ELECTRIC UTILITY

RESTRUCTURING



Senate Bill 937 as enrolled

Public Act 141 of 2000

Sponsor: Sen. Mat J. Dunaskiss


Senate Bill 1253 as enrolled

Public Act 142 of 2000

Sponsor: Sen. Mat J. Dunaskiss


Senate Bills 940 as enrolled

Public Act 155 of 2000

Sponsor: Sen. William Van Regenmorter


Senate Bills 941 as enrolled

Public Act 156 of 2000

Sponsor: Sen. Philip E. Hoffman


First Analysis (8-25-00)

House Committee: Energy and Technology

Senate Committee: Technology and Energy



THE APPARENT PROBLEM:


In 1929, in order to prevent duplication of transmission and distribution wires and facilities, certain utilities were granted what was and is essentially monopoly status in the arena of electrical power production and supply. The government sanctioned monopolies were granted in exchange for the utilities' agreement to be regulated by state utility commissions and to provide reliable electrical service to all of the customers within a specified area. Approximately three-quarters of the electrical power in America is provided by 200 of these investor-owned utilities, like Detroit Edison and Consumers Energy. These utilities are private companies that are owned by their shareholders and are regulated, since the passage of the Federal Power Act in 1935, by both the Federal Energy Regulatory Commission (FERC) (formerly the Federal Power Commission) and the individual states' public service commissions. The Public Utilities Holding Company Act, also passed in 1935, required the utilities to be vertically integrated and limited their operations to serving a specific geographic area. Vertical integration means that these utilities own all of the essential elements involved in supplying electricity to consumers: generation sources - the means of creating electricity, usually through burning fossil fuels, or nuclear or hydroelectric generators; a transmission system - power lines and other means by which the electricity is passed from where it was generated to distribution systems; and a distribution system - wherein the electricity is lowered to operable voltages and sent to the end-user, i.e., residences, General Motors, the local grocery or whomever. Because they own their own means of generation, transmission, and distribution, these companies do not have to rely on others in order to sell and provide electricity to their customers. Municipally-owned utilities make up another large portion of electricity service providers. These are municipally-owned organizations that produce or procure electricity to distribute to residents within a specific geographic area - i.e. that municipality. An example in Michigan is the Lansing Board of Water and Light. They are subject to many of the same rules as the other utilities.


Although they maintain a monopoly on transmission of power between sources of generation and end users, investor-owned utilities and municipally-owned utilities are not allowed to simply charge whatever price the market will bear. Instead, the rates they charge are set and regulated - in Michigan by the Michigan Public Service Commission (PSC). The rates are intended to cover the utility's operating costs, the cost of paying off the utility's investments, and an appropriate level of profit or rate of return. This system, which was similarly reflected in most states throughout the U.S., was constructed to encourage the utilities to invest in establishing and maintaining the infrastructure needed to meet consumer's needs by guaranteeing the companies a return on their investment.


In order to set a utility's rates in Michigan, the PSC holds hearings, known as rate-case proceedings, to determine what is a reasonable rate of return and, based on that, what users should be charged for the power sold by the utility. The actual cost of electricity depends upon the time of day of use, the uniformity and consistency of usage patterns, and the level of voltage used. The specific rate charged to the customer, known as a tariff, is made up of three parts: 1) the costs connected with serving the customer - the billing and meter reading expenses and the source connection, 2) the demand costs, such as the fixed cost of utility plants and operating costs, and 3) variable costs - those that depend upon the amount of power consumed. In addition, the tariff varies depending upon whether the particular customer is an industrial, commercial, or residential customer.


Until the energy shortages of the 1970s, this system dominated the electrical power market. Other power producers had very limited opportunities to enter the market because the cost of creating a separate transmission infrastructure was prohibitively expensive and the regulated utilities (with whom the other companies would be seeking to compete) controlled the existing means of transmission. Some industries and commercial enterprises that used large amounts of electricity choose to generate their own electricity (Michigan State University and some of the automobile manufacturers, for example), but few generation sources existed outside of the regulated utilities to compete with the utilities in the production and sale of electricity. However, in response to the energy shortages of the 1970s, the federal government passed the Public Utilities Regulatory Policy Act in 1978. This act was intended to encourage new supplies of electrical power generation by requiring regulated utilities to meet increases in energy demand by purchasing electrical power from outside sources when it was cheaper to do so, rather than constructing new generation facilities. As a result, since 1978 there has been an increase in the number of independent power producers. Even before the federal laws requiring the transmission of bulk electrical power from remote sources, the utilities had been allowed to exchange power among themselves. The local utilities' transmission systems were linked together into far ranging electric power grids, and it was common practice for one utility to purchase power generated by another utility, and then "wheel" the bulk electricity into its own system when additional power was needed during peak demand times. However, even as the number of independent producers increased due to the Public Utilities Regulatory Policy Act, these independent producers were not generally given access to the utilities' transmission lines.


In 1992, the federal government enacted the Energy Policy Act to allow the independent power producers access to the transmission lines of the investor-owned vertically integrated utilities. This allowed independent power producers to sell their electrical power at wholesale, through the transmission lines of one utility, to another separate utility while paying a fee to the utility that owned the transmission system for "wheeling" the electricity between the producer and the purchasing utility. In addition, the law directed the FERC to adopt a regulation requiring utilities to open their transmission lines to all sellers of electricity. This rule (Order 888) was adopted by the FERC on April 24, 1996 and ensured independent power producers access to transmission lines, while also allowing the regulated utilities to recover any "prudently incurred" stranded costs that they might accrue if their customers moved to other suppliers. Requiring the regulated utilities to allow wholesale wheeling by other electricity providers allowed even more independent power producers to enter and succeed in the marketplace.


Although the 1992 Energy Policy Act and resultant FERC order allowed for wholesale competition by requiring utilities to open their transmission lines for the transmission of power from other sources (allowing wholesale power purchasers to purchase electricity from any supplier), neither the act nor the resultant order mandates any form of retail competition in the field of electrical generation. Thus, the decision as to how much competition will be allowed on the retail level has been left to the state legislatures and their respective regulatory commissions. As a result, many states began to investigate and/or create plans for deregulating or restructuring their electrical power systems. According to the Department of Energy, at present, 23 other states have enacted restructuring legislation. Most of these plans provide for some form of phased-in competition - for example, allowing competition to begin for only new consumers or only those customers that use large amounts of power. However, these plans still, generally, provide for full competition in between one and two years. Other states have allowed for a more expansive competitive environment from the start.


Michigan has taken some action thus far: As of January of 1998, the Public Service Commission (PSC) adopted a phase-in schedule to introduce competition into the state's electric utility market. The schedule allowed 2.5 percent of Consumer's Energy and Detroit Edison customers retail access as early as March of 1998, adding another 2.5 percent on June of 1998, January of 1999, January of 2000, and January of 2001 and for all consumers by 2002. However, in June of 1999, the Michigan Supreme Court decided that the PSC did not have the authority to mandate the retail access required under the phase-in schedule. In spite of this decision, Consumers Energy and Detroit Edison, which serve 90 percent of the consumers in Michigan, have chosen to voluntarily follow the PSC's restructuring plan. However, although legislation has been offered to implement restructuring during each of the last two sessions, no bills have been enacted on the issues to date.


Several challenges have arisen in trying to restructure the provision of electricity. How can access to transmission lines be kept open and reasonably priced, without making ownership of the transmission system so unprofitable that no one wants to be responsible for them? Another issue that must be confronted is the question of "stranded cost recovery." Stranded costs or transition costs refer to past investments made by the investor owned utilities for development and building of existing electrical power infrastructure, such as transmission systems and power plants. The utilities are concerned that one of the results of deregulation will be that the utilities will be unable to pay off the debts that they incurred through these investments. The investor owned utilities argue that many of these investments were made at the behest of state regulatory commissions on behalf of the consumers and with the understanding that by continuing to serve those customers, the utilities would be able to recover the costs of their investments over the long run. It is asserted that the costs of these investments would be unrecoverable in a competitive environment because customers would be able to leave the system rather than pay the rates needed for the utilities to pay off the debt. As a result, the utilities believe that they should not be forced to absorb these costs on their own and assert that any plan for restructuring must account for stranded costs and offer some means for recovery of those costs. On the other hand, some potential competitors argue that the investor owned utilities and their stockholders should pay those costs in whole, while others believe that only those costs that were incurred as the result of government-ordered investments should be recovered while the costs of "bad" decisions by the utilities should be borne by the utilities and their investors.


Yet another issue is how such deregulation will affect residential customers. Because residential customers do not purchase large quantities of electricity, their individual bargaining power in a competitive market will be limited. Therefore, residential customers could be faced with increasing utility rates even as the rates for commercial and industrial users decrease. Furthermore, there is also concern that competition between generators would bring an end to unprofitable social programs for low-income customers. Finally, there is the potential for increased risks to the environment. Many energy savings incentives and other "environmentally friendly" initiatives provided to and by investor owned utilities are costly and result from regulations and the requirements of state and federal government rather than as the result of any expectation of profit. There is concern that it is unlikely that such initiatives would be undertaken by companies competing to provide energy at the lowest cost for the consumer.


The electric utility industry has been undergoing a fundamental change throughout the United States, and Michigan is no exception. In much the same manner as telephone long-distance service, the sale of electrical power is changing from a well-regulated monopoly to a more competitive, market-oriented system wherein suppliers of electricity will be allowed to pick and choose customers and customers will be able to pick and choose suppliers.


However, even as these changes are made, questions have arisen about how the now competing businesses should deal with their customers and with one another. Legislation has been introduced to establish rules under which generators, suppliers, and distributors of electricity would be expected to behave in the new, more market-oriented system.


THE CONTENT OF THE BILLS:


Senate Bill 937 would amend the Public Service Commission (PSC) enabling act (MCL 460.10 et al.) to create the "Customer Choice and Electricity Reliability Act." The purpose of the act, as stated in the bill, would be to do the following:


1) Ensure that all of the state's electric power retail customers have a choice of electric suppliers.


2) Allow and encourage the PSC to foster competition in the provision of electric supply and maintain regulation of the that supply for customers who choose to continue to receive power from incumbent electric utilities.


3) Encourage the development and construction of merchant plants to diversify the ownership of electric generation within the state.


4) Ensure that all persons in the state are afforded safe, reliable electric power at a reasonable rate.


5) Improve the opportunities for economic development and promote financially healthy and competitive utilities in the state.


The provisions outlining the intended purpose of the Customer Choice and Reliability Act would only apply until December 31, 2003.


By January 1, 2002, the PSC would be required to issue orders establishing rates, terms, and conditions of service to allow retail electric utility customers to choose an alternative electric supplier. These orders would also have to provide for full recovery of what the PSC determined were the electric utilities' net stranded costs and implementation costs. Existing orders issued to allow customers to choose an electric supplier, including those orders that authorize recovery of net stranded costs and implementation costs and confirm any voluntary commitments of electric utilities, would remain enforceable. The PSC would have to set a date for those electric utilities whose voluntarily commitments to provide customer choice have not already been approved by the PSC to file a restructuring plan to allow their customers to choose an alternative electric supplier. These plans would also have to include a method of determining the electric utility's stranded and implementation costs.


The act would specify that it would not diminish, increase, or eliminate any rights that parties might have in contracts or agreements that were in effect as of January 1, 2000 between electric utilities and qualifying facilities. Further, receipt of any proceeds of securitization bonds (described below) by an electric utility would not be a basis for any regulatory disallowance. The PSC would be required to fully consider the facility's legal and financial interests when issuing any securitization or financing order relating to a qualifying facility's power purchase contract.


Rates. The PSC would have to establish rates, terms, and conditions of electric service to promote and enhance the development of new generation, transmission, and distribution technology. Residential rates for each electric utility with one million or more retail customers would have to be set by the PSC. Those rates would have to result in a five percent rate reduction from the rates that were authorized or in effect on May 1, 2000. The reduced rates would take effect on the bill's effective date and remain in effect until December 31, 2003. After December 31, 2003, residential rates could not be increased (above the five percent reduced rate) until December 31, 2013 at the latest, or, anytime after January 1, 2006, provided the PSC determined that the utility had met the bill's market power test (see below) and completed the transmission expansion required by the bill (see below). Until that time, the PSC could not authorize any fees or charges that would cause the residential rate reduction to be less than five percent. All other electricity retail rates of an electric utility with one million or more retail customers in effect on May 1, 2000 would have to remain in effect until through 2003. The rates for commercial and manufacturing customers with annual peak demands of less than 15 kilowatts could not be increased before January 1, 2005. Cost shifting from customers with capped rates to customers without capped rates would not be allowed.


After the conclusion of the required five percent rate reduction period, residential rates for those customers who choose to remain with (and those who left and then returned to) an incumbent electric utility would be set by the PSC in the same manner as rates are currently determined.


Unbundling. The just and reasonable costs incurred in unbundling commercial, industrial and residential rate schedules would be recoverable. No later than one year from the bill's effective date, each electric utility would be required to file an application with the PSC to unbundle its existing commercial and industrial rate schedules and separately identify and charge for their discrete services. After that time, the PSC could order each electric utility to file an application to unbundle its existing residential rate schedules. The unbundled rates could be expressed on residential billings in terms of percentages in order to simplify residential billings.


Standby Generation. An electric utility would be obligated, with PSC oversight, to provide standby generation service for open access load on a best efforts basis until December 31, 2001, or until the utility met the bill's market power test and expanded transmission as required. The pricing for electric generation standby service would be equal to the retail market price of comparable standby service. A utility would not be required to interrupt firm off-system sales or firm service customers to provide standby service. The retail market price for electric generation service would be determined by the PSC based on market indices commonly relied upon in the industry, adjusted to reflect retail market prices in the relevant market.


Securitization, Transition and Stranded costs. Beginning on January 1, 2004, annual return of, and on, capital expenditures above the depreciation levels incurred during and before the end of the required five percent rate reduction period and expenses from changes in taxes, laws, or other state or federal governmental actions during that time period would be accrued and deferred for recovery. A hearing would have to be held by the PSC to determine the amount of reasonable and prudent costs, if any, that would be recovered. The recovery period, which could last for up to five years, would not begin until after the end of the required five percent rate reduction.


If the PSC authorized an electric utility to use securitization financing (as proposed by Senate Bill 1253), any savings realized from that securitization would have to be used to reduce retail electric rates from those in effect on May 1, 2000. However, any such reduction could not be less than the required five percent rate reduction.


A financing order issued by the PSC allowing a utility to issue securitization bonds could limit a utility to issuing bonds in an amount equal to or less than the amount the utility had requested. However, the PSC could not prevent a utility from issuing bonds in an amount sufficient to fund the required five percent rate reduction.


If the securitization savings exceeded the amount needed to allow a five percent rate reduction for all customers, then, for six years, one hundred percent of the excess savings, up to two percent of the utility's commercial and industrial revenues, would be assigned to the low-income and energy efficiency fund. Any savings beyond that would be allocated by the PSC for further rate reduction or to reduce the level of any charges authorized to recover a utility's stranded costs. Securitization, transition, stranded, and other related charges and credits would have to be allocated by the commission without reallocating cost responsibility among different consumer classes.


If an electric utility that served less than one million retail customers in this state as of May 1, 2000 issued securitization bonds, it would have the same rights, duties, and obligations as an electric utility with more than one million retail customers in this state as of May 1, 2000.


The Low Income and Energy Efficiency Fund. The commission would administer the fund and establish standards to use the fund to provide shut-off and other protection for low-income customers and to promote energy efficiency by all customers. The commission would be required to report on the fund's effectiveness every two years to the legislature and the governor. In addition, the PSC would be required to take any steps necessary to ensure that all electrical power generating facilities in the state were complying with all the rules, regulations, and standards set by the Federal Environmental Protection Agency regarding mercury emissions.


True-up Adjustments. The PSC, after a contested case hearing, would be required to issue an annual order approving a true-up adjustment for each electric utility to reconcile any over- or under-collections from the preceding 12 months for recovery of net stranded costs. The rates of customers who remain with an incumbent electric utility would not be affected by the true-up process. The commission would have to review the electric utility's stranded cost recovery charges and securitization charges implemented during the prior 12 months, and adjust the recovery charge to allow the netting of stranded costs. In determining net stranded costs, the commission would have to consider the reasonableness and appropriateness of various methods, including but not limited to, the following: evaluating the relationship of market value to the net book value of generation assets and purchased power contracts; evaluating net stranded costs based on the market price of power in relation to prices assumed by the commission in prior orders; or any other method that the commission considers appropriate.


The true-up method chosen by the commission could not result in a modification of the securitization charge. The PSC would be barred from adjusting or changing any authorized securitization charges through its review and actions taken with regard to the annual true-up adjustment.


Market Test. If an electric utility had commercial control over more than 30 percent of the generating capacity available to serve a relevant market (after subtracting the average demand for each retail customer with contract(s) that exceeded 15 percent of the utility's retail load in that market), that utility would have to take certain steps with respect to any excess generation beyond what was needed to serve its firm retail sales load, plus a reasonable reserve margin. The utility would be required to do one or more of the following: divest a portion of its generating capacity; sell generating capacity under a contract with a non-retail purchaser for a term of at least five years; or transfer generating capacity to an independent brokering trustee for a term of at least five years.


The total generating capacity available to serve a particular market would be determined by the PSC, in accordance with a specific calculation outlined in the bill. Within 30 days after the PSC determined the total generating capacity in a relevant market, a utility that exceeded the 30 percent limit would have to file an application for approval of a market power mitigation plan. The utility would have the right to determine what specific actions it wanted to take to achieve compliance. As long as the plan was consistent with bill's provisions, the PSC would be required to approve it. However, the PSC could require an that an inconsistent plan be modified to make it consistent with the bill's provisions.


If the utility chose to transfer some of its capacity to an independent brokering trustee, that trustee would have to be completely independent from and not affiliated with the utility. The terms of the transfer to an independent trustee would have to ensure that the trustee has complete control over the marketing, pricing, and terms of the transferred capacity for at least five years and would have to provide appropriate performance incentives to the trustee for marketing the transferred capacity. The utility could apply to the PSC to replace a trustee during the five year term, provided that the utility showed that the incumbent trustee had failed to market the capacity under his or her control in a prudent and experienced manner.


Upper Peninsula Market Report. Within one year after the bill's effective date, the PSC would be required to issue a report analyzing all aspects relating to market power in the Upper Peninsula. Before issuing its report, the PSC would have to receive written comments and hold hearings to solicit public input. The report would be given to the governor and the legislature and would, at the least, have to include information about the concentration of generation capacity, control of the transmission system, restrictions on the delivery of power, the ability of new suppliers to enter the market, and identification of any market power problems that exist under the market power test established by the bill.


Expansion of Transmission Capability. By January 1, 2001, all electric utilities that serve more than 100,000 retail customers in Michigan would have to agree upon and file a joint plan detailing measures to permanently expand the available transmission capability by at least 2,000 megawatts over what was available on January 1, 2000. The joint plan would have to be filed with the PSC and provide for the expansion to be completed within two years of the bill's effective date. The joint plan would have to detail all the actions needed for the expansion, including the proposed schedule, the additional facilities required, the cost, and the proposed rate making treatment for those costs. The joint plan would also have to identify any actions and facilities that would be required of other transmission owners, including out-of-state entities, in order to implement the joint plan. The PSC could modify a joint plan in order to make it consistent with the act.


If the utilities were unable to agree on a joint plan, the PSC would hold a hearing to establish a joint plan. The PSC's plan would have to authorize recovery of all reasonable and prudent costs incurred by transmission owners for authorized actions taken and for facilities installed to meet the expansion requirements that were not recovered through FERC transmission rates. These authorized costs would be recovered from benefitting customers.


Any utility or affiliate that owned transmission assets and was denied recovery of reasonable and prudent costs expended to implement a joint plan would have no further obligation to implement the joint plan, unless the cost recovery was subsequently granted. However, if cost recovery for reasonable and prudent costs incurred to implement a joint plan were denied, a utility or its affiliate would then be required to develop a new joint plan.


Investor-owned electric utilities would be required to either join a multi-state regional transmission system organization, or other multi-state independent transmission organization, approved by the Federal Energy Regulatory Commission (FERC); or divest its interest in transmission facilities to an independent transmission owner. If an electric utility did not comply by December 31, 2001, the PSC would direct the utility to join a FERC approved multi-state regional transmission system organization selected by the PSC. Investor owned electric utilities with legitimate filings pending before the FERC on December 31, 2001 seeking approval of a proposed multi-state regional transmission system organization would be considered to be in compliance.


Service quality and reliability standards. The PSC would be required to adopt generally applicable service quality and reliability standards for the transmission and distribution systems owned by the entities under its jurisdiction. These standards would need to consider safety, costs, local geography and weather, applicable codes, national electric industry practices, sound engineering judgement, and experience. Provisions to upgrade the service quality of distribution circuits that have historically experienced significantly below-average performance would also have to be included.

All of the entities expected to follow these standards would be required to file an annual report with the PSC. The report would have to contain data required by the commission and detail the actions that the entity will be taking to comply with those standards for the next calendar year and its performance in relation to those standards during the prior year. The PSC would analyze the reported data to determine whether the entities are properly operating and maintaining their systems, to assess the impact of deregulation on reliability, and to take corrective action if needed. The PSC could set financial incentives or penalties for those entities that exceed or fail to meet these service quality and reliability standards.


Code of Conduct. Within 180 days after the bill's effective date, the PSC would be required to establish a code of conduct to prevent cross-subsidization between regulated and unregulated services that would apply to all electric utilities and alternative electric suppliers. The code of conduct would have to include, but would not need to be limited to, measures to prevent cross subsidization, information sharing, and preferential treatment between regulated and unregulated services, whether those services were provided by the utility or supplier or by an affiliated entity.


Aggregation. "Aggregation" (which would mean the combining of electric loads of multiple retail customers or a single customer with multiple sites to facilitate the provision of electric service to those customers) could be used for the purchase of electricity and related services from an alternative electric supplier. Local units of government, public and private schools, universities, and community colleges could aggregate for the purpose of purchasing electricity for themselves or for customers within their boundaries with the written consent of each customer aggregated. However, customers within a local unit of government would not be required to purchase electricity through the aggregator. Further, a school district that aggregated electricity for school properties or an exclusive aggregator for public or private school properties would not be considered to be an electric utility or a public utility for the purpose of that aggregation.


Worker Transition Programs and Other Employee Protections. Each electric utility operating in the state would have to establish an industry worker transition program. The program would have to provide skills upgrades, apprenticeship and training programs, voluntary separation packages consistent with reasonable business practices, and job banks to coordinate and assist placement of employees into comparable employment at no less than the wages and similar benefits received before the transition. Stranded costs would include audited and verified employee-related restructuring costs incurred due to the bill's provisions or due to prior orders of the commission.


Any contract for sale or other transfer of ownership of one or more Michigan divisions or business units, or generating stations or generating units, of an electric utility to either a third party or a utility subsidiary would have to require the acquiring entity or persons to do all of the following for at least 30 months:


1) Hire a sufficient number of non-supervisory employees to safely and reliably operate and maintain the station, division or unit by making offers of employment to the non-supervisory workforce.

2) Refrain from hiring non-supervisory employees from outside the electric utility's workforce unless offers have already been made to all qualified non-supervisory employees of the acquired business unit or facility.


3) Have a dispute resolution mechanism for resolving employee complaints or disputes over wages, fringe benefits, and working conditions that culminates in a final and binding decision by a neutral third party.

4) Offer employment on substantially similar terms and conditions with no less pay and substantially similar benefits as were provided before the sale or transfer or ownership. The payment and benefits would have to continue for at least 30 months from the time of the transfer unless the employees, or collective bargaining representative (if applicable), and the new owner mutually agree to different terms and conditions.


[Note: These provisions would also have to be included in contracts involving the sale of a municipally owned utility. However, the employment provisions would apply to all of the utility employees, not merely non- supervisory employees. In addition, an acquiring entity would be exempt from these obligations if the municipality transferred all of the displaced employees to other employment within the municipality at no less than their current wage rates and with substantially similar fringe benefits and terms and conditions of employment. The wage rates, benefits, and terms and conditions of employment would have to continue for at least 30 months, unless the employees, or, where applicable, their collective bargaining representative, and the municipality mutually agree to different terms during that period.]


An electric utility would have to offer a transition plan to those employees who were not offered jobs because the acquiring party needed fewer workers. If there were litigation concerning the sale or other transfer of ownership, the 30-month period would not begin until the acquiring party took control.


Alternative electric suppliers. "Alternative electric supplier" would mean a person (including business or corporate entities) who sold, but did not deliver directly, electric generation service to retail customers in Michigan. Only investor owned, cooperative, or municipal electric utilities would be allowed to own, construct, or operate electric distribution facilities or electric meter equipment used in the distribution of electricity. However, these facilities and equipment could be used by others if used solely for providing or using self-service power. Further, the bill specifically states that none of these provisions would affect a non-utility's existing rights to construct or operate a private distribution system on private property or private easements, nor would it preclude crossing rights of way.


Alternative electric suppliers would have to be licensed by the PSC. The licensing procedure would have to do all of the following:

In addition to the information required in the licensing application, an applicant wishing to be an alternative electric supplier would also be required to 1) provide information as to its technical ability, as defined under the regulations of the PSC, to safely and reliably generate or otherwise obtain and deliver electricity and provide any other proposed services (this could include information as to the applicant's safety record and its history of service quality and reliability); and 2) demonstrate that its employees, or others with whom the applicant contracted to install, operate, and maintain generation or transmission facilities within this state, have the needed skills, knowledge, and competence to perform those functions in a safe and responsible manner.


The PSC could require an applicant to post a bond or provide a letter of credit or other financial guarantee in a reasonable amount (no less than $40,000) as set by the commission, if it determined that such a bond or other guarantee would be in the public interest.


Cooperative electric utilities. Cooperative electric utilities would not be required to provide their customers the ability choose an alternative electric supplier before January 1, 2005; nor would they have to unbundle their rates before July 1, 2004. However, the retail customers of a cooperative that have a peak load of one or more megawatts would have to be provided the opportunity to choose an alternative supplier no later than January 1, 2002. The PSC could not require a cooperative or an independent investor-owned utility with fewer than 60 employees to maintain separate facilities, operations, or personnel for the delivery of electricity to retail customers, the provision of retail electric service, or to be an alternative electric supplier.


Any debt service recovery charge or other charge that the PSC approved for a cooperative electric utility that primarily offered wholesale service could, on application by its member cooperative or cooperatives, be assessed by and collected through its member cooperative or cooperatives. The PSC could not prohibit a cooperative electric utility from metering and billing its customers for services that the cooperative provided. Further, a cooperative electric utility would not have to provide funding for the customer education program established by the PSC until July 1, 2004, or when all of its customers have choice, whichever is earlier.


Municipally owned utilities. The governing body of a municipally owned utility would have authority to decide whether it will permit its retail customers to choose an alternative electric supplier, subject to the implementation of rates, charges, terms, and conditions. Municipally owned utilities would not be restricted from selling electricity at wholesale and would not be considered an alternative electric supplier or be subject regulation by the PSC for doing so.


Until December 31, 2007, a person could not provide delivery service or customer account service to a retail customer (in this case the building or facilities, not the individual or other entity) that had been served by a municipally owned utility without the municipally owned utility's written consent. After December 31, 2007, the requirement for written consent would not apply if the governing body of the municipally owned utility had not permitted all of its retail customers who lived outside municipality's boundaries to chose an alternative utility supplier.


Municipally owned utilities that choose to provide electric generation service to retail customers who receive delivery service from another electric utility would be subject to all of the following:


(1) The municipally owned utility and electric utility could enter into a written agreement defining each utility's territorial boundaries and any other necessary terms. The agreement would not be effective unless it was approved by both the municipally owned utility's governing body and the PSC.


(2) The municipally owned utility could elect to operate in compliance with R 460.3411 of the Michigan Administrative Code. The utility would have to file its decision to do so with the PSC and serve a copy on the other utility. Beginning 30 days after the election was filed, the electric utility would be subject to the terms of rule R 460.3411 of the Michigan administrative code as to the municipally owned utility. The PSC would decide any disputes that arose under this, subject to judicial review and enforcement.


Complaints that a municipally owned utility that had elected to provide generation service to retail customers had violated these restrictions would be decided by the PSC subject to judicial review and enforcement.


If the governing body of a municipally owned utility established a program to permit choice for any of its customers, that governing body would have exclusive jurisdiction to do all of the following:


Complaints of unduly discriminatory rates or other noncompliance with these provisions would be filed in the circuit court for the county where the municipally owned utility was located.


The bill would provide that, under certain circumstances, a municipally owned utility that was a member of a joint agency established under the Michigan Energy Employment Act of 1976 (MCL 460.801 et al.) could assign electric power to the joint agency that the joint agency could sell at retail as a supplier, provided the joint agency meets some of the restrictions on retail sellers and obtains a license.


Contracts or other records pertaining to a municipally owned utility's sale of electricity that contain specific pricing or other confidential information that are in the possession of a public body could be exempt from public disclosure requirements by the utility's governing body. However, on a showing of good cause, disclosure could be allowed subject to appropriate confidentiality provisions.


The bill would specify that none of the provisions regarding municipally owned utilities would affect the validity of an August 24, 1994 order regarding the terms and conditions of service in the Traverse City area.


Self-service power. The act would not prohibit or limit a person's right to self-service power or allow any transition, implementation, exit fee, or any other similar charge on such power. Anyone using such power would not be treated as an electric supplier, utility, or person conducting an electric utility business. Self-service power would mean any of the following: a) electricity generated and consumed without the use of an electric utility's transmission and distribution system; b) electricity generated primarily by use of by-product fuels which is used as part of a contiguous facility, with the use of a utility's transmission and distribution system, but only if the point or points of receipt are not more than three miles from the point of generation; c) a site or facility divided by an inland body of water or a public road, highway, or street that otherwise meets the requirements of contiguousness as of the bill's effective date, regardless of whether the self-service power was being generated at that time. A commercial or industrial facility or single residence that meets one of the first two definitions would be considered to have self-service power, even if the generation facility was owned by an entity other than the owner of the commercial or industrial site or the single residence.


Affiliate Wheeling. The act also would not prohibit or limit affiliate wheeling or allow any transition, implementation, exit fee, or any other similar charge on affiliate wheeling. Affiliate wheeling would refer to a person or other entity's use of direct access service where an electric utility delivers electricity generated at a person's industrial site to that person or its affiliate. Anyone engaging in affiliate wheeling would not be treated as an electric supplier, utility, or person conducting an electric utility business.


Merchant Plants. A merchant plant (defined as an entity with electric generating equipment and associated facilities located in Michigan with more than 100 kilowatts capacity that are not owned and operated by an electric utility) would be allowed to sell to alternative electric suppliers, electric utilities, municipal electric utilities, retail customers, or other persons. If a merchant plant sold directly to retail customers, it would be considered an alternative electric supplier and would have to obtain a license. The PSC would be required to set standards for merchant plants to interconnect with the electric utilities transmission and distribution systems. The standards would have to be consistent with generally accepted industry practices and ensure the reliability of electric service and the safety of customers, employees and the general public. However, those standards could not require an electric utility to interconnect with a generating facility with less than 100 kilowatts for parallel operations. Electric utilities would have to take all necessary steps to ensure that merchant plants were connected to the transmission and distribution systems within their operational control. If the PSC found that an electric utility had prevented or unduly delayed a merchant plant's ability to connect to the utility's facilities, the PSC could order fines of up to $50,000 per day of violation, or other remedies designed to make whole the injured party. Each merchant plant would be responsible for all costs associated with the interconnection unless the PSC otherwise allocated the costs and provided for cost recovery. However, these provisions would not apply to interconnections or transactions subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC).


Disclosures, explanations, and sales information. The PSC would be required to set minimum standards for the form and content of all disclosures, explanations, or sales information to make certain that electric service customers have adequate, accurate, and understandable information about the service. The standards would have to set different requirements for different services and for different classes of customers where appropriate. The standards could not be unduly burdensome, cause unnecessary delay, or inhibit the development of competition for electric generation service in any market.


Further, the PSC would have to create a funding mechanism for electric utilities and alternative electric suppliers to carry out an educational program for customers before January 1, 2002. The program would have to inform customers of the availability of alternative electric suppliers and the requirements for disclosures, explanations, or sales information set for those alternative electric suppliers. It would also have to provide assistance to customers, to help them understand and use the information provided in order to make reasonably informed decisions about which service to purchase and from whom.


Starting January 1, 2002, all electric suppliers would be required by the PSC to disclose environmental information (average fuel mix, average emissions, average high-level nuclear waste generated, and the regional average of these) in a standardized, uniform format on a customer's bill insert, customer contracts, or, for cooperatives, periodicals issued by an association of rural electric cooperatives. Suppliers would be required to provide this information no more than twice annually. The information would be based upon a rolling annual average and the emissions factors would be based upon annual publicly available data by generation source. All of the information would also have to be provided to the PSC for use on the commission's website.


Finally, the PSC would also be required to create the Michigan Renewables Energy Program to promote the use of existing renewable energy sources and encourage the development of new facilities. The program would also have to inform customers of the availability and value of using renewable energy generation and the potential of reducing pollution.


Slamming and Cramming. The PSC would be required to issue orders to ensure that customers are not switched to other suppliers or billed for any services without their consent. Violations of these provisions would be reviewed by contested case hearing and the PSC could order remedies and penalties to protect customers and other persons who suffered damages from such violations. The remedies and penalties could include a fine of $20,000 to $30,000 for a first offense and $30,000 to $50,000 for a second or further offense. If the PSC found that a second or further offense was a knowing violation, the fine could be increased up to $70,000. For purposes of assessing a fine, each unauthorized action in violation of the PSC's orders would be treated as a separate offense. A fine would not be ordered if the supplier otherwise fully complied with the PSC's orders and showed that the violation was an unintentional and good faith error that had occurred in spite of reasonable efforts to avoid such errors. An error in legal judgement about a supplier's obligations would not be considered a good faith error. A supplier would have the burden of proving that its error was unintentional and in good faith.


The PSC could also: order a refund of any amount greater than the customer would have paid to an authorized supplier; order reimbursement to an authorized supplier of the amount that the customer should have paid; order a full refund of any amounts the customer paid for unauthorized services; allow 10 to 50 percent of the fines described above to be paid to the customer; revoke a license; or issue cease and desist orders.


If the PSC determined that a party's position in a cramming or slamming complaint was frivolous, the PSC would have to award the prevailing party their costs, including reasonable attorney fees, "against the non-prevailing party and their attorney."


Low-income and energy assistance programs. The PSC would be required to monitor the availability of federal funds for low-income and energy assistance programs. If the federal funds available to residents of this state are reduced, the PSC would have to conduct a hearing to determine the amount of funds available and the need, if any, for supplemental funding. The findings would have to be reported to the legislature and the governor.


Service shut off provisions. The PSC would be required to ensure that eligible customers are informed of the requirements of the act regarding service shut-offs for nonpayment. Eligible customers would include eligible low-income customers - those whose household income does not exceed 150 percent of the federal poverty level or who receive assistance from a state emergency relief program, food stamps, or Medicaid; and eligible senior citizen customers - those who are 65 years of age or older and advise the utility of their eligibility.


As long as a customer is an eligible senior citizen or pays a monthly amount equal to seven percent of the estimated annual bill and demonstrates, within 14 days of requesting shut-off protection, that he or she has applied for state or federal heating assistance, an electric utility or alternative service provider could not shut off service during the heating season for nonpayment. However, an electric utility would not be required to shut off an eligible customer's service under this section for failure to pay an alternative electric supplier.


If an arrearage existed at the time an eligible customer applied for shutoff protection, the utility or supplier would be required to allow the customer to pay the arrearage in equal monthly installments between the date of application and the start of the subsequent heating season. A utility or supplier could shut off an eligible low-income customer's service for failure to make these monthly payments and would not be required to offer a settlement agreement to such a customer.


Before shutting off a customer's service on its own or on behalf of an alternative electric supplier, an electric utility would have to give the delinquent customer a notice by personal service or first class mail. The notice would have to provide the customer with all of the following information: that the customer defaulted on the winter protection plan; the nature of the default; that unless the customer makes the past due payments within 10 days of the date the notice was mailed, the utility or supplier may shut off service; that the customer has the right to file a complaint disputing the claim before the date of the proposed shut off; that, if the complaint cannot be otherwise resolved, the customer can request a hearing before a hearing officer, but that, the customer would be required to pay the portion of the bill that is not in dispute within three days of the date that he or she requests such a hearing; that the customer has the right to represent himself or herself, to be represented by an attorney, or to be represented by another person; that the utility or supplier will not shut off service pending resolution of a complaint that is properly filed with the utility under the bill's provisions; the telephone number and address of the utility or supplier where the customer may make an inquiry, enter into a settlement agreement, or file a complaint; that the customer should contact a social services agency if the customer believes that he or she might be eligible for emergency economic assistance; that the utility or supplier will postpone shutoff of service if a medical emergency exists; that the utility or supplier may require a deposit and restoration charge if the service is shut off for nonpayment.


Utility Consumer Participation Board. Language requiring that four of the five members of the utility consumer participation board be chosen from lists submitted by the Michigan consumer's council (which no longer exists) would be stricken. Under the bill, members would be appointed by the governor; however, one member would have to be chosen from a list submitted by the attorney general.


Violations and penalties. Except where otherwise provided, if the PSC found, after notice and hearing, that a utility or alternative supplier was in violation of the bill's provisions or orders issued under the bill, the PSC would have to order those remedies or penalties necessary to make whole the customer or other person who suffered damages. Those remedies or penalties could include a fine of $1,000 to $20,000 for a first offense, $2,000 to $40,000 for a second offense, and no less than $5,000 or more than $50,000 for a third or subsequent offense; a refund of any excess charges; or any other remedies that would make whole the person harmed, including payment of reasonable attorney fees. In addition, the PSC could issue cease and desist orders, and, if a pattern of violations had occurred, revoke an alternative electric supplier's license.


Annual report. The PSC would be required to file a report with the governor and the legislature each year by December 31. The report would have to include the status of competition for the supply of electricity in this state; any recommendations for legislation; the commission's actions taken to implement measures needed to protect consumers from unfair or deceptive business practices; and information regarding consumer educations programs, approved by the commission, to inform consumers of all relevant information regarding the purchase of electricity and related services from alternative electric suppliers.


Saving Clause. The bill would also provide that if any portions of the act were found to be invalid or unconstitutional, the rest of the bill would still remain in full force and effect. However, if any of the provisions allowing for the issuance of securitization bounds were found to be invalid or unconstitutional, the required 5 percent rate reduction would also be void. If this occurred, the rates would instead return to the level they were on May 1, 2000.


Senate Bill 937 is tie-barred to Senate Bill 1253.


Senate Bill 1253 would also amend the Public Service Commission (PSC) enabling act (MCL 460.10h et al.) to require the PSC, if certain criteria were met, to issue a financing order that would authorize an electric utility to issue securitization bonds in order to recover qualified costs. Qualified costs would include regulatory assets, adjusted by investment tax credits, as well as costs the utility would be unlikely to recover in a competitive market - including retail open access implementation costs and the costs of a PSC-approved restructuring, buy-out or buy-down of a power purchase contract. The order also would approve the creation of securitization charges (amounts collected by the utility from its customers for the full recovery of qualified costs) and any corresponding utility rate reductions.


Securitization bonds could not have a term over 15 years, and would be secured by or payable from securitization property (the rights and interests of a utility or its successor under a financing order, including the right to collect securitization charges and to obtain adjustments at least annually for over-collections or under-collections). The bonds would not be a debt or obligation of the state or a charge on its full faith and credit or taxing power. Securitization property (which would include the utility's rights to collect, impose and receive authorized charges, to obtain periodic adjustments of those charges and all the revenue, collections, payments, money, and proceeds arising from those rights and interests) would be considered an account under Article 4 of the Uniform Commercial Code and a description of such property would be sufficient if it referred to the act and to the financing order that established the securitization property. Such property would be treated as existing under both the UCC and the act whether or not the revenue or proceeds had accrued and whether or not the value depended upon the customers receiving service. The validity, perfection, or priority of the security interest in the secured property would not be affected by changes in the financing order or in customers' securitization charges. Any conflicts between the act and any other state law regarding attachment, perfection, and priority would be controlled by the provisions of the act. Notwithstanding the UCC, the laws of the state of Michigan would govern the perfection and the effect of perfection and priority of any security interest in securitization property.


Upon a utility's application, the PSC would have to issue a financing order if it found that the net present value of the revenues to be collected under the financing order was less than the amount that would be recovered over the remaining life of the qualified costs using conventional financing methods. The PSC would have to ensure that the proceeds of the bonds would be used solely for the purpose of the refinancing or retirement of debt or equity; that securitization would provide tangible and quantifiable benefits to customers; that the expected structuring and pricing of the bonds would result in the lowest securitization charges consistent with market conditions and the terms of the order; and that the amount secured did not exceed the net present value of the revenue retirement over the life of the bonds associated with the qualified costs sought to be securitized.


Senate Bill 1253 is tie-barred to Senate Bill 937.


Senate Bills 940 and 941 would amend separate acts to limit the area in which municipal corporations and home rule cities could sell electric generation service at retail, unless the municipal corporation or municipal utility complied with provisions in Senate Bill 937 that govern municipally owned utilities. Senate Bill 940 would amend Public Act 35 of 1951 (MCL 124.3), which authorizes intergovernmental contracts between municipal corporations, and Senate Bill 941 would amend the Home Rule City Act (MCL 117.4f). Both bills are tie-barred to Senate Bill 937.


Currently, a municipal corporation may sell and deliver heat, power, and light at wholesale or "other than wholesale", but "other than wholesale" sales are restricted to the area of cities, villages, or townships that were contiguous to the municipal corporation on June 20, 1974, and to the area of any other city, village, or township that was served by the municipal utility on that date. Similarly, if a home rule city sells heat, power, and light at other than wholesale, the sales are limited to the area of any village or township that was contiguous to the city as of June 20, 1974, and to the area of any other village or township being served on that date. The bill would limit electric delivery service (i.e., transmission or distribution) to those areas that could currently be sold to at other than wholesale. Retail sales of electric generation service would also be limited to those areas, unless the municipal corporation or home rule city complied with proposed Section 10u(4) of Public Act 3 of 1939 (the Public Service Commission enabling act).


In addition, a municipal corporation or home rule city currently may not render heat, power, or light to customers outside its corporate limits already receiving that service from another utility unless the serving utility consents in writing. Under the bills, a municipal corporation or home rule city could not render electric delivery service for heat, power, or light to those customers without the utility's written consent. Senate Bill 941 also specifies that a home rule city could not render retail electric generation service to customers who were outside the city's corporate limits and received service from another supplier, unless the city complied with certain provisions outlined in Senate Bill 937. Those provisions deal with delivery service to retail customers of municipally owned utilities, and would give the governing body of a municipally-owned utility the choice of allowing its retail customers to choose an alternative electric supplier, subject to the implementation of rates, charges, terms, and conditions described in the bill. The provisions also specify conditions that would apply if a municipally-owned utility elected to serve as an electric supplier to retail customers who receive delivery service from a regulated service provider.


Senate Bills 940 and 941 provide that "electric delivery service" would have the same meaning as "delivery service" under Senate Bill 937, i.e., the provision of electric transmission or distribution to a retail customer. "Electric generation service" also would be defined as proposed in Senate Bill 937: the sale of electric power and related ancillary services, but not the provision of a regulated service (i.e., transmission and distribution services subject to the jurisdiction of the Public Service Commission, provided by an electric utility).


FISCAL IMPLICATIONS:


According to the House Fiscal Agency, Senate Bill 937 would have long-term (over the next several years) fiscal impact on state revenues. Tax implications exist for the single business tax, income tax, sales/use taxes, and property taxes. The long-term fiscal impact is indeterminate at this time. However, the immediate 5 percent cut in residential rates (Detroit Edison and Consumers Energy customers) will reduce sales tax revenues by an estimated $5 million in fiscal year 2000-01, which would reduce school aid fund revenue by $3 million, revenue sharing by $1.8 million, and general fund/general purpose revenue by $0.2 million. The bill should not impose any new costs on the Public Service Commission and thus should not affect state costs. (6-22-00)


ARGUMENTS:


For:

Michigan has fallen behind 24 other states, including most of the Midwestern industrial states, that have already passed similar bills to provide customer choice for electricity to lower utility rates and to set new rules in order to increase electric generating capacity. Because the state has not moved forward on this issue, Michigan's rates are too high when compared to other states in the region (rates in Michigan are as much as 10 percent higher than in Ohio, for example). As a result, the legislation will not only serve existing customers by cutting rates, but will also help to attract businesses to Michigan, thus improving the state's economy. Many companies make their decisions about where to locate based upon issues like the cost of electricity, particularly those companies that tend to use large volumes of electricity. Another important issue for businesses is the reliability of electricity. Thus, the provisions of the bills requiring expanded generation capacity and improved transmission will not only help the average consumer, but will also help to encourage businesses to move into the area.


Further, customers will have more choices and be better protected under the new act. Not only will the new act prohibit slamming and cramming and penalize such behaviors, but it also contains protection against shut-offs for seniors and low-income customers and requires worker transition programs for workers who could lose their jobs as the electric market becomes more competitive. In addition, the act requires the PSC to set standards for the electricity suppliers to educate and inform customers about the availability of choice in the electricity market, so that the customers are able to make informed decisions. The legislation also requires electric suppliers to disclose environmental information, such as emissions and the types of fuels used to create the energy. This will allow customers, if they are so inclined, to weigh environmental concerns when choosing electricity providers.


Against:

The bills leave a great deal of the decision making to the PSC and, thus, are dependent upon the how well or how poorly the members of the commission use that authority. As a result, some have argued that, instead of allowing the commission to continue to be appointed by the governor, the members of the commission should be elected by the public. It is argued that such a change would help ensure that the members of the commission were responsive to the voters of the state, rather than to the governor.


Another flaw in the legislation is that the protection for would-be competitive energy providers is insufficient. Given the existing monopoly position held by the incumbent regulated utilities, it has been argued that some of the incentives would have the effect of discouraging, rather than encouraging, competition. In particular, the requirement of a five percent rate cut is not only a clear interference with market forces, it begs the question - why not a ten percent rate cut? Or 20 percent? Of what value, other than political, is an arbitrary rate cut? Opponents point out that by requiring a lowered rate, the bill could limit the ability of some competitors to enter the marketplace. First, the lowered rate could give customers less incentive to shop around and switch providers. Second, if new competitors can be assumed to have smaller profit margins, then the artificially lowered rate could force them to offer lower (possibly unprofitable or only marginally profitable) rates in order to entice customers to switch, weakening those competitors from day one. Even if the new competitors aren't forced to offer significantly lower rates to gain market share, the likelihood is that the incumbent providers will do better on the lower profit allowed under the artificially set rates than the new would-be competitors. Further, the cut does not actually help consumers either, because it has the effect of displacing scheduled rate cuts (some of which would have exceeded the 5 percent rate cut mandated by the legislation) that had been ordered by the PSC to counter higher than expected earnings by the existing monopoly utilities.


In addition, the market power test that is intended to use securitization as a carrot to encourage the incumbent utilities to allow competitors into the market, would no longer fairly judge how much of the particular market is served by the utility. By removing larger demand customers from the market power test, the test is weakened so severely that the regulated utilities will likely meet the test easily, without having to allow competitors into the market. Unfortunately, this could lead to problems similar to those being seen in California's electricity market and to those plaguing with Michigan's local telephone market. In both cases, many observers suggest that deregulation occurred without the existence of significant competition and led to increased prices for consumers. As a result, unless there is healthy competition in the electricity market, consumers could face unreasonably high rates during periods of unusually high demand. Thus, the market power test should be amended to require that all customers be included when measuring how much of a particular market is being served by a particular utility.


Another problem stems from the bill's language regarding aggregation. Although the bill generally states that aggregation may be used to purchase electricity, it only specifically indicates that schools, universities, and local units of government must have the written consent of each customer and that those customers who do not chose to participate in the aggregate may make their own decisions with regard to choosing an electricity supplier. It is unclear whether this means that only schools, universities and local units of government may act as aggregators, or whether only they are required to obtain the written consent of consumers.


Another issue, closely related to aggregation, is whether or not aggregators will be required to pay franchise fees in order to aggregate customers within a local unit of government. If local units of government are allowed to charge other would-be aggregators for access to customers within that local unit, local units of government would have a clear and unfair advantage over other aggregators. In the same vein, some argue that since the legislation prohibits alternative electricity providers from building distribution systems, those providers should not be required to pay franchise fees to local units simply for the use of existing distributions systems, especially when those providers will already have to pay the owners of the distribution systems for their use. While it is clear that local units should have authority to charge franchise fees for the placement of power lines, it seems less fair to allow them to charge for the use of existing lines. These provisions should be clarified by the legislature, before they have to be clarified by the courts.


Analyst: W. Flory



This analysis was prepared by nonpartisan House staff for use by House members in their deliberations, and does not constitute an official statement of legislative intent.