Citizens Utility Board | Consumer Information | Electric

HB 362 provides immediate rate reductions to all residential customers. The amount of the reduction depends upon how the utility's average residential rate compares to the average rate for large investor-owned utilities in the region.

Utility	Date	Residential Rate Cut

Rates above the Midwest average (ComEd and Illinois Power)	August 1, 1998	15 percent

	May 1, 2002	5 percent

Rates below Midwest average (CIPS, Union Electric)	August 1, 1998	5 percent

	October 1, 2000	The lesser of 5 percent or the percent by which rates exceed the 1999 Midwest average.*

	October 1, 2002

Rates less than 90% of the Midwest average, and utility serves between 150,000 and 250,000 customers in Illinois (CILCO)	August 1, 1998	2 percent

	October 1, 2000	2 percent

	October 1, 2002	1 percent

* If these utilities' residential rates are still below the Midwest average, no additional rate reductions will be required in these years.

Utilities that have reduced their rates after October 1, 1996 (e.g., MidAmerican) will be allowed to count those rate reductions toward the total rate decrease.

A utility that elects to file full rate proceedings before the Illinois Commerce Commission ("Commission") in 1998, 2000, and 2002 will not be subject to the automatic rate decreases. Instead, they will be subject to rate decreases that may result from these rate cases.

Access to the Competitive Market

Customers will be allowed to purchase power from alternative electric suppliers according to the following schedule:

Industrial and commercial customers with a demand of at least 4 megawatts; commercial customers with businesses at ten or more sites with an aggregate coincident peak demand of 9.5 megawatts or greater; and non-residential customers accounting for one-third of the remaining electricity use of their customer class.	October 1, 1999

All other non-residential customers.	December 31, 2000

All residential customers.	May 1, 2002

Limited Stranded Cost Recovery

For some utilities, particularly those owning expensive nuclear plants, the market price paid for electricity under competition is likely to be too low to cover all their costs. The investments that cannot be recovered from the sale of power on the market are termed "stranded costs." HB 362 allows utilities to recover a limited portion of their stranded costs. CUB estimates that residential customers are likely to pay less than 50 percent of what their stranded cost payments would be under full recovery.

Stranded costs will be recovered through a "transition charge" paid by all customers who choose to purchase electricity from an alternative suppliers. Transition charges will be calculated per kilowatt-hour according to the following formula:

Foregone revenue (revenue that would have been received from the customer, adjusted for rate decreases)
- revenue from delivery services (transmission, distribution, administrative and other services)
- market value of the electricity no longer purchased from the utility
- mitigation factor (a percentage of the foregone revenue).

The amount collected from transition charges falls below the total stranded costs because:

The formula includes a mitigation factor, which increases over time.
The foregone revenue is reduced by the 20 percent rate reduction, thus lowering the transition charges.
The transition charges are paid only until 2006, after which the utility must absorb any remaining stranded costs.

The table below shows the residential customer mitigation factors and the total likely savings for customers who purchase power from alternative suppliers.

Year	Mitigation Factor	Total Savings*

May - December, 2002	6 percent	24.8 percent

2003	7 percent	25.6 percent

2004 - 2005	8 percent	26.4 percent

2006	10 percent	28 percent

*The total savings are slightly below the 20% rate reduction plus the mitigation factor, because the Litigation factor is a percentage of the reduced rates.

For nonresidential customers, the mitigation factor is determined as follows:

Year	Mitigation Factor equals the greater of:

October, 1999 -2002	0.5 cents or 8 percent

2003 - 2004	0.5 cents or 10 percent

2005	0.6 cents or 11 percent

2006	0.9 cents or 12 percent

Services Provided by the Utility

The electric utility will be required to offer all services that it currently offers until such services are declared competitive. Once a service has been declared competitive, it will no longer be subject to regulation, except for the consumer protection requirements of the bill. The operation and maintenance of the transmission and distribution system, however, is unlikely to be declared competitive, and will therefore continue to be provided by the utility. Transmission, distribution, metering and billing, collectively known as "delivery services," will be provided by the utility at cost-based rates approved by the Commission. Rates for delivery services will be established in tariffs filed by utilities and approved by the Commission prior to the time that customers become eligible to purchase power from alternative suppliers. Utilities must allow suppliers to issue a single bill and pay the customers' delivery services charges to the utility.

Competitive services are defined as services provided under a special contract, services that are not provided under a tariff, and any service that the Commission declares to be competitive in response to a utility petition. A service will only be declared competitive if:

It is being offered by a provider other than the utility to a defined customer group or geographic area at a comparable price.
The utility is likely to lose or has lost business to the competitor.
There is adequate transmission system capacity to deliver electricity to customers.

The Commission may later rescind the competitive declaration if it finds that a service no longer meets the criteria.

A number of provisions in the bill ensure that residential and small commercial customers who choose not to or are unable to purchase power on the competitive market will still benefit from lower market prices.

Although all customers will be allowed to purchase electricity in the competitive market by May 2002, electricity may not be declared competitive for residential and small business customers until 2007, and only if there is sufficient transmission capacity for full competition.
After 2005 and before it is declared competitive, the electricity generation component of tariffed rates will not be allowed to exceed 110 percent of the market price.
After electricity is declared competitive, residential and small commercial customers will still have the option to purchase "bundled" service from the utility, meaning that they may pay a rate that includes all services - generation of electricity, transmission, distribution, metering, and billing. The generation component of the bundled rate will reflect the market price of electricity, determined either by the neutral fact-finder (described later) or by the cost to the utility of obtaining power at wholesale through an arms-length bidding process.
Residential customers will be allowed to select real-time pricing by October 1, 2000, which allows customers to pay a price for electricity that varies according to the hour or other period of time when the electricity is used. Under real-time pricing, customers could save money by using more electricity at times when it is cheapest.

Utilities may request to have rates for regulated services established through "alternative regulation," a method for setting rates, such as a price cap plan, that allows the utility and its customers to share the benefits of cost reductions and revenue increases. (Under cost-based regulation, a utility that reduces its costs or increases its profits may be required to reduce its rates to reflect the lower revenue requirement.) The Commission may only approve an alternative regulation plan if it finds that the plan is likely to produce rates that are lower than would result from cost-based regulation, not compromise reliability, produce substantial and identifiable benefits, not impede competition, and not deteriorate the utility's financial condition.

Utilities will be permitted to conduct billing and pricing experiments for groups of customers with common attributes. These experiments may include consolidated billing for customers under common ownership, real-time pricing or other billing or pricing experiments.

ComEd must allow the City of Chicago and four local agencies to aggregate their electricity use and demand for billing purposes according to an intergovernmental agreement that has been signed by those parties. This consolidated purchasing is likely to result in significant savings. The parties to the agreement will be able to begin purchasing from alternative suppliers by October 1, 2000.

Determination of Market Value

An estimate of the market value of electricity will be required to calculate the transition charges, and to establish the generation component of bundled services. This market value will be determined by one of two methods:

The utility calculates the market value based upon an index of prices at which electricity is bought and sold at an exchange or through contracts; or
A "neutral fact-finder," appointed by the Commission each year, reviews utility contracts for the sale and purchase of electricity and determines an average market price per kilowatt-hour for the electricity sold to each customer class of each utility.

Transmission and Distribution System Reliability

HB 362 contains new requirements regarding the operation and maintenance of the transmission and distribution system. All utilities and alternative suppliers that own, control or operate transmission and distribution facilities will be required to adopt a plan for restoring service following transmission and distribution outages to all customers. These entities will also be required to report the following information to the Commission on an annual basis:

The number and duration of all outages and their effects on customers.
Outages that were exacerbated by the conditions of the facilities or equipment, or actions of operating personnel.
Outages that were caused solely by actions of utility employees or alternative suppliers.
The age, condition and performance of the transmission and distribution system and investments in the system.
A survey of customer satisfaction.
Plans for future investment and reliability improvements, and implementation of plans stated in prior reports.

The Commission will review this information every three years for the purpose of identifying and making recommendations on potential reliability problems.

In addition, ComEd will be required to:

Maintain records of each power outage, fluctuation, or reduction of at least 50% of voltage.
Make reasonable efforts to notify potentially affected customers in advance if maintenance or repairs will result in power losses or reductions.
Compensate customers for damages and reimburse municipal, county or local agencies for emergency expenses in the event of a power outage that affects more than 30,000 customers. For power surges or fluctuations affecting more than 30,000 customers, ComEd shall pay the replacement value of all goods that were damaged. The company may receive a waiver from these provisions if it can demonstrate that the outage, surge or fluctuation was caused by events that were outside of the utility's control.

A key component of a reliable transmission system is an entity that can oversee the entire grid and manage the complex power flows, prevent gridlock, and ensure equal access. HB 362 requires all Illinois utilities owning or controlling transmission facilities establish or join an Independent System Operator (ISO) that will manage and control transmission facilities, ensure that buyers and sellers of power have equal access to the grid, direct transmission activities, and ensure that needed transmission maintenance and upgrades are implemented. The ISO will also establish a competitive exchange auction for power in the event that a spot market or other real-time market-based exchange does not develop for electricity. If a utility does not join an ISO, it will be required to transfer control of its transmission facilities to an Illinois ISO that will be established by a legislatively created oversight board.

Consumer Protection

HB 362 requires that all alternative retail electric suppliers receive certification from the Commission to sell power to customers in Illinois. "Alternative retail electric suppliers" are sellers of electricity other than the incumbent utility. Electric cooperatives, municipal corporations, utilities owned or operated by public institutions of higher education, customers that obtain their own power from self-generation or cogeneration, or customers owning their own distribution facilities are all excluded from this definition. Municipalities and cooperatives, however, may ask to be defined as an alternative supplier.

A supplier may be certified to sell electricity services throughout the state or to customers in a specified geographic area. In order to receive certification, the supplier must demonstrate that it possesses sufficient technical, financial and managerial resources to provide the services for which it is seeking certification. Certified suppliers will be required to:

Comply with all federal, state, regional and industry rules concerning the safe and reliable operation of the transmission system.
Follow all informational or reporting requirements established by the Commission.
Observe rules for standards of service, winter shut-off restrictions, deferred payment plans, safety standards, and accident reporting that are currently applicable to utilities.
Obtain verifiable written customer authorization prior to changing suppliers. Such authorization will prevent "slamming," the practice of switching a customer without their knowledge.
Establish and maintain call centers where customers can reach a representative of the supplier.
Provide "reciprocity" to the host utility if the alternative supplier or its affiliates own or control transmission and distribution facilities. Reciprocity means that a supplier selling power to customers of an Illinois utility must allow the Illinois utility to sell power to the customers served by their transmission and distribution system.
Refrain from entering into an agreement which has the effect of preventing a residential or commercial customer from having access to the services of the electric utility or charging for such access.
Conspicuously state any penalties associated with the termination of the contract prior to the end of its term.
Clearly disclose all associated costs in any advertisements that make statements about prices.
Display the supplier's name, toll-free phone number, and a description of the services provided on customers' bills.

Alternative suppliers serving residential and small commercial customers (annual usage below 15,000 kilowatt-hours) will also be required to:

Adhere to non-discrimination requirements that prevent the denial of service or offering of different prices or terms to customers on the basis of race, gender, income or neighborhood.
Provide clear written disclosure of all prices, terms and conditions of their products and services in billing statements to existing customers, in marketing materials to potential customers, and to new customers prior to switching from another supplier. The Commission may adopt a standard uniform disclosure form that the suppliers must complete.
Submit documentation to the Commission that substantiates claims regarding the technologies and fuel types used to generate the electricity provided to customers.
Provide a statement to their customers, at least once a year, of the average monthly prices paid by the customer for electricity and the terms and conditions of the sales.

All of the requirements of certified suppliers will also apply to utilities that are selling competitive services.

The Commission will have the authority to impose financial penalties or revoke the certification of any supplier found to be in violation of their certification requirements, has failed to provide service to a residential or commercial customers, or is not complying with delivery services tariffs or agreements. A provider that is found to have engaged in deceptive or fraudulent behavior in the sale of services to an elderly or disabled person will be subject to a civil penalty of $50,000.

The bill creates a new Consumer Utilities Unit within the Office of the Attorney General that will have the power to intervene in, initiate, enforce and defend all legal proceedings in matters related to the marketing, sale and provision of electricity as needed to protect the citizens and energy consumers of Illinois. The Unit will automatically be a party to all hearings and investigations conducted by the Commission on electricity matters, and will have access to Commission material on a confidential basis.

Several provisions of the bill will encourage participation in the competitive market by small customers:

Small customers will be permitted to aggregate their electricity purchases, necessary for arranging contracts with suppliers. Such aggregation must meet reliability criteria established by a regional reliability council, an independent system operator or other entity overseeing the transition system.
Utilities cannot make the purchase of new meters a requirement for residential or small customer access to the competitive market, unless the Commission finds that such metering is needed to ensure reliable service. If such metering is required, alternative suppliers will be required to provide such metering at their own expense or pay the utility for the meters according to rates set in a tariff.
Customers who are purchasing power from alternative suppliers will be allowed to return to the utility upon payment of an administrative fee. Utilities will have the right to require that a customer returning to the utility remain with the utility for two years.

Consumer Education

Utilities and alternative suppliers will distribute a package of educational material to all residential and small commercial customers before such customers become eligible purchase power on the competitive market. The information package will be developed by a working group consisting of representatives of utilities, residential customers, small businesses, alternative suppliers, and the Commission, and will at a minimum include the following information:

How the new electricity market will function.
Services provided by and choices available from alternative electricity suppliers and the existing utility.
Consumer rights, risks and responsibilities.
Legal obligations of alternative suppliers.
The types of products and services that may be offered in the new market.
The meaning of the different components of electricity bills.
Procedures for filing complaints against alternative suppliers.
Additional information that is available upon request from the Commission.

The Commission will be responsible for:

Distributing the information packet to consumers upon request and posting the information on their website.
Answering questions from consumers.
Providing guidelines to customers on selecting among options offered by energy suppliers. MLI> Maintaining a list of certified suppliers serving residential and small commercial customers, indicating those who have been found to be in violation of the terms of their contracts.

Funding for the Commission's expenses in conducting the education program will be appropriated from the state General Revenue Fund, including the costs of printing the materials.

Development of a Competitive Market

The Commission will have the authority to take the following steps to encourage the development of a competitive market for electricity.

Establish standards of conduct for utilities ensuring that the utility allows customers to purchase electricity from alternative suppliers and provides generation, delivery services, competitive and non-competitive services in a manner that does not discriminate among customers and that promotes efficient competition.
Investigate the need for and require, if necessary, the functional separation of generation from delivery services. (Such a separation will help ensure that revenues collected for delivery services are not used to subsidize generation prices, which would give the utility an unfair competitive advantage.) After 2003, the Commission may also investigate and require functional separation of competitive and non-competitive services.
Conduct an investigation every three years after the start of direct access of the need to further unbundle delivery services tariffs into services such as metering and billing. (Unbundling allows customers to pay a separate price for each component of electric service, and thus to purchase those services from alternative suppliers.)
Adopt rules governing the relationship between the electric utility and its affiliates that require the provision of services in a manner that does not discriminate against non-affiliate companies.
Approve a merger between utilities only if the Commission finds that the merger is not likely to impede competition or result in rate increases for retail customers.

Environmental Benefits

HB 362 establishes trust funds to support the development of renewable energy sources and energy conservation programs. These trust funds will expire after ten years, unless reauthorized by the legislature.

The Renewable Energy Resources Trust Fund will be used to provide grants, loans, and other types of financial support for the development of renewable resources. This fund will receive half of the revenue collected from the following monthly charges (the other half will be deposited in the existing Coal Technology Development Assistance Fund):

5 cents from residential electric and gas customers.
50 cents from nonresidential customers with peak demands below 10 megawatts and gas usage below 4,000,000 therms.
$37.50 from large nonresidential customers.

Revenue for the fund is expected to amount to $100 million over ten years, half of which will come from residential customers.

The Energy Efficiency Trust Fund will be used to support residential energy efficiency programs, such as the replacement of windows, appliances, lighting and efforts targeted at low income customers. The fund will collect $3 million each year from all electric utilities and alternative electric suppliers, each of whom will contribute a share equal to their percentage of total electricity sales in the state.

Municipal utilities and cooperatives may decide not to contribute to the trust funds. But if they choose not to pay, their customers will not be eligible for the benefits from the trust funds.

A second environmental provision in the bill is the requirement that all electric utilities and alternative electricity suppliers provide to their customers, to the extent practicable, on a quarterly basis:

The percentage of the known sources of electricity supplied to the customer from biomass, coal, hydro, natural gas, nuclear, oil, solar, wind and other sources.
Amounts of carbon dioxide, nitrous oxides, and sulfur dioxide emissions and nuclear waste generation attributable to the known sources of electricity supplied to the customer.

Provision of Affordable Electricity to Low-Income Customers

HB 362 creates a Low-Income Energy Assistance Fund to support programs designed to provide low-income customers with access to affordable electricity. Revenue for the fund will be collected beginning in January 1998 from a monthly charge of 40 cents per month for residential electric and gas customers, $4 per month for commercial and small industrial customers, and $300 per month for large industrial customers. These charges will be levied on all customers, including those purchasing electricity from other suppliers, and are expected to generate about $75 million per year, half of which will come from residential customers. Municipal utilities and cooperatives may decide not to pay into to the low-income funds, but if they do not contribute, their customers will not be eligible for assistance from the fund.

Revenue will be available to the Department of Commerce and Community Affairs (DCCA) through appropriations. DCCA may use the funds for financial assistance, energy efficiency measures, weatherization (limited to 10 percent of the total expenditures) and administrative expenses (also limited to 10 percent). The only program currently in existence to provide energy to low-income consumers in Illinois is the Low-Income Heating Energy Assistance Program (LIHEAP). But by 2003, the funds will be used for new programs developed by a design group chaired by the Director of DCCA and comprised of representatives of the Commission, the Department of Natural Resources, electric cooperatives, local agencies, electric and gas utilities, municipalities, marketers, public agencies, and low-income, residential, commercial and industrial customers. The program design group will report its recommendations to the General Assembly on January 1, 2002, and DCCA will hold public hearings on the recommended programs during the year.

Nuclear Decommissioning

Federal law requires that nuclear plants be "decommissioned" at the time that they are taken out of service. Decommissioning entails reducing the radioactivity in the plant and the property to safe levels, including dismantling, decontaminating, entombing, removing and disposing of the plant and all radioactive materials. Utilities who own nuclear power plants (ComEd and Illinois Power) currently collect funds from ratepayers that are placed into a trust fund to be used for the eventual decommissioning of the plants.

HB 362 requires that utilities owning nuclear power plants or having a contractual responsibility for decommissioning continue to collect revenue for the decommissioning trust funds through a separate tariff approved by the Commission. Base rates would be reduced to remove the amount currently collected in rates for decommissioning.

Protection of Labor

The legislation seeks to mitigate the displacement of workers that may result from competition by requiring that:

Utilities planning a workforce reduction before 2005 or selling an asset that will result in the need for fewer workers must present a plan to mitigate the adverse effects of such reductions on employees.
Entities that purchase or receive divisions, business units or generation plants from a utility after January 1, 1997, must agree to first offer available jobs to current non-supervisory employees of the division, unit or plant at the same wage and benefit levels.
Utilities that transfer divisions, business units or generation plants to an affiliate must continue to employee the current staff.
In order to receive certification, alternative suppliers must demonstrate that their employees or the employees of any contractor involved in installing, operating and maintaining electric generation, transmission or distribution facilities have the skills and knowledge to do so in a safe and reliable manner.

Public Revenue Neutrality

In order to maintain tax revenue and competitive neutrality, HB 362 revises the municipal and state taxes on utilities such that they apply to all electricity sales, as shown below:

Existing Tax	New Tax

Public Utility Revenue Tax: 0.32 cents per kilowatt-hour of electricity delivered or sold by public utilities.	Excise tax ranging from 0.33 cents to 0.20 cents per kwh purchased for final consumption, depending upon the total number of kwh. Customers of municipalities will pay the lesser of 0.32 cents per kwh or 5% of the purchase price.

Gross Revenue Tax: 0.1 percent of the gross revenue of electric utilities is paid into the Public Utilities Fund, which pays the expenses of the Commission.	The Public Utilities Fund will receive 3 percent of the revenue collected under the excise tax.

Invested Capital Tax: 0.8 percent of invested capital.	Tax ranging from 0.31 cents to 0.131 cents per kilowatt-hour distributed in the state, depending upon the total number of kwh distributed, to be paid by the electric cooperative, utility, or alternative supplier that distributes the electricity. Amount of tax depends upon total amount distributed.

Municipalities have the authority to impose a tax of 5 percent on the electric utility's gross revenue.	Municipalities will be able to impose a tax ranging from 0.61 to 0.3 cents per kwh consumed within its borders.

Franchise fee: Amount of money or free electricity that municipalities collect from utilities in exchange for providing the rights of way for the transmission and distribution lines.	Municipalities may waive the right to receive the franchise fee, and instead collect an amount per kilowatt-hour up to a maximum established in the bill depending upon the total number of kilowatt-hours purchased. The fee would to collected from all suppliers of electricity to customers within the municipality.

To address concerns about the loss of property tax revenue, the bill creates an Electric Utility Property Assessment Task Force that will advise the General Assembly on how the restructuring may affect the valuation of electric generating plant and the taxing districts in which such plants are located. The task force will issue a report by January 1, 1999 containing recommendations for legislation that can address potential tax revenue losses.

Opportunities for Utility Reorganization

The bill establishes a mandatory "transition period" from the effective date of the legislation until January 1, 2005. During this period, utilities will be able to prepare for competition by undertaking cost mitigation efforts, such as retiring or selling uneconomic plants, accelerating depreciation, implementing a reorganization, or other measures without ICC approval, subject to the following conditions:

The utility must provide to the Commission information on how the measure will be recorded on its books and how it will be used to reduce costs, and pledge not to impose any additional stranded cost recovery on customers.
The Commission may prohibit the sale or transfer of assets above a certain threshold if it finds that safety and reliability of service will be compromised or the utility's earnings are likely to fall below the financial viability threshold that will enable it to request a rate increase.
The Commission may choose not to use an accelerated depreciation rate in determining the rates for regulated services. (A higher depreciation rate results in higher expenses, and could therefore produce higher rates). Moreover, to prevent erosion of the property tax base, the cash value of a utility's plant shall be calculated as the original cost net of depreciation, where depreciation is based on current rates, not on an accelerated depreciation rate, even if there is a new owner of the plant.

During the transition period, utilities will be allowed to request (and not necessarily to receive) an increase in rates if their average return on common equity for the past two years is below the two year average yield of U.S. Treasury bonds. If the utility earns an excessive return on equity, it will be required to refund half of the excess earnings to its customers. Excess earnings will be measured as the difference between utility's average return on equity for the prior two years and the following:

	The average of U.S. treasury bond yields for the prior two years

+	5.5 percentage points until September, 1999 (+9.5 percentage points for CILCO)

+	6.5 percentage points until September, 2004 (+10.5 percentage points for CILCO)

During and after the transition period, utilities will be able to issue stock or bonds, or engage in sales, purchases, or other transactions that fall below established thresholds without Commission approval.

Recovery of Fuel Costs

Utilities currently collect fuel costs through the use of a Fuel Adjustment Clause (FAC). Base rates contain an estimate of the cost of fuel per kilowatt-hour, and any fluctuations in those costs are collected or refunded through the FAC. Each year, the Commission holds a reconciliation proceeding to determine if the utility has correctly calculated the amount of the FAC charge or credit and if the fuel purchases were prudent. The legislation contains a number of provisions that allow utilities to eliminate or freeze their FAC.

Utilities other than ComEd and Illinois Power may select one of the following options:

Eliminate the FAC before 2005 and include in base rates the average cost of fuel for the most recent two years in which the Commission has approved those costs in a reconciliation proceeding. The utility cannot reinstate the FAC for five years.
Utilities that sell or transfer generation plants that account for at least 15 percent of their total capacity and enter into a power purchase agreement with the new owner must eliminate their FAC in accordance with the above provision. If it is less than 15 percent, the fuel costs of the plant that are included in the FAC may not exceed the inflation adjusted costs included in the FAC for the prior year.
Freeze the FAC before 2005 at the average rate for the preceding 24 months as long as that average rate results in a credit to customers' bills. The freeze must remain in place for at least three but no more than five years.
Eliminate the FAC or purchased gas adjustment (PGA) clause (used to recover gas costs) at any time and include such costs in base rates. The Commission will only approve this action if it finds that the costs embodied in the FAC or PGA reflect "reasonable, prudent, and necessary" costs incurred during a 12 month period, chosen by the Commission, that falls within the past 15 months or the succeeding 15 months. The utility cannot reinstate the FAC or PGA for five years.

An electric utility serving more than one million customers (ComEd) will be able to eliminate the FAC from any time during the six months following the effective date of the bill until 2005. Base rates would not be affected by this action. The utility will be required to refund any charges billed to customers through the FAC after January 1, 1997.

An electric utility serving between 500,000 and one million customers (Illinois Power) may eliminate the FAC from a date within the six months following the effective date of the bill until 2005. The utility would include in base rates an amount needed to recover 91 percent of the average fuel costs for the two most recently completed reconciliation proceedings. The utility will refund any charges billed to customers through the FAC after January 1, 1997.

The legislation stipulates that the inclusion of fuel costs in base rates shall not decrease the rate reductions required by the bill.

Transitional Funding

The bill allows utilities to issue "transitional funding instruments," which are bonds or other debt instruments that will be paid off by the collection of an "instrument funding charge" deducted from all customer bills. (This practice is also known as securitization.) Because revenue to pay off the debt is guaranteed in legislation, these instruments are likely to receive a higher rating than existing utility debt. As a result, the interest payments on the bonds will be lower than the utility's current cost of debt. The utility may sell the right to collect the payments to a third party.

The Commission will only approve the issuance of a transitional funding instrument between August 1, 1998 and December 31, 2004, and only if the instrument funding charge will be:

Stated separately and deducted from the other components of the bill (base rates, other tariffed rates and the transition charge).
Allocated among all customer classes based on the percentage of total base rate revenue represented by the class' base rate revenue.
Not be collected after the end of 2008.
Not cause rates to increase.

The proceeds from transitional funding instruments may be used to:

Refinance debt or equity in a manner that results in a lower cost of capital, as long as the utility's common equity (not including the transitional funding instrument) does not fall below the lesser of 40 percent of the capital structure or the percentage of the capital structure on December 31, 1996.
Repay or retire fuel contracts related to spent nuclear fuel.
Pay for the costs of complying with the labor provisions of the bill.
Fund the costs of marketing, issuance, and collateralization of the transitional funding instruments (no more than 20% of the proceeds).

The utility may not issue transitional funding instruments prior to August 1999 that in total represent more than 25 percent in 1996, and more than 50 percent in later years of the total capitalization multiplied by the percentage of electric retail revenue represented by Illinois customers.

Reporting Requirements

HB 362 contains reporting requirements that enable the Commission and the General Assembly to be informed of the development of competition in the Illinois electricity market. Utilities will be required to report to the Commission data on:

The number of customers in each class who are purchasing from alternative suppliers and their annual usage.
Revenue loss resulting from customer purchases from other suppliers.
Amounts collected from transition charges.
A description of cost-reduction measures and a quantification of the resulting savings.
Actions taken in accordance with the bill's provisions on accelerated depreciation, reorganization, collection of fuel costs, and rate changes, and the annual savings or costs to customers resulting from these actions.
A description of the use of transitional funding instruments and the use of the proceeds from those instruments.
Revenues from 1996 electricity sales adjusted to account for the prior year's rate reductions, transition charge collections, and tax changes.

The Commission will also provide the General Assembly with information on the development of the market by issuing:

A report every three years that identifies barriers to entry and to customer participation, identifies other impediments to the establishment of a competitive electricity market, and makes recommendations to address these barriers.
An annual report from 2001 through 2006 that provides the peak demand of retail customers in Illinois, and the number and percentage of kilowatt-hours sold and delivered to Illinois customers by each utility within its service territory, by each utility outside of its service territory, and by alternative electric suppliers, and any other relevant information.