You asked for a discussion of measures the state can take to reduce electric costs and give it greater control over its energy future.

SUMMARY

This report discusses five options that have been under discussion in the past year: (1) using integrated resources planning in meeting the state's electricity needs, (2) broadening the ability of the electric utilities to own power plants and other generation resources, (3) providing further incentives for non-utility generation resources, (4) creating a state power authority, and (5) reducing taxes on electricity.

These options are not mutually exclusive and all of them could potentially reduce, or at least stabilize, electric costs in the medium to long-term. Utility-owned generation and the creation of a state power authority could give the state greater control over its energy future, as could use of integrated resources planning. The impact of the generation options on rates and the state's control of its energy future depend on (1) the amount of generation built, (2) the types of generation that is built, (3) where it is located, and (4) when it goes into service.

All of these options have costs, and several have substantial risks. If the state does not have enough resources (including demand side resources such as efficiency programs) to meet its demand growth after implementing one or more these options, electric costs are likely to rise. Currently, peak demand in Connecticut is approximately 7,600 megawatts (MW) and peak demand is growing by about 2% (150 MW) per year. Conversely, if the state over-invests in generation resources, or invests in the wrong types of resources, ratepayers or taxpayers could bear the burden for decades. If the state takes no action to address the imbalance between supply and demand, it could face a risk of brownouts or blackouts, perhaps as early as the summer of 2007.

Moreover, none of these options, with the possible exception of tax reductions, would have any effect on costs during the first half of 2007. This is because Connecticut Light and Power (CL&P) and United Illuminating (UI) have already bought all of the power they will need for this period. Similarly, none of the options would have a substantial effect in the second half of 2007, because the utilities have already bought most of the power they will need for this period (70% in the case of CL&P and 66% in the case of UI).

Finally, so long as the state and the rest of New England rely heavily on natural gas and oil to generate power, the price of electricity in the state and region will continue to be affected by changes in the prices of these fuels. (Currently, 60% of the generating capacity in Connecticut and in New England uses these fuels. ) The price of oil, and increasingly natural gas, are set on global markets that are beyond the state's ability to control.

INTRODUCTION

Connecticut's electric rates are currently among the highest in the country. This was also the case before the passage of PA 98-28, which restructured the electric industry to permit competition.

Several factors have led to these high rates, including:

1. aggregate electricity demand exceeding supply, particularly during peak periods;

2. increasing generating fuel costs, particularly for natural gas and oil;

3. the state's reliance on purchasing power on the New England wholesale market, whose rules allow some generators to charge rates that at times substantially exceed their costs of producing power; and

4. congestion on the transmission system, which has limited the state's ability to import less expensive power from other states.

In addition to these factors that affect electric rates, the cost to consumers has increased due to the growth in consumption of individual customers. (Electric costs are basically rates multiplied by consumption. ) In New England, average residential consumption per household grew by approximately 10% since the passage of PA 98-28, according to the Independent System Operator-New England. The increase is attributable to increased use of air conditioning, among other things.

Two components of electric rates are likely to decrease in the next few years in any case. First, federally mandated charges associated with congestion on the transmission system currently account for about 15% of the average residential customer's monthly bill. The Department of Public Utility Control (DPUC) believes these charges will fall significantly as the Norwalk-Stamford and Norwalk-Middletown transmission lines are completed in 2008 and 2009, respectively. Second, the competitive transition assessment, which accounts for approximately 5% of the average residential bill, will decline as the utilities' stranded costs are paid off. These are costs, primarily for power plants, that had previously been approved by DPUC but whose continued recovery was jeopardized with the advent of competition.

INTEGRATED RESOURCES PLANNING

The Energy and Technology Committee is considering several proposals to establish a planning process that would identify the state's long term power needs and the best ways to meet these needs. The planning process would involve the electric utilities, other market participants, consumer representatives, and other interested parties. The participants would consider a wide range of potential resources, including efficiency programs and new generating plants (including those needed to meet peak as well as baseload demand). In developing the plan, the participants would be required to consider such factors as fuel diversity and environmental impacts as well as the plan's impact on rates. The proposals vary in terms of the specifics of the planning process, how frequently the plan would be developed, who would approve the plan, and how it would be implemented.

Proponents of this approach believe that creating such a planning process could promote a number of policy goals. These include reducing rates and rate volatility and increasing the diversity of fuels used to generate power for state consumers. This approach could also give the state greater control over its energy future, for example by requiring that utilities invest in all cost-effective efficiency programs as identified by the participants in the planning process.

There appears to be a consensus that integrated resources planning could benefit ratepayers. However, past history suggests that this approach has some risks. In an earlier version of integrated resources planning, the state required the electric utilities to buy power from cogeneration and renewable energy facilities owned by non-utility generators. The state required the utilities to enter into long-term contracts with these generators at the utilities' avoided costs. This was the projected cost of fuel and other utility operating expenses that the utility would avoid by buying power rather than generating power at its own plants. In a number of cases, the projected costs were substantially higher than the utilities' actual operating costs. Ratepayers have continued to pay the difference, which accounts for a substantial part of the utilities' remaining stranded costs. It is possible that projections made in an integrated resources plan could suffer from similar miscalculations, exposing ratepayers to long-term risks.

UTILITY OWNERSHIP OF GENERATION

PA 98-28, in effect, required the electric utilities to sell off their generation assets and current law only allows them to own power plants under limited circumstances. PA 05-1, June Special Session, required DPUC to issue a request for proposals (RFP) to reduce federally mandated congestion charges. It allowed (1) utilities and others to submit proposals to build new power plants, among other measures, in response to this RFP; and (2) DPUC to approve proposals that reduced these charges.

The utilities are subject to several restrictions that do not apply to other potential bidders. Among other things, (1) a utility must demonstrate to DPUC that its proposal is not being subsidized by its corporate affiliates; (2) DPUC can approve no more than 250 MW of utility-owned generation statewide (about half of the generating capacity of a typical power plant); and (3) if DPUC approves a utility proposal, the utility must sell off the plant or the power it generates five years after the plant went into operation, although DPUC must waive this requirement if it finds that compliance would harm the utility's customers. CL&P and UI have chosen not to submit proposals under the act.

Proponents of this option argue that allowing the utilities to re-enter the generation market under less restrictive circumstances would benefit ratepayers. They claim that utility ownership of 500 MW of generation (the size of a typical power plant) could reduce federally-mandated congestion charges by $ 70 million over five years. They base this estimate on the utility's lower cost of capital compared to that of non-utility generators.

Proponents of utility-owned generation also argue that this would give the state greater control over its energy future. The current owners of power plants in the state operate solely in the wholesale market. As a result, they fall under the jurisdiction of the Federal Energy Regulatory Commission, rather than the DPUC. The state cannot (1) force these generators to build new plants or locate plants in specified areas; (2) determine the types of plants that will be built (e. g. , plants that meet peak demand vs. baseload plants that operate most of the time); or (3) regulate the rates charged for power produced from the plants that the generators operate. In contrast, the state would have this authority with regard to plants built or purchased by the electric utilities that DPUC regulates.

The impact of this and other generation options on rates and the state's control of its energy future depend on (1) the amount of generation built, (2) whether this generation is designed to meet peak loads or run most of the time (peakers vs. baseload plants), (3) where the generation is located, and (4) when the generation goes into service. There are differing views as to how much new generation the state needs, and how much of this generation should be peakers. Locating generation in the southwestern third of the state would help reduction congestion related costs. Building generation before 2010 would help avoid costs by preventing the state being treated as a separate zone for wholesale pricing purposes.

However, allowing the utilities to re-enter the generation market could expose ratepayers to several risks. Ratepayers would be required to pay for overruns in the cost of building new utility plants if these costs were not due to the utility's imprudence. Ratepayers would also have to pay for the plants' capital costs even when they were not running, again assuming that this was not due to the utility's imprudence. Potentially, allowing utilities in the generation market could discourage non-utility generators from entering this market, because it would add to their economic uncertainty.

STATE POWER AUTHORITY

A state power authority could be allowed to purchase power on behalf of Connecticut consumers, and to finance, build, buy, and operate power plants. The authority could serve as a “builder of last resort” if the private market was unable or unwilling to build sufficient generation capacity.

Potentially, an authority could build or finance plants for less than private market. This is because could issue tax-exempt bonds and thus its cost of capital could be lower than utility or non-utility generators. As a result, the authority's plants might be able produce power less expensively than plants built by private market generators. The authority could also buy power directly from generators, avoiding the marketers who currently serve as middlemen in the utilities' procurement of power. This could reduce the cost of power, particularly if the authority bought power under long-term contracts. Current law does not preclude generators from bidding directly to supply the utilities, but none chose to bid in the last procurement round.

The creation of an authority could increase the state's control over its energy future in the same way as allowing utility-owned generation could. It could take a longer term perspective than either utility or non-utility generators, for example investing in renewable energy projects that have relatively long payback periods but that advance the state's environmental goals. Moreover, the state could use the relatively inexpensive power produced at the authority's plants for economic development purposes, as the New York State Power Authority currently does.

While power authorities have economic advantages over private market generators, they can make blunders that expose ratepayers and potentially taxpayers to risks. In the 1970s and 1980s, the Washington Public Power Supply System experienced huge cost overruns in building five nuclear power plants. In 1982, the system's board stopped construction on two plants when total cost for all of the plants was projected to exceed $ 24 billion. Because these plants generated no power and brought in no money, the system was forced to default on $ 2. 25 billion in bonds it had issued. More recently, the Connecticut Resources Recovery Authority lost approximately $ 220 million in a failed deal with Enron (the state was subsequently able to recover approximately half of this amount). If a state power authority's bonds were backed by a Special Capital Reserve Fund, taxpayers ultimately could bear the risk of poor decisions by the authority.

PROVIDING INCENTIVES FOR NON-UTILITY GENERATION

PA 05-1, June Special Session, provides a wide variety of incentives for the creation of new resources, including new power plants and distributed generation facilities. Distributed generation facilities are generally located on a customer's permises, and can include such technologies as cogeneration, microturbines, and fuel cells. By generating power on site, these facilities can reduce stress on the transmission and distribution system and avoid the loss of power that occurs when power is transported over this system. As discussed above, the act requires DPUC to conduct an RFP to seek a wide range of resources to reduce federally mandated congestion charges.

To date, DPUC has approved incentives for 37. 4 megawatts of distributed generation capacity, with applications pending for an additional 135 megawatts. The RFP drew initial proposals for more than 6,000 megawatts of capacity. Proposals were made for new gas- and oil-fired generation; repowering existing, retired, and deactivated generation units; demand-side reduction; and conservation and energy efficiency measures. While some of the generation proposals were alternatives for a given site, the majority of the proposed projects do not overlap.

If the current RFP does not produce enough resources to meet the state's needs, the legislature could extend or expand the incentives. For example, the legislature could expand the current RFP to solicit bids for energy, as well as generating capacity. (Capacity is analogous to an attorney's retainer, i. e. , the amount she charges to be available to a client; energy charges are analogous to the attorney's hourly rate. ) Alternatively, the legislature could require DPUC to conduct a second RFP with new incentives for energy, capacity, or both products.

Building more non-utility generation in the state would reduce capacity charges, which account for about 5% of total electric rates. But, it would only have an indirect effect on the cost of energy, which is the largest component of electric rates. Assuming that most of the new plants would use natural gas as a fuel (as most recent power plants have), the energy costs for the power from these plants would be substantially affected by the price of natural gas. The price of natural gas has been very volatile in recent years. The average national price of natural gas purchased by the electric power industry rose from $ 3. 71 per thousand cubic feet (mcf) in September 2002 to $ 11. 01/mcf in September 2005 and down to $ 7. 52/mcf in August 2006 (latest available data).

In addition, it is unclear to what extent modifying the current RFP would delay the construction of new power plants, since DPUC has already received and begun reviewing bids. If Connecticut does not bring its peak demand and resources in line by approximately 2010, it risks being treated as a separate zone for wholesale pricing purposes, which could significantly increase electric costs in the state.

TAX REDUCTIONS

The principal tax on electricity is the utility company tax. The tax is 6. 8% of an electric utility's revenues from providing transmission and distribution services to residential customers and 8. 5% of its revenues from providing these services to nonresidential customers. In addition, the 6% sales tax applies to that part of the total monthly electric bill of a nonresidential customer who not engaged in manufacturing or farming that exceeds $ 150.

The legislature could reduce these tax rates, increase the exemption level of the sales tax, or eliminate the taxes. Unlike the other options discussed in this report, the impact of a tax reduction would be immediate. The disadvantage of tax reductions is that they would cost the state revenue. For example, eliminating the utility companies tax entirely would cost the state approximately $ 120 million in revenues annually. Eliminating the sales tax on commercial customers would cost about $ 30 million per year. Moreover, the impact of tax reductions on the overall electric bill for most customers would be modest. For example, eliminating the utility companies tax would reduce the average monthly bill of Connecticut Light and Power residential customers by less than $ 3. On the other hand, eliminating both the utilities companies tax and the sales tax on commercial customers would have a substantially large impact on the bills of these customers.

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