SB0437: SUMMARY OF INTRODUCED BILL IN COMMITTEE (Date Completed: 7-14-15)

CONTENT

The bill would amend Public Act 3 of 1939, the Public Service Commission law, to do the following:

-- Delete provisions allowing a gas or electric utility to implement a proposed rate increase if the Public Service Commission (PSC) has not issued an order within 180 days after the utility filed its application for the increase; and requiring the utility to refund to customers the difference between the increased rate and the rate ultimately approved by the Commission.

-- Provide that a gas or electric utility's petition or application to alter its rates would be considered approved if the PSC did not make a final decision within 10 months, rather than 12 months, after the petition or application was filed.

-- Authorize the PSC to approve a revenue decoupling mechanism for a natural gas or electric utility that adjusted for changes in actual sales volumes compared to the projected levels used in the utility's rate case.

-- Require an electric utility's five-year forecast filed to implement a power supply cost recovery clause to demonstrate that the utility had adequate resources to meet a required reserve margin.

-- Delete a requirement that the PSC disallow unapproved capacity charges associated with power purchased for periods longer than six months in a power supply cost reconciliation order for an electric utility.

The bill also would delete provisions allowing an electric utility to apply to the PSC for a certificate of necessity (CON) for increased generation capacity and requiring each utility applying for a CON to file an integrated resource plan (IRP). Instead, each electric utility whose rates are regulated by the PSC would have to file an IRP within two years after the bill took effect. Specifically, the bill would do the following:

-- Require the PSC to commence a proceeding every four years to establish statewide parameters for IRPs.

-- Require the PSC, within 270 days after an IRP was filed, to issue an order approving it or denying it with recommended changes.

-- Require the PSC to hold a hearing on an IRP.

-- Prescribe conditions under which the PSC would have to approve an IRP.

-- Require an electric utility to file periodic reports on the status of the projects contained in its IRP.

-- Authorize an electric utility to withdraw its IRP or proceed with a proposed generation construction, investment, or power purchase if the PSC denied any of the relief requested by the utility.

-- Provide that an IRP denied by the PSC would be considered approved if the utility modified it to be consistent with the Commission's recommendations.

-- Allow a utility that did not accept the PSC's recommendations to submit a revised IRP for approval, and required the Commission to commence a contested case hearing and issue a final order on the plan within 90 days.

-- Provide for review of a PSC order approving an IRP by the Court of Appeals and prescribe the scope of the review.

-- Require the PSC to include in an electric utility's retail rates all reasonable and prudent costs for a generation facility or power purchase agreement included in an approved IRP.

-- Require the PSC to adopt standard IRP filing forms and instructions within 90 days after the bill took effect.

-- Revise the information that must be included in an IRP.

-- Allow an electric utility to seek amendments to or review of its IRP.

-- Authorize the PSC to order an electric utility to file an IRP review, and allow the Department of Environmental Quality to request the PSC to issue such an order to address changes in environmental regulations and requirements.

-- Require the PSC, within 90 days after the bill's effective date, to commence a study to consider the adoption of performance-based regulation, under which a utility's profits would depend on the utility's achieving targeted policy outcomes.

-- Require the PSC, within 180 days after the bill took effect, to make written recommendations to the Legislature and the Governor based on the study's results.

Additionally, the bill would amend the part of the PSC law known as the Customer Choice and Electricity Reliability Act to do the following:

-- Change the title to the "Electricity Reliability Act".

-- Revise the Act's purposes.

-- Provide that an electric customer who was taking service from an alternative electric supplier (AES) on January 1, 2015, would be eligible to continue taking service from the AES; and a customer on a list awaiting retail open access service on that date could remain on the list to take service from an AES if the service became available.

-- Require each AES customer, by December 15, 2015, to notify the electric utility that provided the customer's distribution services whether the customer intended to remain with an AES or return to standard tariff service with the utility.

-- Require each customer on the retail open access list, by December 15, 2015, to notify the electric utility that provided the customer's distribution services whether the customer would remain on the list.

-- Require each electric utility, by January 1, 2016, to file with the PSC a list of all customers that had elected to be eligible for retail open access service.

-- Create several exceptions to a provision limiting to 10% the amount of an electric utility's average retail sales that may take service from an AES.

-- Provide that a customer taking service from an AES on the bill's effective date who subsequently desired to return to standard tariff service from an electric utility would no longer be eligible to receive service from an AES.

-- Require an AES customer that elected to continue receiving service from the AES to provide at least three years' notice to the electric utility, if the customer subsequently desired to return to standard tariff service from the utility; and provide for the customer to bear the incremental costs of providing the service if the customer did not comply with the three-year notice requirement.

-- Provide that a customer on the retail open access list who was notified of the opportunity to take service from an AES and did not take that service within seven days would be removed from the list.

-- Require an AES to demonstrate annually to the PSC that it would be able to supply sufficient generating capacity for the next three years (or five years, in the case of an identified shortfall) or the term of any contract, whichever was longer.

-- Require the PSC to revoke the license of an AES that was unable to make the required demonstration of sufficient generating capacity, and bar the AES from providing electricity supply for three years.

-- Require the PSC to establish planning reserve margin requirements for all customer electric loads served by an AES.

-- Authorize an electric utility to offer other value-added programs and services to its customers, in addition to an appliance service program, without violating a utility code of conduct, as long as certain conditions were met.

-- Allow an electric utility or AES to shut off service to a customer who did not make a required payment for an energy project financed under the electric provider's residential energy projects program.

The bill also would repeal Section 6e of the law, which required the Legislature to review and evaluate the impact of a provision exempting the owner of a renewable resource power production facility from regulation or control by the PSC, if certain conditions were met. The review and evaluation had to be completed by March 25, 1983.

The bill would take effect 90 days after enactment.

Utility Rates

The PSC law prohibits a gas or electric utility from increasing its rates and charges or altering, changing, or amending any rate or rate schedules so as to increase the cost of services to its customers without first receiving PSC approval as provided in the law.

If the PSC has not issued an order within 180 days after a utility has filed a complete application for a rate increase, the utility may implement up to the amount of the proposed annual rate request through equal percentage increases or decreases applied to all base rates. For good cause, the PSC may issue a temporary order preventing or delaying a utility from implementing its proposed rates or charges. If a utility implements increased rates or charges before the PSC issues a final order, the utility must refund to customers, with interest, any portion of the total revenue collected through application of the equal percentage increase that exceeds the total that would have been produced by the rates or charges subsequently ordered by the Commission. Any refund or interest awarded under these provisions may not be included in any application for a rate increase by a utility. The bill would delete these provisions.

The law requires the PSC to adopt rules and procedures for the filing, investigation, and hearing of petitions or applications to increase or decrease utility rates and charges as the Commission finds necessary or appropriate to enable it to reach a final decision within 12 months after a complete petition or application is filed. Except as otherwise provided, if the PSC fails to reach a final decision within that 12-month period, the petition or application is considered approved. The bill would reduce the time frame from 12 months to 10 months.

The bill would authorize the PSC to approve a revenue decoupling mechanism for a natural gas or electric utility that adjusted for increases or decreases in actual sales volumes compared to the projected levels used in the utility's most recent rate case. In determining the decoupling mechanism for a particular utility, the PSC would have to defer to the proposed mechanism submitted by the utility. The Commission could approve a different mechanism if it determined that the mechanism was reasonable and prudent.

Electric Utility: Power Supply Cost Recovery

Under the law, the PSC may incorporate a power supply cost recovery (PSCR) clause in the electric rates of rate schedule of an electric utility. "Power supply cost recovery clause" means a clause in an electric utility's rates or rate schedule that permits the monthly adjustment of rates for power supply to allow the utility to recover the booked costs, including the costs of transportation, reclamation, and disposal and reprocessing, of fuel burned by the utility for electric generation and the booked costs of purchased and net interchanged power transactions by the utility incurred under reasonable and prudent policies and practices.

In order to implement the PSCR clause, the utility annually must file a complete PSCR plan describing the expected sources of electric power supply and changes in the cost of power supply anticipated over a future 12-month period and requesting for each of those months a specific PSCR factor. Additionally, the utility must file a five-year forecast of the power supply requirements of its customers, its anticipated sources of supply, and projections of power supply costs, in light of its existing sources of electrical generation and sources under construction. The forecast must include a description of all relevant major contracts and power supply arrangements entered into or contemplated by the utility, as well as any other information required by the PSC. Under the bill, the forecast also would have to include a demonstration that the utility had adequate resources to meet any reserve margin required by law.

The law requires the PSC to commence a power supply cost reconciliation at least once a year after the end of the 12-month period covered by an electric utility's PSCR plan. At the reconciliation, the Commission must reconcile the revenue recorded pursuant to the PSCR factors and the allowance for cost of power supply included in the base rates established in the latest PSC order for the utility with the amounts actually expensed and included in the utility's cost of power supply.

In its reconciliation order, the PSC must disallow any capacity charges associated with power purchased for periods longer than six months unless the utility has obtained the Commission's prior approval. The bill would delete this provision.

Electric Utility: Certificate of Necessity & Integrated Resource Plan

Filing of CON Application or IRP. The law allows an electric utility that proposes to construct an electric generation facility, make a significant investment in or purchase an existing generation facility, or enter into a power purchase agreement for the purchase of electric capacity for a period of at least six years to apply to the PSC for a certificate of necessity for the construction, investment, or purchase, if it costs more than $500.0 million and a portion of the cost would be allocable to Michigan retail customers. The PSC may not issue a CON for any environmental upgrades to existing generation facilities or for a renewable energy system. The PSC may implement separate review criteria and approval standards for electric utilities with fewer than 1.0 million retail customers who seek a CON for projects costing less than $500.0 million.

An electric utility submitting an application may request a CON affirming one or more of the following:

-- That the power to be supplied as a result of the proposed construction, investment or purchase is needed.

-- That the size, fuel type, and other design characteristics of the existing or proposed generation facility or the terms of the power purchase agreement represent the most reasonable and prudent means of meeting that power need.

-- That the price specified in the power purchase agreement will be recovered in rates from the utility's customers.

-- That the estimated purchase or capital costs of and the financing plan for the existing or proposed generation facility will be recoverable in rates from the utility's customers.

The bill would delete all of these provisions.

Instead, within 120 days after the bill took effect and every four years after that, the PSC would have to commence a proceeding to establish statewide parameters for integrated resource plans (described below). In consultation with the Michigan Agency for Energy and the Department of Environmental Quality (DEQ), the PSC would have to do all of the following in the proceeding:

-- Conduct an assessment of the potential for reduction in energy waste in Michigan based on what was economically and technologically feasible.

-- Identify any new State or Federal environmental standard, law, or rule and how it would affect electric utilities in Michigan.

-- Identify any proposed State or Federal environmental standard, law, or rule that had been published in the Michigan Register or the Federal Register and how it would affect electric utilities in Michigan.

-- Establish the modeling scenarios and assumptions each electric utility would have to use in developing its IRP.

-- Allow other State agencies to provide input regarding any other regulatory requirements that should be included in modeling scenarios or assumptions.

-- Publish a copy of the proposed modeling scenarios and assumptions to be used in IRPs on the PSC's website.

-- Receive written comments and hold hearings to solicit public input, before issuing the final scenarios and assumptions.

The established scenarios and assumptions would have to include all of the following:

-- Any required reliability standards.

-- All applicable State and Federal environmental standards, laws, and rules identified under these provisions.

-- Any required investments in generation, transmission, and distribution infrastructure.

-- Any supply-side and demand-side resources that could address any need for additional generation capacity, including the type of generation technology for any proposed generation facility, projected energy efficiency savings, and projected load management and demand response savings.

-- Any regional infrastructure limitations in Michigan.

-- The projected costs of different types of fuel used for electric generation.

Within two years after the bill took effect, each electric utility whose rates were regulated by the PSC would have to file with the Commission an IRP that minimized the present value of forward-looking capital and production costs while meeting all applicable State and Federal reliability and environmental regulations, and provided a long-term projection of the utility's load obligations and a plan to meet them over the plan's ensuing term. The PSC would have to establish filing requirements for an IRP that demonstrated how the utility would comply with the requirements to provide generation reliability, including meeting reserve margin requirements established by the PSC or a federally authorized regional transmission system operator for a five-year, 10-year, and 15-year planning period.

PSC Order & Hearing. Currently, within 270 days after a utility files a CON application, the PSC must issue an order granting or denying the requested CON. The Commission must hold a hearing, conducted as a contested case under the Administrative Procedures Act (APA), on the application. Also, the PSC must allow intervention by interested people.

Under the bill, instead, within 270 days after an electric utility filed an IRP, the PSC would have to issue an order approving or denying it, with recommended changes. The Commission would have to hold a hearing on the IRP, conducted as a contested case.

The bill would require the PSC to request an advisory opinion from the DEQ regarding whether the IRP reasonably could be expected to achieve compliance with applicable State and Federal environmental regulations and result in pollution reductions required by those regulations. The PSC could invite other State agencies to provide testimony regarding other relevant regulatory requirements related to the IRP.

The law requires the PSC to permit reasonable discovery before and during the hearing in order to assist parties and interested people in obtaining evidence concerning the CON application, including the reasonableness and prudence of the proposal. A similar requirement would apply in the case of a hearing regarding an IRP.

CON/IRP Approval. Under the existing CON process, the PSC must grant the utility's request if it determines all of the following:

-- The utility has demonstrated a need for the power that would be supplied by the existing or proposed generation facility or pursuant to the power purchase agreement through its approved IRP that complies with standards prescribed in the law (described below).

-- The information supplied indicates that the existing or proposed facility will comply with all applicable State and Federal environmental standards, laws, and rules.

-- The estimated cost of power from the existing or proposed facility or the price of power specified in the proposed purchase agreement is reasonable.

-- The existing or proposed facility or power purchase agreement represents the most reasonable and prudent means of meeting the power need relative to other resource options for meeting power demand, including energy efficiency programs and electric transmission efficiencies.

-- To the extent practicable, the construction or investment in a new or existing facility (except a facility located in a county that lies on the border with another state) is completed using a workforce composed of Michigan residents.

With regard to the IRP process, the bill would require the PSC to approve an IRP if it determined all of the following:

-- The utility had demonstrated a need for the investments and resources including the proposed plan, and that those investments and resources would be sufficient to provide the capacity necessary to serve the utility's reasonably projected electric loads and applicable reserve margins.

-- The information supplied indicated that the proposed IRP and the resources contained in it would comply with all applicable State and Federal environmental standards, laws, and rules.

-- The estimated cost of power from the existing or proposed facility or the price of power specified in the proposed purchase agreement was reasonable.

-- The existing or proposed IRP represented the most reasonable and prudent means of meeting the capacity needs relative to other resource options for meeting them, including energy efficiency programs, demand-side management, and transmission efficiencies.

-- To the extent practicable, the construction or investment in a new or existing capacity resource (except one located in a county that lies on the border with another state) was completed using a workforce composed of Michigan residents.

To determine whether the IRP was the most reasonable and prudent means of meeting capacity needs, the PSC would have to consider whether it appropriately balanced all of the following factors:

-- Resource adequacy and capacity to serve anticipated peak electric loads and reserve margin requirements.

-- Compliance with applicable State and Federal environmental regulations.

-- Competitive pricing.

-- Reliability.

-- Commodity price risks.

-- Diversity of generation supply.

With regard to the estimated cost of power, the PSC would have to find it reasonable if, in the construction or investment in a new or existing facility, to the extent it was commercially practicable, the costs were the result of competitively bid engineering, procurement, and construction contracts, or in a power purchase agreement, the cost was the result of a competitive solicitation. Up to 150 days after the utility made its initial filing, it could file to update its cost estimates if they had materially changed. No other aspect of the initial filing could be modified unless the application was withdrawn and refiled. A utility's filing updating its cost estimates would not extend the period for the PSC to issue an order approving or denying the IRP. An affiliate of an electric utility that served customers in Michigan and at least one other state could participate in the competitive bidding to provide services to that utility for a project covered under the bill. (Similar provisions apply to the current CON process.)

Under the current CON process, the PSC may consider any other costs or information related to the costs associated with the power that would be supplied by the existing or proposed generation facility or pursuant to the proposed purchase agreement or alternatives to the proposal raised by intervening parties. The bill would require, rather than allow, the PSC to consider these other costs with regard to the IRP. The bill also specifies that intervening parties could include electric customers, potential resource suppliers of the utility's proposed IRP, any regional transmission organization serving any portion of the utility's service area, Michigan's Attorney General, or any other parties approved by the PSC.

Currently, in approving a CON, the PSC must specify the costs approved for the construction of or significant investment in an electric generation facility, the price approved for the purchase of an existing facility, or the price approved for the purchase of power under the terms of an agreement. Under the bill, this requirement would apply to the approval of an IRP. Also, among the approved costs that the Commission must specify, the bill would include those associated with other investments or resources used to meet capacity needs that were included in the approved IRP. For power purchase agreements that a utility entered into with an entity that was not affiliated with the utility after the bill's effective date, the PSC could authorize a rate of return that did not exceed the utility's weighted average cost of capital. The costs for specifically identified investments included in an approved IRP that were commenced within three years after the PSC's order approving the initial plan, amended plan, or plan review would be considered reasonable and prudent for cost recovery purposes.

Status Reports. Currently, the law requires an electric utility to file annually, or more frequently if required by the PSC, reports regarding the status of any project for which a CON has been granted, including an update concerning the cost and schedule of the project. Under the bill, a similar requirement would apply to an IRP and the projects included in it.

Denial of Relief. Under the current law, if the PSC denies any of the relief requested by an electric utility, the utility may withdraw its CON application or proceed with a proposed construction, purchase, investment, or power purchase agreement without a CON and the law's assurances of cost recovery. Under the bill, this provision would apply to a utility's IRP.

Additionally, if the PSC denied the utility's IRP but the utility accepted the Commission's recommendations regarding the plan, the plan would be considered approved as modified by the utility consistent with those recommendations. If the utility did not accept the PSC's recommendations, within 30 days after the date of the final order denying the IRP, the utility could submit a revised IRP to the Commission for approval. The Commission would have to commence a contested case hearing under the APA. Within 90 days after the utility submitted the revised IRP, the PSC would have to issue a final order approving the plan or denying it with recommendations.

Review of IRP Approval. Notwithstanding any other provision of law, a PSC order approving an IRP could be reviewed by the Court of Appeals upon a filing by a party to the Commission proceeding within 30 days after the order was issued. All appeals would have to be heard and determined as expeditiously as possible with lawful precedence over other matters. Review on appeal would have to be based solely on the record before the PSC and briefs to the court. The review would be limited to whether the order conformed to the Constitution and laws of Michigan and the United States and was within the PSC's authority under the PSC law.

Retail Rates. Currently, the PSC must include in a utility's retail rates all reasonable and prudent costs for an electric generation facility or power purchase agreement for which a CON has been granted, once the facility or agreement is considered used and useful or as otherwise provided in the law. The PSC may not disallow recovery of costs a utility incurs in constructing, investing in, or purchasing a generation facility or in purchasing power pursuant to an agreement for which a CON has been granted, if the costs do not exceed those approved by the Commission. Once the facility or agreement is considered used and useful, the PSC must include in the utility's retail rates the costs actually incurred by the utility that exceed those approved by the Commission only if it finds that they are reasonable and prudent. In that case, the utility has the burden of proving by a preponderance of the evidence that the costs are reasonable and prudent. The bill would eliminate the references to the generation facility or power purchase agreement, and instead would refer to an approved IRP and the costs incurred in implementing the plan.

The law provides that the portion of the cost of a plant, facility, or power purchase agreement that exceeds 110% of the approved cost is presumed to have been incurred due to lack of prudence. The PSC may include any or all of that excess portion of the cost if it finds by a preponderance of the evidence that the costs were prudently incurred. Under the bill, these provisions also would apply in the case of other investments in a resource that met a demonstrated need for capacity.

IRP Standards. The law requires the Commission to establish standards for an IRP filed by an electric utility, and requires an IRP to include all of the following:

-- A long-term forecast of the utility's load growth under various reasonable scenarios.

-- The type of generation technology and the capacity proposed for a generation facility, including projected fuel and regulatory costs under various reasonable scenarios.

-- Projected energy and capacity purchased or produced by the utility pursuant to any renewable portfolio standard (RPS).

-- Projected savings under any energy efficiency program requirements and the projected costs for that program.

-- Projected load management and demand response savings for the utility and the projected costs for those programs.

-- An analysis of the availability and costs of other electric resources that could defer, displace, or partially displace the proposed generation facility or purchased power agreement, including additional renewable energy, energy efficiency programs, load management, and demand response.

-- Electric transmission options for the utility.

The bill would retain this requirement with several changes.

The bill would refer to projected energy and capacity purchased or produced from a clean energy resource, rather than pursuant to an RPS.

The bill also would eliminate the requirement that an IRP include projected savings and costs related to energy efficiency programs, and instead would require details regarding the utility's plan to eliminate waste, including the total amount of waste reduction expected to be achieved annually, the cost of the plan, and the expected savings for its retail customers.

With regard to the analysis of the availability of other electric resources, the bill would eliminate the reference to additional renewable energy, energy efficiency programs, load management, and demand response. Regarding transmission, the bill would refer to an analysis of potential new or upgraded options.

In addition, the bill would require an IRP to include the following:

-- Data regarding the utility's current generation portfolio including the age, licensing status, and remaining estimated time of operation for each facility in the portfolio.

-- Plans for meeting current and future capacity needs with cost estimates for all proposed construction, major investments, and power purchase agreements.

-- An analysis of the cost, capacity factor, and viability of all generation options available to meet projected capacity needs.

-- Projected economic and environmental threats that could affect rates and service delivery.

-- Projected rate impact for the periods covered by the plan.

-- How the utility would comply with all applicable State and Federal environmental standards, laws, and rules.

-- A forecast of the utility's peak demand and details regarding how the utility proposed to reduce it.

Within 90 days after the bill's effective date, the PSC would have to adopt standard application filing forms and instructions for use in all requests for an IRP. In its discretion, the PSC could modify the forms and instructions.

IRP Amendment & Review. The bill would allow an electric utility to seek amendments to an approved IRP. An electric utility would have to file an application for review of its IRP within three years after the effective date of the most recent PSC order approving a plan, plan amendment, or plan review. The PSC would have to consider the amendments or review under the same process and standards that governed the review and approval of an IRP.

In addition, the PSC could order an electric utility to file a plan review. The DEQ could request the PSC to order a plan review to address material changes in environmental regulations and requirements that occurred after the PSC approved an IRP. A utility would have to file a plan review within 270 days after the PSC ordered it.

Performance-Based Regulation

Within 90 days after the bill took effect, the PSC would have to commence a study in collaboration with representatives of each customer class, utilities with at least 1.0 million Michigan retail customers, and other interested parties to consider the adoption of performance-based regulation, under which a utility's profits would depend on the utility's achieving targeted policy outcomes. The bill states, "The overall goal of performance-based regulation is to foster greater innovation and investment by the utility industry in this state, in light of the aging utility infrastructure in this state and demands on the utilities with regard to the environment and climate."

In the study, the PSC would have to review performance-based regulation systems implemented in another state or country, including the RIIO (Revenue = Incentives + Innovation + Outputs) model used in the United Kingdom.

A performance-based regulation system would have to include the following factors:

-- A method for estimating the revenue needed by a utility during a multiyear pricing period, and a fair return, that used forecasts of efficient total expenditures by the utility instead of distinguishing between operating and capital costs.

-- An increase in the length of time between rate cases, to provide utilities with more opportunity to retain cost savings without the threat of imminent rate adjustments, and to encourage utilities to make investments that had payback periods longer than five years.

-- Profit-sharing provisions that could spread efficiency gains among consumers and utility shareholders and could reduce the degree of downside risk associated with attempts at innovation.

-- Performance incentives established at the outset of a rate period that pertained to issues such as customer satisfaction, safety, reliability, conditions for connection, environmental impact, and social obligations.

Based on a utility's performance regarding those incentives, the utility could receive financial rewards or penalties that adjusted its base revenue.

A performance-based regulation system also would have to include the use of utility-drafted business plans based on the factors listed above and informed by consultation with environmental groups, consumer advocates, government officials, and third-party service providers. A business plan would include proposals for base revenue, various outcomes of interest that would be pursued, the metrics that would be used to gauge the achievement of those outcomes, and the methods that would be used to manage uncertainty during the extended price control period.

Within 180 days after the bill took effect, the PSC would have to report and make written recommendations to the Legislature and the Governor based on the result of the study.

Customer Choice and Electricity Reliability Act

Title. Currently, Sections 10 through 10bb of the PSC law are known as the "Customer Choice and Electricity Reliability Act". Under the bill, those sections would be known as the "Electricity Reliability Act".

Purpose. The bill would delete the following from the Act's prescribed purposes:

-- To ensure that all electric retail customers in Michigan have a choice of electric suppliers.

-- To allow and encourage the PSC to foster competition in Michigan in the provision of electric supply and maintain regulation of electric supply for customers who continue to choose supply from incumbent electric utilities.

-- To encourage the development and construction of merchant plants which will diversify the ownership of electric generation in Michigan.

Another stated purpose of the Act is to ensure that all people in the State are afforded safe, reliable electric power at a reasonable rate. The bill would refer to a competitive rate rather than a reasonable one.

PSC Orders: Retail Choice. The Act requires the PSC to issue orders establishing the rates, terms, and conditions of service that allow "all retail customers of an electric utility or provider" to choose an alternative electric supplier. The bill would refer instead to "retail customers".

The orders must provide that not more than 10% of an electric utility's average weather-adjusted retail sales for the preceding calendar year may take service from an AES at any time. Under the bill, this provision would apply except as described below.

The orders also must set forth procedures necessary to administer and allocate the amount of load that will be allowed to be served by AESs, through the use of annual energy allotments awarded on a calendar year basis. The bill would delete the reference to "administer".

Also, the bill would delete a requirement that the orders provide that existing customers who were taking electric service from an AES at a facility on October 6, 2008, be given an allocated annual energy allotment for that service at that facility, and that customers seeking to expand use at a facility served through an AES will be given next priority with the remaining available load, if any, allocated on a first-come, first-served basis. Currently, the procedures must provide how customer facilities are defined for the purpose of assigning the annual energy allotments. The PSC may not allocate additional energy allotments at any time when the total annual allotments for the utility's distribution service territory is greater than 10% of the utility's weather-adjusted retail sales in the calendar year preceding the date of allocation. The bill would delete these provisions. Instead, the PSC would have to use the annual energy allotment awarded under the Act to determine the eligibility of a customer to receive service from an AES.

The orders must provide that if a utility's sales are less in a subsequent year or if the energy use of an AES customer exceeds its annual allotment for that facility, the customer cannot be forced to purchase electricity from a utility, but may purchase it from an AES for that facility during that calendar year. The bill would retain this provision.

Currently, the orders must provide that customers seeking to expand use at a facility that has been continuously served through an AES since April 1, 2008, must be permitted to purchase electricity from an AES for both the existing and any expanded load at that facility as well as any new facility constructed or acquired after October 6, 2008, that is similar in nature if the customer owns more than 50% of the new facility. The bill would delete this requirement.

The orders also must provide that any customer operating an iron ore mining and/or processing facility located in the Upper Peninsula may purchase all or any portion of its electricity from an AES, regardless of whether the sales exceed 10% of the serving electric utility's average weather-adjusted retail sales. Under the bill, this provision would apply if the utility agreed or if the customer and utility had entered into a settlement agreement allowing the customer to purchase from an AES.

The bill would require the PSC's orders to provide that a customer that was taking service from an AES on January 1, 2015, could elect to continue to take service from an AES. Beginning on the bill's effective date, only customers who were taking service from an AES on January 1, 2015, would be eligible to take service from an AES. By December 15, 2015, each AES customer would have to give written notice to the electric utility that provided that customer with distribution services. The notice would have to state whether the customer would remain with an AES or intended to return to standard tariff service with the utility upon the termination of the customer's electricity supply contract with an AES. If a customer intended to return to standard tariff service, the customer would have to include with the notice the intended return date.

Currently, a customer that elects to receive service from an AES may subsequently notify the electric utility of the customer's desire to receive standard tariff service from the utility. The procedures in place for each electric utility as of January 1, 2008, that set forth the terms pursuant to which an AES customer could return to full service from the utility were ratified and remain in effect and may be amended by the PSC as needed. If an electric utility did not have the procedures in place as of January 1, 2008, the PSC had to adopt them. The bill would delete these provisions.

The bill also would require the orders to provide that a customer on a list awaiting retail open access service on January 1, 2015, could elect to continue to remain on the list to take service from an AES if that service became available. By December 15, 2015, each customer qualified to receive service under this provision would have to give written notice to the electric utility that provided that customer with distribution services. The notice would have to state whether the customer would remain on the list.

Additionally, the orders would have to require each utility to file with the PSC by January 15, 2016, a list of all customers that had elected to be eligible for retail open access service. The filing would have to include the estimated amount of electricity used by each customer.

The bill also would require the orders to provide that customers seeking to expand use at a facility that was served by an AES could purchase electricity from an AES for both the existing and any expanded load at that facility, as well as any new facility constructed or acquired after the bill's effective date that was similar in nature if the customer owned more than 50% of the new facility, regardless of whether the sales exceeded the 10% limit for the serving electric utility.

Further, the orders would have to provide that an AES customer subsequently could notify the electric utility of the customer's desire to receive standard tariff service from the utility. If a customer that was receiving service from an AES on the bill's effective date subsequently elected to return to service from the utility, the customer would no longer be eligible to receive service from an AES. A customer that elected to continue receiving electric supply service from an AES after notifying the utility could return to standard tariff service from the utility if the customer gave the utility three years' advance written notice of the intent to return. A notice of intent to return would be irrevocable. The utility could waive all or any part of the notice requirement for any customer returning to standard tariff service. If a customer returned to the utility without giving at least three years' notice, any incremental costs, including capacity, energy, ancillary services, distribution service, and transmission service, associated with the customer's return could not be borne by the utility or any other customer of the utility. If the return of such a customer created additional costs or impaired reliability, the PSC could establish tariff provisions or other terms and conditions to assign those costs or impairments to that customer.

In addition, the orders would have to provide that if the customer next on the list awaiting retail open access service were notified that less than 10% of an electric utility's average weather-adjusted retail sales for the preceding calendar year was taking service from an AES, the customer could purchase all or any portion of its electricity from an AES, regardless of whether the sales exceeded the serving utility's 10% limit. The orders also would have to provide that a customer who refused to take service from an AES within seven days after being notified would be removed from the list and would not be eligible to receive electric generation service from an AES.

Additionally, the orders would have to provide that an electric utility had no duty to provide generation resource adequacy for AES customers.

The Act defines "customer" as the building or facilities served through a single existing electric billing meter. The term does not mean the person, corporation, partnership, association, governmental body, or other entity owner or having possession of the building and facilities. The bill would delete the definition.

AES Licensure. The Act requires the PSC to issue orders establishing a licensing procedure for all AESs. To ensure adequate service to Michigan customers, the Commission must require an AES to maintain an office within the State; assure that an AES has the necessary financial, managerial, and technical capabilities; require an AES to maintain necessary records; and ensure an AES's accessibility to the Commission, to consumers, and to electric utilities. Under the bill, the PSC also would have to require that an AES filed all of its electricity supply contracts with the Commission. The price terms of the contracts could be filed under seal.

As a condition of licensure, except as otherwise provided, by November 1 of each year an AES would have to demonstrate to the PSC, in a PSC-approved format, that it would be able to supply enough dedicated, firm, and physical electric generating capacity to serve its retail electric customers' total current peak demand, including a reasonable projection of total peak demand growth, plus the applicable planning reserve margin requirements, for the subsequent three years or the term of any contract, whichever was longer.

If the appropriate independent system operator, where the AES's demand was served, issued a resource adequacy forecast or similar capacity assessment report that projected a capacity shortfall within the subsequent two-year period, an AES would have to demonstrate to the PSC by November 1 of the year in which the report was issued, in a format determined by the Commission, that it would be able to supply enough dedicated, firm, and physical electric generating capacity to serve its retail customers' total current peak demand, including a reasonable projection of total peak demand growth, plus the applicable planning reserve margin requirements for the subsequent five years or the term of any contract, whichever was longer. If the system operator had not issued a forecast or assessment report for at least the subsequent two-year period, the PSC would have to make a formal request that the operator do so.

In determining whether an AES had demonstrated adequate capacity to meet the bill's requirements, the PSC would have to consider only the following:

-- Capacity that was physically located in or deliverable to the resource adequacy zone, as defined by the independent system operator, where the AES's demand was served in Michigan.

-- If the AES relied on power purchase contracts for any portion of its demonstration of capacity supply, that the contracts were prepaid for the required periods.

-- If the AES relied on capacity that was the result of a wholesale market auction for any portion of its demonstration of capacity supply, that the purchases would not exceed 5% of the AES's capacity requirements.

-- If the AES's capacity purchases required the capacity to be transported into Michigan, that the AES had the contracted transmission capacity to import it into the resource adequacy zone where the AES's demand was served in Michigan.

If an AES were unable to demonstrate to the PSC that it had procured the required dedicated, firm, and physical capacity, the PSC would have to notify the AES in writing that the AES had 60 days to remedy any defects identified by the Commission. If the AES failed to remedy those defects within 60 days, the PSC would have to revoke the AES's license to supply electricity and bar the AES from providing electricity supply in Michigan for a three-year period.

The PSC's consideration of an AES's annual demonstration of capacity would have to be performed under a contested case proceeding under the APA.

The PSC would have to establish planning reserve margin requirements for all customer electric loads served by an AES in Michigan. The requirements would have to be based on recent actual levels of peak demand plus a reasonable projection of five-year peak demand growth, and would have to be designed to ensure that the risk of an outage in Michigan due to lack of electricity supply was not more likely than once every 10 years. The reserve margin requirement could take into account customer demand response measures only if the PSC determined that they were as reliable as firm, physical generating capacity. The Commission could elect to use the planning reserve margin requirement set by the appropriate independent system operator.

Electric Utility Code of Conduct. The Act required the PSC to establish a code of conduct applicable to all electric utilities. The code of conduct must include measures to prevent cross-subsidization, information sharing, and preferential treatment, between a utility's regulated services and unregulated services, whether they are provided by the utility or its affiliated entities. The code of conduct applies to electric utilities and AESs. The bill would refer to an electric utility's regulated electric services and unregulated retail open access services.

Appliance Service Program & Value Added Programs. The Act allows an electric utility to offer its customers an appliance service program (ASP). Under the bill, a utility also could offer other value-added programs and services.

A utility offering an ASP must do all of the following:

-- Locate within a separate department of the utility or affiliate within the utility's corporate structure the personnel responsible for the day-to-day management of the program.

-- Maintain separate books and records for the program, and make access to them available to the PSC upon request.

-- Not promote or market the program through the use of utility billing inserts, printed messages on the utility's billing materials, or other promotional materials included with customers' utility bills.

The Act also contains provisions regarding the allocation of the utility's costs attributable to an ASP, inclusion of charges for the program on its monthly customer billings, and program marketing.

Under the bill, all of these provisions also would apply to any other value-added program or service offered by the utility

The Act specifies that the ASP provisions do not prohibit the PSC from requiring a utility to include revenue from such a program in establishing base rates. The bill would refer to an ASP or any other value-added program or service, and instead provides that the Commission would not be required to include revenue from such a program in establishing base rates. The bill would authorize the PSC to permit a utility to retain profits generated by a program, and allow the utility to use a portion of that revenue to invest in business development of new programs and services.

Service Shutoff. The bill would authorize an electric utility or AES to shut off service to a customer as provided in Part 7 of the Clean and Efficient Energy Act. (Senate Bill 438 would add Part 7 to that Act to allow an electric provider to establish a residential energy projects program under which property owners could finance energy projects through an itemized charge on their utility bills.)

If a customer failed to comply with the applicable terms and conditions, an electric utility could shut off service on its own behalf or on behalf of an AES after giving the customer a notice containing specified information, including the following:

-- That the customer had not paid the per-meter charge for a residential energy projects program.

-- That, unless the customer made the past due payments within 10 days of the date of mailing, the utility or AES could shut off service.