March 9, 2007
CONNECTICUT'S ELECTRIC COSTS VS. OTHER STATES
By: Kevin E. McCarthy, Principal Analyst
You asked how Connecticut's electric costs compare to those in other states. You also wanted to know why Connecticut's electric rates are so high. We have enclosed an article from the March 4, 2007 Hartford Courant, which also addresses these topics.
As of November, 2006 (the latest date for available comprehensive data) Connecticut had the third highest electric rates in the country, behind Hawaii and Massachusetts. Connecticut has had relatively high rates for many years. In 1998, when the state adopted its electric restructuring law, it had the fourth highest rates in the country. High electric rates are a regional phenomenon. The ten states with the highest rates in 2006 included five New England states, New York, and New Jersey. The other New England state (Vermont) had the 11th highest rates. In contrast, the Southeast, the Pacific Northwest, and much of the Midwest have substantially lower rates than Connecticut.
We are aware of no definitive empirical analysis of why Connecticut's rates are so high. However, market participants and regulators point to a wide array of reasons, including (1) a tight market caused by growth in demand outstripping supply; (2) rapid increases in the price of natural gas, which is extensively used in generation and whose price affects the price charged by plants that use other fuels; (3) federally-imposed charges, particularly charges connected to congestion on the transmission system; (4) the age of the state's generating plants; and (5) the state's environmental standards, among other things. A number of these factors interact with each other. On the other hand, it is not clear what effect, if any, the restructuring law has had on rates.
RATES IN CONNECTICUT VERSUS OTHER STATES
Table 1 presents the top ten states with the highest average price of electricity across sectors in November 2006 and in 1998, when Connecticut passed it restructuring law (PA 98-28). Connecticut had the third highest rates in the country as of November 2006, when the national average was 8.58 cents per kilowatt-hour (kwh). As you know, customers in Connecticut, particularly those served by United Illuminating have seen substantial increases since November. In 1998, when the national average was 6.74 cents per kwh, Connecticut had the fourth highest rates in the country.
Table 1: Ten States with the Highest Electric Rates, 1998 and 2006
Ten most expensive states
as of 11/06 (cents/kwh)
Ten most expensive states
as of 1998 (cents/kwh)
New Hampshire (11.93)
New York (10.71)
Rhode Island (13.97)
New York (13.96)
New Jersey (10.17)
New Hampshire (13.89)
New Jersey (11.91)
Rhode Island (9.58)
Source: Energy Information Administration
As the table indicates, rates have been high across much of the northeast. Five of the New England states were in the top ten in both years, as were New Jersey and New York. Vermont was in the top ten in 1998 and fell to the 11th position in 2006.
REASONS FOR CONNECTICUT'S HIGH ELECTRIC RATES
Growth in Demand versus Supply
Growth in electric demand, particularly during peak periods, has exceeded growth in supply (electric generation) in the state in recent years. For example, from 2000 to 2005, total annual demand in Connecticut increased by 2,000 gigawatt-hours (a gigawatt-hour is one billion watts of electricity used for one hour). During this time peak demand grew from 5,900 megawatts to 7,120 megawatts (a megawatt is about the amount of power used by 700 homes at one time). Total demand is currently growing at about 1.3% per year and peak demand at about 2% per year. The Siting Council attributes the growth in demand to larger homes, economic growth, and the growing use of electric appliances, office machines, computers, and especially air conditioning. Across New England, average residential consumption per household grew by approximately 10% since 1998, according to the Independent System Operator-New England (ISO-New England, the entity that administers the regional wholesale electric market). ISO-New England estimates that New England needs the equivalent of one new 500-megawatt plant per year to keep up with the growth in peak demand.
While several new power plants were built 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 their adoption of restructuring laws in the late 1990s. For a variety of economic and environmental reasons, most of the new generating capacity in Connecticut and the rest of New England has been gas-fired.
The growth in demand relative to supply puts pressure on rates in several ways. In Connecticut and the rest of New England, 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 and oil to produce power. Increased demand expands the need for 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.
Rising Fuel Costs
Connecticut and New England rely heavily on generation fuels, notably natural gas and oil, whose prices have increased rapidly in recent years. These two fuels account for more than one-third of the power produced in the state. The price of natural gas has nearly tripled since the restructuring law went into effect and the price of oil has also increased substantially. Part of the cost of these fuels is the expense of transporting them to the state. For example, Connecticut gets much of the gas it uses for generation from western Canada.
The price of these fuels also affects the price of electricity produced from other sources of energy, due to the way the wholesale electric market works. The market has two major component, the spot market and bilateral contracts. Each day ISO-New England solicits bids from generators and marketers for the power it anticipates will be needed in each hour of the following day. ISO-New England accepts bids, starting with the least expensive, until it has acquired enough power to meet the forecast demand. All of the chosen bidders receive the amount bid by the last successful bidder, even when this is above their cost of producing of power. For example, during peak demand periods gas-fired plants often need to run in order to maintain the reliability of the electric system. During these times, nuclear and coal-fired plants will receive the same payment as the gas-fired plants, even they cost substantially less to run.
Most of the power sold in the wholesale market is sold under bilateral contracts, rather than in the spot market. (In some cases generators sell directly to utilities under such contracts, in others they sell to marketers who then sell to the utilities.) However, the price in the spot market affects the price of the bilateral contracts, since generators will base their contract offers on what they could make if they sold their power on the spot market.
Federally Mandated Charges
In recent years, demand has grown while the state's infrastructure of power plants and transmission lines 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 new 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. To maintain the economic viability of these plants, the Federal Energy Regulatory Commission (FERC) has granted their owners “reliability-must run” payments, which currently cost Connecticut consumers about $280 million per year. Other congestion charges amount to about $60 million per year. Moreover, congestion decreases the physical efficiency of the transmission lines, which increases the cost of power in the state. DPUC chairperson Don Downes estimates that transmission congestion increases the state's electric rates by more than 10% in total. The good news is that these congestion charges should decline substantially in the next two years as the new Norwalk-Middletown and Stamford-Norwalk transmission lines go into service.
In 2004, FERC initially approved the establishment of a new, Locational Installed Capacity (LICAP) system to supersede the reliability-must run payments. FERC's goal was to encourage the construction of new power plants where they are most needed. OLR Report 2005-R-0436 provides additional information on LICAP.
DPUC and a number of parties opposed this decision, arguing that it could cost Connecticut consumers hundreds of millions of dollars in additional electric costs per year. FERC subsequently approved a settlement agreement that will instead establish a forward capacity market, which will go into effect in 2010. In this market, ISO-New England will project the region's electric needs three years in advance and then hold an annual auction to purchase resources to satisfy these needs. New generating plants would be allowed to bid in on the same basis as existing ones and, for the first time, demand response resources (e.g., conservation programs) could bid in a form of capacity supply. While the forward capacity market is likely to be less expensive for Connecticut ratepayers than LICAP would have been, it will still likely increase residential rates. Under the settlement, utilities are already making transition payments to move towards the new market, and these payments are recovered in rates.
Age of Generating Plants
Many of Connecticut's generating plants are old. For example, the New Haven Harbor plant went into commercial operation in 1975. Some individual units at plants are even older. For example, the oldest unit at Middletown went into operation in 1958, while the oldest unit at Montville went in operation in 1954. In general, older plants are less efficient than newer plants, that is, they need to burn more fuel to create a kilowatt-hour of electricity. As a result, the power from these plants is more expensive than that from newer plants which are more common in other parts of the country.
Connecticut and the other New England states have some of the tightest environmental standards in the country, particularly with regard to air emissions from power plants. These standards are part of the reason why there are relatively few coal-fired plants in the region. In contrast, the emissions standards in several other parts of the country, notably the Ohio River Valley, are substantially less stringent for older plants.
In recent years, Connecticut has further tightened its standards, particularly with regard to the older plants sometimes referred to as the “sooty six.” To comply with these standards, one of these plants buys its coal from Indonesia. The legislature was aware of the potential implications of these standards. For example, when it adopted the provisions dealing with the older plants, it specifically allowed costs associated with workers who might be displaced as a result of the legislation (PA 02-64) to be paid for from the systems benefits charge on electric bills.
A number of market participants attribute part of the state's high rates to regulatory uncertainty. This uncertainty arises when the legislature or regulatory agency change the rules governing a market. In Connecticut, the legislature significantly changed the restructuring law, which went into effect in 2000, in 2003 and 2005 and is contemplating major changes this year. It also passed several laws placing a moratorium on new transmission lines. As noted above, FERC made a major change in the wholesale market with its approval of the settlement in lieu of its original LICAP decision. In addition, DPUC's implementation of the restructuring law has evolved over time.
There are a variety of views as to whether the electric restructuring law has been a factor in Connecticut's high rates. The law opened the retail electric market to competition. It also effectively required the electric companies to sell off their power plants and other generation resources.
It appears unlikely that opening the market to competition, in itself, has had a significant effect to date on rates. Although customers may be able to reduce their rates by choosing a competitive supplier, very few have done so until recently. In its January 17, 2007 electric industry competition report to the legislature, DPUC found that “an insignificant number (1.5%) of electric consumers have switched as the differential between the utilities' prices, the “price-to-beat”, and competitive supplier pricing was negligible.” However, in recent months a growing number of customers have chosen competitive suppliers.
The relationship between competition in the electric market and rates is unclear. For example, while Massachusetts has had a much more competitive market for commercial and industrial customers than Connecticut for several years, the amount these customers pay for power is virtually the same. Massachusetts' industrial customers paid slightly less, on average than Connecticut industrial customers as of November 2006, while the reverse was true for commercial customers.
Some commentators believe the law's divestiture provisions have contributed to high electric rates. They note that prior to restructuring, the electric companies' rates were based on their cost of serving customers. To the extent that the companies were able to meet their customers' needs by using relatively inexpensive plants, their rates were based on the costs of owning and operating these plants, plus a rate of return set by DPUC. In contrast, under the current market rules, rates are based on supply and demand, which can lead to wholesale rates that substantially exceed costs in a tight market.
In contrast, proponents of competition note that the current power plant owners only get paid when their plants operate. As a result, they have a financial incentive to increase the proportion of time that their plants are operational and to make other efficiency improvements. For example, Dominion Resources notes that the two units currently operating at Millstone produce about as much power as when the three units located there were utility-owned.
A 2005 analysis by Lester Lave and colleagues at Carnegie Mellon University found virtually no difference in rate trends in states that had restructured and those that had not. They also found that industrial customers in New England (the ones most likely to take advantage of competitive markets) did not experience lower rates due to restructuring, other than customers in Maine, where new gas supply lines lowered electric costs. In contrast, a 2006 study conducted by the consulting firm Polestar Associates for an electric generators' trade association found that New England consumers have saved between $6.5 and $7.6 billion in the 1998 to 2005 period, based on a comparison of actual retail electricity prices against a projection of where they would likely have trended in the absence of restructuring.