public utility commissions (PUC), and other rulemaking bodies, are still trying to interpret the law and determine what steps if any are appropriate for their area. Over the course of the next several months, utilities will be working with their state PUCs to come up with a process that works to address their obligations under EPAct.
Advanced Metering under EPAct
HR 6 Section 1252 Smart Metering (paragraph 14A) states “Not later than 18 months after the date of enactment of this paragraph, each electric utility shall offer each of its customer classes, and provide individual customers upon customer request, a time-based rate schedule under which the rate charged by the electric utility varies during different time periods and reflects the variance, if any, in the utility’s costs of generating and purchasing electricity at the wholesale level. The time-based rate schedule shall enable the electric consumer to manage energy use and cost through advanced metering and communications technology.”
Paragraph B goes on to define types of time-based rate schedules that may be offered. Time-based rate schedules defined by EPAct are:
“- Time-of-Use (TOU) pricing where electricity prices are set in advance for specific times of day. Typically, these rates will not change more than twice a year and are based on the utility’s cost of generating or purchasing electricity at the wholesale level. Customers pay for energy consumed during these periods according to the TOU prices that are established in advance, allowing customers to vary their demand and usage as TOU prices change.
“- Critical peak pricing (CPP) where TOU pricing is in effect except for certain peak days. On certain peak days, prices may reflect the costs of generating or purchasing electricity at the wholesale level and consumers may receive additional discounts for reducing peak period energy consumption.
“- Real-time pricing (RTP) where electricity prices are set in advance for specific times of day and reflect the utility’s cost of generating or purchasing electricity at the wholesale level. RTP may change as often as hourly.
“- Credits for consumers with large loads who enter into pre-established peak load reduction agreements that reduce a utility’s planned capacity obligations.
An accompanying requirement states that the utility must provide a suitable meter to any customer who requests time-base rates or else demonstrate why EPAct 2005 compliance cannot be achieved.
How it Affects Utilities
EPAct requires electric utilities to follow standards adopted by regulatory or governing bodies that have jurisdiction over the utility. In the case of investor-owned utilities, this typically means individual state public utility commissions. For municipal utilities and cooperatives, this means the board of directors or councils with controlling authority, such as city or local government councils.
For investor-owned utilities, the state PUC will host a rulemaking or similar proceeding to address EPAct’s directives and establish a forum for discussion to determine how the directives will be met. For utilities not under a state PUC, the process to review opportunities for time-based pricing and smart metering will be different. Unlike IOUs, municipal electric companies and electric cooperatives may not have a process implemented by the commissions. The commission or governing body-either as a component of their smart metering rulemaking, or as a stand-alone proceeding-must make decisions about implementing time-based pricing and how to deploy smart metering technology to support it.
These provisions give states the responsibility to interpret the law and determine how to implement it. Within two years of EPAct’s enactment, each state must determine how they will implement time-based demand response programs or else demonstrate why the programs aren’t viable for them.
Additionally, the Department of Energy (DOE) and Federal Energy Regulatory Commission (FERC) have responsibilities under EPAct. Within six months, DOE was to issue a report that quantified the benefits of demand response as well as recommendations for achieving the benefits. This report has since been issued and summarizes various studies that quantified the benefits of demand response. DOE recommended that the following six areas should be focused upon to encourage demand response:
1. Foster price-based demand response through time-based rates.
2. Improve incentive-based demand response programs to increase participation.
3. Strengthen demand response analysis and valuation.
4. Integrate demand response into resource planning.
5. Adopt enabling technologies.
6. Enhance federal demand response actions.
Furthermore, FERC is required to provide annual assessments of advanced metering technology already in place and to determine what new technologies are needed to increase demand response on a regional basis.
Some utilities feel strongly that the state-by-state approach to implementing demand response is the right approach. So far, each utility has taken a different perspective of what technology is required to implement time-based pricing for their customers. Each utility needs to evaluate if demand response is economically viable for them and beneficial to their customers.
The Role of Rates/Tariffs
From the mid 1980s until today, more than 70 utilities in the U.S. have offered RTP tariff programs, but these programs have operated in relative obscurity. Under real-time pricing tariffs, retail electricity consumers are charged prices that vary over short time frames (typically hourly) and are quoted one day or less in advance, to reflect contemporaneous, marginal supply costs. Customers participating in these RTP programs are primarily commercial and industrial customers such as large institutional customers with on-site generation, or universities, military bases, and industrial plants with cogeneration. Many U.S. utilities have also offered TOU rates for smaller commercial and residential customers. Few utilities have offered CPP or RTP rates to this same class of customer.
If time-based rates are to be available to all customers, two questions will be the source of much discussion: What is the price differential for on-peak, critical peak, and off-peak, and will customers be attracted to these rates?
The Link between Metering and Demand Response
To make time-based rate schedules available for all customer classes, meters capable of time-stamping usage are needed. In the past, standalone TOU meters were used for the small number of customers who elected to be on such a rate.
Where confusion and uncertainty have muddied the advanced metering waters is in the area of mass residential service. For the most part, these meters do not have clocks in them. Most residential meters are nothing but kWh-only meters.
The challenges for greater saturation of advanced metering in the residential market results in the need to either install standalone TOU or interval meters that have timekeeping and batteries. Batteries, however, require maintenance programs and are not good for millions of customers. Another way to provide time in a meter is by connecting the meter to a two-way communication network. With the two-way communication network, time could be broadcast to endpoint meters similar to the way a public cellular tower broadcasts time to a mobile phone.
Revenue-quality time-based data must be certifiable, according to ANSI standards that govern metering (ANSI C12.1 absorbed the original standard, ANSI C12.13 and C12.15 that covers electronic TOU metering). The Electricity Metering Handbook, 10th edition, Chapter 7 states that “accuracy must be reliable over a variety of environmental conditions and performance must be certifiable to an energy provider, consumer, and regulatory agency.” If AMR and AMI networks are performing time-based metering functions, then the system needs to provide revenue quality data that is certifiable. Time keeping in the meter at the point of consumption better ensures a consumer is priced on what they use at a given time. If demand response programs are to be encouraged and time-based pricing offered for all customer classes, the costs of communication networks and time-based recording meters are sure to be points of discussion.
At first glance, satisfying the requirements set forth in EPAct might seem like a daunting task to any utility that has not yet established a plan for implementing demand response programs based on time-based metering. Since regulators and policy makers are still defining what functions and features a smart metering system should have, some utility companies may be at a loss on choosing the most cost-effective and viable smart metering system, or having a plan in effect to comply with these federal regulations within 18 months. The good news is that economical smart metering systems are available on the market today that can be easily deployed as customers request time-differentiated pricing on their energy usage. In addition, these systems have features that can be used to streamline business operations. Perhaps the greater challenge is establishing various rates for smaller customers and incentives for demand response.
The impetus behind smart metering as defined by EPAct is to allow energy consumers to participate with their utility company to voluntarily manage their energy consumption. Regulators and policy makers who had an influence on including smart metering in the bill believe this has the potential to save billions of dollars per year and ease the strain on an aging power distribution infrastructure. It will also empower consumers to conserve energy when energy supplies are short.â®â®
Allan is Elster’s chief knowledge officer.