You asked for a description of efforts to reduce electric peak demand and the extent to which they have succeeded.

SUMMARY

In Connecticut and the rest of New England, electric demand (the amount of consumption at a particular point in time) varies substantially by time of day and season, typically peaking in the summer. During the earlier part of this decade, growth in peak demand had contributed to higher electric rates, among other problems. However, in recent years peak demand has fallen substantially.

There have been initiatives to address growth in peak demand at the state and regional levels. In 2007, the legislature required the electric companies to provide credits to customers who reduced their summertime consumption (the program did not directly address peak demand). The Department of Public Utility Control (DPUC) concluded that the program was probably not cost effective and there has been no legislation enacted to replicate it. The same legislation also established the energy efficiency partners program to provide ratepayer funding for technologies that reduce energy demand. However, funding under this program has been very modest and DPUC has not evaluated the program.

A nonprofit organization, the Independent System Operator (ISO) -New England, administers the regional wholesale electric market. ISO-New England currently operates five programs designed to limit peak demand, three of which are meant to address reliability (i.e., avoid brownouts and blackouts) and two are designed to reduce the rate impacts of peak demand.

The programs enroll just under 2,000 megawatts (MW) of demand; 37% of this demand is in Connecticut. In comparison, peak demand in New England was 25,081 MW in 2009. ISO-New England has not had to use the reliability-related programs recently; it has found the rate-related programs to be cost-effective.

BACKGROUND

Electric demand is the total amount of electric consumption at a specific point in time. Electric demand varies significantly over the course of each day and by season. In Connecticut and the rest of New England demand peaks in the summer, particularly when there is a series of humid days when the temperature is in the 90s. The peak demand period typically accounts for 5% or fewer of the hours in the year.

Until recently, the growth in peak demand has been notably faster than growth in overall demand, in large part due to greater use of air conditioning. The growth in peak demand has at times stressed the transmission and distribution system, increasing the likelihood of brownouts and blackouts. The peak demand is typically met by using generating technologies that have low capital costs but very high operating costs, e.g., jet turbines. As a result, the wholesale cost of electricity during peak hours can be many times the cost during the rest of the year. The growth in peak demand has also led to higher retail electric prices year-round. This is because there must be adequate generating capacity serving the state to meet peak demand. This generating capacity must be paid for, even though it is only used for a limited period during the year.

In recent years peak demand has fallen substantially. Across New England, summer peak demand fell from 28,130 MW in 2006 to 26,145 MW in 2007, 26,138 MW in 2008, and 25,081 MW in 2009. For Connecticut, the peaks were 7,261 MW, 6,788 MW, 7,073 MW and 6,346 MW respectively. The decline in peak demand is the result of

conservation and demand response programs, the recession, and in some years, cooler than average summers. ISO-New England projects that peak demand will grow by 1.1% per year in the region and 0.9% per year in Connecticut, assuming normal weather.

STATE AND REGIONAL INITIATIVES TO REDUCE PEAK DEMAND

State

In Connecticut, PA 07-242 required electric companies to offer a program to encourage their customers to limit their consumption during the summer (the program was not specifically designed to reduce peak demand, although peak demand occurs in this period). The program had to compare electricity use during the period from June 1, 2007 to August 31, 2007 to use in the same period in 2006 and give customers an incentive to conserve electricity in 2007. The comparison had to be adjusted for changes in weather between the two years. The program was open only to customers who lived in the same dwelling in both years.

Electric companies had to issue credits to eligible customers who successfully participated in the program. The credit was 10% of the summer 2007 bill for customers who used 10% less electricity than they used in summer 2006. Customers who reduced their summer consumption by 15% or 20% received proportionally larger credits.

In its 2008 report to the legislature on the program, the DPUC found that 32% of eligible customers received credits under the program. The total cost of the program was slightly more than $24 million. DPUC noted that the electric companies had not provided adequate information at that time to determine the program's actual cost effectiveness, but that based on the program's design and timing it was likely it was not cost effective in 2007.

DPUC noted that many and possibly most of the recipients may have received credits without a conscious decision or effort to participate. Those that did conserve may have taken action before the program was announced in response to significant increases to electric rates that occurred in January 2007. For these reasons many of the customers receiving credits may have been “free riders” who received a credit for actions that were not a result of the program. DPUC observed that paying large numbers of free riders can significantly reduce the cost effectiveness of conservation programs, and that this was likely true for

the program. DPUC also noted that the reduction in participating customers' demand (as distinct from consumption) was not measured and could not be assessed with the standards under which the program operated.

PA 07-242 also required the Energy Conservation Management Board to evaluate and approve technologies that can be deployed by “Connecticut electric efficiency partners” (including electric company customers and energy management companies) to reduce electric demand. The board's decision was subject to DPUC approval.

Under the act, anyone can seek DPUC approval and funding as a partner by showing adequate financial resources, managerial ability, and technical competence. The application must describe the DPUC-approved technologies that the partner will buy or provide and the amount of funding it is seeking. In evaluating the application, DPUC must consider the applicant's potential to reduce overall and peak demand. DPUC must determine how much of the cost of an approved application the customer will bear and how much will be funded by ratepayers. DPUC must ensure that approved applications achieve a two-to-one payback ratio. No more than $60 million in ratepayer funds can go to this program each year. The act also requires DPUC to develop a low-interest loan program to finance the customer's share of the capital cost of the technologies. It can provide these loans through several mechanisms, including an agreement with the Connecticut Development Authority. The financing agreements entered into with the Connecticut Development Authority cannot exceed $10 million dollars.

To date, the only projects that have been funded under this program have been two small projects to use natural gas chillers in lieu of electric air conditioning. The combined funding for these projects is $75,000. DPUC has approved several other technologies for the program.

ISO-NEW ENGLAND DEMAND RESPONSE PROGRAMS

ISO-New England currently operates five year-round demand response programs. Three of the programs address reliability i.e., they seek to avoid brownouts and blackouts, either in a zone or across New England. In these programs, participating customers agree to reduce their demand within a specified period (30 minutes or two hours). They are paid for reducing their demand at a rate that depends on how quickly they can respond.

The other two programs are designed to reduce the rate impacts of peak demand. One allows participating customers to agree to limit their demand in the real time market for those periods when the forecast hourly price is 10 cents per kilowatt-hour or more and ISO New England has transmitted instructions that the eligibility period is open. The other program operates in ISO-New England's other major (“day ahead”) market, in which generators and other energy suppliers submit bids to meet the following day's demand. The participating customers in both programs are paid based on market prices at the time.

The five programs enroll 3,200 customers with just under 2,000 MW of demand as of March 2009; 37% of this demand is in Connecticut. In contrast, slightly more than 25% of the total demand in New England comes from Connecticut.

In the most recent reporting period (October 2008 to March 2009) there were no instances when ISO-New England needed these demand response resources to maintain reliability. The real time program was invoked for 236 hours during this period in one or more zones. The day ahead program was used on 54 days.

The average payment for customers who reduced their demand across all programs in the region was just over 8.9 cents per kilowatt-hour; in Connecticut the average payment was just over 9.3 cents per kilowatt-hour. ISO-New England estimates that the programs reduced overall rates by 0.3 cents per kilowatt-hour in the October through December 2008 period and by 0.2 cents per kilowatt-hour during the January through March 2009 period. It found similar cost savings in the previous reporting period (April 2007 to September 2008).

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