You asked for a summary of sHB 6906, An Act Concerning Energy Independence, favorably reported by the Energy and Technology Committee.

SUMMARY

The bill establishes incentives for installing distributed electric generation (fuel cells and other technologies) on customer premises in order to reduce federally mandated costs associated with transmission congestion. It requires the existing Conservation and Load Management and Clean Energy funds to give a preference to funding projects that maximize the reduction in these congestion costs. It bars the funds being used for purposes other than what is specified in current law.

The bill requires the Department of Public Utility Control (DPUC) to identify where it would be appropriate to install distributed generation connected to the transmission and distribution grid. DPUC must issue a request for proposals (RFP) for such projects by October 1, 2005. Connecticut Light & Power and United Illuminating cannot bid on the RFP, but their generation affiliates can. The utilities must make their property available to distributed generation developers for fair market value. DPUC must approve any resulting power supply contract between the utility and the generation developer.

After January 1, 2006, the utilities can build, own, and operate grid-connected distributed generation, with DPUC approval, to meet the need identified in the DPUC analysis that was not met by the developers.

The bill requires the utilities and competitive electric suppliers to acquire 1% of their supply from conservation and customer-side distributed generation starting in 2007. This proportion increases to 2% in 2008 and 4% in 2010.

Under the bill, the utilities 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 allows DPUC and the Connecticut Energy Advisory Board to jointly direct a utility to issue an RFP for long-term contracts for the capacity of generating plants. Contracts are subject to approval by DPUC, contingent on increasing reliability and reducing long term costs. The utilities must either sell the capacity on the wholesale market to reduce congestion costs or use it to offset their costs in providing the service they must provide to customers who do not choose a competitive supplier.

The bill entitles the utilities to recover their costs and investments incurred pursuant to its provisions through several mechanisms. It modifies how programs are selected for funding by the Conservation and Load Management funds.

In addition, the bill:

1. requires DPUC to conduct an assessment of distributed generation and report its findings to the Energy and Technology Committee;

2. allows Connecticut Innovations, Inc. , which administers the Clean Energy Fund, to invest in combined heat and power (cogeneration) and waste heat recovery systems;

3. requires municipal electric utilities to spend at least 3% of their gross revenues on conservation and load management;

4. reduces, from 500 to 100 kilowatts, the maximum demand a customer must have to be eligible to be directly billed by a competitive supplier rather than a utility; and

5. requires, rather than allows, purchased gas adjustment clauses to contain a provision that reflects the difference between actual and projected retail sales (such clauses modify gas rates to reflect changes in the cost of gas the companies buy from wholesalers).

CUSTOMER INCENTIVES

Under current law, distributed generation is considered the generation of electricity on a customer’s premises using technologies such as fuel cells, photovoltaic systems, and small wind turbines. The bill instead uses the term “customer-side distributed generation. ” The new term additionally includes systems that reduce a customer’s peak electricity demand. On the other hand, the new term appears to exclude systems that take power directly from the transmission system, e. g. , very large manufacturers.

The bill establishes incentives for newly developed customer-side distributed generation, including: (1) subsidies to reduce the capital costs of the generation, paid from the Conservation and Load Management and Clean Energy funds, (2) long term financing for distributed generation and associated monitoring and metering equipment provided by a third party selected by DPUC, (3) reduced natural gas rates and possible waiver of electric back up charges, with the costs paid by electric ratepayers and (4) an expedited Siting Council approval process for certain facilities.

Capital Cost Subsidy

The bill requires DPUC to provide a $ 100 to $ 200 per kilowatt subsidy for new customer-side distributed generation. The amount of the subsidy depends on the effect of the generation on congestion costs. DPUC must establish the actual subsidies in a contested case (a quasi-judicial proceeding). The subsidy comes from the Conservation and Load Management and Clean Energy funds.

Long-term Financing

The bill requires DPUC to select one or more entities through a competitive bid process to provide long-term financing for distributed generation and associated advanced power monitoring and metering equipment. The entity cannot be a utility, but can be its generation affiliate. DPUC can retain a consultant to help it pick the entity or entities. The cost of the consultant is recovered through the systems benefit charge on electric bills.

The financing can cover the capital and on-going operations and maintenance costs of such system, among other things. Although it does not appear that DPUC provides long-term financing under the bill, the bill states that DPUC must give preference to projects, “on providing financing” to projects that maximize the reduction of congestion costs.

People receiving financing from the selected entity must enter into a contract with a utility to provide billing and collection services for payment of the principal and interest of the financing. Any costs that the utility prudently incurs in providing these services (including costs associated with a customer’s nonpayment) are recoverable in the utility’s rates as an operating expense.

Natural Gas Rates

The bill also requires gas companies to waive the delivery charge they impose on customers that install distributed generation. The company must report the resulting revenue loss to DPUC. DPUC must recover this revenue by adjusting the rates of the affected electric utility and transferring the revenue to the gas company. DPUC must adopt regulations to implement this provision.

Back-up Rates

Utility customers with on-site generation must pay the utility a charge for the back-up power that the utility may be required to supply if the customer’s generation capacity becomes unavailable. The bill waives this charge if a customer has distributed generation capacity that (1) is less than the customer’s maximum electric load (demand) and (2) is reasonably available to support system-wide capacity requirements. The utility can recover the costs associated with this waiver.

Expedited Siting Council Approval

By law, a Siting Council certificate is required to build most types of utility facilities, but the council can approve certain types of facilities under a more expedited process called a declaratory ruling. The bill expands the latter option to customer-side distributed generation facilities that have a capacity of up to 25 megawatts and meet Department of Environmental Protection air quality standards.

GRID-CONNECTED DISTRIBUTED GENERATION

The bill requires DPUC to identify (1) the most advantageous locations to develop distributed generation facilities with capacity of up to 40 megawatts connected to the transmission and distribution grid and the appropriate size, fuel source, and operating features of such facilities; and (2) grid-side distributed generation projects that are needed primarily for grid stability, voltage support, or to otherwise improve the operation and reliability of the grid. DPUC must consult with the Connecticut Energy Advisory Board, the entity that operates the regional grid, the utilities, and other parties DPUC considers appropriate in making its identification, which it must complete by August 1, 2005.

DPUC must, by October 1, 2005, develop and issue an RFP for development of the first kind of projects. A utility cannot submit a proposal but its generation affiliate can, subject to the existing code of conduct that governs interactions between utilities and their affiliates. DPUC can retain a consultant with expertise in the area of energy procurement or project development to oversee the development of the RFP and the procurement of contracts between the utility and generators. The reasonable and proper expenses of retaining the consultant can be recovered through the systems benefits charge on electric bills.

Each utility must, within 60 days after the issuance of the RFP, identify any of its real property in the areas identified by DPUC that could be (1) beneficial or suitable for the development of distributed generation and (2) leased or sold to the winning bidder. DPUC may order the utility to sell, lease, or assign such property, provided that the utility receives fair market value for it. The conveyance is subject to an existing law that requires DPUC approval of transfers of utility property, but transfers to a nonaffiliated entity do not have to go through a public sale or auction.

If a utility enters into a contract to buy the power from a project, the contract must be approved by DPUC to go into effect. DPUC must review the contract in a contested case. DPUC cannot approve a contract unless it (1) results in the lowest reasonable cost, (2) increases reliability, and (3) minimizes congestion costs over time. Such contracts cannot run for more than 15 years.

Starting January 1, 2006, the utilities can submit proposals to develop, own, and operate grid-side distributed generation projects in the locations identified by DPUC that were not the subject of a proposal submitted by other developers. The proposal must describe how the utility will use of sell the capacity and energy associated with the project. Each utility can own up to 100 megawatts of such capacity, notwithstanding the existing law that bars them from owning generation facilities. DPUC must, in a contested case, approve, reject, or modify the proposal. DPUC cannot approve a project unless it (1) results in the lowest reasonable cost, (2) increases reliability, and (3) minimizes congestion costs over time.

LONG TERM CAPACITY CONTRACTS

The bill allows DPUC to consult with the Connecticut Energy Advisory Board to recommend the size, location, fuel source, and operating features of new operating plants (not just distributed generation), in order to minimize electric capacity costs, including congestion costs, over time. Based on these recommendations, DPUC may direct a utility to develop and issue an RFP to solicit long-term contracts for electric capacity rights in the area where the utility operates. (Generators sell their facility’s capacity, i. e. , its ability to generate power on the wholesale market, as well the power it actually produces. An analogy would be an attorney’s retainer vs. his hourly rate. ) The proposal must encourage diversity in types of generation and the fuel they use.

DPUC can retain a consultant with expertise in the area of energy procurement to oversee the development of the RFP and the procurement of contracts between the utility and generators. The reasonable and proper expenses of retaining the consultant can be recovered through the systems benefits charge on electric bills.

A contract between a utility and generator must be approved by DPUC before it can go into effect and can run for no more than 15 years. The department must hold a contested case on the contract. To be approved, DPUC must find that the contract increases reliability and minimizes electric capacity over time. The costs of such contracts must be recovered through the congestion costs component of electric bills.

UTILITY COST RECOVERY MECHANISMS

The bill entitles the utilities to recover, through several mechanisms, the costs and investments they prudently incur under its provisions.

These mechanisms are:

1. traditional rate-making;

2. the energy adjustment clause, which allows rates to be adjusted to reflect changes in such things as fuel and purchased power costs and conservation expenditures; and

3. the systems benefits charge, which covers the costs of various public policies regarding the provision of electricity.

In addition, if a utility’s loses earnings due to decreased sales caused by the bill, the lost earnings can be recovered through rates under an existing mechanism.

CONSERVATION/DISTRIBUTED GENERATION PURCHASING REQUIREMENT

By law, the utilities must provide, starting January 1, 2007, “standard service” to small and medium size customers who do not choose a competitive supplier. The bill requires utilities, with regard to this service, and competitive suppliers to demonstrate to DPUC, starting January 1, 2007, that 1% of their total power supply comes from conservation or customer-side distributed generation. The proportion increases to 2% starting January 1, 2008 and 4% starting January 1, 2010. Power from distributed generation must come from facilities that meet the Department of Environmental Protection’s air quality standards in order to count towards this requirement. If a utility or supplier does not meet this standard, it must pay a 5. 5 cents charge for each kilowatt-hour of its shortfall. Half of this charge goes to the Conservation and Load Management Fund and half to the Clean Energy Fund.

Alternatively, a utility or supplier can meet the requirement by participating in a DPUC-approved renewable energy program. Under this program, the person that saved energy or installed customer-side distributed generation retains 10% of the credit attributable to his action. The remainder goes to the Conservation and Load Management Fund for demand response and peak reduction programs (these programs change the timing of power consumption to reduce demands on the electrical system. )

SEASONAL AND TIME OF USE RATES

The bill requires each utility to submit an application to DPUC by September 1, 2005 to implement (1) daily time of use rates that would be mandatory for customers that have a maximum demand of 350 kilowatts or more (i. e. , approximately half of the demand of the Legislative Office Building) and (2) optional time of use rates for all customers. All of these rates would go in effect starting June 1, 2006. The application must establish the rates through a procurement plan, revenue neutral adjustments to the delivery component of electric rates, or both. In addition, the bill requires each utility to submit application to DPUC by September 1, 2006 to implement rates that vary by season that would be mandatory for all customers starting June 1, 2007.

DPUC must review the applications in a contested case. It can only approve a rate if it finds that it would reasonably reflect the cost of service during peak and off-peak period and (2) the implementation costs, impact on customers, and benefits to the system justify implementing the rates.

From March 1, 2006 through May 31, 2006, the utilities must issue comparative bills to customers with demand of 350 kilowatts or more showing how the proposed rate change would affect them. Any customers on daily time of use rates are eligible for the bill’s benefits from June 1, 2006 through May 31, 2007. The utilities must help all customers manage loads and reduce peak consumption.

CONSERVATION AND LOAD MANAGEMENT FUNDS

By law, each utility must establish a conservation and load management fund, which is funded by a charge on customers’ electric bills. The Energy Conservation Management Board must assist each utility in developing and implementing its plan for the use of its fund, which is subject to DPUC approval.

By law, to be included in the plan, a conservation program must be cost-effective. The bill specifies that the determination of program benefits include system benefits, including reduction in congestion costs. It requires that the board give preference to projects that maximize the reduction of these costs. Under the bill, programs in the plan may not be subject to a requirement that the distribution of program funding among customer classes reflect each class’s contributions to the fund.

DPUC ASSESSMENT AND REPORT

The bill requires DPUC to conduct an assessment by January 1 annually, starting in 2007, on:

1. the number and type of customer-side and grid-connected distributed generation facilities;

2. projects financed under the bill; and

3. the projects’ contributions to achieving fuel diversity, transmission support, and energy independence in the state.

DPUC must, by January of every odd-numbered year, collect the information in the assessments and report its findings to the Energy and Technology Committee.

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