You asked for a discussion of options open to the legislature to restrain utility rates, specifically those charged by electric companies.

SUMMARY

At least in the next several years, the legislature has little ability to substantially affect electric rates since they are primarily determined by factors that are beyond the legislature's control. These factors include the growth in electric demand vis-à-vis supply, prices of the fuels used to generate electricity, and wholesale market rules.

The Energy and Technology Committee has favorably reported two bills that could potentially reduce electric rates in the longer term. sHB 5819 creates the Connecticut Energy Authority and specifies its goals, powers, and responsibilities. The authority's goals include (1) procuring electric power and resources through competitive procurement processes to meet the needs of retail customers who choose to be served by the authority and (2) constructing and operating power plants and other generation facilities. The bill also modifies how electric companies procure power for customers who do not choose competitive suppliers, with provisions for a request for proposals (RFP) to solicit the development of energy efficiency measures, and new or expanded power plants whose rates would be set based on their cost of service, rather than at wholesale market rates.

sHB 5783 requires the Department of Public Utility Control (DPUC) to determine how much it costs coal- and nuclear-powered generating plants in the state to generate power. It requires the local electric company to offer to enter into long-term contracts to buy the power produced by these plants on a cost-of-service basis. The contracts would be subject to DPUC approval. If the plant does not enter into the contract, it becomes subject to an annual market incentive recovery charge. Each year, DPUC must determine the charge, which must be the difference between (1) what the plant earned in the year from its power generation operations, and (2) its cost of service, including a reasonable rate of return on equity. The charge must be returned to customers through a credit to the charge on monthly electric bills as approved by DPUC.

Other options the legislature could consider include:

1. expanding energy efficiency programs,

2. reducing taxes on electricity,

3. expanding the ability of electric companies to own power plants and other forms of electric generation, and

4. facilitating the construction of generation whether owned by electric companies or non-utilities.

INTRODUCTION

Connecticut's electric rates are among the highest in the country. Several factors have led to these high rates, including:

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

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

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.

In addition to these factors, 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% over the past ten years, with the increase attributable to increased use of air conditioning, among other things.

OPTIONS CURRENTLY BEFORE THE LEGISLATURE

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 at a lower cost than the private market. This is because it could issue tax-exempt bonds and thus enjoy a lower cost than electric companies 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 also would not earn the return on its investments that private generators do, allowing the authority to charge lower rates.

sHB 5819 creates the Connecticut Energy Authority and specifies the authority's goals, powers, and responsibilities. The authority's goals include (1) procuring supply- and demand-side resources (e.g., electric power and conservation savings, respectively) at the lowest cost through competitive procurement processes to meet the electricity needs of retail customers who choose to be served by the authority; (2) constructing and operating generation facilities (e.g., power plants); and (3) selling electricity at cost to electric companies. The authority's powers include (1) entering into contracts or agreements needed perform its duties and (2) employing a staff and hiring consultants.

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 power deal with Enron (the state was subsequently able to recover much 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.

Taxing Low-cost Power Generators

As noted above, the rules governing the New England wholesale market allow some generators (notably those with nuclear or coal-fired power plants) to charge rates that at times substantially exceed their costs of producing power. In the wholesale spot market, the rate is set by the marginal power plant, i.e., the last plant needed to meet regional demand in a particular hour. During daytime hours, this is usually a natural gas-fired plant. All of the plants whose bids were lower than this plant are paid the price bid by the marginal plant, even if their cost of producing power is lower than the marginal plant's. Most of the power sold in the regional market is sold under long-term contracts rather than in the spot market. However, the rates charged under these long-term contracts reflect the rates paid in the spot market.

Some legislators believe that these market rules give owners of low cost plants a windfall. They believe that part of this money should be recovered through taxes or similar mechanisms and used to reduce rates for electric company customers.

sHB 5783 requires DPUC to determine how much it costs coal- and nuclear-powered generating plants in the state to generate power. It requires the electric company serving each plant's location to offer to enter into long-term contracts to buy the power produced by these plants on a cost-of-service basis. The contracts are subject to DPUC approval.

If the plant does not enter the contract, it becomes subject to an annual market incentive recovery charge. Each year, DPUC must determine the charge, which must be the difference between (1) what the plant earned in the year from its power generation operations, including payments received under markets administered by the entity that runs the regional wholesale market and under bilateral contracts, and (2) the plant's cost of service, including a reasonable rate of return on equity, as determined by DPUC each calendar year as required by the bill. The charge must be returned to customers through a credit to the charge on monthly electric bills as approved by DPUC. DPUC must determine the

charge for each plant in a contested case in which the plant owner can participate. If the plant owner chooses not to participate in its proceeding or does not provide information to DPUC needed to determine the charge, DPUC must derive the charge using reasonable estimates.

It is not clear how these provisions comport with the Federal Power Act that govern wholesale transactions, such as between generators and electric companies. It is also unclear what effect, if any, such a tax would have on the willingness of generators to build or expand plants in the state that might be subject to the tax.

OTHER OPTIONS FOR THE LEGISLATURE

Expand Energy Efficiency Program

As noted above, part of the reason for Connecticut's high electric rates is that electric demand in the state has been growing more rapidly than supply. In addition, peak demand has been increasing more rapidly than overall demand. This increases rates, since electric companies must have the transmission and distribution capacity to meet peak demand, even if it is unused for most of the year.

For many years, Connecticut has required electric companies to develop and implement conservation programs. These programs have been successful in reducing demand. According to the Energy Conservation Management Board's 2007 report to the legislature, since 1998, electric conservation programs have resulted in demand reductions equivalent to the generating capacity of a 500 megawatt power plant. This additional capacity produced through energy efficiency is enough to power nearly 43,000 homes. The board also found that the lifetime cost of additional electrical capacity made available through energy efficiency is far less than the cost for generation by coal, oil, or gas. The board estimates that the energy savings from Connecticut's efficiency programs in 2007 will yield $776.8 million in consumer savings over the life of the measures at today's electric rates, at a cost of approximately $98 million.

While Connecticut has some of the most extensive efficiency programs in the country, they have not exhausted cost-effective measures. One of the provisions of PA 07-242 may lead to an expansion of efficiency programs. It 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. The legislature may wish to expand funding for efficiency programs, either by increasing the conservation charge on electric bills (currently 0.3 cents per kilowatt-hour) or allowing electric companies to include their long-term efficiency investments in their rate base. The latter option is analogous to using bonding rather than appropriations to pay for capital investments.

While there is a broad consensus that Connecticut has opportunities for further cost-effective conservation, energy efficiency is not without cost. Increased spending on efficiency could increase rates in the near term, although reducing rates in the longer run. Allowing electric companies to place their efficiency investments in their rate base may encourage them to invest more heavily in efficiency, but would also increase the cost of these measures since the companies would in effect earn a profit on them.

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 is 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 more than $120 million in revenues annually. Eliminating the sales tax on commercial customers would cost more than $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 $5. On the other hand, eliminating both the utilities companies tax and the sales tax on commercial customers would have a larger impact on the bills of these customers.

Utility Ownership of Generation

The law restructuring the electric industry (PA 98-28), in effect, required the electric companies to sell off their generation assets, and current law only allows them to own power plants under limited circumstances. The legislature could expand the ability of electric companies to build or buy power plants. The company-owned plants could potentially provide power at lower rates than are charged on the wholesale market, since they would charge rates based on their cost of service, which could be lower than the wholesale market rates that the companies pay for the power they currently buy.

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 for 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, (3) how the plant is fueled, (4) where the generation is located, and (5) 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 baseload plants that operate most of the time, versus plants that primary meet peak demand.

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.

Encouraging New Generation

As noted above, electric supply in Connecticut in recent years has increased more slowly than demand. A large part of this is due to instability in economics of power plant construction brought about by increasing prices for natural gas, concrete, steel and other resources, which are largely beyond the legislature's ability to affect. However, the state's regulatory climate may also contribute to the slow growth in electric supply. In addition to obtaining air and water permits and obtaining a certificate from the Siting Council, a proposed power plant must undergo an alternatives analysis under CGS § 16a-7c. Under this provision, 15 days after the Siting Council receives an application to build a power plant (and certain other energy facilities), the Connecticut Energy Advisory Board must issue a request for alternative proposals. If the board receives any proposals, it must evaluate them and submit its preferred alternative to the Siting Council. The two processes can take a total of 14.5 months. In addition to these provisions, CGS § 16a-3a requires the electric companies, in consultation with the board, to develop an annual comprehensive procurement plan. Under CGS § 16a-3b, if the plan specifies the construction of a generating facility, DPUC must issue a request for proposals for such facilities. Current law does not specify the relationship between this process and the one required by CGS § 16a-7c. (As noted above, sHB 5819 would require another request for proposal process.) The legislature may wish to better articulate the relationship between these various requirements, and perhaps simplify the process that must be followed to build new generation in the state.

Building more generation in the state would reduce capacity and congestion charges in electric rates. But, assuming that most new plants would use natural gas as a fuel (as most recent power plants have), the construction would only have an indirect effect on the cost of energy, which is the largest component of electric rates. The energy costs for the power from these plants would be substantially affected by the price of natural gas, which has been very volatile in recent years.

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