August 5, 2008
FACTORS BEHIND CONNECTICUT'S HIGH ELECTRIC RATES
By: Kevin E. McCarthy, Principal Analyst
You asked us to (1) update OLR memo 2007-R-0247 as to why Connecticut's electric rates are higher than rates in most other states and (2) describe measures the legislature has taken in the past four years to reduce electric costs in the short and long-term.
As of February 2008 (latest available data) Connecticut had the second highest electric rates in the country. High rates are a regional phenomenon, with eight of the ten states with the highest rates being located in the Northeast, including all the New England states.
We are aware of no empirical analysis as to why Connecticut's rates are so high. However, it appears that several factors that apply across New England and which interact among each other are the primary causes of our high rates. These include (1) the structure of the electric industry in New England, where the vast majority of power is supplied by non-utility generators; (2) federally-approved wholesale market rules; (3) a tight market caused by growth in demand outstripping supply; (4) the mix of fuels used to generate power in the region; and (5) environmental standards. In addition, it appears Connecticut's high rates are partially due to congestion on the state's electric transmission system and restrictions on how the electric companies in the state procure power on the wholesale market.
The legislature adopted legislation in 2005, 2006, 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 06-187 reinstated, for 13 months, a sales tax exemption for residential weatherization products and energy efficient equipment. PA 07-242 restored funding for energy conservation programs and established new energy efficiency programs and tax incentives for energy efficiency. The act also (1) includes various measures to encourage the development of new power plants and other forms of power generation by electric companies and others; (2) requires electric companies, with the approval of the DPUC, to engage in “integrated resources planning” in which the need for electricity is first met by conservation; and (3) expands energy assistance programs. In addition, PA 07-64 increased the income thresholds for receiving low interest rates on loans from the Energy Conservation Loan Fund.
WHY ARE CONNECTICUT ELECTRIC RATES SO HIGH?
As of February 2008 Connecticut had the second highest electric rates in the country, an average of 16.4 cents per kilowatt-hour (kwh), compared to a national average of 9.0 cents per kwh. Connecticut has had relatively high rates for some time. As OLR memo 2007-R-0247 notes, Connecticut had the third highest rates in the country as of November 2006 and the fourth highest rates in 1998, when the legislature partially deregulated the electric industry with the passage of PA 98-28.
High electric rates are a regional phenomenon. The ten states with the highest rates in February 2008 included the six New England states and New York and New Jersey. (The other two states were Hawaii, which had the highest rates in the country, and Alaska.) The average rate in New England was 14.9 cents per kwh. In contrast, the Southeast, the Pacific Northwest, and much of the Midwest have substantially lower rates than Connecticut and nearby states.
Prior to the passage of PA 98-28, electric companies in Connecticut were vertically integrated. This means the companies owned power plants and other generation assets as well as transmission and distribution facilities. The companies were regulated on a cost of service basis. Their rates were set to allow the companies to recover their fuel and other operating costs and earn a rate of return (profit) on investments in their facilities as well as recovering the costs of these investments.
PA 98-28 effectively required the companies to sell off their generation assets and buy power on the regional wholesale market. While DPUC continues to set rates for transmission and distribution on a cost of service basis, the regional wholesale market is under the jurisdiction of the Federal Energy Regulatory Commission, which approves the rules governing this market. The electric companies pass on the cost of the power they buy on this market to their customers, but do not earn a rate of return on their purchased power. The cost of this power accounts for the bulk of electric rates.
The electric companies across New England obtain the vast majority of their power from the wholesale market. As of February 2007 (latest available data), electric companies generated only 1.5% of the power sold in New England.
Wholesale Market Rules
The wholesale market has two primary components. Most power is sold under bilateral contracts between electric companies and wholesale suppliers (which can be power plant owners or marketers who purchase power from them and resell it on the wholesale market). The second component is the spot market. The prices set in the spot market substantially affect the prices charged under bilateral contracts.
The prices set in the spot market are not based on the power plants' cost of service. Instead, the Independent System Operator-New England (ISO-New England, the wholesale market administrator) estimates the amount of power needed hour-by-hour for the next day. It accepts bids to provide this power, beginning with the lowest 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. During periods of high demand (for example weekday afternoons), this price is typically set by plants that use natural gas. However, the owners of power produced by lower-cost nuclear and coal plants are paid the same price. New York state has its own ISO, which has similar rules.
When the wholesale market is tight, as is currently the case, 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.
On the other hand, when there is ample generation supply on the market, the rates produced under the market rule can 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 are able to at least recover their fuel and other 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.
Growth in Demand versus Supply
Growth in electric demand, particularly during peak periods, has exceeded growth in supply (electric generation) in the state and New England in recent years. In New England, the summer peak demand increased from 23,150 megawatts in 2000 to 27,640 MW in 2007 (adjusted for changes in weather). The reserve margin of generating capacity over peak summer demand fell from 29% to 10% from 2004 to 2006.
In Connecticut, while total demand growth is essentially flat (0.7% per year) at present, peak demand is growing at 1.4% per year. According to the Siting Council, this growth is primarily due to the use of air conditioning in summer. The growth in peak demand is important because the plants that are used to meet peak demand must be paid for, ultimately by ratepayers, even if they are used very infrequently.
While several new power plants were built in Connecticut in the wake PA 98-28, the last major plant went into service in 2004. Other New England states have had a similar experience following adoption of their restructuring laws in the late 1990s.
The growth in demand relative to supply puts pressure on rates in several ways. Under the market rules described above, when demand is low generators use relatively low cost plants (primarily those that use nuclear power and coal). As demand increases, generators are more likely to use more expensive plants, notably those that use gas to produce power. Increased demand expands the need for power imports from other states, with the associated costs of transmission. Increased demand also exacerbates congestion on the state's transmission system, which increases rates as described below.
New England depends more heavily than other regions on natural gas as a generating fuel. In February 2007 (last available data), natural gas was used to produce 34% of the power generated in New England, compared to 22% in the country as a whole. During most of the year, natural gas powered plants set the spot market price. In contrast, other regions rely much more heavily on coal as a generating fuel than New England. Nationally, 49% of all power was generated by coal as of February 2007; the comparable figure for New England was 16%. As coal is a significantly less expensive source of power than natural gas, this difference accounts for part of the difference in rates.
Part of the reason why New England uses more natural gas and less coal than other regions is its air quality standards. The New England states have among the most stringent emission standards in the country for nitrogen oxides, sulfur oxides, and other pollutants. Emissions of these pollutants from natural gas plants are lower and easier to control than from coal plants. Connecticut's emissions standards, as they apply to one coal-fired plant in the state, have led the plant's owner to import coal from Indonesia.
In addition, all of the New England states except Vermont have renewable portfolio standards that require that part of the power sold in these states come from renewable resources. This slightly increases the cost of the power (approximately 0.2 to 0.4 cents per kwh in Connecticut).
As noted above, in recent years, demand in Connecticut has grown while the state's infrastructure of power plants has not. As a result, the transmission system has become increasing congested, particularly in the southwestern third of the state. This congestion has led to several costs. In order to maintain reliability, older, less efficient 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 in the state. These 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 6% of the average Connecticut residential customer's bill.
Until recently, DPUC policy has precluded long term contracts between electric companies and wholesale suppliers, allowing a maximum term of three years. It has also required that the companies enter into “full requirements” contracts with these suppliers. Under these contracts, the supplier bears the risk that electric customers will choose to be served by competitive retail suppliers, decreasing the amount of power sold by the electric company. It banned the companions from entering into supply contracts outside the request for proposal process.
It appears that these policies, which DPUC has recently modified, may have increased electric company rates. As discussed in OLR report 2007-R-0014, Connecticut's municipal utilities, which purchase power on the same wholesale market as the electric companies, have residential rates that are substantially below those of the electric companies. While part of the difference is due to different treatment under tax law and other structural factors, it appears that the municipal utilities' greater flexibility in procuring power also contributes to their lower rates.
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 program to provide one-time capital subsidies to customers who install customer-side distributed generation. The subsidy ranges from $200 to $500 per kilowatt of generating capacity. A subsidy can be granted only if the project reduces FMCCs 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, by competitive bid, 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. The act requires the electric companies to implement, with DPUC approval, (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. The act's sponsors anticipate that these rates will encourage customers to shift when they use electricity, ultimately decreasing the costs of electricity, by taking advantage of lower cost, off-peak power.
Among other things, PA 06-187 reinstated, for 13 months, a sales tax exemption for residential weatherization products and energy efficient equipment (legislation adopted in 2007 made the exemption permanent). It also required the Department of Economic and Community Development to prepare a plan for fuel cell economic development.
Energy Efficiency. PA 07-242 (1) makes permanent the sales tax exemption for residential energy efficiency goods such as insulation, programmable thermostats, and gas furnaces that meet Energy Star standards and (2) makes oil furnaces and boilers that are 84% or more efficient, rather than 85% efficient or more, eligible for this exemption. The act also permanently exempts compact fluorescent light bulbs from the sales tax. Finally, it exempts household appliances that meet federal Energy Star standards until June 30, 2008. (PA 07-1, June Special Session terminated the appliance exemption on September 30, 2007).
The act required electric companies, in calendar year 2007, to offer an electricity conservation incentive program to their customers. The program must 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 must be adjusted for changes in weather between the two years.
The act requires the Office of Policy and Management secretary to provide a rebate of up to $500, between July 1, 2007 and July 1, 2017, for the purchase and installation of certain replacement home heating equipment. The rebate is available for equipment installed in residential structures containing up to four dwelling units. Replacement gas furnaces must be Energy Star-rated and oil and propane equipment must be at least 84% efficient. The act caps the total amount of rebates at $5 million annually. Prior law authorized the issuance of up to $5 million in bonds for low interest energy efficiency loans. The act, instead, makes this an annual authorization and allows the proceeds to be used for the rebate program as well as the loan program.
The act reinstated, until June 30, 2008, provisions of prior law that lowered the interest rate for the Department of Economic and Community Development's energy efficiency loan program. It increases, from $15,000 to $25,000, the maximum loan that can be provided to owners of one- to four-unit residential properties under this program.
The act establishes energy efficiency standards for various products. These include certain incandescent lamps, medium voltage transformers, bottled water dispensers, commercial hot food holding cabinets, portable electric spas, walk-in refrigerators and freezers, and pool heaters. In most cases, the standards go into effect January 1, 2009.
The act requires ECMB 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, as well as high efficiency natural gas and oil furnaces.
Supply Incentives. The act requires the electric companies, singly or jointly, to submit a plan to DPUC between January 1 and February 1, 2008, to build peaking generation plants. Other entities can submit such plans during this period. DPUC must review each plan and can retain a consultant to help it determine whether the plan's costs are good-faith estimates. Within 120 days of receiving the plan, DPUC must approve it unless it determines that the plan is not in customers' interests. Any approved plan must 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. The act extends the incentives to distributed generation developed in the state before January 1, 2007 if the generation:
1. undergoes upgrades that (a) increase its thermal efficiency operating level by at least 10 percentage points (five percentage points for resources that have thermal efficiency of at least 70%);
2. increases its electrical output by at least ten percentage points;
3. operates at a thermal efficiency level of at least 50%; and
4. adds electric capacity in the state.
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 electric companies to (1) review the assessment and (2) 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's goal is 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 and demand reduction resources that are cost-effective, reliable, and feasible. The Connecticut Energy Advisory Board must review the plan and submit it, together with a statement of any unresolved issues, to DPUC. DPUC must approve, or modify and approve the plan and the electric companies must implement it under DPUC oversight.
Energy Assistance. The act required the Department of Social Service to maintain the energy assistance benefit increases that were adopted in 2005 when it proposed its low-income energy assistance block grant allocation plan for 2007-2008. Among other things, the 2005 legislation (1) increased, by $200, the basic benefit provided to low-income households under the Connecticut Energy Assistance Program and (2) required the program to provide a $300 basic benefit and $200 crisis benefit for moderate-income households.