Connecticut Siting Council
Review of the Connecticut Electric Utilities’
1997 Twenty-Year Forecasts of Loads and Resources
SUMMARY
Pursuant to Connecticut General Statutes § 16-50r (a), the Connecticut Siting Council (Council) is authorized to review the State’s electric utilities’ Twenty-Year Forecasts of Loads and Resources, including their plans to balance public demand for safe, reliable, and cost-effective electricity with an efficient mix of programs and resources to meet this demand. The Council has reviewed these forecasts since 1974; this report is the 24th issued by the agency. The electric utilities reviewed for this report are as follows: The Connecticut Light and Power Company (CL&P), a subsidiary of Northeast Utilities (NU); The United Illuminating Company (UI), The Connecticut Municipal Energy Electric Cooperative (CMEEC); and The Farmington River Power Company.
The shutdown of the three Millstone nuclear generating plants in 1996 continues to threaten the supply of the State’s electric generators needed to meet peak demand this summer. Had these nuclear generating facilities been operational, the utilities would have reported a surplus of generation capacity, and no new electric generation facilities would have been needed until after the year 2009. Restart of these units will be possible only after Nuclear Regulatory Commission (NRC) approval. NU is working in cooperation with the NRC to restart these units and expects they will be approved by the NRC for operation by year’s end or early 1998. In addition to the emergency installation of 200 MW of turbine generation in 1996, the utilities continue to seek additional power purchases from both in and out of Connecticut; full operation of all available generation units; power factor correction through installation of transmission and distribution capacitors; reinforcement of electric substations; reconductoring of transmission lines; continued temporary reactivation of retired units in Middletown, Bridgeport, Norwalk, and Wallingford; transfer of load to be served by facilities outside of Connecticut; temporary placement of eight mobile generators at the U.S. Navy Subbase in Groton; and voluntary interruption of service with certain customers who agree to such interruption. Despite these contingencies, the State’s supply and transmission infrastructure may be strained and vulnerable to failure and outage during prolonged periods of hot weather. Potential capacity deficiencies this summer may be further aggravated by the outage of Maine Yankee. Furthermore, the reactivation of older fossil-fueled units will likely increase point-source pollution levels and the State will likely see a deterioration of ambient air quality that could have an effect on public health. These increased pollutants include sulfur oxides, nitrogen oxides, carbon monoxide, hydrocarbons, particulate matter, and secondary photochemical oxidants that include ground level ozone. The deterioration of Connecticut’s ambient air quality will be further worsened if Connecticut imports electricity from other states that have less stringent air emission controls than does this State. The consequences of importing electricity from mid and central states that burn low-cost, high sulfur coal to generate electricity will be the migration of sulfur oxides and nitrogen oxides, the precursors to acid precipitation, into this State.
To offset the need to activate older fossil-fueled facilities in this State and to minimize the import of electricity from coal facilities located in states upwind of Connecticut, certain conservation and load management (C&LM) programs must be implemented. These programs can be highly effective, but they require active and diligent public participation. These C&LM programs include lowering of air-conditioner and water heater-temperature levels, restricted use of lighting, and more conservative use of electric equipment during peak periods. While these C&LM programs must be tolerated by the public during the unscheduled outages of the Millstone nuclear units, the value of these programs to minimize generation and reduce air pollution should be recognized and applied as necessary even after reactivation of these units. However, expenditures for C&LM programs within a deregulated electric environment will be a factor in determining the price of electricity in a competitive market. Consequently, only C&LM programs that can demonstrate cost-effective savings with relatively short amortization periods are expected to be implemented.
Natural gas has been selected to fuel new replacement facilities, including four of the five turbine units recently installed to replace capacity from the Millstone units. Nonetheless, use of this fuel for baseload facilities combined with other heating and transportation uses might result in over-dependence and concern to reliability. While coal resources in the United States remain plentiful and reliable, use of this fuel is expensive and problematic in that there are difficulties meeting existing and possible future Clean Air Act requirements.
The Council and the electric utilities clearly recognize a growing movement to allow full access to the electric transmission and distribution system for the purpose of retail sales. Changes associated with retail access might result in the development of new generation facilities and construction of transmission and substation facilities to support this generation. Additionally, new transmission facilities might be needed when certain generation is retired and greater reliance is placed on importing power to or through an area. However, the amount of new generation and the extent of changes to the electric transmission system associated with retail access remain unknown.
LOAD FORECAST
The State’s largest utilities, CL&P, UI, and CMEEC, predict increased load growth throughout the forecast period. Total energy output requirements for the State are expected to grow from 30,504 GWh in 1996, at an annual average compound growth rate of 1.08 percent, to 37,788 GWh in 2016. Total sales for the State are expected to grow from 28,391 GWh in 1996, at an annual average compound growth rate of 1.06 percent for the forecast period, reaching 35,025 GWh in year 2016. While both sales and energy output are expected to increase, total revenues from sales might grow at a slower rate or even decline as it did from 1994 to 1995, as a consequence of weather, efficiency losses, company use, and special contracts targeted to certain large customers. If retail access and open competition become established in the State’s energy market, restructured utilities could experience further reduction in sales and revenue as customers are lost to external suppliers and competitive pricing.
Over the past 10 years, Connecticut utilities have primarily experienced annual peaks during summer months. CL&P has experienced a summer load factor, the ratio of the average load supplied during a specified period to the peak during that period, that ranged from 64.7 percent in 1986, to 65.6 percent in 1996. CL&P predicts a decrease in the 1997 load factor to 60.3 percent, that will gradually increase to 62.1 percent by 2016. UI’s load factor has varied from 60 percent in 1986, to 62 percent in 1996 and has fluctuated by only a few percentage points during this period. However, UI forecasts its load factor will decline to 56 percent in 1997 and then remain constant to the year 2016. CMEEC predicts a continued gradual increase in their load factor from 69.2 percent in 1996 to 72.6 percent in 2016. An increasing electric load with improved load factors might be related to factors such as time of use and appliance efficiency. However, if load factors erode, a less efficient and more expensive system would affect nearly all energy users of the State. In an open, restructured electric market place, higher load factors will become increasingly important as generators compete for Connecticut customers.
RESIDENTIAL
Statewide sales to the residential class are expected to steadily increase at an average compound rate of 0.67 percent during the forecast period with CL&P, UI, and CMEEC predicting annual compound growth rates of 0.66, 0.68, and 0.83 percent respectively. Although potential variables such as weather and economic growth beyond the turn of the century may alter future demand, growth is expected to continue at least until 2016.
Increased residential sales are forecast to occur despite recent improvements in appliance efficiency and distribution of C&LM programs targeted for the residential sector. Overall, C&LM programs and appliance efficiency have slowed the growth of residential per capita kilowatt hour usage, but an increase in the number of electric appliances used per capita has offset much of the savings achieved.
COMMERCIAL
As Connecticut continues to move from an industry-based economy to a service-based economy, Connecticut’s economic condition might be measured by the performance of the commercial class. In some cases, the commercial class is expected to nearly double the rate of the residential class. CL&P predicts an annual compound growth rate of 1.98 percent for commercial sales in its service territory over the forecast period, which by the end of 1997, would make the commercial class the largest customer class in terms of gigawatt hours sold. Commercial sales would grow from 39.9 percent of all retail sales in 1996 to 46.6 percent in 2016. UI expects commercial class demand would increase by an annual compound rate of 0.58 percent over the next 20 years. CMEEC is predicting an annual compound growth rate of approximately 1.07 percent for this class over the forecast period. The growth of electricity usage by the commercial class is predicted to occur despite C&LM programs and increased equipment efficiency standards designed to slow the growth of electric consumption.
With increased use of computers, sensitive motors, and other electronic equipment, new commercial businesses have become increasingly reliant on large quantities of high quality, reliable electric service. With new market forces driving the quality and reliability of the electric supply, the need to further increase quality is expected.
INDUSTRIAL
The industrial class includes all manufacturing and processing plants and associated office space. Of all the classes, it is the most sensitive to fluctuation in the economy and has historically demonstrated greater variation in annual levels of electricity sales than any other class. The trend for Connecticut over the past 10 years continues to be either slow growth or loss. CL&P’s industrial class makes up the smallest portion of its three main customer classes, (18.4 percent of total retail sales) with 3,928 GWh sold in 1996. CL&P is expecting the annual compound growth rate for the industrial class to be 0.2 percent, slightly raising total sales to the industrial class to 4,067 GWh by 2016. UI’s industrial sales comprise 21.4 percent of total sales and are expected to grow by an average compound rate of 0.50 percent annually to 2016. CMEEC’s industrial class is its largest user class with 814.7 GWh at 46.1% of total sales in 1996. CMEEC expects a steady increase in industrial sales, growing at an overall annual compound growth rate of 0.49 percent over the total forecast period.
The projected modest increased use of electricity in the industrial class suggests penetration of electro-technologies and other manufacturing techniques using electricity. However, industrial use of electro-technologies such as climate controls, including humidity control in air-conditioning, have become more important as an increasing number of products require manufacture in clean and controlled environments, and will be a potential source of productivity and gain.
PEAK LOADS
In 1996, statewide non-coincident peak loads dropped 516 MW during the cooler than normal summer peak period. Annual peak loads are expected to grow in the State at an annual compound growth rate of 1.5 percent for CL&P, 1.1 percent for UI, and 0.6 percent for CMEEC over the forecast period. The State’s utilities predict 1,658 MW or 31 percent coincident peak load growth by the year 2016. Although the utilities maintain adequate generating capacity when all generation facilities are operational, demand can approach supply resources when unscheduled outages of large baseload facilities occur during periods of seasonal, weekly, and daily peaks. While similar outages can affect smaller units, the loss of a large block of capacity can have significant impacts on supply planning.
As peak demand continues to grow, so will the cost of generating electricity unless such growth can be managed with an increased load factor. In addition, the State has become increasingly dependent on reliable operation of a few, very large generation sources available to the New England Power Pool (NEPOOL). Without increased diversity, there will continue to be a need for regional dispatch to avoid local curtailment of electricity during periods of energy supply failure and high peak demand.
CONSERVATION AND LOAD MANAGEMENT
In 1997, the total impact from all current and previous CL&P Demand Side Management (DSM) sources is forecasted to reduce summer peaks by 389 MW and winter peaks by 302 MW. Total DSM initiatives for CL&P from all sources are expected to reduce peak demand by 338 MW for summer loads and 222 MW for winter loads by the year 2016.
Residential DSM programs include future promotion of efficient lighting, thermal weatherization, and water heater insulation. Commercial and industrial DSM programs include rebates on purchases of efficient motors, lighting rebates, incentives for energy-efficient construction, and retrofit programs.
Some of these DSM programs have demonstrated long-term cost-effectiveness to avoid generation and delivery, lower fuel costs, and reduce air emissions, particularly during peak periods. However, some less than cost-effective programs have been discontinued to reduce short-term costs as avoided costs and need for capacity have declined.
As competition increases, the utilities will likely refocus DSM programs to emphasize market transformation strategies. C&LM may survive in a competitive environment, but the focus by consumers will be on those programs that have short-term payback. Without mechanisms to internalize environmental externalities over long periods of time, conventional programs with short payback periods may be all that can be expected. If long-term energy programs are to survive in a fully competitive electricity market, the planning, design, and implementation might have to be undertaken by the State through its general revenues or more likely by a regulated distribution company using a systems benefit charge rather than by power marketers or energy suppliers.
RESOURCE FORECAST
As long as all active generators are available for continuing use, the State's utilities have supply resources that are anticipated to be adequate to meet demand until early next century. However, in April 1996, the NRC issued letters to each Millstone unit requesting that each unit conform to federal regulations. The NRC subsequently designated the Millstone units as Category 3 Watch List plants, requiring an approval vote by the NRC Commissioners to permit the units to restart. In December 1996, NU announced that Connecticut Yankee (Conn Yankee) would be retired and decommissioned. The three Millstone units’ total generating capacity at 2,668 MW comprise about 10 percent of the electricity available to New England utilities and 38.0 percent of the electricity available in Connecticut. In anticipation that the Millstone nuclear units would not be operational for the summer of 1997, the State’s utilities have maintained the following plan to avoid capacity deficiencies during peak demand periods:
- purchase power from every available resource, both in and out of Connecticut;
- operate all of its available generating units to their reasonable limits;
- upgrade several transmission lines and substations to support power import capability into Connecticut from interstate generation while maintaining system voltages;
- install capacitors on distribution feeders and in various bulk substations;
- install transmission voltage capacitors in several transmission substations;
- request all private power producers in the State to generate to their maximum output;
- maintain the reactivation of Middletown unit 1, Wallingford Pierce Station, Bridgeport Harbor unit 1, and Norwalk Harbor unit 10;
- continue operating 8 mobile diesel generators for 15 MW of capacity in service at the U.S. Navy Subbase in Groton;
- arrange to temporarily shift load on high load days to substations and transmission facilities outside Connecticut to help relieve the capacity shortage in the State; and
- explore additional interruption of service with industrial and commercial customers, and use of customer-owned emergency generators.
Additional capacity was provided with the installation of four General Electric LM6000 gas turbines at CL&P’s Devon plant in Milford and a similar unit modified for dual-fuel capability to burn jet fuel and natural gas on the site of CL&P’s South Meadow facility in Hartford. The siting of these five 40 MW units was authorized by the Council on May 9 and May 21, 1996. They were installed and operational by the 1996 summer peak period. The cool summer of 1996 offset the need for these facilities; however, Connecticut could experience a capacity deficiency for the summer of 1997 if the State’s peak exceeds 5,750 MW; emergency relief fails to produce 669 MW of load reduction; existing facilities are unable to generate 3,660 MW of in-state generation not including 2,630 MW lost from the Millstone units or 560 MW (summer rating) lost from the retired Conn Yankee unit; and the transmission grid experiences contingency situations that reduces power-import capability below 2,520 MW. With these supply and demand resources in place, Connecticut will have a thin margin of 1,519 MW to meet peak demand. However, this scenario is speculative and subject to a number of variables, conditions, and expectations that can quickly change, resulting in possible brownouts and rolling blackouts.
Furthermore, the New England region shares the responsibility for system reliability with Connecticut through NEPOOL, which may not be able to provide sufficient electricity to Connecticut or the region. NEPOOL projects a regional summer net peak load of 21,400 MW. With capacity resources of 24,053 MW, 4,481 MW allocated to operating reserve requirements and typical forced outages, and with net emergency Nepex Operating Procedure No. 4 measures in operation; 1,792 MW of reserve capacity is left to cover unexpected outages. This projection assumes Millstone Point and Maine Yankee are temporarily out of service. However, a capacity deficiency may occur if additional generation is lost, Maine Yankee remains out of service for an extended period or is retired, peak loads occur at levels higher than projected, and less than 3,400 MW capacity is imported into the region. This situation could be relieved when Seabrook returns to full operation from refueling in June. The regional capacity situation would be greatly improved with the return of the Millstone units by the end of 1997 and early 1998.
While the State’s utilities’ response to the continued shutdown of the Millstone units, as modeled in Appendix B, has been justified and appears appropriate, questions remain regarding the shutdown of these nuclear facilities. The direct costs of this shutdown will include accelerated plant rehabilitation, facility installation, and replacement power and has been estimated to cost in the hundreds of millions of dollars. Indirect costs include the disruption to the State’s electric supply system created by a few large, inactive nuclear generation facilities. In order to return the Millstone nuclear units to service, NU and the NRC have agreed upon a “Significant Items List” which, when completed, would provide the basis for the NRC Commissioners’ approval to restart. NU plans for Millstone 3 to be returned to active service by December 1997 and Millstone 1 and 2 activated later in early 1998.
As shown in Figure 1, and Appendix A, the Statewide generation fuel mix for 1996, under normal operating conditions is weighted toward nuclear and oil usage. The generation mix has most recently changed by the retirement of CL&P's Conn Yankee facility in December 1996. By year 2016, nuclear capacity from Conn Yankee, Millstone 1, and Millstone 2 will likely be replaced with natural gas units. However, there are no precise plans at this time by utilities for new supply facilities to permanently replace the 3,251 MW of nuclear capacity that will ultimately be lost from the State’s capacity. Nuclear capacity, which accounted for 45 percent of the State’s capacity, has already been reduced by the retirement of Conn Yankee (583.2 MW, 8.1 percent of the State’s total capacity) and will be affected by indefinite suspension or retirements of Millstone 1 (647.7 MW, 9.0 percent of the State’s total capacity, scheduled to retire in 2010); Millstone 2 (874.5 MW, 12.1 percent of the State’s total capacity, scheduled to retire in 2015); and Millstone 3 (1,145.7 MW, 15.9 percent of the State’s total capacity, scheduled to retire in 2025).
CHART (Omitted)
- Assumes Conn Yankee is decommissioned.
- Assumes other nuclear units are retired according to schedule, existing active generators are operating and licenses renewed, English Station units 7 and 8 are reactivated, existing contracts with private power producers are extended, and temporary units reactivated or installed in 1996 are deactivated.
- Excludes 203 MW from Devon and South Meadows gas turbine units temporarily installed in 1996. Includes 2,105 MW of future, gas-fueled units replacing nuclear generation retired before 2016.
- Includes diesel, jet fueled, and units with dual oil/gas fuel capability.
- Includes refuse, wood, methane, tires, and fuel cells.
With nuclear facilities subject to unknown shutdowns and Connecticut scheduled to lose almost half of its current generating capacity by 2025, energy planners will be forced to consider technology, timing, fuel sources, and the public oversight needed to replace this generation. Issues will include safety, long-term reliability, environmental compatibility, need, and cost. In addition, if cost of facility operation and maintenance, and disposal of radioactive waste escalate, decommissioning or indefinite shutdown of the Millstone units could occur before scheduled dates, hastening the time when replacement generation will be needed.
Normal construction lead times for new electric generation facilities range from approximately two to five years, as shown in Table 1.
TABLE 1
New Facility Construction Lead Times and Costs
1996
Lead Time Installation Cost
(yrs.) (7/96 $/kW)
Combustion Turbine1 2.6 370 Combined Cycle Natural Gas 2 3.1 522 Gassified Coal3 5.0 1,978 Fluidized Bed Coal4 4.5 1,882 Fuel Cells5 2.0 2,500
- Reflects a currently available technology with a nominal capacity of 85 MW.
-
Reflects a commercially available unit with a nominal capacity of 350 MW.
-
Reflects a commercially available unit with a nominal capacity of 500 MW.
-
Reflects a commercially available atmospheric fluidized bed coal unit with a nominal capacity of 300 MW.
-
Reflects a commercially available 200 kW phosphoric acid fuel cell.
NU’s year of need is approximately 2010, which is one year earlier than was forecasted last year. CL&P’s year of need is forecast on a system-wide basis because it is part of the NU system that includes CL&P, Public Service Company of New Hampshire, Western Massachusetts Electric Company, and Holyoke Water Power Company. Although not needed for capacity, NU’s application before the Council to construct a 200 kilowatt (kW) fuel cell at the Groton landfill in Groton, Connecticut, was approved by the Council on January 23, 1996. This unit became operational on July 15, 1996, and is being used to test, determine, and improve the applicability and reliability of fuel cell technology.
UI does not anticipate a need for new generating capacity until 2009, which is five years earlier than last year’s forecast. This forecast includes the permanent reactivation of Bridgeport Harbor Station unit 1 and English Station units 7 and 8, in the year 2000, for a total addition of 160 MW of capacity generation. If for some reason these units are not reactivated, UI may experience a shortage of installed capacity under NEPOOL’s proposed amended agreement by the summer of 2001. Currently, UI, with two partners, has proposed the construction of 520 MW of new, combined cycle natural gas-fired generators to replace 84.7 MW of an old oil-fired unit at Bridgeport Harbor Station.
Without CMEEC’s contracted share in idled nuclear plants, CMEEC’s year of need is 1998, a change from the reported year of need of 2002 in last year’s forecast. Although CMEEC has not proposed new generating facilities, CMEEC has reactivated Wallingford’s existing idled Pierce Station in 1996 for an additional 15 MW of peaking power in cooperation with CL&P to increase the availability of capacity in Connecticut during extended outages of the Millstone units. Pierce Station had been taken out of service and was in the process of being retired prior to this reactivation.
NUCLEAR POWER
Although nuclear power was rejected at an early stage as a new supply option, it offers unique benefits and constraints that must be fully considered in the planning process. By releasing no sulfur oxides, nitrogen oxides, or carbon dioxides, nuclear power may represent a zero-air emission generation source. In fact, if CL&P were to permanently lose the contribution of all four of its nuclear facilities now operating in Connecticut, it would no longer have 1) a surplus of sulfur dioxide allowances granted under the 1990 Clean Air Act Amendments (CAAA), and 2) possible future emission allowances being considered for CAAA. Nonetheless, there remain issues of scheduled and unscheduled outages; nuclear waste storage, transport, and disposal; public safety; and facility costs.
At this time no permanent, high-level radioactive waste disposal site is available for spent-fuel rods. With the completion of reracking activities, Connecticut’s Millstone nuclear facilities are expected to be able to operate throughout the end of their license periods, managing the full content of their respective reactor cores at on-site spent-fuel pools.
Connecticut’s primary method for management of low-level radioactive waste is to transport such waste out-of-state. However, the status for long-term access to a low-level radioactive waste disposal site in Barnwell, South Carolina, and the Envirocare facility in Utah is uncertain for long-term disposal. Physical burial capacity at the Barnwell facility is currently projected at 18 to 20 years. As a contingency, NU has the ability to temporarily store low-level radioactive waste at its nuclear sites for approximately five years. NU is continuing to work on a program to reduce the volume of low-level radioactive waste to extend the life of its storage facilities. In addition, existing low-level radioactive waste management methods, including retrievable storage techniques, are being investigated for their technological, economical, and political merits.
Decommissioning for Conn Yankee began in January 1997, and is expected to be completed by the year 2003. Decommissioning for all three of the reactors at Millstone Station is expected to begin when their licenses expire and be completed by the year 2033. Estimated costs for decommissioning the nuclear units are: Conn Yankee, $340 million (1993 dollars); Millstone 1, $361.2 million (1996 dollars); Millstone 2, $320.1 million (1996 dollars); and Millstone 3, $426.7 million (1996 dollars).
FOSSIL FUEL GENERATION
Coal
Fossil fuels including coal, petroleum, and natural gas make up the largest remaining portion of the State's electric fuel supply mix. Coal is more available than oil and natural gas, with current world reserves totaling over 200 years based on the world's 1994 consumption levels. Despite this apparent benefit of supply, coal is not immediately being considered as a supply-side fuel due largely to the relative expense of installation costs, and to the concern for control of unhealthful air emissions, including possible future carbon dioxide regulations. However, with the United States in possession of approximately 24 percent of world's current estimated total recoverable coal, it may be a fuel supply option that will not be ruled out of future forecasts.
Crude Oil
New crude oil-based generation has been largely ruled out for future new supply due in part to the historic and potential volatility of the crude oil market. The United States holds an estimated two percent of the world’s known oil reserves expected to last 41 to 45 years based on 1994 consumption levels.
Approximately 60 percent of the United States’ oil is imported, making the United States’ supply of crude oil potentially vulnerable to market manipulation by foreign nations. Although the current price of oil is low when compared to other fuel types, Connecticut utilities have made an attempt to diversify their fuel mix away from crude oil. On a nationwide basis, crude oil contributes to less than 2.2 percent of the kilowatt hours sold. However, as shown in Figure 1, the State’s capacity relies on crude oil for approximately 44 percent of the current overall State fuel mix.
Natural Gas
Natural gas is expected to be the fuel used for electric generation to meet sulfur dioxide standards and other limitations set by the CAAA. Although natural gas has become more available, current reserves are anticipated to last for the next 65 years at 1994 consumption levels. Furthermore, the majority of world resources are controlled by OPEC and countries in the former Soviet Union. Although new sources of natural gas and more efficient ways of extracting it may expand supplies, increased usage of this finite resource must be carefully planned to avoid ill-fated long-term dependence. While natural gas is considered attractive for new generation, generation facility location, size, and function remain to be determined. Additionally, it is less clear if natural gas generation will be able to economically meet future carbon dioxide and nitrogen oxide CAAA standards and how competition for natural gas by non-utility users will affect the supply of natural gas to fuel electric facilities.
HYDROELECTRIC GENERATION
Connecticut's hydroelectric generation including pumped storage facilities consist of approximately 165 MW from 29 facilities. Hydro-power, long considered to be an environmentally acceptable source of power, has recently come under increased scrutiny by environmental advocacy groups, whose concerns include the effects of dams on water quality, fish population, and wildlife habitats. Consequently, while hydro-power may be considered a clean and renewable energy source, development of any additional large units in Connecticut would likely be limited by these constraints and relative cost.
NU and UI receive approximately 190 MW (winter rating) from the Hydro-Quebec project Phase I and an additional 279 MW (winter rating) from Phase II, with CMEEC receiving approximately 10 MW (winter rating) from both Phase I and II. The State’s utilities will lose their Hydro-Quebec contribution obtained through NEPOOL just after the turn of the century when their various contracts with Hydro-Quebec expire. If the currently available 1,200 MW contracted to NEPOOL from Hydro-Quebec continues to be available for sale, each utility will have the option to individually establish new contracts with Hydro-Quebec based on cost, availability, reliability, the application of environmental factors, and political factors in light of the recent resurgence of the Quebec separatist movement.
PRIVATE POWER PRODUCERS
There are 32 private power facilities operating in the State with a total capacity of 564.06 MW, representing eight percent of the State’s overall fuel mix. Of these, eight are cogeneration facilities totaling approximately 341 MW of capacity with units ranging in size from 0.15 MW to 181.0 MW.
In September 1995, the 54 MW O’Brien gas cogeneration facility in Hartford ceased operation six years after completion of construction and 15 years before the end of its operating contract. Reasons for closing the facility include lower than expected efficiency, relative high cost to generate electricity when compared to other facilities, and salvage value of the plant for operation in other locations.
In Connecticut, cogeneration facilities use oil, natural gas, and coal to simultaneously produce diversified electricity and process steam. Waste fuels, including refuse and waste tires, are currently used by non-utility generators in seven facilities. The resource recovery facilities are diversified, privately operated, and contribute 168.2 MW, representing approximately 2.3 percent of the State’s overall fuel mix for electric generation. Because the source of this fuel is limited and affected by environmentally prudent reuse, reduction, and recycling programs, new facilities of this type are few, with plans for future development limited to fuel cells and engines powered by methane gas generated at landfills and waste water treatment plants.
The costs for these unique privately-operated facilities were intended to be borne by the private sector developers of these projects. However, electric purchase agreements have been scrutinized recently for expensive rates that may unnecessarily burden electric customers and place the electric utility at a competitive disadvantage with competing sources of electric generation. Nonetheless, additional new privately-owned generation might still be installed at customer sites seeking to self-generate or wheel electricity to other users.
FUTURE TECHNOLOGIES
Future sources of utility generation from renewable energy sources such as wave motion, tidal power, ocean thermal gradient, and geothermal power are in various stages of development with research focusing on cost-effectiveness. However, these energy sources are not technically available or currently feasible for Connecticut and the utilities would only consider these options once they became available, economical, and environmentally prudent for utility generation.
Future technology generation sources that appear much closer to being economically prudent for utilities to use are fuel cells, wind turbines, and photovoltaic technologies. Fuel cells are diversified and can be placed near load centers. Currently there are three main types of fuel cells being developed for electric utility use: phosphoric acid, molten carbonate, and solid oxide. International Fuel Cells, a United Technology Corporation subsidiary, and Energy Research Corporation of Danbury, Connecticut, have fuel cells in operation or in development ranging in size from 20 kW to 200 kW. The smaller fuel cells might provide a significant environmental benefit by using methane gas from waste water treatment facilities and from landfills, as is currently used at the 200 kW unit installed by NU in July 1996, in Groton, Connecticut. Larger fuel cell units might provide both thermal energy and clean, abundant, and cost-effective electricity generated from natural gas and other sources of hydrogen some time in the near future.
Wind turbines would need to be placed in windy areas, as along Long Island Sound and hilltop areas. Consequently, the siting of these facilities could potentially compromise the preservation of scenic resources in Connecticut. Additionally, potential effects on migratory bird species would have to be considered in developing large wind turbine generators. There are no known plans to develop any wind turbines for utility generation in the State.
Various solar technologies have become more efficient. Nevertheless, large solar power generation for utilities would occupy a large area to achieve significant generation output. In addition, Connecticut has limited solar exposure for much of the year. However, both passive and active solar power systems are likely to remain an important decentrally-located energy supply source to reduce electric usage.
RETAIL ACCESS
Pursuant to Special Act 95-15, the Connecticut Task Force for Restructuring the Electric Industry was established to examine electric industry restructuring and related policy issues. The task force identified the cost components of electricity and assessed which of these costs could be reduced or changed in order to reduce Connecticut’s cost of electricity without sacrificing system reliability.
In its final report, as submitted to the Connecticut Legislature in December 1996, the task force presented a comparison of other electric industry models, defined key principles for a restructured industry in Connecticut, and made recommendations for legislative action. Legislative action was proposed through substitute Bill No. 6774; however, this bill unexpectedly died during the 1997 session and future legislation will be necessary to deregulate the electric industry. As a consequence of future restructuring legislation, the Council’s jurisdiction and statutory decision criteria may be modified to provide uniform treatment between utilities and private power producers so that a full range of environmental and economic effects can be appropriately considered for new generation facilities.
In addition, the movement toward assuring electric consumers low-priced, reliable electric service through deregulation and retail competition continues at the federal level. The 105th U.S. Congress has introduced several electric industry restructuring bills in both the House and Senate. The issues that have been pursued include State pre-emption and jurisdiction, stranded costs, securitization, taxes, market power, subsidies, renewable energy sources, and utility divestiture of generators.
TRANSMISSION SYSTEM
Connecticut’s electric system consists of approximately 1,300 circuit miles of 115-kV, 392 circuit miles of 345-kV, 5.8 circuit miles of 138-kV, and 164 circuit miles of 69-kV lines. While much of the State’s electric transmission infrastructure is already developed, the electric utilities maintain the system and expand where needed to serve load centers. As shown in Table 2, the majority of construction is planned to rebuild or reconductor existing lines to increase each line’s capacity. In addition, the utilities seek transmission and substation upgrading to improve system reliability, promote efficiency, and reduce energy losses.
TABLE 2
Planned Transmission Lines
Length Planned Date of
(Miles) kV Completion
1. Grand Avenue S/S, New Haven to West River S/S, New Haven
(upgrade of the existing high pressure fluid-filled cables) (UI) 2.6* 115 1999
2. Baird S/S, Stratford to Congress Street S/S, Bridgeport
(Rebuild) (UI) 2.5 115 2004
3. Cook Hill Jct., Cheshire to Wallingford Jct., Wallingford
(Reconductor) (CL&P) 2.9 115 1997
4. Hosley Railroad S/S, Branford to Line #1460, Branford
(New) (CL&P) 0.2 115 1998
5. New London Railroad S/S, New London to Line
#1500, New London (New) (CL&P) 0.9* 115 1998
6. New London Railroad S/S, New London to Line #1605, New London
(New) (CL&P) 0.9* 115 1998
7. Compo Substation S/S, Westport to Line #1130, Westport
(Rebuild) ( CL&P) 0.1 115 1997
8. Manchester S/S, Manchester to Wapping Jct., South Windsor
(Rebuild) (CL&P) 5.1 115 2001
9. Farmington S/S, Farmington to Newington S/S, Newington (Rebuild)
(CL&P) 3.6 115 2005
10. Wapping Jct., South Windsor to Barbour Hill S/S, South Windsor
(Rebuild) (CL&P) 2.4 115 2005
*Underground
Although private power producers in the State have not created transmission power flow problems, future private power projects may do so, depending on their size and location. In addition, there are limits to the aggregate amounts of private power capacity which the existing transmission system can accommodate. If such private power facilities continue to be added, transmission line and substation reinforcements might be necessary. Additionally, continued transmission line and substation upgrades might also become a significant planning issue in the event that new generation is added or energy paths are rerouted as a consequence of retail wheeling.
Recently, transmission lines have received increased scrutiny by groups concerned about the possible effects of electric and magnetic fields. Although the current results of the science are conflicting and not conclusive, there is interest in reducing electric and magnetic field levels with alternative technologies, such as underground transmission lines or alternative line configurations. To qualify and quantify the costs of these alternatives, Public Act 94-176 authorized the Council to begin investigation of life-cycle costs for both overhead and underground transmission line alternatives. This investigation began in October 1994, with the Council’s final report released August 1, 1996.
Distribution voltage substations in the State have been reduced in the past 10 years as a result of wide-spread conversion of distribution feeders to a higher voltage to reduce line losses, increase circuit capacity, and improve area reliability. As shown in Table 4, five new bulk power substations to reduce high-voltage transmission to lower voltage might be needed in the State by the turn of the century. As this trend continues, the siting of these facilities might become more involved and complex.
TABLE 4
Planned Bulk Substations
Planned Date of Completion
-
Installation of new Meadowbrook S/S, Hamden (UI) Beyond 2006
-
Installation of new Trumbull S/S, Trumbull (UI) Beyond 2006
-
Installation of new Hosley Road S/S, Branford (Amtrak/CL&P) 2000
-
Installation of new New London Railroad S/S, New London (Amtrak/CL&P) 2000
-
Installation of new Northford S/S, Wallingford (CMEEC) Uncertain
Because the development of both new transmission and substation facilities might be considered undesirable by local communities, utilities must assess supply locations, load center demands, and the need for new or upgraded facilities far in advance of actual construction. In some cases, unplanned bulk substations like the Compo Substation in Westport, Connecticut in 1996, may be developed during the forecast period to improve local reliability. Although the Council has rejected the concept of facility pre-licensing, the Council has supported an integrated system approach to accommodate the construction of new and upgrading of existing facilities when needed.
CONCLUSION
These forecasts have modeled Connecticut’s electric energy future for the next 20 years and show adequate supply to meet demand. Nonetheless, these forecasts are models that are based on assumptions that are subject to change. While these forecasts are useful to develop plans, there is uncertainty, never more obvious than at present, with the three Millstone nuclear units rendered idle by the NRC’s decision to suspend operations pending the outcome of its investigation into operating procedures at the three facilities. Not only can these unexpected changes substantially influence long-range forecasts, but they can affect the State’s air quality and reliance on certain fuels. The key is to use these models not as a tool to merely predict the future, but to increase learning curves and to identify prudent, flexible, and effective strategies and techniques to obtain desirable goals. Issues that warrant attention include emergency contingency planning, system reliability and cost containment, retail access to the electric grid, the allocation of C&LM and public policy costs now borne by the electric utility customers, responding to a slow and changing economy that has proven difficult to predict, long-term acquisition of politically volatile fuel supplies, and managing loads for both overall demand and peaks with efficient and reliable energy. In addition, market mechanisms need to be assessed to determine if there is sufficient incentives to ensure an adequate supply of generation and demand-side resources to provide reliable service.
While the strategies to resolve these issues may be difficult and complex, this forecast provides information for rational decision making. Because this analysis has been well received by the public and other participants of the proceeding, it is expected that this process to publicly review energy forecasts will continue in cooperation with the Department of Public Utility Control, the Department of Environmental Protection, the Office of Policy and Management, and the Connecticut State Legislature.
Appendix A
Connecticut Based Generation
1996
Base
Facility Location Fuel Winter Rating (MW) % of Total MW
Millstone 1 Waterford Nuclear 647.70 9.23
Millstone 2 Waterford Nuclear 874.50 12.46
Millstone 3 Waterford Nuclear 1,145.70 16.32
Conn. Yankee Haddam Nuclear 0 1
Bridgeport Harbor #2 Bridgeport Oil 170.00 2.42
Bridgeport Harbor #3 Bridgeport Coal 385.00 5.48
New Haven Harbor New Haven Oil 447.00 6.37
BASE SUBTOTAL 3,669.90 52.28%
Intermediate
Devon #7 Milford Oil/Gas 109.00 1.55
Devon #8 Milford Oil/Gas 109.00 1.55
Middletown #2 Middletown Oil 120.00 1.71
Middletown #3 Middletown Oil 245.00 3.49
Middletown #4 Middletown Oil 400.00 5.70
Montville #5 Montville Oil/Gas 82.00 1.17
Montville #6 Montville Oil 410.00 5.84
Norwalk Harbor #1 Norwalk Oil 164.00 2.34
Norwalk Harbor #2 Norwalk Oil 172.00 2.45
INTERMEDIATE SUBTOTAL 1,811.00 25.80%
Peaking 2
Cos Cob #10 - #12 Greenwich Oil 68.50 0.98
Devon #10 Milford Oil 19.20 0.27
Devon #11 Milford Gas/Oil 40.37 3 0.57
Devon #12 Milford Gas/Oil 40.07 3 0.57
Devon #13 Milford Gas/Oil 41.03 3 0.58
Devon #14 Milford Gas/Oil 41.82 3 0.60
Middletown #10 Middletown Oil 19.20 0.27
Montville #10 & #11 Montville Oil 5.50 0.08
South Meadow #11-#14 Hartford Oil 195.60 2.79
South Meadow #15 Hartford Gas/Oil 40.00 3 0.57
Bridgeport Harbor #4 Bridgeport Oil 22.00 0.31
Norwich Norwich Oil 18.38 0.26
So. Norwalk Electric
Works (SNEW) #1-6 South Norwalk Oil 16.67 0.24
Franklin Drive #19 Torrington Oil 18.25 0.26
Torrington Terminal #10 Torrington Oil 21.80 0.31
Tunnel #10 Preston Oil 20.80 0.30
Branford #10 Branford Oil 18.80 0.27
PEAKING SUBTOTAL 647.99 9.23%
Conventional Hydro
Bantam #1 Litchfield Hydro 0.32 4
Bulls Ridge #1- #6 New Milford Hydro 8.40 0.12
Falls Village #1- #3 Canaan Hydro 11.00 0.16
Robertville #1- #2 Colebrook Hydro 0.62 4
Scotland #1 Windham Hydro 2.20 0.03
Shepaug #1 Southbury Hydro 43.40 0.62
Stevenson #1- #4 Monroe Hydro 28.90 0.41
Taftville #1- #5 Norwich Hydro 2.03 0.03
Tunnel #1- #2 Preston Hydro 2.10 0.03
Farmington River Windsor Hydro 9.45 0.14
Norwich 10th St. Norwich Hydro 1.25 0.02
Norwich 2nd St. Norwich Hydro 0.53 0.01
Occum Norwich Hydro 0.80 0.01
HYDRO SUBTOTAL 111.00 1.58%
Pumped Storage
Rocky River New Milford Hydro 30.35 0.43
PUMPED SUBTOTAL 30.35 0.43%
Fuel Cell
Groton Landfill Groton Methane 0.20 4
FUEL CELL SUBTOTAL 0.20 4
Private Power Producers
Pfizer 5 Groton Oil 25.00 0.36
AES Thames 5 Montville Coal 181.00 2.58
C. H. Dexter 5 Windsor Locks Gas 39.00 0.56
Capitol District 5 Hartford Gas 58.28 0.83
G. Fox 5 Hartford Gas 4.10 0.06
Hartford Hospital 5 Hartford Gas 10.15 0.14
Pratt & Whitney 5 E. Hartford Gas 23.80 0.34
Colebrook Colebrook Hydro 3.00 0.04
Dayville Pond Plainfield Hydro 0.10 4
Derby Dam Shelton Hydro 7.05 0.10
Glen Falls Moosup Hydro 0.25 4
Goodwin Dam Hartland Hydro 3.29 0.05
Kinneytown A Ansonia Hydro 0.40 4
Kinneytown B Seymour Hydro 1.50 0.02
Mechanicsville Thompson Hydro 0.27 4
Putnam Putnam Hydro 0.25 4
Quinebaug Danielson Hydro 2.81 0.04
Rocky Glen Newtown Hydro 0.11 4
Toutant Putnam Hydro 0.40 0.01
Willimantic A Willimantic Hydro 0.90 0.01
Willimantic B Willimantic Hydro 0.90 0.01
Wyre Wynd Jewett City Hydro 2.60 0.04
New Milford New Milford Methane 2.59 0.04
Shelton Landfill Shelton Methane 2.00 0.03
Bridgeport RRF (CRRA) Bridgeport Refuse 57.00 0.82
Bristol RRF Bristol Refuse 13.20 0.19
Mid-CT RRF (CRRA) Hartford Refuse 63.71 0.91
Preston RRF (SCRRRA) Preston Refuse 13.85 0.20
Riley Energy Systems Lisbon Refuse 13.50 0.19
Wallingford RRF (CRRA) Wallingford Refuse 6.90 0.10
Exeter Sterling Tires 26.00 0.37
Pinchbeck5 Guilford Wood 0.15 4
PRIVATE POWER PRODUCER SUBTOTAL 564.06 8.04%
SUBTOTAL 6,834.50 97.36%
Temporary Reactivated Generators
Middletown 1 Middletown Oil 73.00 1.04
Bridgeport Harbor 1 Bridgeport Oil 84.70 1.21
Norwalk Harbor 10 Norwalk Oil 11.82 0.17
Pierce Wallingford Oil 16.00 0.22
REACTIVATED GENERATORS SUBTOTAL 185.52 2.64
TOTAL 7,020.02 100%
- Conn Yankee (583 MW) was retired December 1996
- Oil includes diesel and jet fueled units
- Temporary installation with dual-fuel capability
- Less than 0.01 percent
- Cogeneration Facilities