OLR Research Report

January 20, 2010





By: Kevin E. McCarthy, Principal Analyst

You asked why Connecticut's electric rates are so much higher than the national average, and what the legislature has done in recent years to reduce electric rates.


Historically, Connecticut's electric rates have been among the highest in the country. In 2009, Connecticut's rates were second only to Hawaii. For the first nine months of 2009 Connecticut's average rate was 17.5 cents per kilowatt-hour (kwh), compared to the national average of 9.82 cents per kwh. The gap has grown in the past five years; in 2004 Connecticut's average rate was 34.8% above the national average while in 2009 the gap had grown to 74.3%.

High electric rates are a regional phenomenon. New England's average rate for the first nine months of 2009 was 15.64 cents per kwh, 59.3% above the national average and noticeably higher than any other region in the continental United States. Similarly, New York state's average rate was 16.08 cents per kwh.

We are aware of no empirical analysis of why Connecticut's rates are so high. However, it appears that several factors are the primary causes of our high rates. These include policy choices made by the state and federal governments, rising fuel prices (notably for natural gas), Connecticut's lack of indigenous energy resources and the resulting fuel transportation costs, and congestion on the transmission system. Several of these factors interact. One example of this interaction is that: (1) the legislature effectively required the electric companies to sell their power plants and buy power on the wholesale market; (2) wholesale market rules approved by the federal government tend to tie the wholesale price of electricity to the wholesale price of natural gas, whether or not the power is generated from a plant that uses gas; and (3) gas has become more expensive over time due to market forces and policy decisions and is more expensive in Connecticut than elsewhere because it must be shipped here from regions with gas resources.

The legislature adopted major legislation in 2005 and 2007 to reduce electricity costs, providing incentives for energy efficiency and new sources of supply. PA 05-1, June Special Session, included several initiatives to reduce costs associated with congestion on the electric transmission system. It created incentives for customers for installing “distributed resources” such as small-scale generators on their premises. PA 07-242 (1) included various measures to encourage the development of new power plants and other forms of power generation by electric companies and others; and (2) required electric companies, with the approval of the Department of Pubic Utility Control (DPUC), to engage in “integrated resources planning” in which the need for electricity is first met by conservation in order to reduce rates. The legislature also passed legislation in 2008 to promote energy efficiency programs.


Table 1 compares electric rates in Connecticut and the nation from 1999 (the year before PA 98-28, which restructured the electric market to permit competition) to 2009. The rate is calculated by dividing total electric revenues earned by electric utilities and competitive suppliers by the total number of kilowatt-hours (kwh) sold. It thus reflects the customers' total bills, including the flat monthly customer service charge. The data cover all types of customers and similar trends appear when customers are broken into residential, commercial, and industrial classes.





(% above national average)



9.96 (50)



9.53 (39.9)



9.62 (32.0)



9.71 (48.6)



10.16 (36.6)



10.26 (34.8)



12.06 (48.2)



14.83 (66.6)



16.45 (80)



16.92 (72.3)


(first 9 months)


17.5 (79.3)

Source: Energy Information Administration, U.S. Department of Energy

Although the average electric rate in Connecticut is much higher than the national average, Connecticut consumers use less power than the national average, and the difference in monthly bills is not quite as pronounced as the difference in rates. For 2007 (latest available data) average residential consumption in Connecticut was 764 kwh per month, compared to a national average of 936 kwh. As a result, the average monthly bill in Connecticut in that year was 46% higher than the average monthly bill nationally while rates were 80% higher.

In addition, electric rates in the state have come down slightly as of January 1, 2010 due to decreased electric wholesale rates. The discovery of a large supply of economically recoverable shale gas located as close as New York and Pennsylvania may allow natural gas prices to remain moderate and may thereby help to moderate electric rates.


Policy Choices

Introduction. Historically, electric companies had a monopoly on selling power in their service territories. They were vertically integrated, meaning that they owned and operated generation, transmission, and distribution facilities. Their rates were regulated by public utility commissions (PUC) on a cost of service basis. The commissions set rates

at a level that allowed the companies to recover their PUC-approved capital and operating costs and earn a rate of return, set by the PUC, on their capital investments.

In the 1990s, approximately half of the states, including every New England state except Vermont, restructured their electric industries to permit retail competition in electric supply. The legislation (in Connecticut, PA 98-28) did not affect the regulation of the transmission and distribution functions.

Electric Restructuring. The impact of restructuring on rates has been sharply debated. Connecticut's average electric rate was 50% above the national average in 1999, suggesting that while restructuring may have contributed to Connecticut's high electric rates, it is not their sole cause. In addition, Connecticut's rates for the transmission and distribution components of electric service, which were unaffected by restructuring, are well above the national average. According to the Office of Consumer Counsel, the national average rate for these components is 2.74 cents per kwh, compared to 3.74 cents per kwh for Connecticut Light and Power and 6.75 cents per kwh for United Illuminating.

Nonetheless, it is relevant to compare the experience of Vermont, which did not restructure, with Connecticut. In 1999, Vermont's average rate was 12.19 cents per kwh compared to 9.96 cents in Connecticut. Since then, Vermont's rate has been essentially flat, increasing to 12.79 cents per kwh in 2009. The average rates in Connecticut began to exceed Vermont's average rate in 2005 and now are 37% higher than Vermont's average rate.

Similarly, the rates charged by Connecticut's six municipal utilities, which have chosen not to restructure, are below the rates charged by the state's electric companies. As of January 1, 2010, the total bill for a municipal utility residential customer using 800 kwh per month was 11% to 40% below a comparable Connecticut Light and Power customer, depending on the utility. Some of this difference is due to structural factors, such as the municipal utilities' access to lower cost capital due to their tax exempt status. But it appears that a significant part of the difference may be due to restructuring. For example, the gap between the average rate for all customer classes for Norwich's municipal utility (whose current rates are close to the average for the municipal utilities) and the statewide average increased from 0.37 cents per kwh in 1999 to 2.62 cents per kwh in 2009.

Electric Company Divestiture of Generation Assets. PA 98-28 effectively required the electric companies to sell off their power plants and other generation resources. This forced the companies to buy power on the wholesale market under the Federal Energy Regulatory Commission (FERC)-approved rules described below.

Rates in New Hampshire, which passed restructuring legislation but allowed its major electric company to retain its generation assets, have increased much less than rates in Connecticut. From 1999 to 2009, rates increased in New Hampshire by 11.8% compared to 75.7% in Connecticut.

Wholesale Market Rules. The regional wholesale market is administered by the Independent System Operator-New England (ISO-New England) under rules approved by FERC. The market has two primary components. Most power is sold under bilateral contracts between wholesale suppliers and electric companies or retail suppliers. The second component is the spot market. The prices set in the spot market substantially affect the prices charged under bilateral contracts. Much of the power generated in New England is purchased by marketers who sell this power on the spot and bilateral markets.

The prices set in the spot market are not based on a power plant's cost of service. Instead, ISO-New England estimates the amount of power needed hour-by-hour for the next day. It accepts bids to provide this power, beginning with the lowest cost bid, until it has enough supply to meet projected demand. All of the winning bidders are paid the price charged by the highest selected bidder. Approximately 90% of the time this price is set by plants that use natural gas. However, the successful bidders using lower-cost nuclear and coal plants are paid the same price.

When the wholesale market is tight these market rules can lead to rates that are higher than would apply under the cost of service approach. In a January 1, 2008 filing with the DPUC, Connecticut's electric companies asserted that the cost of service approach for existing and new power plants in the state would result in 2011 electric rates that would be 5.1 cents per kwh lower than would apply under the market rules, with a slightly smaller differential in 2013 and 2018. Connecticut Light and Power staff note that this estimate would be lower today due to a decrease in wholesale market rates since 2008.

On the other hand, when there is ample generation supply on the market, the rates produced under the market rule may be less than those produced under cost of service. This is because plant owners will provide power, even at rates that are below their full cost of service, so long as they can at least recover their operating costs. In addition, the market rule can increase the efficiency of power plant operations, since their owners do not earn money when their plants do not operate. Under the cost of service approach, the owner continues to recover the plant's capital costs and earn a rate of return on its investments even if the plant is not operating.

Environmental Policies. As part of PA 98-28, the legislature required electric companies and competitive suppliers to obtain an increasing proportion of their power from renewable resources under the renewable portfolio standard. DPUC staff estimate that complying with this mandate adds about 0.45 cents per kwh to the price of electricity. PA 98-28 also imposes a 0.3 cent per kwh charge to pay for conservation programs and a 0.1 cent per kwh charge to pay for renewable energy programs.

Another environmental policy that affects Connecticut's electric rates is the state's stringent air pollution standards. Connecticut has among the most stringent standards in the country for nitrogen oxides, sulfur oxides, and other pollutants. It is easier to meet these standards by generating electricity from natural gas than coal, a less expensive fuel. Moreover, Connecticut's mercury emissions standards, as they apply to coal-fired plants in the state, have led one plant's owner to import coal from Indonesia. As a result of these standards and other factors, nearly all of the new generating capacity built in Connecticut (and more generally New England) in the past ten years has used gas. In addition, Connecticut and other northeastern states participate in the Regional Greenhouse Gas Initiative, which discourages the use of coal, to address climate change.

Volatility Mitigation Measures. The law (CGS 16-244c) requires electric companies to procure power for their customers in a way that reduces rate volatility, i.e., rapid changes in rates. It requires them to procure overlapping contracts for power for fixed periods of time. For example, a company might buy one-third of the power it anticipates it will need for 2013 this year, one-third in 2011, and one-third in 2012. This approach, called laddering, protects consumers who buy their power from electric companies when wholesale electric rates increase dramatically, as occurred in 2008. On the other hand, when wholesale rates decrease, as is happening now, it takes several years for these consumers to reap the benefit. However, the consumers can switch to competitive suppliers, who may be able to offer them lower rates than are charged by the electric companies if the supplier has bought power when the price was falling.

In addition, in the past DPUC limited the strategies the electric companies could use to procure power for standard service (the service the companies provide to small and medium size customers who do not choose a competitive supplier) in order to limit volatility. DPUC required the companies to buy power on a “full requirements” basis, under which wholesalers providing power for this service assumed the risk for changing levels of demand, including the risk that standard service customers would choose competitive suppliers after the wholesaler bought power for them. The wholesalers charged a premium on their prices to reflect these risks, and this premium was incorporated in the rates for standard service. While DPUC has broadened the procurement options open to the electric companies, much of the power currently being supplied to standard service customers was bought under the former more restrictive rules.

Fuel Prices

As discussed above, electric rates are closely tied to the wholesale price of natural gas. This price has increased substantially over the past ten years, although it has fallen dramatically in the past 18 months. However, much of the power the electric companies are currently selling was contracted for when gas prices were at their peak. Nationally, the price of gas went from $2.38 per million British thermal units (mmBTU) in 1999 to $9.11 per mmBTU in 2008 to $5.02 in the first nine months of 2009. This trend was affected by market forces, notably changes in the price of oil which competes with gas on the market, and the increasing use of gas for power generation, which in part reflected policy decisions such as air emissions standards.

Connecticut's Geography

Connecticut has no fossil fuel resources and limited renewable energy generating capacity. As a result, fuel and electricity from renewable resources needs to be transported from other regions. Natural gas used in Connecticut is transported from other parts of the United States and Canada and coal from as far away as Indonesia. Although it is not possible to precisely quantify the impact of fuel transportation costs on electric rates, the cost of transporting natural gas to New England is about $1 per 100 cubic feet, or about 1 cent per kwh when the gas is

used to generate power. As described above, the cost of gas-powered generation generally sets the price of power on the New England wholesale market, so the cost of gas transportation affects the price of electricity generated by other fuels.

Transmission Congestion

In recent years demand in Connecticut has grown faster than the state's electric infrastructure. As a result, the transmission system became increasing congested, particularly in the southwestern third of the state. In order to maintain reliability, less efficient power plants have had to run more often than would have been the case in the absence of congestion. Moreover, congestion decreases the physical efficiency of the transmission lines, which increases the cost of power. As described below, PA 05-1, June Special Session, included several initiatives to reduce costs associated with congestion.

Congestion costs have decreased substantially in recent years with the construction of the Bethel-Norwalk and Norwalk-Middletown transmission lines. Nonetheless, the federally-mandated congestion charge (FMCC), which covers both the cost of congestion and legislatively-mandated measures to respond to it, accounts for about 0.85 cents per kwh for customers who buy their power from Connecticut Light and Power. The FMCC is negligible for United Illuminating customers. In addition, while the new transmission lines have reduced FMCCs, they increased the transmission component of electric bills. According to DPUC, between 2000 and 2010, Connecticut Light and Power's average transmission rate increased by 1.07 cents per kwh, while United Illuminating's average rate increased by 0.93 cents per kwh.

Other Factors

General Costs. Connecticut is a relatively high-cost state in terms of salaries, taxes, land, and other costs. For example, in 2009 the television network CNBC rated Connecticut as having the fourth highest cost of doing business in the country. These costs affect electric companies and other participants in the electric market.

Growth in Peak Demand. For many years, peak demand in Connecticut has grown more quickly than overall demand. The peak demand must be met by power plants that typically operate for fewer than 200 hours per year or by demand response programs. The capital costs of these plants must be recovered, notwithstanding the fact that

they are used infrequently, and this places upward pressure on electric rates. While demand response programs are less expensive than these plants, the cost of the programs must be recovered in rates as well.



PA 05-1, June Special Session, included several initiatives to reduce costs associated with congestion on the electric transmission system. The act required DPUC to identify measures that could reduce FMCCs and that could be implemented, at least partially, by January 1, 2006. These measures included (1) demand-response programs (programs designed to change when electricity is consumed, in order to reduce demands on the electric system); (2) other distributed resources (such as conservation programs and small power plants); and (3) contracts between an electric company and power plant owners for rights to the capacity of the plant. DPUC had to order the electric companies to begin implementing the measures that it considered appropriate by January 1, 2006.

The act also required DPUC to issue a request for proposals to identify ways to reduce FMCCs over the period May 1, 2006 through December 31, 2010. The proposals could be for distributed resources; other new generation resources, including expanded and repowered generation; or contracts between an electric company and another party for up to 15 years to buy generation capacity rights in the area where the company is authorized to operate.

The act created incentives for customers for installing distributed resources on their premises. These resources include small- and medium-size generating facilities and conservation and load management measures. The incentives include capital- and operating-cost subsidies and the provision of long-term financing. Specifically, the act required DPUC to establish a one-time capital subsidy of $200 to $500 per kilowatt of generating capacity to customers who install customer-side distributed generation. A subsidy could be granted only if the project reduces FMCCs by more than the award, and no person can receive more than one award. The size of the award depends on the reduction of FMCCs. The act also (1) reduced natural gas charges for those customers who use gas to fuel distributed resources facilities and (2) exempted new distributed resources from electric backup charges if the resource's capacity is less than peak load and the resources are available to the system during peak periods. In addition, the act required DPUC to select one or more entities to provide long-term financing for the capital and other costs of customer-side distributed resources and advanced power monitoring and metering equipment. DPUC had to implement a mechanism that reduces the interest rate for people receiving this financing to no more than the prime rate. Each selected entity must give preference to financing projects that maximize reductions in FMCCs.

The cost of supplying electricity increases dramatically during peak demand, particularly during the summer. These costs are reflected in rates. In order to promote conservation and reduce rates, the act required the electric companies to implement (1) mandatory daily time-of-use rates for large commercial and industrial customers and voluntary time-of-use rates for other customers starting June 1, 2006 and (2) mandatory seasonal rates for all customers starting June 1, 2007.


Energy Efficiency. PA 07-242 contains a wide range of measures to reduce electric rates by decreasing demand and increasing supply. It makes permanent the sales tax exemption for such things as insulation, programmable thermostats, and gas furnaces that meet Energy Star standards. It newly exempts compact fluorescent light bulbs from the tax.   The act also established energy efficiency standards for various commercial products, such as walk-in refrigerators and freezers, as well as certain incandescent lights.

The act requires the Energy Conservation Management Board to evaluate and approve technologies to reduce electric demand that can be deployed by “Connecticut electric efficiency partners,” including electric company customers and energy management companies, as well as high efficiency natural gas and oil furnaces.

Supply Incentives. The act required the electric companies to submit plans to DPUC to build peaking generation plants. Other entities were allowed to submit such plans. Within 120 days of receiving the plan, DPUC had to approve it unless it determined that it is not in customers' interests. Any approved plan had to include a requirement that the applicant be compensated at the plant's cost of service plus a reasonable rate of return. The applicant must also agree to run the plant when and at the capacity needed to reduce overall rates.

Selected entities can recover only the just and reasonable costs of building the plant. The entities are entitled to recover their prudently incurred costs, including capital and operating expenses, fuel, taxes, and a reasonable return on equity. DPUC must review the cost recovery using existing rate-making principles. The return on equity must be updated at least once every four years. The selected entity must bid the power from the plant into the regional wholesale electric markets, including the energy, capacity, and forward resource markets.

As described above, PA 05-1, June Special Session, established capital incentives for new distributed generation. PA 07-242 extends the incentives to distributed generation developed in the state before January 1, 2007 if the generation increases its efficiency and output.

Integrated Resources Planning. The act requires the electric companies to annually assess, among other things:

1. the energy and capacity requirements of their customers for the next three, five, and 10 years;

2. how best to eliminate or stabilize growth in electric demand; and

3. the estimated lifetime cost and availability of potential energy resources.

The act requires the companies to review the assessment and develop a comprehensive plan for procuring energy resources. The plan must include a wide range of resources, including energy efficiency, conventional and renewable generating resources, combined heat and power (cogeneration), and emerging energy technologies. The plan must seek to minimize the cost of these resources and maximize customer benefit consistent with the state's environmental policies. Under the act, resource needs must first be met through all available energy efficiency measures that are cost-effective, reliable, and feasible. The Connecticut Energy Advisory Board must review the plan and submit it to DPUC. DPUC must approve, or modify and approve the plan and the electric companies must implement it under DPUC oversight.


PA 08-2, August Special Session, increases the maximum income a household can have to participate in the energy conservation loan program from 150% to 200% of the median area income.  The program, administered by the Department of Economic and Community Development (DECD), provides loans for energy efficiency improvements and replacement furnaces and boilers in residential structures.  The act sets a 0% interest rate for loans for natural gas furnaces or boilers that meet or exceed federal Energy Star standards and propane and oil

furnaces and boilers that are at least 84% efficient. The act appropriates $2 million in FY 09 to DECD to provide additional loans for this program for the efficiency improvements, alternative energy devices, and replacement furnaces and boilers.  

The act required the Office of Policy and Management to establish a program in FY 09 to subsidize energy audits conducted by oil dealers or other entities for people who heat their homes with fuels other than natural gas or electricity.  The act appropriated $7 million in FY 09 for the program.  The act also appropriated $2 million in FY 09 to the Department of Social Services to develop a plan for funding weatherization projects for low-income households who participate in the Connecticut energy assistance program.