OLR Bill Analysis

HB 7501

Emergency Certification



This bill establishes several initiatives to reduce charges associated with congestion on the electric transmission system. It creates incentives for customers for installing distributed resources on their premises. These resources include small and medium size generating facilities and conservation and load management measures. The incentives include a capital and operating cost subsidies and the provision of long-term financing. The bill also provides awards to electric companies for their efforts in connection with the installation of these resources.

The bill requires the Department of Public Utility Control (DPUC) to identify near term measures that could reduce the transmission congestion costs and order the electric companies to begin implementing the steps DPUC considers appropriate by January 1, 2006.

The bill requires DPUC to conduct a request for proposals to identify measures that would reduce congestion costs over the 2006 to 2010 period. Proposals can be submitted for distributed resources, larger generating plants, and contractual rights to the generating capacity of power plants. Electric companies can submit bids but, if selected, the companies (1) can build only 250 megawatts of generation capacity statewide, (2) can only recover the costs they submitted in their bids, and (3) must sell off the plants or auction the power they produce within five years of the plants going into service, unless DPUC waives this requirement. Proposal submitted by entities other than electric companies that are selected by DPUC are eligible to enter into long-term contracts with the companies, with DPUC approval. Distributed resources projects are eligible for the incentives described above, other than the capital cost subsidy. The bill also entitles electric companies to an award for generation proposals submitted by other entities that are selected by DPUC.

The bill facilitates the siting of the generation projects approved or ordered by DPUC and makes other changes in the Siting Council law.

The bill requires that the groups that recommend how the Conservation and Load Management and Clean Energy funds are used to give a preference to funding projects that maximize the reduction in these congestion costs. It also requires these groups to evaluate the effectiveness of the funds’ programs every five years, starting December 31, 2006. It modifies how money in the Conservation and Load Management funds are spent. It provides incentives for the electric companies to develop new conservation programs.

The bill requires the electric companies and competitive suppliers to acquire 1% of their supply from distributed resources starting in 2007. This proportion increases to 4% by 2010.

Under the bill, the companies must implement, with DPUC approval, (1) mandatory daily rates for large commercial and industrial customers and voluntary time-of-use rates for other customers starting June 1, 2006 and (2) mandatory seasonal rates for all customers starting June 1, 2007.

The bill entitles the electric companies to recover their costs and investments incurred pursuant to its provisions through several mechanisms, including the existing congestion charge and placing the costs in the companies’ rate bases. In addition, the bill:

1. sets a floor on municipal electric utility expenditures on conservation and load management programs, phased in over five years;

2. requires DPUC to conduct a study on establishing a procurement fee for the services electric companies must provide starting in 2007;

3. requires DPUC to conduct an assessment of distributed resources;

4. makes several changes to the requirements that the electric companies obtain part of their power from renewable resources and enter into long-term contracts with specified renewable energy generators;

5. allows the Clean Energy Fund to invest in combined heat and power (cogeneration) and waste heat recovery systems;

6. reduces, from 500 to 100 kilowatts, the demand a customer must have to be directly billed by a competitive supplier rather than an electric company;

7. requires DPUC, the Energy Conservation Management Board, and the electric companies to establish links on their websites to the federal Energy Star energy efficiency program;

8. establishes a process for the development and review of natural gas conservation programs;

9. requires DPUC to investigate how best to decouple earnings of gas companies and other utilities from their sales in order to promote the state’s energy policy and requires DPUC to report its findings and recommendations to the Energy and Technology Committee by January 1, 2006;

10. exempts gas pipelines that have a design capacity of less than 20% of its specified minimum yield strength from the Siting Council’s jurisdiction, thereby subjecting them local planning and zoning regulation, and

11. exempts bonding by municipalities for cable TV systems from statutory bond limits;

12. generally requires that utility dispositions of property be done by public auction or other public sale procedure; . and

13. modifies who can file a claim for a property tax exemption for air or water pollution control equipment and structures and establishes procedures for continuing the exemption, under certain conditions, when the ownership of the equipment or structure changes.

EFFECTIVE DATE: Upon passage, except where indicated.


The bill defines

1. “combined heat and power” as systems that produce power and thermal energy from a single source that reduces aggregate electricity use;

2. ‘“grid side distributed resources” as generating units, including those primarily used to meet peak demand, of up to 65 megawatts capacity that are connected to the transmission or distribution grid; and

3. “class III” resources as (1) electricity savings from commercial and industrial facilities in the state under conservation and load management programs established on or after January 1, 2006 and (2) electricity produced by generating electricity from the waste heat produced by combined heat and power units that (a) are part of customer side distributed resources located in the state, (b) have an efficiency of at least 50%, and (c) go into operation on or after January 1, 2006.


The bill renames “distributed generation” as “customer side distributed resources” and expands the definition to include conservation and load management, including peaking reducing and demand response systems. It specifies that generation covered by this definition must have a capacity of no more than 65 megawatts.

The bill expands the definition of “federally-mandated congestion costs” (FMCC) to include Locational Installed Capacity payments made by utilities to electric generators and the costs of measures approved by the Department of Public Utility Control (DPUC) that reduce FMCCs. It refers to FMCC as a charge, rather than a cost.


The bill allows electric companies to own power plants and other generation resources as described below.


By law, the two electric utilities must develop plans for implementing conservation programs. The plans are reviewed by the Energy Conservation Management Board, which completes a cost effectiveness analysis, and are subject to DPUC approval. A charge on electric bills funds the programs in approved plans.

The bill requires that the plans be consistent with the statewide Connecticut Energy Advisory Board plan. It requires that the plan provide for the energy conservation Management Board’s expenses for consultants and administrative costs. It specifically allows the company plans to target low-income consumers and establish joint fuel (electricity/natural gas) initiatives.

The bill requires the management board to (1) give preference to programs that reduce FMCCs, (2) to examine opportunities for joint fuel conservation programs, (3) consult with the Clean Energy Fund advisory committee before conducting its review, and (4) counts system benefits, including FMCC reductions, in its cost effectiveness analysis. In order to reduce FMCCs, the bill allows for disparities between the amounts customer classes pay into the funds and the extent to which the programs will benefit each class.

The bill adds a representative of the Connecticut Municipal Electric Energy Cooperative (CMEEC) and two representatives selected by gas companies to the board. The gas company representatives cannot vote on matters unrelated to gas conservation, and the electric utility members cannot vote on matters unrelated to electric conservation. It establishes a joint committee consisting of members of the board and the Clean Energy Fund advisory committee to coordinate programs to reduce long-term costs, environmental risk, and security risks.

The bill eliminates the board’s 2006 sunset on the date the board reports to the legislature. It expands the report to cover the board’s collaboration with the Clean Energy Fund. It requires the board, in consultation with Clean Energy Fund advisory committee, to evaluate the conservation funds’ performance by December 31, 2006, and every five years thereafter. The board must submit a copy of this evaluation to the Energy and Technology Committee.


Connecticut Innovations, Inc. administers this fund, which invests in various energy technologies. An advisory committee helps develop a plan to spend money in the fund, which comes from a charge on electric bills.

The bill expands the types of technologies that the fund can invest in to include electricity production from combined heat and power systems with waste heat recovery and thermal storage systems. It requires the plan to (1) give preference to projects that maximize the reduction of FMCCs and (2) be consistent with the Connecticut Energy Advisory Board plan.

The bill requires that the annual legislative report prepared by the advisory committee cover collaboration between the Clean Energy Fund and the utility conservation funds. It also requires the committee to evaluate the effectiveness of Clean Energy Fund programs and activities by December 31, 2006 and every five years thereafter and report its findings to the Energy and Technology Committee.


The bill allows competitive electric suppliers to directly bill customers with a peak demand of 100 to 500 kilowatts. It eliminates a provision that allows direct billing of customers whose demand does not reach the threshold but who use a demand meter.


The bill requires DPUC to establish, by January 1, 2006 a program to provide one-time capital subsidies to customers who install customer side distributed generation. The subsidy ranges from $ 200 to $ 500 per kilowatt (kw) of generating capacity. A subsidy can be granted only if the project reduces FMCCs more than the award, and no person can receive more than one award. The size of the award depends on the reduction of FMCCs. By October 1, 2005, DPUC must conduct a contested case to establish additional standards for the amount of the subsidies and criteria and procedures for awarding subsidies and their size.

The bill also requires DPUC to establish, by January 1, 2006 a program to provide awards to the electric companies to educate, assist, and promote investments in these resources. The one-time award is paid when the resource becomes operational, under the following schedule, $ 200 per kw for resources developed by January 1, 2008, $ 150 per kw for resources developed by January 1, 2009, $ 100 per kw for resources developed by January 1, 2010, and $ 50 per kw for resources developed thereafter.

Both subsidies are funded from the FMCC charge on electric bills. The company’s revenues from its award do not count in DPUC’s determination of whether the company’s rates are just and reasonable.


The bill requires DPUC to select, by competitive bid, one or more entities other than electric companies to provide long term financing for the capital costs of customer side distributed generation and advanced power monitoring and metering equipment. DPUC must implement a mechanism that reduces the interest rate for people receiving this financing to no more than the prime rate. DPUC can retain a consultant to help it select these entities, which it must do by January 1, 2006.

Each selected entity must give preference to financing projects that maximize reductions in FMCCs. After receiving DPUC approval, the entity must enter into an agreement with an electric company to provide billing services on the entity’s behalf. The company can recover its costs, including the cost of the interest rate reduction, from the FMCC charge.


The bill requires DPUC, by January 1 annually starting in 2007, to assess the number and types of distributed resources (customer and grid-side); the projects financed under the bill; and projects’ contribution to fuel diversity, transmission support, and energy independence. By January in odd-numbered years, DPUC must collect the information in the annual assessments and report to the Energy and Technology Committee.


The bill requires electric companies, by January 1, 2006 to institute programs to rebate their customers with customer side distributed resources projects for the customer’s gas delivery charges from their local gas company. The costs are recoverable by the electric company through the FMCC charge. DPUC can adopt implementing regulations.


Near Term Measures

The bill requires DPUC to identify measures that could reduce FMCCs and that could be implemented, at least partially, by January 1, 2006. These measures can include (1) demand response programs designed to change when electricity is consumed in order to reduce demands on the electric system; (2) other distributed resources such as conservation programs and small power plants; and (3) contracts between an electric company and power plant owners for rights to the capacity of the plant.

DPUC must complete the identification by November 1, 2005 and order the utilities to begin implementing the measures that it considers appropriate by January 1, 2006. The company’s cost in implementing these measures is recovered through the FMCC charge.

Request for Proposals

Development. DPUC must develop, through a contested case completed by January 1, 2006, principles and standards for the RFP described below. Before it issues the RFP, however, it must conduct a contested case to investigate the possible impact of long-term capacity contracts (one of the types of resources that can bid in the RFP) on the financial condition of the electric companies that would buy the capacity rights. If DPUC determines that there are such impacts, it must establish a method, before issuing the RFP, for compensating the companies for them. If DPUC subsequently determines that the contracts increase a company’s costs, DPUC must annually allow it to recover the costs in its rates or in another way that DPUC considers appropriate. DPUC can determine whether or not to consider these potential costs in evaluating or selecting bids in the RFP.

DPUC must conduct the RFP by February 1, 2006. The RFP must seek proposals to reduce FMCCs over the period May 1, 2006 through December 31, 2010 (DPUC can specify a later end date). The proposals can be for customer-side or grid-connected distributed resources; other new generation resources, including expanded and repowered generation; or contracts between a company and another party for up to 15 years to buy generation capacity rights in the area where the company is authorized to operate. The RFP must be designed to encourage responses from various types of resources and encourage diversity in fuel types. DPUC can retain a consultant to develop the RFP and help it pick the winning bids. The cost for the consultant is recoverable through the FMCC charge. DPUC must allocate these costs between the two companies based on their load. DPUC must publicize the RFP in several ways.

Submission of Proposals. Electric companies can submit bids, subject to the following provisions:

1. the proposal must include its full projected cost that would borne by ratepayers; and

2. the company must demonstrate to DPUC’s satisfaction that its bid is not being subsidized by its affiliates.

Electric company affiliates can also submit proposals, subject to the existing code of conduct that regulates interactions between the companies and their affiliates.

Proposals for generation resources and long-term contracts submitted by entities other than electric companies must include a draft contract for transferring the various capacity rights associated with the proposal, but not the actual energy produced by the plants. The draft contract can run for no more than 15 years and must includes provisions that DPUC directs. All proposals must agree to forgo or credit locational installed capacity payments and similar payments.

Evaluation of Proposals. By May 1, 2006, DPUC must evaluate all of the proposals and may approve one or more of them. In approving the proposals, DPUC must give preference to those that (1) result in the greatest reduction of FMCCs during the designated period, (2) make efficient use of existing sites and supply infrastructure, and (3) serve the long-term interests of ratepayers.

DPUC can approve a total of no more than 250 megawatts of electric-company-owned generation statewide under the initial and any subsequent RFPs. In approving such generation, DPUC must be guided by the company’s relative shares of electric load in the state. Electric companies cannot submit proposal under any RFP after February 1, 2011. By January 1, 2010, DPUC must recommend to the Energy and Technology Committee whether this deadline should be extended.

Benefits for Approved Projects. All approved distributed resources projects are eligible for approval from the Siting Council by declaratory ruling under certain circumstances. Approved customer-side distributed resources projects are eligible for long-term financing and the natural gas, and backup power subsidies described above, but not the capital subsidy. Approved proposals from parties other than the electric companies are eligible to enter into long-term capacity purchase contracts with the companies, with DPUC approval.

If an electric company proposal is selected in the RFP process, the company can own and operate the approved project. But it can recover no more than the full costs identified in its proposal. The revenues from the project do not count in DPUC’s determination as to whether the company’s rates are just and reasonable. After five years of operation, the company must either sell the plant or auction off the power and capacity associated with it. The auction must be conducted under a plan approved by DPUC; by law sales of utility assets are subject to DPUC approval. DPUC must waive these requirements, after notice and hearing, if it determines that compliance with them would harm the company’s customers. The company is entitled to recover, through the FMCC charge, the unrecovered part of the project’s full projected costs as identified in its bid.

Approval of Long-term Capacity Contracts. If DPUC approves a bid for a long-term contract, the electric company must negotiate in good faith the final terms of the contract with bidder and must submit the contract to DPUC for its approval. After 30 days, either party can request DPUC’s assistance in resolving any outstanding issues. Contracts must have DPUC approval to go into effect. The contract must have provisions to mitigate long-term risks to consumers.

DPUC must, in a contested case, approve, reject, or modify a long-term contract. The contract must contain terms to mitigate the long-term risks assumed by ratepayers and cannot have a term exceeding 15 years. For DPUC to approve a contract, it must (1) result in the lowest reasonable costs, (2) increase reliability, and (3) minimize FMCCS over time. Utilities that enter into such contracts must either sell capacity rights into market or retain them for services they provide to customers who do not choose competitive suppliers, as determined by DPUC. Contracts costs are recovered through the FMCC charge.

Electric Company Award for Generation Projects

Under the bill, if DPUC selects a bid from an entity other than an electric company for grid-side distributed resource or new generation facilities, the electric company that serves the area where the project would be located receives an award for investments necessary for improvements to its transmission and distribution system to accommodate the facilities. For facilities that become operational by January 1, 2008, the award is $ 25 per kilowatt. For those that become operational by January 1, 2010, the award is $ 15 per kilowatt, and for those that become operational by January 1, 2012, the award is $ 5 per kilowatt. No award can be granted unless the projected reductions in FMCCs from the project are greater than the amount of the award. The costs of the awards are recovered from the FMCC charge. Revenues from the award do not count in DPUC’s determination of whether the company’s rates are just and reasonable.

Miscellaneous Provisions

By law, a Siting Council certificate is needed to build most types of power plants, and one of the factors the council must consider is whether the plant produces a public benefit. The bill establishes a rebuttable presumption that there is public benefit in building the projects approved by DPUC in the RFP and projects that DPUC has ordered a company to build.

The bill exempts all of the DPUC-approved or –ordered projects from a provision of existing law that requires applications for power plants to go through an RFP process administered by the Connecticut Energy Advisory Board.

Notwithstanding other provisions of law, DPUC may conduct additional RFPs to reduce FMCCs and approve proposals in order to meet its statutory obligations. DPUC can order an electric company to bid in the initial or subsequent RFPs.


Under the bill, the utilities submit time of use rate plans to DPUC by October 1, 2005. The plans must provide for (1) optional interruptible/load response for commercial and industrial customers with at least 350 kilowatts of demand and (2) optional time of use and seasonal plans for other customers, both to go into effect June 1, 2006. By October 1, 2005, utilities must also submit plans to implement mandatory peak, shoulder, and off-peak time of use rates for customers with 350 kilowatts of demand to go into effect by January 1, 2007, which can be provided through a procurement plan and/or revenue neutral rate adjustments. Finally, the utilities must submit plans by November 1, 2005 to implement mandatory seasonal rates for all customers, going into effect on April 1, 2007.

Utilities must provide customers with comparative billing information regarding mandatory time of use and seasonal rates. Utilities must help customers manage loads/reduce peak consumption through their conservation plans.

DPUC must hold a contested case on whether to approve the rates. To be approved, (1) rates must reasonably reflect costs, (2) the benefits must justify the costs of implementation and the impact on customers, and (3) the rates must alter consumption patterns without undue adverse effects on customers.

DPUC must hold a contested case to determine standards and process by which commercial and industrial customers can opt out of mandatory time of use rates until July 1, 2010. It must issue its decision by January 1, 2006.


The bill exempts new customer side distributed resources from backup charges if the resource’s capacity is less than peak load and the resources are available to the system during peak periods. The costs of this measure are recoverable through the FMCC charge. The customer has to pay other applicable charges.


The bill entitled electric companies to recover the costs they prudently incur under the bill. The recovery can be through the FMCC charge, rate basing, or the energy adjustment clause. If the company’s rate of return is below its authorized rate of return for six consecutive months, it is also eligible to offset lost earnings. In any case, it is eligible to earn an incentive on its costs in implementing the bill. DPUC must hold a contested case to determine the appropriate recovery mechanisms.


Under the bill, electric companies and competitive suppliers must get part of their requirements from Class III resources, i. e. various types of distributed resources from commercial and industrial customers. Starting January 1, 2007, companies must get 1% of their standard service supply from these resources. (The companies must provide standard service to small and medium size customers who do not choose a competitive supplier. ) Suppliers must get 1% of their total output from Class III resources. This proportion increases by 1% in each of the following three years. The resources must meet Department of Environmental Protection air standards to be eligible. An electric company can contract with its wholesaler for the wholesaler to meet the standard. DPUC must annually conduct a contested case to determine whether the wholesaler met its responsibility.

If a company, supplier, or wholesaler does not meet the standard, it must pay up to 5. 5 cents for each kilowatt-hour of its shortfall. Three quarters of the penalty payment goes to the company’s conservation fund and one quarter to the Clean Energy Fund. If the wholesaler is responsible the penalty goes first to the electric company, which must immediately transfer it into the funds. Such money does not count as utility revenue or income.

Companies and suppliers can meet the standard by participating in a DPUC-approved credit trading program. DPUC must complete a contested case by February 1, 2006 to specify the program’s administrative process and specifications. Among other things, this case must establish (1) the way that qualifying activities are certified, tracked, and reported; (2) how credits are created, accounted for, and transferred; (3) mechanism to avoid double counting credits. DPUC can retain a consultant to help it develop and operate the program.

At least 25% of the credit must go to the person who conserved or generated the electricity. DPUC must establish a schedule by January 1, 2007 for splitting the credit between such persons and the conservation funds, but can give the person a larger share. DPUC must consider the incentives received by such person and the impact of the measure on FMCCs in splitting the credit. The part of the credit going to the funds must be used for demand response/peak reduction programs.


The bill requires municipal electric utilities to charge at least 1. 0 mill per kilowatt-hour sold for conservation and load management programs in 2006, with the charge increasing in four steps to 2. 5 mills by January 1, 2011. The charge does not apply to sales to the U. S. naval facilities base.

The money goes into a special nonlapsing fund held by CMEEC, which must develop an annual conservation plan for member utilities. The plan may direct the expenditures of the fund to any of the areas served by the municipal utilities. It may provide for (1) the establishment of goals and standards for measuring the cost effectiveness of the fund’s expenditures, (2) maximizing the reduction in FMCCs, and (3) achieving appropriate geographic scope and balance. The plan must be consistent with the comprehensive plan developed by the Energy Conservation Management Board. CMEEC must submit its plan to the board for review.


The bill allows the Siting Council to approve by declaratory ruling customer-side and grid-side distributed resources projects with a capacity of up to 65 megawatts that meets DEP air quality standards.

By law, the Siting Council must approve, by declaratory ruling, a new power plant that is not coal- or nuclear fueled and that is built on the site of a plant that was in existence before July 1, 1998. The bill extends this provision to sites where plants were operating before July 1, 2004.


The bill specifies that its provisions apply to distributed resources developed in Connecticut that add capacity on or after January 1, 2006 and in accordance with its provisions.


The bill requires DPUC, the Energy Conservation Management Board, and the utilities to establish links on their websites to the federal Energy Star energy efficiency program.


The bill requires DPUC to investigate how best to decouple earnings of gas companies and other utilities from their sales in order to promote the state’s energy policy. DPUC must report findings and recommendations to the Energy and Technology Committee by January 1, 2006.


Under current law, gas companies must submit conservation plans to DPUC by October 1 in even-numbered years. The plan must establish quantitative targets, describe conservation options, and estimate the costs and benefits of these options. DPUC must hold a hearing on the plan and can require a company to update its plan in odd-numbered years.

The bill instead requires gas companies to follow the same procedures as electric companies in developing and evaluating their conservation plans. The bill specifies the types of programs that can be included in the plan, which parallel existing provisions regarding electric conservation plans. The programs in the gas company plan must be screened on the basis of cost effectiveness. The company must submit the plan to the Energy Conservation Management Board for its review. The board must accept, reject, or modify the plan before passing on it to DPUC for final approval. By January 1 annually, starting in 2007, the board must report to the Energy and Technology Committee on gas company funding of conservation programs, how they spent the money, and the cost effectiveness of the programs. However, the bill specifies that it cannot be construed to require DPUC to establish a conservation charge to support these programs.


The bill requires the Siting Council to consider other state and municipal laws when issuing declaratory rulings, as well as certificates.


Under current law, a Siting Council certificate is needed to build a gas pipeline, other than one that has a design capability of less than 200 pounds per square inch. The bill additionally exempts pipelines that have a design capacity of less than 20% of their specified minimum yield strength.


By law, the electric companies must collectively enter into long-term contracts for 100 megawatts of capacity from renewable generating projects that meet specified characteristics. Under current law, the utilities’ costs of entering into these contracts counts towards the cap on the rates they charge for the service they provide to customers who do not choose a competitive supplier. The bill instead creates a separate rate adjustment, not subject to the cap, to recover the direct costs of the contracts and the utilities costs in procuring the contracts.


The bill additionally requires that these projects be located in Connecticut. The bill delays, from July 1, 2007 to July 1, 2008, the deadline for the utilities to submit their procurement plans to DPUC for its approval.

The bill gives project developers an additional option on how the electricity from the selected projects will be priced. Under current law, the developer is entitled to the wholesale electricity price plus 5. 5 cents per kilowatt-hour. The bill allows the developer to opt to receive the sum of the following: (1) half of the wholesale electricity price, (2) the projected cost of natural gas used to fuel the project, based on the futures price of contracts measured at the Henry Hub, Louisiana, (3) the charge for delivering the fuel to the project, and (4) 5. 5 cents per kilowatt-hour.

Under current law, the utilities entering into these contracts receive the renewable energy credits associated with the project. The bill provides, that in the case of fuel cell projects that are principally manufactured in the state, the project developer keeps half of these credits, plus all of the air emission reduction and tax credits associated with the project.

Under the bill, this adjustment will continue under the standard service the utilities are required to provide starting in 2007. By law, utilities must provide this service to any customer with a demand of less than 500 kilowatts who has not chosen a competitive supplier.


Under the bill, DPUC must, by October 1, 2005, conduct a study to determine (1) a reasonable amount of compensation for electric companies for providing standard service and (2) whether each company should receive compensation for providing last resort service for large business customers. In making its determination, DPUC must consider the costs the companies will incur in providing such services, the risks they will sustain, the value to the companies' customers in providing such services, and the amount that a private third-party entity would seek as compensation for procuring contracts for the services. By February 1, 2006, DPUC must report its recommendations to the Energy and Technology Committee.


The bill establishes new information disclosure requirements for electric companies and suppliers, changes the frequency and timing of reports they must make to DPUC, and makes related changes.


The bill allows DPUC to adopt regulations establishing the terms and conditions under which companies subject to its jurisdiction and municipal utilities may terminate service for reasons other than nonpayment of a delinquent account. This provision applies to electric, gas, telephone, and water companies; competitive electric suppliers; and certified telecommunications providers (e. g. , long distance carriers), as well as municipal electric, gas, water, and telecommunications companies.


The bill requires that cable TV advisory councils report to the DPUC on the funding or services they receive from cable TV companies by January 31, rather than January 1, each year.


The bill increases, from $ 5,000 to $ 10,000 per violation, the maximum civil penalty for telecommunications companies, their affiliates, and representatives that the DPUC determines have violated telemarketing laws and laws governing switching service and billing for telecommunication service.


By law, municipalities can apply for a DPUC franchise to provide cable TV services. The bill exempts from municipal bonding limits bonds or other evidence of indebtedness issued for the construction and operation of cable TV systems.


The bill requires DPUC to conduct a proceeding to determine whether there is a practical, cost-effective process for an electric company customer, when beginning service with the company, to receive information on selecting generation services from a qualified entity. DPUC must complete the proceeding by December 1, 2005 and implement its decision by March 1, 2006 or a later date it considers appropriate. The company can recover its costs in participating in the proceeding and implementing DPUC's decision in DPUC-approved generation services cost adjustment.


By law, electric companies and competitive suppliers must get part of their power from class I renewable resources such as wind and class II resources such as trash to energy plants. The bill delays, until January 1, 2010, when they can get such power from Delaware, Maryland, New Jersey, New York, or Pennsylvania.


The bill requires DPUC, by January 1, 2006, to establish a program to grant awards equal to $ 25 per kilowatt-year to the companies for specified conservation programs approved by DPUC and developed in Connecticut on or after January 1, 2006. The programs are for load curtailment, demand reduction, and retrofit conservation that reduce FMCCs. This program runs from January 1, 2006 to December 31, 2010. No award can be made unless the projected reduction in FMCC costs exceeds the award amount.

Funding for the awards and the companies’ costs in establishing the conservation program comes from the FMCC charge. Revenues from the programs do not count in DPUC’s determination of whether a company’s rates are just and reasonable. The companies must report to the Energy Conservation Management Board by January 31 annually on its activities under this section. The reporting requirement runs from 2007 to 2011, unless extended by the board.


The bill generally requires that any sale or other disposition of real property that is an essential part of a utility regulated by DPUC be done by public auction or other public sale procedure. (By law, such dispositions require DPUC approval. ) The bill gives DPUC the authority to allow the utility to use an alternative sale process if it makes a finding of good cause.

The bill requires that there be notice of the auction or sale at least once per week in the two weeks before the auction or sale. The notice must run in a newspaper with substantial circulation in the county where the property is located. The utility must give DPUC evidence that it provided the notice.


By law, structures and equipment acquired for the purpose of air or water pollution control are exempt from the property tax. The bill specifies, in the case of water pollution equipment and structures, the exemption applies to acquisitions by lease and purchase, as is already the law with regard to air pollution control equipment and structures. The bill specifies that an owner or lessee of the equipment or structure who wishes to claim the exemption, rather than any person who claims the exemption, may file the Department of Environmental Protection (DEP) certificate needed to obtain the exemption. It allows the assessor to specify the form and manner the application is made.

The bill requires that, if there is a new owner or lessee of the structure or equipment, it must file a revised application with the assessor by the November 1st immediately following the end of the assessment year during which such change occurs. However, in the 2005 assessment year, a revised application may be filed when there has been a change in ownership during any assessment year and the exemption continued to be granted for each assessment year following such change. If the structures and equipment have not been altered in any manner, the new owner or lessee is entitled to a continuation of the exemption and does not have to obtain or provide a DEP certificate.


The bill increases DPUC’s FY 06 appropriation for personal services from $ 10,754,193 to $ 10,940,000, and its FY 07 appropriation from $ 11,106,405 to $ 11,397,000.


The bill repeals obsolete provisions regarding foreign (out-of-state) and domestic electric companies.