You asked how electric company rates are set in Connecticut and other states. This memo addresses how rates in Connecticut are set for transitional standard offer service, which is provided to approximately 99% of the companies' customers who have not chosen a competitive supplier. Starting in 2007, the companies will be subject to new rate-setting provisions for customers who do not choose competitive suppliers.

SUMMARY

In Connecticut and most other states, electric company rates are set based on the company's costs. Under traditional rate regulation, which is used in Connecticut to set part of the companies' rates, rates are set to allow companies to just recover their prudently incurred costs, including the cost of their prudent capital investments, and allow the companies to earn a reasonable rate of return (profit) on these investments. Regulatory agencies such as the Department of Public Utility Control (DPUC) determine whether costs are prudently incurred and set the rate of return.

Connecticut sets an electric company's transmission and distribution rates under traditional rate regulation. On the other hand, the restructuring law currently bars the companies from owning power plants, and therefore they must buy the power they need on the wholesale market. They issue a request for proposals for this power and select the winning bids under DPUC supervision. The companies are allowed to recover the costs of these wholesale contracts, but do not earn a rate of return on them. DPUC reviews these costs in a contested case proceeding. The rates also cover state- and federally-mandated charges, without earning a return on these costs. The rates are subject to adjustment for changes in certain costs, such as purchased power.

Most of the other states that have restructured their electric industries to permit competition set electric rates in a similar manner. About half of the states have not restructured their electric industries and allow their electric companies to own power plants. In most of these states, rates are set under traditional ratemaking procedures for their generation as well as transmission and distribution functions.

A few states use alternative methods to set rates in which there is a less direct relationship between electric company costs and rates. Several of these states use performance-based ratemaking techniques that allow companies to charge rates up or earn overall revenues, up to a cap if the company meets quality of service and other standards.

CONNECTICUT

In Connecticut, electric rates are tied to the company's costs. The costs fall into three broad categories: those associated with transmitting and distributing power to the company's customers, its costs of purchasing the power (the largest component of overall costs), and state and federally-mandated charges.

The total of these costs determine the company's revenue requirement, i. e. , the amount of money it needs to earn to reliably and safely provide electric service to its customers. The revenue requirements are allocated among customer classes based on the cost of serving each class. This means that residential customers pay all of the costs associated with serving their class, industrial customers pay all of the costs associated with them, etc. The rate charged a class is the revenue requirements associated with the class divided by company's projected sales to that class. In addition to rates, customers pay a flat monthly charge to cover the company's customer service costs, e. g. , the cost of maintaining a call center. Larger customers also pay a demand charge based on their maximum use of power in the recent past.

Transmission and Distribution Costs

While the restructuring law allows customers to choose their electric supplier, the transmission and generation functions remain an electric company monopoly. DPUC determines the rates for these functions in a traditional rate case.

A rate case is a quasi-judicial proceeding in which the DPUC hears a company's application to change its rates. The case is heard by a panel of DPUC commissioners (all five commissioners in major rate cases). If an electric (or gas) company goes more than four years between rate cases, DPUC must conduct a review to determine whether its rates are just and reasonable or initiate a rate case on its own (CGS § 16-19a).

The Office of Consumer Counsel, which represents ratepayer interests, is entitled to participate in rate cases and other contested cases at DPUC (CGS § 16-2a). Both it and the attorney general routinely participate in rate cases. DPUC and the participants in the case file interrogatories to gather information from the electric company that is not contained in its application. DPUC and other participants cross-examine the company. The company and other participants file briefs and make oral arguments.

Based on the record in the case, the participating commissioners issue a draft decision. Parties can file written exceptions, proposing that the decision be amended in some way. The commissioners then issue a final decision, usually about a week after the draft decision goes out. Parties in the case can appeal it to the courts.

Purchased Power Costs

As discussed in OLR Report 2006-R-0048, the state's restructuring law effectively required Connecticut Light & Power (CL&P) and United Illuminating (UI) to auction off their power plants. PA 05-1, June Special Session allows the two companies to build a limited amount of generating capacity under certain circumstances starting later this year.

As a result of these provisions, the companies currently have to buy power for their customers on the wholesale market. As memo 2006-R-0034 describes, CL&P has purchased power in a series of overlapping contracts. It recently contracted for half of the power it will need for transitional standard offer service for 2006, and a cost that was more than double what it had previously paid for the power needed to cover the other half of its supply.

DPUC reviewed CL&P's recent application to increase its rates to recover these costs in a contested case proceeding, following the procedures similar to those used in a rate case although in a shorter period of time. In its final decision approving the increase, DPUC stated that CL&P has limited control over its wholesale costs and that the department must pass these costs through to customers. As a result of this increased cost, CL&P's overall rates will increase by 22. 5% in 2006. The final decision noted that CL&P passes on all of revenue it receives for the power to its wholesale suppliers and that CL&P shareholders do not benefit from the company's recovery of these costs.

UI, which is substantially smaller than CL&P, was able to enter into contracts in 2003 to cover its entire demand through 2006. Under these contracts, the cost of purchased power has been relatively stable. However, unless the wholesale cost of electricity falls significantly, it is likely that the company will face substantially higher purchased power costs in 2007.

State- and Federally-Mandated Costs

The third component of the costs is state- and federally-mandated charges. For example, state law imposes a charge of 0. 3 cents per kilowatt-hour to pay for conservation programs and a charge of 0. 1 cents per kilowatt-hour to pay for renewable energy programs (although the legislature has allocated part of these revenues to the General Fund) (CGS §§ 16-245m and 16-245n).

At the federal level, there are several charges associated with congestion on the transmission system. In the southwestern third of the state electricity demand exceeds the supply that can be provided by local power plants at market rates. At the same time, constraints on the transmission system limit the amount of power that can be imported to this region. As a result, older, less efficient plants in the region have to run more often than they otherwise would. In addition, the plant owners receive payments to make them available as a form of insurance to assure system reliability. These “federally-mandated congestion charges” account for approximately 18% of the total rate of UI, whose service territory is entirely within southwest Connecticut. They account for approximately 11% of the rates of CL&P, most of whose service territory is in other parts of the state.

DPUC allows the companies to pass these costs on to their ratepayers. The companies do not earn a return on these costs. The federally mandated congestion costs vary over time. DPUC periodically reviews the actual costs and modifies the companies' rates to reflect any differences between projected and actual costs in a contested case proceeding.

OTHER STATES

Most of the states that have restructured their electric industries set electric rates as Connecticut does. That is, electric company rates cover the company's costs (including its purchased power costs) and its return on its capital investments, primarily transmission and distribution facilities. As noted in OLR Report 2006-R-0037, there are differences in the way the electric companies in these states procure power, which has affected the extent to which rates have increased. Among other things, there are differences in how often the companies go on the wholesale market to buy power and whether they buy all of the power it needs at one time or in a series of overlapping contracts. In California, the companies must first meet their anticipated demands by investing in cost-effective conservation measures and then go on the wholesale market to buy power needed to meet the unmet demand.

About half of the states have not restructured their electric industries and allow their electric companies to own power plants. In most of these states, rates are set under traditional ratemaking procedures for the generation as well as transmission and distribution functions. As a result, the rates in these states are based on recovery of (1) the company's operating costs such as fuel for its power plants and personnel for all of its functions, (2) recovery of its capital costs for power plants and transmission and distribution facilities, and (3) a return on these investments. As in Connecticut, the public utility commission determines whether costs are prudently incurred and sets the rate of return on investments.

Some restructured states, such as New Hampshire, have allowed electric companies to retain their power plants. These states use a hybrid of traditional ratemaking and the procedures used in Connecticut to set the rates of their electric companies.

A few states, both restructured and unrestructured, have adopted alternative ways of setting rates that are less directly tied to the company's costs. These approaches are commonly called performance based ratemaking. One approach caps the rate the company based on its costs at the time. Alternatively, the company's total revenues are capped at its current revenue requirement. Under either approach, the cap is periodically adjusted to reflect changes in a variety of factors, including inflation, productivity gains in the electric industry, and the company's performance in meeting quality of service goals and other standards. The cap is also adjusted for factors beyond the company's control, such as increased taxes. While the company's rates are based on its costs, they also reflect non-cost factors.

Performance-based ratemaking has been used in Maine, New York, and several other states. It has produced mixed results according to a 1997 study conducted for the National Association of Regulatory Utility Commissioners (the national organization of state public utility commissions). The study is available on the publications page of http: //www. synapse-energy. com.

KM: ro