You asked for information on the status of competition in the state’s electric power industry. You also asked that we discuss options for regulating the industry in the future, including three specified options, and the implications of these options for the state.

SUMMARY

Although the state opened its retail electric markets to competition in 2000, there has been very little competition to date. Fewer than 2% of consumers have chosen a competitive supplier, and few suppliers are actively seeking new customers.

The three specified options are (1) limiting competition to larger commercial and industrial (C&I) customers, but requiring utilities to offer options to their residential and small business customers (Oregon has adopted this approach); (2) establishing a public power authority to serve consumers in the state, and (3) having the state procure power for consumers, with the utilities retaining ownership of the transmission and distribution systems. We also discuss the option of requiring utilities to engage integrated resource planning to seek the lowest cost response to the state’s electric demand. These options are not mutually exclusive.

It appears unlikely that any of these options would significantly reduce electric rates in the near or medium term future. This is because neither the state nor the utilities can control several of the principal elements of electric rates, including fuel costs and federally mandated transmission congestion costs. On the other hand, several of the options could potentially reduce electric rate volatility (the degree to which rates go up and down). Limiting competition could result in the state foregoing the opportunity to (1) reduce electric costs over the long term and (2) benefit from innovation.

STATUS OF COMPETITION

Connecticut opened its retail electric markets to competition in 2000 with the adoption of PA 98-28. However, there has been very little competition to date. The proportion of consumers choosing competitive suppliers has consistently been below 2%. Currently, approximately 20,000 of the state’s 1. 4 million consumers (1. 5%) have chosen competitive suppliers. Although the Department of Public Utility Control (DPUC) has licensed ten entities as suppliers, none is currently seeking residential customers, according to a DPUC website (http: //www. dpuc. state. ct. us/Electric. nsf/ByElectricApplicants?OpenView&Start=1&Count=30&Expand=1. 1#1. 1). Five are marketing to business customers.

While most states that have restructured their electric industries have seen few residential consumers choose a competitive supplier, Connecticut is highly unusual in that the proportion of C&I customers that have chosen competitive suppliers (less than 1%) is less than the proportion of residential customers. In contrast, the proportion of C&I customers that have chosen competitive suppliers is much higher in other states. For example, in Massachusetts 20% of medium size C&I customers and 85% of large C&I customers had chosen competitive suppliers as of September 2004.

OPTIONS

Oregon

As discussed in OLR Report 2002-R-0909 Oregon’s electric restructuring law differs from the laws in other states that have adopted deregulation in that it allows only non-residential customers to choose a supplier. At the same time, the Oregon utilities must offer residential and small commercial customers a choice of supply options at rates that are regulated by the Public Utility Commission (PUC). These customers can choose services in which (1) prices fluctuate with changes in the wholesale energy market or (2) prices reflect significant new renewable resources. The PUC must regulate these options to ensure that the rates under each option reflect the utilities' costs and risks.

The implications of Connecticut’s adoption of a similar approach largely depend on whether Connecticut would allow the utilities to acquire power plants and other generation resources. While it is not entirely clear that current law precludes Connecticut Light & Power (CL&P) and United Illuminating from owning generation resources, it appears that the utilities and the DPUC interpret the law this way. If this ban is not changed by the legislature or DPUC, it appears that adopting the Oregon model here would have little practical effect. As noted above, the utilities serve the overwhelming majority of residential consumers, and it does not appear that this will change in the near future. In compliance with PA 03-135, DPUC has authorized the utilities to offer “green” options for their customers who have not chosen competitive suppliers, and the utilities have issued a request for proposals. DPUC anticipates that winning bidders will offer one option in which all of the power comes from renewable resources and another in which half of the power comes from such sources. In early 2005, consumers will be able to sign up for this program through their utility company or directly with the winning bidders.

If the legislature adopted the Oregon model and allowed the utilities to acquire generation resources, this approach could result in lower rate volatility. Currently, DPUC has little control over key components of utility rates. These include the cost of power that the utilities purchase from wholesalers (which is sensitive to changes in fuel costs) and federally mandated transmission costs. In addition, in the case of CL&P, the bulk of its stranded costs have been securitized. This leaves little room to adjust the company’s competitive transition adjustment, which is used to recover these costs. If the utilities were allowed to own generation resources, DPUC could adjust the timing of their recovery of the cost of acquiring these resources to offset changes in the other costs of serving residential customers, e. g. , purchased power costs. This would not reduce the overall cost of electricity over the long run, but could reduce rate volatility. In addition, if the legislature adopted the Oregon approach and allowed the utilities to acquire generation resources, it could require that they engage in integrated resources planning, as discussed below.

While allowing the utilities to own generation resources could reduce rate volatility, it could inhibit competition at the wholesale level. Currently, non-utility generators such as NRG and Dominion own most of the power plants in New England. These companies only recover their investments in their plants if they compete successfully in the wholesale electric market. In contrast, electric utilities are entitled to recover, through rates, the costs of the investments they make so long as DPUC determines that they are prudent. Utilities owning generation would thus have a competitive advantage over non-utility generators, and this could inhibit wholesale competition and increase retail rates over the long term. Utility ownership of generation could also inhibit the development of distributed generation, i. e. , smaller scale generating facilities owned by C&I users. Distributed generation has the potential of providing a wide range of benefits, including decreasing stress on the transmission and distribution system, lowering customer bills, and providing high quality power to users (power quality includes such factors as harmonics, which are significant to high technology manufacturers and others).

Establishing a Public Power Authority

There are more than 2,000 public power systems in the United States, serving over 43 million people, or about 14% of the nation's electricity consumers. Most systems (including Connecticut’s six municipal utilities) are small, but there are large public power systems serving Long Island, Seattle, and parts of Los Angeles. About two-thirds of public power systems do not generate electricity, but merely distribute it to their customers. Generally, public power systems charge lower rates than comparable investor-owned utilities. Much of this difference is attributable to differences in the tax treatment of the utilities and the ability of public power systems to issue tax-exempt bonds.

The rate implications of establishing a public power authority depend, in part, on the cost of acquiring the utilities’ transmission and distribution systems compared to their book value. If the acquisition costs exceeded the systems’ book value, this would put upward pressure on rates. Conversely, rates could be reduced if the acquisition cost was less than book value. Recent efforts to municipalize systems in Chicago and San Francisco led to significant controversies on the valuation of these systems. (The city of Chicago dropped its efforts and the referendum to municipalize Pacific Gas and Electric’s San Francisco assets failed). Another factor in determining the rate effect of establishing an authority is whether it would be tax-exempt. If it was not tax-exempt, the rate benefits of creating an authority would be reduced. If it was, the state and municipalities could lose a significant amount of tax revenue.

Another major issue is whether the authority would acquire generation resources, either by purchase or condemnation. If it did not, the authority and its customers would be subject to the same price trends and volatility as other utilities. Acquiring generation resources could allow the authority to mitigate rate volatility through its choice of supply and conservation resources. On the other hand, acquiring such resources would significantly increase the costs of creating a public power system.

Apart from the rate impacts, a public power authority might be more accountable to the public than an investor-owned utility. It might make different decisions than an investor-owned utility would with regard to spending on conservation and renewable resources and on developing transmission and distribution systems. On the other hand, establishing a public power authority could lead to politicization of complex economic and engineering issues.

State Procurement

In the process of developing PA 03-135 (which modified PA 98-28), one of the utilities suggested having the state procure power, on behalf of the utilities, for customers who did not choose a competitive supplier. The utilities would continue to own their transmission and distribution system, and would be responsible for distributing power to their customers. The proposal did not contemplate the state acquiring power plants or other generation resources.

The proposal could lower rates somewhat through increased economies of scale. Rather than buying power separately for CL&P’s 1. 1 million customers and UI’s 300,000 customers, the state could purchase all of the power at one time. However, the state has very little experience shopping for power. It would have to acquire expertise in this area, either by hiring staff or retaining consultants.

It does not appear that this proposal would affect, positively or negatively, progress towards the state’s other energy policy goals. These include ensuring reliability, promoting energy efficiency and increased use of renewable resources, among other things.

Integrated Resource Planning

Under integrated resources planning, utilities or state agencies project future electricity demand and supply. Utilities then identify the least cost solution to projected shortfalls in supply, simultaneously evaluating investments in energy efficiency and energy supply. There was widespread interest in this approach in the years before states began restructuring their electric industries. Connecticut adopted several measures to promote this approach before it adopted PA 98-28. These included requiring the Siting Council to prepare long-term forecasts of electricity supply and demand (CGS § 16-50r) and requiring electric utilities to implement cost effective conservation programs consistent with integrated resource planning principles, with incentives to the utilities for such programs (CGS § 16a-49).

PA 98-28, in effect, required the utilities to divest themselves of their power plants. This substantially reduced the utilities’ ability to engage in integrated resources planning and the state’s ability to require them to do so. This is because the utilities and DPUC no longer control when power plants are built. Instead, non-utility generators make their decisions on when to build power plants based on market conditions, but are not responsible for designing and implementing conservation programs. In addition, while the Siting Council regulates where a plant can be built, the proposals are primarily based on market forces and are not integrated with decisions regarding conservation programs. Moreover these generators are subject to Federal Energy Regulatory Commission, rather than DPUC, jurisdiction. As a result, the state cannot require them to engage in integrated resource planning.

But, the state could require Connecticut utilities to engage in integrated resource planning. For example, the state could require the utilities or DPUC to project the anticipated cost of meeting the projected demand for power several years in the future by buying power on the wholesale market. The state could require the utilities to make all of the conservation investments that would cost less than purchasing this power. A variant of this approach would allow the utilities to invest in power plants or distributed generation if this was more cost-effective than buying power on the market or investing in energy conservation. A similar policy could apply to proposed investments in utility transmission and distribution systems.

A similar approach appears to be contemplated in PA 03-140. This act requires the Connecticut Energy Advisory Board to issue a request for proposals (RFP) to identify alternative solutions when the Siting Council receives an application to build a power plant or a transmission or distribution facility. The RFP must solicit, where appropriate, proposals that include energy efficiency or distributed generation. The board must evaluate each of the proposals it receives and send its results to the Siting Council. Entities responding to the RFP can submit their application to the council, which must hold a hearing on the competing applications. The council must grant a certificate to the facility that represents the most appropriate alternative, based on the law’s criteria, which primarily deal with the need for the facility and its environmental impacts. In the case of transmission lines, the proposal must also serve the interests of electric system economy and reliability.

While the act could encourage the consideration of additional alternatives to energy facilities, it appears to have several limitations. First, submitting a proposal brings the proposed facility under the council’s jurisdiction, even if was not previously, which may discourage submissions (this would primarily affect proposals to build distributed generation). Second, the act does not provide a mechanism to integrate possible alternatives that are under separate ownership. For example, it is possible that the most appropriate alternative to a proposed large power plant or transmission line project is a smaller project combined with investments in energy efficiency or distributed generation. There does not appear to be a way that the board could develop or the council consider such a hybrid proposal.

The legislature could amend PA 03-140 to address these issues. It could also amend the act to encourage a least-cost approach to facility development, consistent with the environmental and other goals of the siting law.

It should be noted that integrated resources planning appears to be inconsistent with a key provision of PA 98-28. By effectively forcing the utilities to divest themselves of their power plants, PA 98-28 left the development of power plants and other generation resources to the market. In contrast, integrated resources planning would have state agencies determine whether it was appropriate to build a plant based on their determination of what constitutes the most economic choice. A similar tension also appears to exist between PA 03-140 and PA 98-28.

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