You requested a discussion of the environmental issues the electric restructuring working group may wish to address. The group is reviewing PA 98-28 (CGS § 16-244 et seq. ), which restructured the electric industry to allow consumers to choose their electric suppliers.

SUMMARY

The working group may wish to consider:

1. what changes, if any, to make to the renewable energy and conservation funding established by the act;

2. whether to extend the act's environmental requirements to electric utilities in their provision of default service starting in 2004;

3. whether to modify the renewable portfolio standard (RPS), which requires generation suppliers to obtain part of their power from renewable resources; and

4. whether to promote distributed generation.

As discussed below, promoting some of the act's environmental goals as specified in CGS § 16-244 may conflict with its other goals. For example, extending the act's environmental requirements, notably the RPS, may increase electric rates. Conversely, not taking these steps may substantially slow the development of renewable resources, which is also one of the act's goals.

INTRODUCTION

PA 98-28 restructured the electric industry to allow customers to choose their suppliers. The act created a Clean Energy Fund, paid for from a charge on electric bills, to promote the development of renewable energy sources. It established ratepayer-funded energy conservation programs administered by the state's two investor-owned utilities. It also required competitive generation suppliers to obtain part of their power from renewable energy resources, disclose the environmental characteristics of their power supplies, and provide net metering to their residential customers. As discussed below, these three requirements have had little effect to date.

Under the act, the utilities must, until December 31, 2003, provide standard offer service at a statutorily set rate to customers who do not choose a supplier. Thereafter, the utilities must provide default service to such customers. At all times, utilities must provide back-up service to a customer whose supplier fails him.

CONSERVATION AND RENEWABLE ENERGY FUNDING

Renewable Energy

Current Law. The Department of Public Utility Control (DPUC) must impose a charge of 0. 05 cents per kilowatt-hour (kwh) on all electric consumers in the state, other than those served by municipal utilities. The money goes into the Clean Energy Fund, which is administered by Connecticut Innovations, Inc. (CII). The charge will increase to 0. 075 cents per kwh on July 1, 2002 and 0. 1 cents per kwh on July 1, 2004. CII can use the fund to implement a plan it develops to promote the development and commercialization of renewable energy resources and related enterprises and to stimulate the demand for and deployment of these resources. These resources include solar and wind energy, landfill gas, fuel cells, and certain other technologies (CGS § 16-245n).

CII's website (http: //www. ctcleanenergy. com/) describes the fund. Originally, CII focused on investing in (1) companies that market renewable energy and (2) projects that increase demand for renewable energy products and services. Recently, CII has changed its focus and is also investing directly in renewable energy production projects. Earlier this year it issued a request for proposals for fuel cell projects, with total funding of $ 6 million. It received 31 proposals by the closing date and anticipates making funding decisions in early 2002. CII has also invested in wind power and other renewable energy projects.

Issues for the Working Group. The working group may wish to consider modifying the renewable energy charge. The response to CII's request for proposals indicates that the level of interest in renewable energy projects substantially exceeds the amount of funding available. Investing in these projects could help diversify the fuel mix used to generate power and reduce the rate of growth in the state's dependence on natural gas as a generating fuel. (A substantial majority of new power plants in Connecticut and elsewhere are fueled by natural gas. )

On the other hand, increasing the renewable energy charge would increase electric rates. As discussed in OLR report 2001-R-0081, rates are likely to be stable through 2003. However, it appears that rates could rise substantially thereafter. While the charge is a small part of a consumer's electric bill, raising it while the overall bill is increasing could be unpopular.

The working group could also consider specifying where CII may invest the fund. The law is silent on this point; in practice, CII has invested in projects in New England and New York State. Allowing CII to make investments over a larger geographical area may allow it to find more cost-effective projects. For example, solar energy is generally most cost-effective in the Southwest, while wind energy is generally most cost-effective in the Plains states. On the other hand, investing in these areas would provide little immediate benefit for Connecticut ratepayers.

Energy Conservation

Current Law. DPUC must assess a charge of 0. 3 cents per kwh to fund programs through the Energy Conservation and Load Management Fund. A DPUC-established board, including state agency representatives, business groups, and other interested parties must assist the utilities in their development of a comprehensive plan to promote conservation programs and programs to develop more energy-efficient products. The law allows the fund to be used for a wide variety of programs, which must pass a cost-effectiveness test (CGS § 16-245m). Legislation adopted in 2001 allocates $ 12 million of the fund in FY 2002 for projects in state buildings.

Issues for the Working Group. The working group may wish to consider whether the current funding level for conservation programs is appropriate. The currently funded programs save electricity at a cost substantially below the cost of producing it, according to DPUC. Additional expenditures may be cost-effective. On the other hand, increases in the conservation charge would be reflected in rates. In addition, some participants in the working group have suggested exempting industrial customers from the charge as a means of reducing their rates (such customers would then become ineligible for conservation funding). The rationale for this option is that the market for conservation services for these customers should be sufficiently robust to support itself without ratepayer charges.

Another issue the working group may wish to address is whether to target conservation programs in areas where transmission is constrained. Doing so could reduce the impact of geographically targeted transmission rates, which are anticipated to go into effect in the next few years. On the other hand, the area most subject to transmission constraints (southwestern Connecticut) is also the richest part of the state, raising equity concerns if conservation funding is geographically targeted. These issues also apply to funding for renewable energy projects.

Finally, the working group may wish to consider having a third party administer the conservation programs. Although the utilities' administration of the programs has been well received by a wide range of stakeholders, it does pose a potential conflict of interest. The utilities' earnings and ultimately their profits are affected by how much electricity they sell. This may reduce their enthusiasm for promoting conservation programs that reduce their sales. The working group may wish to consider having a third party administer the program to avoid this potential conflict. Vermont, which has not authorized retail competition to date, has taken this step.

RPS AND OTHER REQUIREMENTS ON SUPPLIERS

Requirements Under Current Law

Under the act, suppliers must obtain at least 0. 5% of their power from sources such as the sun, wind, and fuel cells (class I renewable resources). They must obtain an additional 5. 5% from these or other (class II) renewable resources, including hydropower and resources recovery facilities. The RPS rises annually over 10 years until at least 6. 0% of the supplier's power must be from class I resources and an additional 7. 0% from either class of resources (CGS §§ 16-245a). Part of the rationale for the RPS was to create a guaranteed market for developers of renewable energy. RPS proponents anticipated that it would help reduce the costs of renewable energy, which are generally well above the costs of conventional energy.

In addition to meeting the RPS, suppliers must inform DPUC about the environmental characteristics of their power supplies. The information includes the percentage of each supplier's output that comes from class I and class II renewable resources and the percentage that comes from specified non-renewable resources. In addition, suppliers must provide information regarding their emissions of various pollutants, including carbon dioxide. DPUC must make the information the suppliers provide available to customers (CGS § 16-244d and 16-245p). Collectively, these are commonly referred to as disclosure requirements.

Suppliers must give residential customers a credit for the power they produce using class I resources. The utilities must provide metering to permit this (CGS § 16-243h). These net metering provisions apply to one- to four-unit dwellings.

DPUC Decision on RPS and Its Implications

As discussed in OLR report 99-R-1153, DPUC has held that the RPS does not apply to the standard offer service the utilities provide. Part of its rationale was that the RPS on its face applies to suppliers, while the utilities that provide standard offer service are "distribution companies," which are subject to different requirements under the act. The Office of Consumer Counsel challenged this interpretation, but the courts have recently upheld the DPUC.

As a result, the RPS does not apply to the vast majority of power sold in the state. More than 99% of all customers are currently on standard offer, and it appears that this proportion will not change significantly in the next two years. The slow development of retail competition and DPUC's decision have effectively vitiated the RPS at present.

While the decision does not address whether the disclosure and net metering requirements apply to the utilities, the same logic applies. In practice, the bills of customers on standard offer do not disclose the environmental characteristics of the power they consume. While it appears that the utilities provide net metering to a few customers, PA 98-28 made the statute that requires them to do so (CGS § 16-243a) obsolete.

Moreover, DPUC's decision suggests that the RPS and the other requirements would not apply to default service starting in 2004. (The court's decision does not clearly address this issue. ) While the proportion of customers who will be served under default service cannot be predicted in advance, experience in other states suggests that relatively few customers will choose a supplier in the near future. This would imply that PA 98-28's environmental requirements would apply only to a limited share of the total market for electricity in the state.

Issues for the Working Group

The working group may wish to consider extending the act's environmental requirements to utilities in their provision of default service. (Since the wholesale contracts for providing power for standard offer service are already in place, subjecting them to the requirements might violate the Contracts Clause of the U. S. Constitution. ) There are arguments for and against extending the requirements to the utilities, particularly with regard to the RPS.

RPS. Requiring the utilities to meet the RPS would, in all likelihood, substantially accelerate the development of renewable resources in New England and increase the diversity of the state's energy supply. Having the RPS and other requirements only apply to suppliers could impede the development of a competitive retail market, a key goal of PA 98-28. This is because requiring suppliers, but not utilities, to comply with the RPS would give the latter a competitive advantage. To the extent that complying with the RPS increases the cost of power, limiting it to suppliers will encourage consumers to stay on default service rather than choose a supplier.

On the other hand, several entities including DPUC believe that there is insufficient renewable generating capacity in New England (particularly powered by class I resources) to meet the RPS if it applies to default service. Extending the RPS requirement to default service could increase the cost of this service and decrease the number of wholesalers bidding to provide power for it.

Independent of whether the working group decides to recommend extending the RPS to utilities, it may wish to consider modifications to CGS § 16-245a. This section could be amended by (1) extending its deadlines to give the renewable energy industry more time to develop, (2) modifying the amount of renewable energy a supplier must obtain, or (3) modifying the definitions of class I or class II renewable resources. In addition, the working group wish to investigate tradable renewable credits. CII has proposed adoption of this option, which would allow a supplier that has difficulty in meeting the RPS to buy credits from another supplier that exceeds the requirements of CGS § 16-245a.

All of these alternatives could make it easier for suppliers to comply with the RPS. However, adopting any of them could increase the level of uncertainty in New England's renewable energy industry, discouraging investments in new projects.

Other Requirements. Extending the disclosure requirements to cover default service would make it easier for consumers to consider environmental issues when choosing whether to remain on default service. It is unclear whether this extension would have any effect on rates. However, the usefulness of the disclosure requirements may not be as great as originally anticipated. When PA 98-28 was adopted, its proponents anticipated that suppliers would own power plants and other generation assets such as long-term contracts. However, in practice plant owners have chosen not to participate in the retail market. Instead, they sell their power to suppliers on the wholesale market. To the extent that wholesale contracts are sold and resold through third parties, it may not be feasible to provide consumers with accurate information regarding the environmental characteristics of the power they buy.

Very few residential consumers generate power using renewable resources and it is unlikely that this number will grow dramatically over the next few years. As a result, it is unlikely that extending the net metering requirements to utilities in their provision of default service would impose substantial costs on them or raise the rates for default service. However, a mechanism would have to be established through which the utilities could recover their costs.

DISTRIBUTED GENERATION

The working group may also wish to address whether to propose measures to promote distributed generation. Distributed generation (which can use renewable or conventional resources) produces power using small-scale facilities at a business or institution. These generation facilities can improve energy efficiency and reduce the need for new transmission and distribution lines.

Distributed generation raises several policy issues. If newer and cleaner technologies are used to generate power on site, air quality could improve. But if existing generation resources, which are primarily diesel-fired, were used more extensively air quality could be harmed. In addition, the widespread use of distributed generation could threaten recovery of the utilities' stranded costs. The working group is addressing this issue in its discussion of the future of the exit fee (CGS § 16-245w).

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