Connecticut General Assembly
OFFICE OF LEGISLATIVE RESEARCH
June 3, 1998 98-R-0775
FROM: Kevin E. McCarthy, Principal Analyst
RE: Electric Restructuring Bill
You requested a section-by-section analysis of sHB 5005, “An Act Concerning Electric Restructuring” as passed by the House and Senate.
SECTION - BY - SECTION ANALYSIS
Section 1. The bill amends CGS § 16-1 (utility definitions) to: (1) sunset the term “electric company” after the companies separate (“unbundle”) their generation functions from their other functions (see section 5); (2) include “electric distribution company,” (the part of an unbundled company responsible for distributing power to customers) as a utility which will continue to be subject to Department of Public Utility Control (DPUC) rate regulation; (3) define a supplier as any entity that provides generation services, including the generation component of an unbundled electric company; and (4) define many other terms used in the bill.
Section 2. This section contains the bill's findings and principles, including that it is in the public interest to allow competition in the generation function of electric utilities while continuing to regulate the distribution function.
Section 3. Base rates, including demand and customer service charges, are capped from July 1, 1998 until December 31, 1999, at rates authorized by DPUC as of December 31, 1996. DPUC must adjust base rates under the existing energy adjustment clause and to reflect changes in state and federal taxes. It may adjust base rates for cost changes brought about by legislative changes, administrative requirements, and accounting rule changes occurring after the bill's effective date. The cap does not apply to customers on special contracts.
Section 4. Starting January 1, 2000, up to 35% of the peak load of each rate class for each electric company can choose their electric supplier. These customers must be located in distressed municipalities, with participation on a first-come, first-served basis. If the number of such customers in a class exceeds 35% of the peak load, preference must go to customers in cities with 100,000 or more residents. The remaining customers can choose their supplier as of July 1, 2000. Starting January 1, 2000, customers who do not choose or are unable to enter into or stay on a contract with a supplier must be served under the standard offer option (section 20). DPUC can adopt regulations to implement the phase in.
Section 5. By August 1, 1998, DPUC must complete a proceeding to unbundle the price of generation services from other utility services. Starting July 1, 1999 each company must separate its charges for generation services on its bills.
Each company must submit a plan to DPUC by October 1, 1998 to unbundle its generation assets from the rest of the company. The plan must discuss its effects on company employees, and include provisions to mitigate these effects.
Any non-nuclear assets that are not divested by January 1, 2000 must be transferred to a separate corporate affiliate, and the company gets no stranded cost recovery for them. Any nuclear asset that is not sold before January 1, 2000 must be divested as described in section 7 or sold or transferred to a separate corporate affiliate. They can be transferred to a division of the distribution company only if this is required to meet Nuclear Regulatory Commission (NRC) requirements. Long term purchased power contracts that have not been bought out go with the distribution company.
DPUC must act on the plan in time for unbundling to be completed by October 1, 1999. Once unbundling is completed, the part of the company that provides transmission and distribution services is called the distribution company. The part that provides generation services is called the generation entity or affiliate.
Section 6. Unless it chooses to totally forgo recovery of stranded costs, each electric company must put its non-nuclear generation assets up for auction. It must submit a divestiture plan to DPUC by October 1, 1998. (The auction requirement does not apply to assets that the company sells, with DPUC approval, under the existing asset transfer law before DPUC approves the divestiture plan.) The plan must describe the company's proposal for auctioning these assets and the book value of these assets. DPUC must act on the proposal in time to allow divestiture to be completed by January 1, 2000. DPUC, after consulting with Office of Consumer Counsel (OCC), must appoint an independent entity to run the auction. A generation entity or affiliate of the distribution company can bid on the assets if it is qualified to do so.
DPUC cannot approve a sale unless (1) it is consistent with the divestiture plan and produces a net benefit for consumers, (2) the sales price at least equals the minimum set by DPUC, and (3) the bidder meets relevant federal requirements and agrees to preserve existing union contracts. The minimum price is the book value for all plants other than one that began operation between 1974 and 1976 and that has a capacity of at least 420 megawatts (i.e., New Haven Harbor). With regard to this plant, the minimum is based on the income that would be produced by a comparable plant. If no qualified bidder submits a bid at least equal to the minimum, DPUC must determine its stranded costs as described in section 8. These costs are not eligible for securitization, which is described in sections 9 through 14.
The assets cannot be transferred until DPUC determines the buyer is qualified to provide generation services. The net proceeds of the sale go to reduce stranded costs associated with nuclear assets and purchased power contracts.
Section 7. By January 1, 2004, each distribution company must divest itself of its nuclear generating assets either by putting them up for auction or by transferring them to separate corporate affiliates, in which case the company receives no stranded cost recovery. From January 1, 2000 until divestiture takes place, the competitive transition assessment (described in the next section) is used to pay the company the difference between the assets' capital costs allowed in rates and the income a comparable plant that is prudently and efficiently run would produce. This amount is not eligible for securitization.
If the company chooses to auction its assets, it must submit a plan to DPUC that allows divestiture to occur by January 1, 2004. The plan must describe the proposed auction procedures and give DPUC information it needs to determine the minimum bid. DPUC must set the minimum bid based on the future income a comparable plant would earn if it were prudently and efficiently run. The generation entity or affiliate of the distribution company can bid for the asset. The conditions of transfer that apply to non-nuclear assets also apply to nuclear assets.
If the winning bid is at or above the minimum bid, but below the asset's book value, the difference is considered a stranded cost. If the bid is above book value, the difference goes to reduce stranded costs associated with purchased power contracts. If there are no qualified bids at or above the minimum, DPUC must calculate the stranded costs of the asset as described in the next section. In this case, the distribution company must transfer the unsold assets to a separate affiliate by January 1, 2004. If the NRC does not permit this, the assets may remain in a separate division of the distribution company. The stranded costs of nuclear generation assets are not eligible for securitization.
Section 8. This section defines the terms used with regard to stranded cost recovery, including securitization. It requires the company to apply to DPUC for a determination of the stranded costs that can be recovered through a competitive transition assessment (CTA). The CTA applies to all users of the distribution system (other than customers under existing special contracts), regardless of their electric supplier. The application must describe the company's efforts to mitigate its stranded costs. DPUC must act on the application in time to permit the CTA to go into effect by January 1, 2000.
Types of Stranded Costs That Can Be Recovered. The bill permits recovery of three types of stranded costs. The first is the above market costs of generation plants and related assets that were in rates before July 1, 1997. The second is regulatory assets, i.e., the cost of deferred taxes, conservation programs, and public policies that DPUC approved before July 1, 1998 for deferred recovery. The third is the costs of purchased power contracts the company entered into before January 1, 2000 that it was required by law to enter into or that were approved by the Federal Energy Regulatory Commission.
Conditions for Recovery. An electric company cannot recover any stranded costs unless it has met the bill's divestiture requirements with regard to non-nuclear assets. With one exception, it cannot recover costs associated with a nuclear asset (including associated regulatory assets) if the nuclear plant is not operating due to a plant-specific NRC order. The exception is for a plant with a capacity of 641 megawatts (i.e. Millstone 1). The company can apply to DPUC for the retirement of this plant for economic reasons under the existing utility rate regulation law. DPUC must allow any recovery ordered under this law by means of the CTA. But this recovery cannot include decommissioning costs or costs that DPUC has found to have been caused by imprudent management.
The company must mitigate all of its stranded costs to the maximum extent possible. Mitigation must include: (1) getting written commitments from the buyers of generating assets that they will offer jobs to the affected workers at their current salaries and (2) making good faith efforts to reduce the costs of purchased power contracts through such means as buy-downs. The bill identifies many other types of permitted forms of mitigation. It allows DPUC-approved mitigation costs, including the costs of the entities that conduct the divestiture auctions, to be recovered through the CTA.
Determination of Generation Assets Stranded Costs. DPUC must calculate the stranded costs of non-nuclear generation assets as described in section 6. In the case of an asset that is put up for auction, but draws no qualified bids, stranded costs are the difference between asset's book value and the market value of a comparable plants that is prudently and efficiently run. DPUC must revise this calculation at least every three years.
The company can apply for recovery of its stranded costs for its nuclear generation assets until January 1, 2004. DPUC must calculate the stranded cost of any nuclear asset that is divested as the difference between the winning bid and the book value. If a plant is put for auction but there are no qualified bids, stranded costs are the difference between the market value of a prudently and efficiently run comparable asset and the nondivested asset's book value. DPUC must revise this calculation at least every four years.
In either case, the following are subtracted to determine the amount to be recovered through the CTA: (1) net proceeds from the sale of non-nuclear plants, (2) any above book net proceeds from sales of nuclear plants, and (3) net proceeds from the sale or lease of company property. If the sum of these three amounts exceeds the stranded costs of the nuclear plant, the difference goes to reduce the CTA used to recover purchased power contract costs.
As noted above, a company can transfer its nuclear generation assets to a separate subsidiary rather than auctioning them but recovers no stranded costs if it does so. If the company sells any of these assets before January 1, 2012, any proceeds of the sale that exceed the asset's book value must go to reduce the CTA. DPUC can order additional forms of reimbursement it considers appropriate.
Determination of Regulatory Asset and Purchased Power Contract Stranded Costs. DPUC must calculate the stranded costs of regulatory assets as their January 1, 2000 book value. It must calculate the stranded cost of purchased power contracts that have a fixed present value (e.g. those that have been bought out) as that value. For other contracts, DPUC must at least annually calculate the contract's stranded costs as the difference between its cost and its market value. DPUC must net contracts approved by the Federal Energy Regulatory Commission which cost less than market value (whether they have a fixed value or not) against those that cost more than market.
Section 9. The bill allows the use of securitization (refinancing) for the following stranded costs: regulatory assets, purchased power contracts that have been reduced to a fixed value, and mitigation costs. It does not allow securitization of generation assets. The company must demonstrate that the resulting savings will be passed on to customers. DPUC can only approve securitization if it finds that this will not give the distribution company or its generation affiliates an unfair competitive advantage.
Section 10. DPUC must assess and collect the CTA, which is used to pay for both securitized and unsecuritized stranded costs, starting January 1, 2000. DPUC must set the CTA at a uniform rate within each rate class of each company. The assessment does not apply to customers under existing special contracts until they expire, but this exemption cannot result in a rate increase for any customer. The assessment does apply, starting January 1, 2000, to any existing special contract that is renewed after the bill's effective date or to any new contract.
The CTA must be sufficient to cover the principal and interest of the securitization bonds, the costs of the financing, and the electric company's stranded costs that are not covered by the bonds. It must be charged until the bonds are paid off and the other stranded costs are fully recovered. The CTA must be broken down into the amount used to pay for costs eligible for securitization, other stranded costs, and other charges.
Section 11. The rights to the part of the CTA used to cover the costs eligible for securitization is called “transition property,” which belongs to the electric company or the distribution company. The company can sell its interests in this property to an affiliate. The company or its affiliate can, in turn, sell this interest to a financing entity, to be used as the basis of the securitization bonds. Any of these entities can also pledge the transition property as collateral for the bonds.
Section 12. DPUC can issue “financing orders” authorizing the issuance of securitization bonds to facilitate the recovery and financing of stranded costs. The order can only be adopted if the company consents to all of its terms. The order and CTA is irrevocable. DPUC cannot: (1) revise the order, (2) revalue the stranded costs for ratemaking purposes, (3) determine that the CTA is unjust or unreasonable, or (4) do anything to reduce the value of the transition property. DPUC must adjust the CTA in order to allow timely recovery of all stranded costs that it covers, and it must provide a timely process for doing this.
Section 13. A “financing entity” (the state treasurer or an entity it designates) can issue securitization bonds after DPUC approves the financing order. The bonds must mature by December 31, 2011. Their proceeds must be used for DPUC-approved purposes as specified in the financing order, including the retirement or refinancing of debt. The proceeds cannot be used to buy generation assets, buy back stock, pay dividends to shareholders, or pay operating costs (other than taxes on the proceeds).
The bonds and the financing order are not state debt, and the bonds must say this on their face. They do not count towards the state's debt limits. They do not make the state or municipalities contingently liable.
The state pledges with the bondholders and the owners of transition property that it will not alter the CTA, transition property, and financing orders until its obligations have been met. The parties involved in the securitization process are exempt from taxes on the relevant property or revenue. The bonds are treated for state income tax purposes as though a public body had issued them.
Section 14. This section describes how a security interest in transition property is created and perfected.
Section 15. By January 1, 1999 DPUC must develop, by regulation, a code of conduct, to prevent a distribution company from favoring its generation entities or affiliates over other suppliers. DPUC can investigate and act upon violations of the code and anyone harmed by a violation has a private right of action. The code cannot prohibit communications necessary for the provision of the standard offer or to deal with emergencies. The code applies to all distribution companies, their generation entities and affiliates, and other suppliers. It must go into effect by July 1, 1999. DPUC can enforce the code by issuing orders and imposing civil penalties.
Section 16. DPUC must continue to regulate distribution companies, which must maintain system safety and reliability and offer nondiscriminatory access to all licensed suppliers. These companies must provide system metering, billing, and collection services. They must continue to connect all customers to the grid at DPUC-approved rates.
Section 17. DPUC must develop, by December 1, 1998, a comprehensive consumer education program. OCC must establish an advisory council to involve members of the public in developing this program. DPUC must begin implementing the program by January 1, 1999. It may retain consultants until December 31, 2000 to develop and implement the program, with costs recovered through the systems benefits charge (see section 18).
The advisory council, in consultation with Connecticut Academy of Science and Engineering and the New England Conference of Public Utility Commissioners, must analyze the environmental costs and benefits of various types of generating facilities. Based on the analysis, the council must establish uniform standards for the disclosure of environmental information to customers.
Section 18. DPUC must establish a systems benefit charge (SBC) payable by distribution company or electric company customers starting January 1, 2000. The charge does not apply to customers on existing special contracts, but does apply to new or renewed contracts starting January 1, 2000. The charge is used to pay for consumer education, low-income energy conservation, hardship protection, and dislocated worker programs; and the costs of nuclear plant post-retirement safe shutdown and site protection, and decommissioning, spent nuclear fuel storage and disposal, and certain payments to municipalities and resources recovery authorities.
Section 19. Municipal utilities may not use the transmission or distribution systems of the distribution company to provide service outside of their service areas without DPUC approval. DPUC must establish regulatory procedures allowing municipal utilities to participate in the competitive market. If a municipal utility wishes to participate, it must provide nondiscriminatory access to its distribution system to all suppliers and allow its customers to choose their suppliers. If a participating municipal utility generates electricity it must be licensed and must unbundle its generation assets from its transmission and distribution assets. It must demonstrate that the buyer of the generation assets will preserve any labor contracts in effect. The Connecticut Mutual Electric Energy Cooperative may not become a supplier or provide generation services to retail customers.
The charges established by the bill apply to any municipal utility created or expanded after July 1, 1998 with regard to its new customers at the rate they would have had to pay if the creation or expansion had not taken place.
Section 20. Distribution companies must provide all customers in their service areas a standard offer option from January 1, 2000 through January 1, 2004. They must provide power under this option to customers who choose the standard offer, who do not arrange for service from a supplier, or who do not maintain such service. The company may obtain power from its affiliates, so long as they are licensed suppliers.
Participating customers receive a guaranteed rate, which DPUC must set by October 1, 1999. Under the standard offer, rates (including costs of generation, transmission, and distribution services, and the CTA, SBC, and other charges established by the bill) must decrease by at least 10%, compared to December 31, 1996 rates. The standard offer must be adjusted to reflect changes in state and federal taxes and the existing energy adjustment clause. Tax decreases cannot be shifted among customer classes. DPUC may adjust the standard offer to reflect changes in utility costs associated with changes in law, administrative requirements, and accounting changes. It may also adjust the standard offer to the extent needed to ensure safe and reliable service if a company incurs extraordinary and unanticipated expenses. The price reduction does not apply to customers on special contracts or flexible tariffs. These provisions end January 1, 2004 unless extended by the legislature under section 74 of the bill.
From January 1, 2000 until the Independent System Operator (which runs the New England power grid) implements procedures for the provision of back up power, each distribution company must provide generation services to any customer whose supplier has failed to deliver electricity, except in cases where a customer fails to pay. The company, which need not be licensed as a supplier, can procure this power by bid or from its licensed affiliates until December 31, 2003. Thereafter the distribution company must bid out this service. Its generation affiliate can bid if it is licensed.
Starting January 1, 2004, each distribution company must provide default service to customers who do not arrange for service from an unaffiliated supplier or who do not maintain such service. The companies must bid out this service, although generation affiliates can bid if licensed.
The distribution company is entitled to receive its reasonable costs for its provision of the standard offer, back up, and default services. DPUC must adopt regulations to implement these provisions.
Section 21. DPUC must develop, by regulation, a standard billing format to enable customers to compare the prices and policies of suppliers. Starting January 1, 2000, each electric or distribution company must include specific information on its bills as required by the regulations. The regulations must provide guidelines for determining the billing relationship between the distribution company and suppliers, including the allocation of partial and late payments. The distribution company is entitled to reasonable transaction costs and a rate of return in meeting its obligations under this section.
Section 22. Aggregators, brokers, marketers, and other suppliers must be licensed by DPUC. DPUC must begin licensing by April 1, 1999 and has 90 days to act on a completed application. DPUC must set the license application fees to recover its costs. Licenses cannot be valid before July 1, 1999.
The applicant must: (1) demonstrate technical, managerial, and financial capability; (2) show that it has adequate capacity and reserve margins, as specified by the Independent Systems Operator (ISO); (3) show that its generating facilities in North America comply with Department of Environmental Protection (DEP) emission standards; and (4) comply with state environment and Siting Council law with regard to its facilities in the state. In addition, the applicant or the entity from which it buys power must (1) comply with Federal Energy Regulatory Commission licensing requirements and (2) be registered or certified by the ISO. The application must include information about the applicant and its proposed scope of service. The applicant must attest that it is subject to relevant Connecticut taxes and will pay them. Aggregators, who gather customers together but who do not buy or sell power, are subject to less extensive licensing requirements
The licensee must comply with the National Labor Relations Act, the Connecticut Unfair Trade Practices Act (CUTPA), the code of conduct, DEP emission limits, and the bill's anti-redlining provision, among other things. It must comply with the ISO's standards and obtain a specified percentage of its electricity from renewable resources. DPUC may adopt other requirements, to ensure that all customers have access to service. Licensees must periodically submit information to DPUC regarding changes. Licensees that do not comply with license requirements or violate the bill are subject to sanctions by DPUC, including license suspension or revocation and bans on signing up new customers.
Section 23. Any municipality (including the Connecticut Resources Recovery Authority) that aggregates the sale of electricity to residents, either individually or with other municipalities, is not subject to licensure but must register annually with DPUC. Municipalities can also aggregate the purchases for municipal facilities.
Section 24. DEP must adopt air emission standards for specified pollutants by January 1, 1999 for suppliers' generation facilities in North America that serve the Connecticut market. The standards may provide for an emission credit trading program. The standard for each specific pollutant goes into effect when adopted by three northeastern states with a total population of at least 27 million people.
Section 25. Suppliers must obtain specified percentages of their power from renewable resources. Originally, they must obtain at least 0.5% of their power from sources such as solar power, wind power, and fuel cells (class I renewable sources). They must obtain an additional 5.5% from these or other (class II) renewable resources, including hydropower and resources recovery facilities. These “portfolio requirements” rise to 6.0% of the supplier's power from Class I sources and an additional 7.0% from either type of renewable sources, starting July 1, 2009. The portfolio requirements do not apply to a supplier that obtains all of its power from Class II sources.
Section 26. The distribution company must provide each customer an DPUC-approved form, with which the customer can indicate that she does not wish information about her to be released to suppliers. Starting July 1, 1999, electric distribution companies must provide basic information (name, address, phone number, and customer class) to all suppliers regarding customers who do not return this form. Electric distribution companies cannot release detailed customer information to suppliers without the customer's written consent. All suppliers must be given equal access to data.
Suppliers must give potential customers notice of rates, terms, and conditions of service, and information regarding the environmental characteristics of the generating facilities. They cannot engage in deceptive advertising and must comply with federal telemarketing law. They must verify the customer's decision if it is not in writing. Customers have three business days to rescind their choice of supplier. Violation of these provisions is an unfair trade practice.
Section 27. Suppliers must provide information to DPUC that it, in consultation with the Consumer Education Advisory Council, determines will help customers make informed choices. Suppliers must submit quarterly reports on rates and other information DPUC requires. Suppliers must comply with these provisions in order to receive the basic customer information described above.
DPUC must keep on file (1) information provided by suppliers on their rates, contract terms and conditions, (2) information on the environmental characteristics of their generating plants, (3) information regarding customer complaints and (4) other information DPUC believes will assist customers in choosing their suppliers. The information must be formatted to facilitate comparisons of services provided by suppliers.
Section 28. Customers may change suppliers free of charge once every 12 months at the end of a billing cycle. At other times, a distribution company and supplier may charge their actual costs for the change.
Section 29. Suppliers may not discriminate in providing service. They may not refuse to provide service to customers who live in economically distressed areas or who are covered by hardship protections under existing law.
Section 30. A distribution company cannot change a customer's supplier unless the change (1) has been verified by an independent third party, (2) was requested or confirmed in writing by the customer, or (3) the customer consents electronically, for example, by using a computer. Violation of this provision is an unfair trade practice.
Section 31. DPUC is responsible for handling supplier customer complaints and must set up a toll-free number for this purpose. Customers having complaints about suppliers regarding disputed bills, terminations of service, or adequacy of service can use existing statutory remedies that currently apply to utilities.
Section 32. DPUC must monitor the market for generation and distribution services to prevent anti-competitive and unfair practices. It can investigate complaints about such practices upon complaint or on its own motion. It can require suppliers to provide information. Proprietary information can be protected. The Attorney General and OCC can participate in these investigations subject to the nondisclosure provisions. If DPUC finds that the law has been violated it can refer the case, including any protected information, to the appropriate enforcement agency.
Section 33. DPUC must assess a charge of 0.3 cents per kilowatt-hour starting January 1, 2000 to fund energy conservation programs through the Energy Conservation and Load Management Fund. The charge cannot be used to amortize costs incurred before July 1, 1997.
A DPUC-appointed board must assist the distribution companies in their development and implementation of a comprehensive conservation plan. The plan, which must be approved by DPUC, must promote cost-effective conservation programs and programs to develop more energy-efficient products. The board must include state agency representatives, business groups, and other interested parties. It must report to the Energy and Technology and Environment committees annually between 2001 and 2006 on the programs.
Section 34. Suppliers are subject to an assessment to cover the costs of consultants for DPUC and OCC. DPUC may retain consultants for the consumer education program until December 31, 2000, with a cap on total expenditures of $350,000. The cost of these consultants is recovered through the SBC.
Section 35. Suppliers and entities that violate the law by supplying power without a license are subject to DPUC orders and civil penalties if they do not comply.
Section 36. Suppliers that sell at retail in Connecticut are subject to an annual assessment for the costs of DPUC and the Office of Consumer Counsel for each year that they have more than $100,000 in Connecticut revenue.
Section 37. Distribution companies and suppliers are subject to the current law that restricts to one year the period of time that utilities can seek recovery when they make a billing error.
Section 38. Distribution companies and suppliers are subject to the current law's notice requirements regarding termination and the restrictions on terminations on weekends and, for hardship cases, during the winter. If a supplier loses money because of this requirement, it can make a claim against the distribution company, which must reimburse the supplier at the supplier's contract price or the distributor's price for default service, whichever is less. The distribution company can then recover this amount through the SBC. The DPUC regulations on these protections must be amended to describe the responsibilities of suppliers to their customers.
Sections 39 and 40. Distribution companies and suppliers are subject to the law's notice requirements and related provisions regarding terminations of residential service and complaints.
Section 41. A distribution company or supplier may petition the court for the appointment of a receiver when a landlord fails to pay his electric bill, as utilities can under existing law.
Section 42. DPUC may adopt regulations governing the terms and conditions of service of distribution companies and suppliers in terminating service when an account is in the name of a current or former spouse.
Section 43. Suppliers must give residential customers a credit for the power they produce using certain renewable technologies. The distribution company must provide metering to permit this. The customer must pay the competitive transition assessment and the system benefit charge based on his total, rather than net, consumption. These “net metering” provisions go into effect January 1, 2000 and apply to one to four unit dwellings.
Section 44. DPUC must impose a charge of at least 0.5 mils (0.05 cents) per kilowatt-hour starting January 1, 2000 to go into a new Renewable Energy Investment Fund. Starting July 1, 2002, the charge goes to .75 mils and then to 1.0 mil starting July 1, 2004. Connecticut Innovations, Inc. (CII, a quasi-public agency) must use money in the fund to promote investments in renewable energy technologies. It can provide financial assistance for commercialization of renewable energy technologies as well as research and development. CII must establish an advisory board to assist in this program.
Section 45. The law allows municipalities to exempt renewable energy technologies from the property tax. The bill eliminates a 2006 sunset date from this provision and makes minor changes.
Section 46. Electric and distribution companies and generation affiliates must develop lists of workers dislocated due to industry restructuring and give the information (except regarding workers who do not want to participate) to DPUC, which must forward this information to distribution companies and suppliers. DPUC must provide a list of suppliers to each worker on the list.
Section 47. Suppliers are entitled to a one-time $1,500 corporation tax credit, starting July 1, 1998 for each dislocated worker they employ for more than six months.
Section 48. Municipalities that lose property taxes on generating plants as a direct result of restructuring are entitled to partial reimbursement through the systems benefits charge. The reimbursement applies to losses that occur before the assessment year 2005. The reimbursement is 90% of the revenue loss in the first year the loss occurs, declining by 10% per year over the next nine years. Any gain in property tax revenue from new generating plants is subtracted from the reimbursement.
Section 49. The Siting Council must approve a new generating plant, using a fuel other than coal or nuclear energy, proposed to be built on an existing generating plant site, by declaratory ruling rather than issuing a certificate of public convenience and necessity, unless the council determines that the plant will cause substantial environmental harm.
Section 50. The bill reduces the amount of time the Siting Council has to issue a decision on siting new generating plants from 12 to 6 months, and eliminates determination of need for such plants.
Section 51. Municipalities may bond the costs of liquidating purchased power contracts.
Section 52. DPUC must consider whether energy conservation or load management could obviate the need for increased spending on the distribution system if a distribution company seeks to increase its rates for this purpose.
Section 53. Conforming change.
Section 54 and 55. The bill eliminates the gross receipts tax as it applies to generation services as of January 1, 2000. The current tax rate, which applies to all components of electric service, is 4% for residential customers and 5% for remaining customers, other than manufacturers that are exempt from tax. The bill increases, as of the same date, the rate as it applies to transmission and distribution services to 6.8% for residential customers and 8.5% for non-residential customers (other than manufacturers). It makes the CTA and SBC and the charges for energy conservation and renewable energy subject to the tax.
Section 56. The bill eliminates the current funding mechanism for recovering nuclear decommissioning costs starting January 1, 2000. After this date, funding for this purpose will come from the SBC (see section 18).
Section 57 and 58. Electric companies currently offer special contracts with rate discounts, pursuant to the law, to manufacturers to promote economic development. Under the bill, if an electric or distribution company (1) modifies an existing contract that expires before July 1, 2000 so that it extends beyond this date or (2) enters into a new contract, the contract must include the CTA and SBC. In addition these contracts cannot shift costs to other ratepayers.
Section 59. The Office of Policy and Management (OPM) must provide technical assistance to municipalities that want to aggregate generation services.
Section 60. OPM must operate an electricity purchasing pool for state facilities. The pool must also be open to each household that receives means-tested assistance from the state or federal government. They must be offered the rates offered for state facilities. OPM must use energy assistance funds to achieve the lowest practicable rates for households participating in this pool.
Section 61. By law, electric companies must pay retail rates for power produced at resource recovery facilities. The bill establishes a mechanism, starting in 2000, to hold harmless the municipalities that use these facilities from any reduction in electric rates. The cost of this provision is recovered through the SBC.
Sections 62 through 65. The bill extends several consumer protection measures, which currently apply to utilities, to cover suppliers.
Section 66 and 67. The bill expands the powers of electric cooperatives but subjects any cooperative established after July 1, 1998 to the CTA and systems benefits charge.
Section 68. DPUC must investigate performance-based regulation by having each distribution company design a plan that encourages them to control their costs while providing safe and reliable service. DPUC also look at whether such regulation would better reduce costs than the current regulatory structure. It must report its findings to the Energy and Technology Committee by January 1, 2000.
Section 69. DPUC must design an exit fee for self-generators to offset loss of the CTA and other charges established by the bill. The fee must apply to self-generation facilities that go into operation after June 30, 1998. The fee does not apply to those serving up to four residential units or to facilities serving expanded industrial plants with regard to the incremental load. DPUC must determine how to identify self-generators and collect the fee and report its recommendations to the Energy and Technology Committee by January 1, 1999.
Section 70. DPUC must investigate how to encourage aggregation of customers into buying groups. It must report to the Energy and Technology Committee by January 1, 1999.
Section 71. The Siting Council must examine its procedures regarding the siting of new generation facilities in a restructured electric industry to determine how siting can be expedited while taking environmental concerns into account. It must report to the Energy and Technology and Environment committees by January 1, 1999.
Section 72. The Connecticut Energy Advisory Board, in consultation with DPUC and OCC, must study whether metering and billing services should be opened to competition, and the potential negative effects of such a move. It must report to the Energy and Technology Committee by January 1, 1999.
Section 73. DPUC and OCC must jointly study how best to structure default service for people who are unable to arrange for service from a supplier. The agencies must consider four specified options, with the goal of maintaining high quality service at the lowest possible cost. They must report their findings to the Energy and Technology Committee by January 1, 2002.
Section 74. Each distribution company must report to DPUC by October 1, 2002 the proportion of its customers who are on the standard offer and the average rate they pay. By January 1, 2003, DPUC must determine the difference between rates for customers on and off the standard offer, and report its recommendations regarding an extension of the standard offer to the Energy and Technology Committee.
Section 75. DPUC, in consultation with OCC, must monitor the status of competition and the average total rates of each customer class. DPUC must report its findings to the Energy and Technology Committee annually, starting in 2002. If it finds that the difference between industrial and residential rates increases more than three percentage points above the January 1, 1998 ratio, it must conduct an investigation as to why. If it finds that the cause is a violation of the law, it must take appropriate enforcement actions. If the growth in the ratio is due to other causes, it must take steps, using specified statutory remedies, to bring the ratio to within the three-percentage point difference. But the remedy cannot result in subsidies within or between rate classes. It must report to the Energy and Technology Committee on its findings, actions, and recommendations by January 1 of any year when the difference in rates goes above the trigger amount.
Section 76. Municipalities can abate property taxes for electric cooperatives.
Section 77. Electric and distribution companies must report annually to DPUC and the Department of Environmental Protection regarding system reliability, and environmental quality and the agencies must report on these issues to the legislature. DPUC must report on dislocated workers to the Energy and Technology and Labor and Public Employees committees. It must report to the Energy and Technology Committee on the number of licensed suppliers. All of these reports are due annually by January 1, starting in 1999.
The remainder of the bill primarily extends to distribution companies and suppliers many of the laws that currently apply to utilities.
Section 78. The bill extends “revolving door” restrictions on DPUC commissioners to include employment with or lobbying for suppliers.
Section 79. OCC must represent the interests of customers of suppliers. Suppliers are also brought under the “revolving door” restriction with regard to the Consumer Counsel.
Section 80. Officers and employees of suppliers may not serve as DPUC commissioners or employees.
Section 81. DPUC may adopt regulations regarding services, accounting practices, safety and operations of suppliers.
Section 82. DPUC may enter a supplier's property, with a fine of up to $200, imprisonment for up to six months, or both for anyone who obstructs entry.
Section 83. DPUC must audit distribution companies with more than 75,000 customers at least every six years
Sections 84 through 86. Individuals and municipalities may file complaints with DPUC with regard to safety problems of suppliers. Suppliers that violate DPUC orders in response to such complaints are subject to a fine of up to $1,000 per offense and double damages for injuries resulting from such violations.
Section 87. Suppliers must notify DPUC in case of accidents, subject to a fine of up to $500 per offense for failing to report.
Section 88. DPUC must investigate fatal accidents involving suppliers.
Section 89. Distribution companies must file information with their rate amendment proposals describing their effects.
Section 90. DPUC must conduct a comprehensive rate investigation of distribution companies with more than 75,000 customers every four years, as it already must do with large electric and gas companies.
Section 91. Distribution companies are subject to the limits on ratepayer-financed advertising that apply to electric and gas companies.
Section 92. The bill eliminates, as of January 1, 2000, the requirement that large electric companies indicate the customer service charge on their residential bills.
Section 93. Distribution companies must use revenues that exceed the company's authorized rate of return allocated by DPUC to reduce future rate increases or refund the money to customers within one year of their receipt.
Section 94. Distribution companies with more than 75,000 customers must periodically report to DPUC on outages that result from power surges.
Section 95. Distribution companies must permit submetering at campgrounds.
Section 96. Water companies can adjust their rates using an expedited DPUC approval process to reflect the increased cost of electricity bought from distribution companies and suppliers.
Section 97. DPUC may require distribution companies to file infrastructures maintenance plans, including tree-trimming provisions.
Section 98. The bill extends to the holding companies of distribution companies the provisions that regulate activities of utility holding companies.
Section 99. By law, the siting of emergency generating devices that are owned by electric and gas companies, unlike those owned by other entities, are subject to the Siting Council's jurisdiction. The bill subjects such devices owned by distribution companies to the council's jurisdiction.
Section 100. By law, applicants for Siting Council certificates for transmission lines must notify the customers of the local electric company of the application. The bill extends this provision to require notification of distribution company customers.
Section 101. The bill gives DPUC sole jurisdiction over the method of building and using distribution, as well as transmission, lines.
Section 102. DPUC must regulate distribution company line extensions in the same way as it currently must regulate extensions of electric company lines.
Section 103. Distribution companies are subject to the “Call Before You Dig” laws.
Sections 104 and 105. Distribution companies, like electric and gas companies, are exempt from Department of Public Safety regulation of the storage and transportation of combustible liquids.
Section 106. By law, the Department of Economic and Community Development annually assesses electric and gas companies with at least 75,000 customers for costs associated with the Energy Conservation Loan Fund program. The bill extends this and related provisions to distribution companies.
Sections 107 through 111. The bill bars business, foreign, nonstock, and foreign nonstock corporations and limited liability corporations from acting as distribution companies.
Section 112. State banks may act as collection agents for distribution companies.
Section 113. Property of distribution companies is subject to the same lien provisions as electric or telephone company property.
Sections 114 and 115. Distribution companies, their generation affiliates, and other suppliers are subject to the corporation business tax.
Section 116. The generation, transmission, and distribution counts as tangible personal property for purposes of the sales tax.
Section 117. Most of the bill is effective July 1, 1998. Sections 6 (unbundling), 45 (property tax exemptions for residential renewable energy systems), 46 (roster of dislocated utility workers), and 57 (special contracts) are effective upon passage. Sections 54, 55, and 56 (gross receipts tax and funding DPUC costs) are effective January 1, 2000.