SB0437: SUMMARY AS PASSED BY THE SENATE (Date Completed: 12-12-16)

-- Allow the PSC to order a delay in filing an application to establish a 21-day spacing between filings of electric utilities serving more than 1.0 million customers in Michigan.

-- Require a utility to coordinate with PSC staff before filing its general rate case application to avoid resource challenges with applications being filed at the same time as applications filed by other utilities.

-- Effective January 1, 2019, delete a requirement that a utility file a five-year forecast in order to implement a power supply cost recovery clause.

-- 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.

Senate Bill 438 (S-7) would repeal provisions of the Clean, Renewable, and Efficient Energy Act that establish a renewable energy standard, consisting of a renewable energy capacity portfolio and a renewable energy credit portfolio, under which 10% of an electric provider's energy must come from renewable sources by 2015. Instead, the bill would require each electric provider to maintain its currently mandated renewable energy credit portfolio through 2018; and achieve a renewable energy credit portfolio of at least 12.5% in 2019 through 2021 and at least 15% in 2021. Additionally, the bill would amend the Act with respect to energy optimization programs, net metering, renewable energy credits, and other matters.

In relation to renewable energy, the bill would do the following:

-- Provide that an electric provider's renewable energy plan in effect on the bill's effective date would remain in effect.

-- Require the PSC, within one year after the bill took effect, to review each electric provider's plan.

-- Prescribe procedures for the amendment of a renewable energy plan.

-- Revise provisions related to renewable energy credits.

In regard to energy optimization, the bill would provide for the transition of energy optimization programs to energy waste reduction programs. In particular, the bill would do the following:

-- Establish a goal of meeting at least 35% of the State's electric needs through energy waste reduction and renewable energy by 2025.

-- Provide that established energy optimization programs intended to reduce the future costs of providing service to customers would continue in effect as energy waste reduction programs.

-- Refer to "energy waste reduction" rather than "energy efficiency" and "energy optimization" throughout the Act.

-- Revise the incentive a rate-regulated provider may obtain by exceeding the energy waste reduction standard.

-- Authorize a rate-regulated electric or natural gas provider that could not achieve the waste reduction standard in a cost-effective manner over a two-year period to petition the PSC to establish alternative standards.

-- Revise provisions allowing a utility to recover costs associated with the implementation of an energy waste reduction plan, and provide that the charges to recover those costs could be itemized on utility bills until January 1, 2021.

-- Eliminate a provision limiting to 2% the amount of a gas or electric provider's total annual sales revenue that the provider may spend to comply with energy waste reduction requirements.

-- Exempt an electric provider from provisions regarding the suspension of a cost-ineffective energy waste reduction program, beginning January 1, 2021.

-- Provide for redress of violations of the waste reduction provisions by a member-regulated cooperative electric utility or a municipally owned electric utility.

-- Specify that load management could include a voluntary program under which an electric provider could remotely shut down energy intensive systems of participating customers.

-- Delete requirements that the PSC engage in certain activities related to energy efficiency and conservation.

-- Include among the PSC's responsibilities related to the promotion of load management, demand response programs that use time of day and dynamic rate pricing and similar programs for utility customers with advanced metering infrastructure; and allow the programs to provide incentives for customer participation.

-- Require the PSC to submit an annual report to the Legislature on whether the energy waste provisions were cost-effective.

In regard to net metering, the bill would replace the net metering program with a distributed generation program under which an electric customer could generate up to 100% of the customer's electricity consumption for the previous 12 months. An electric utility or alternative electric supplier would not have to allow for distributed generation that was greater than 1% of its average in-State peak load for the preceding five years, allocated as provided in the bill. A customer participating in a net metering program approved by the PSC before the bill took effect could elect to continue to receive service under the terms and conditions of that program for up to 10 years from the date of enrollment.

The bill also would do the following:

-- Require an electric provider to offer to its customers the opportunity to participate in a voluntary green pricing program, under which the customer could specify that a certain amount of the electricity attributable to that customer be renewable energy.

-- 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.

In addition, the bill would repeal a requirement that the PSC report annually to the Governor and the Legislature on the impact of establishing wind energy resource zones, expedited transmission line siting applications, estimates for future wind generation within wind zones, and recommendations for program enhancements or expansion.

The bill also would change the name of the Act to the "Clean and Renewable Energy and Energy Waste Reduction Act".

The bills are tie-barred. Each bill would take effect 90 days after it was enacted.

Senate Bill 437 (S-7)

Assessment Proceeding

Within 120 days after the bill took effect and then every five years, the PSC would have to commence a proceeding and, in consultation with the Michigan Agency for Energy, the Department of Environmental Quality (DEQ), and other interested parties, do all of the following in the proceeding:

-- Conduct an assessment of the potential for energy waste reduction and the use of demand response programs in Michigan based on what was economically and technologically feasible, as well as what was reasonably achievable.

-- Identify significant State or Federal environmental regulations, laws, or rules and how each would affect electric utilities in Michigan.

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

-- Identify any required planning reserve margins and local reserve clearing requirements in areas of the State.

-- 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 demand response assessment would have to account expressly for advanced metering infrastructure that had already been installed in Michigan and seek to maximize potential benefits to ratepayers in lowering utility bills.

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

-- Any required planning reserve margins and LCRs.

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

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

-- Any supply-side and demand-side resources that reasonably could address any need for additional generation capacity, including the type of generation technology for any proposed generation facility, projected energy waste reduction 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.

The proceeding would have to be completed within 120 days and would not be a contested case under the Administrative Procedures Act (APA). The determination of the modeling assumptions for IRPs would not be considered a final order for purposes of judicial review. The determination would be subject to judicial review only as part of the final PSC order approving an IRP.

Integrated Resource Plan Requirement

IRP Filing; Procedures. The bill would add Section 6t to require each electric utility whose rates are regulated by the PSC, within two years after the bill took effect, to file with the Commission an IRP that provided a five-year, 10-year, and 15-year projection of the utility's load obligations and a plan to meet them, to meet the utility's requirements to provide generation reliability, including meeting planning reserve margin and LCRs determined by the PSC or the appropriate independent system operator, and to meet all applicable State and Federal reliability and environmental regulations over the term of the plan. The PSC would have to issue an order establishing filing requirements, including application forms and instructions, and filing deadlines for an IRP filed by a rate-regulated electric utility. The utility's plan could include alternative modeling scenarios and assumptions in addition to those identified by the Commission. The PSC could issue an order implementing separate filing requirements, review criteria, and approval standards for an electric utility with fewer than 1.0 million customers.

Within 300 days after an electric utility filed an IRP, the PSC would have to state whether it had any recommended changes and, if so, describe them in sufficient detail to allow their incorporation in the IRP. If the Commission did not recommend changes, it would have to issue a final, appealable order approving or denying the plan. If the Commission recommended changes, it could set a schedule allowing parties at least 15 days to file comments regarding the recommendations, and allowing the utility at least 30 days to consider the recommended changes and submit a revised IRP that incorporated them. If the utility submitted a revised plan, the Commission would have to issue a final, appealable order approving or denying it. The Commission would have to issue a final, appealable order within 360 days after the utility filed the IRP. 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. The Commission would have to review the IRP in a contested case proceeding.

The PSC would have to allow intervention by interested people, and to request an advisory opinion from the DEQ regarding whether any potential decrease in emissions of sulfur dioxide, oxides of nitrogen, mercury, and particulate matter reasonably would be expected to result if the proposed IRP were approved and whether the plan reasonably could be expected to achieve compliance with Federal and State regulations, laws, and rules. The PSC could take official notice of the DEQ's opinion pursuant to State administrative rules. Information submitted by the DEQ would be advisory and would not be binding on future determinations by the DEQ or the Commission in any proceeding or permitting process. These provisions would not prevent an electric utility from applying for, or receiving, any necessary permits from the DEQ. 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 on a CON application in order to assist parties and interested people in obtaining evidence concerning the application, including the reasonableness and prudence of the proposal. A similar requirement would apply in the case of a hearing regarding an IRP related to the reasonableness and prudence of the plan and alternatives raised by intervening parties.

IRP Approval. The bill would require the PSC to approve a proposed IRP if it determined all of the following:

-- The IRP represented the most reasonable and prudent means of meeting the electric utility's energy and capacity needs.

-- 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.

-- The IRP met the bill's requirements for IRP content.

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 load, applicable planning reserve margin, and LCR.

-- Compliance with applicable State and Federal environmental regulations.

-- Competitive pricing.

-- Reliability.

-- Commodity price risks.

-- Diversity of generation supply.

-- Whether the proposed levels of peak load and energy waste reduction were reasonable and cost effective.

Exceeding the renewable energy resources and energy waste reduction goal proposed by Senate Bill 438 (S-7) would not, in and of itself, be grounds for determining that the proposed levels of peak load reduction, renewable energy, and energy waste reduction were not reasonable and cost effective.

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 after the bill's effective date with an unaffiliated entity, the PSC would have to consider and could authorize a financial incentive 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.

For a new electric generation facility approved in an IRP that was to be owned by the electric utility and that was commenced within three years after the PSC's order approving the plan, the Commission would have to finalize the approved costs for the facility only after the utility had done all of the following and filed the results, analysis, and recommendations with the Commission:

-- Implemented a competitive bidding process for all major engineering, procurement, and construction contracts associated with the construction of the facility.

-- Implemented a competitive bidding process that allowed third parties to submit firm and binding bids for the construction of an electric generation facility on behalf of the utility that would meet all of its specifications for the facility, such that ownership of the facility vested with the utility by the date the facility became commercially available.

-- Demonstrated to the PSC that the finalized costs for the new facility were not significantly higher than the initially approved costs.

If the finalized costs were found to be significantly higher than the initially approved costs, the PSC would have to review and approve the proposed costs if it determined they were reasonable and prudent.

If the capacity resource were for the construction of a generation facility of at least 225 megawatts or for the construction of additional generating units totaling at least 225 megawatts at an existing generation facility, the utility would have to submit an application to the PSC seeking a CON.

IRP Standards. The bill would require an IRP under proposed Section 6t to include all of the following:

-- A long-term forecast of the electric utility's sales and peak demand under various reasonable scenarios.

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

-- Projected energy purchased or produced by the electric utility.

-- Details regarding the utility's plan to eliminate energy waste, including the total amount of energy waste reduction expected to be achieved annually, the cost of the plan, and the expected savings for its retail customers.

-- An analysis of how the combined amounts of renewable energy and energy waste reduction achieved under the plan compared to the renewable energy resources and energy waste reduction goal provided in the Clean and Renewable Energy and Energy Waste Reduction Act.

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

-- Projected energy and capacity purchased or produced by the utility from a cogeneration resource.

-- An analysis of potential new or upgraded electric transmission options for the utility.

(This requirement is similar to a requirement under Section 6s for an IRP filed by an electric utility seeking a CON.)

An IRP filed under proposed Section 6t also would have to include the following:

-- Data regarding the utility's current generation portfolio, including the age, capacity factor, 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 and major investments, including transmission or distribution infrastructure that would be required to support the proposed construction or investment, and power purchase agreements,

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

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

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

-- A forecast of the utility's peak demand and details regarding actions the utility proposed to take to reduce it, and the projected cost of compliance.

Beginning January 1, 2022, the projected amount of energy the utility purchased or produced from a renewable resource would have to equal at least 15%. A utility could comply with this requirement using renewable energy in any form, including generating electricity from renewable energy systems for sale to retail customers or purchasing or otherwise acquiring renewable energy credits with or without associated renewable energy, allowed under the Clean and Renewable Energy and Energy Waste Reduction Act as it existed before the bill's effective date.

Denial of Relief. Currently, in the CON process, if the PSC denies any of the relief requested by an electric utility, the utility may withdraw its 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, a similar provision also would apply in the case of the PSC's denial of a utility's IRP.

If the utility did not accept the PSC's recommendations, within 60 days after the date of the final order denying the IRP, the utility could submit plan revisions 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, if the revisions were not substantial or inconsistent with the original IRP that was filed. If the revisions were substantial or inconsistent, the PSC would have up to 150 days to issue an order approving or denying the plan 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. The bill would require the PSC to include in an electric utility's retail rates all reasonable and prudent costs for an approved IRP. The PSC could not disallow recovery of costs a utility incurred in implementing an approved IRP, if the costs did not exceed those approved for constructing, investing in, or purchasing an electric generation facility, purchasing power under the terms of a power purchase agreement, or making other investments to meet energy and capacity needs. If the actual costs exceeded the approved costs, the utility would have the burden of proving by a preponderance of the evidence that the costs were reasonable and prudent. The portion of cost that exceeded the approved cost would be presumed to have been incurred due to lack of prudence. (Similar provisions currently apply regarding a CON.)

The bill would require the PSC to disallow costs that it found were incurred as the result of fraud, concealment, gross mismanagement, or lack of quality controls amounting to gross mismanagement. The PSC also would have to require refunds with interest to ratepayers of any of these costs already recovered through the electric utility's rates and charges. If the assumptions underlying an approved IRP materially changed, a utility could request, or the PSC on its own motion could initiate, a proceeding to review whether it was reasonable and prudent to complete an unfinished project or program included in an approved plan. If the PSC found that completion was no longer reasonable and prudent, the Commission could modify or cancel approval of the project or program and unincurred costs in the utility's IRP. Except for costs the PSC found a utility incurred as the result of fraud, concealment, gross mismanagement, or lack of quality controls amounting to gross mismanagement, if its approval were modified or canceled, the Commission could not disallow reasonable and prudent costs already incurred or committed to by contract by a utility. Once it found that completion was no longer reasonable and prudent, the Commission could limit future cost recovery to those costs that could not be reasonably avoided.

IRP Amendment & Review. The bill would allow an electric utility to seek to amend an approved IRP. Except as otherwise provided, the PSC would have to consider the amendments under the process and standards governing the review and approval of a revised IRP.

The bill would require an electric utility to file an application for review of its IRP within five 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 process and standards governing the review and approval of an IRP. A PSC order approving a plan review would have the same effect as an order approving an IRP.

In addition, the PSC, on its own motion or at the electric utility's request, could order a 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.

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.

Electric Utility: Certificate of Necessity

Filing of CON Application or IRP. Section 6s of 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 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. The bill would reduce the threshold from $500.0 million to $100.0 million.

The bill would delete a provision prohibiting the PSC from issuing a CON for a renewable energy system, but would retain a prohibition against issuance of a CON for environmental upgrades to existing generation facilities. If the application were for the construction of an electric generation facility of at least 225 megawatts or for the construction of additional generating units totaling at least 225 megawatts at an existing facility, the PSC would have to consolidate its proceedings under the CON provisions and proposed Section 6t, which would require each rate-regulated electric utility to file an IRP with the PSC, as described below. If the PSC approved or denied an application for a generation facility under Section 6s that had been submitted as required under Section 6t, Section 6s would prevail in a conflict with Section 6t.

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.

Within 270 days after a CON application is filed, the PSC must issue an order granting or denying the certificate. The PSC must grant a CON request if it makes certain determinations, including that the existing or proposed facility or proposed 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 program and electric transmission efficiencies. Under the bill, the other resource options would include alternative proposals submitted under Section 6t.

The law requires the PSC to establish standards for an IRP that must be filed by an electric utility requesting a CON. Under the bill, this would not apply to a utility that had an approved IRP under Section 6t.

The PSC must specify in a CON the costs approved for the construction of or significant investment in the electric generation facility, the price approved for the purchase of the existing facility, or the price approved for the purchase of power pursuant to the terms of the power purchase agreement. Under the bill, for power purchase agreements that an electric utility entered into with an entity that was not affiliated with that utility after the bill's effective date, the PSC would have to consider and could authorize a financial incentive for the utility that did not exceed the utility's weighted average cost of capital.

Under the law, once the electric generation facility or power purchase agreement is considered used and useful or as otherwise provided, the PSC must include in an electric utility's retail rates all reasonable and prudent costs for a facility or agreement for which a CON has been granted. The portion of the cost of a plant, facility, or power purchase agreement that exceeds 110% of the cost approved by the PSC is presumed to have been incurred due to a lack of prudence. The bill instead provides that any cost that exceeded the cost approved by the PSC would be presumed to have been incurred due to a lack of prudence.

The law requires the PSC to allow financing interest cost recovery in an electric utility's base rates on construction work in progress for capital improvements approved before the assets are considered used and useful. Under the bill, the PSC would be permitted to allow such cost recovery.

The bill would allow an existing supplier of electric generation capacity currently producing at least 200 megawatts of firm electric generation capacity resources located in the independent system operator's zone in which the utility's load was served that sought to provide generation capacity resources to the utility, to submit to the PSC directly a written proposal as an alternative to the construction, investment, or purchase for which the CON was sought. The submitting entity would have standing to intervene and the PSC would have to allow reasonable discovery in the contested case proceeding. In evaluating an alternative proposal, the PSC would have to consider the cost of the proposal and the submitting entity's qualifications, technical competence, capability, reliability, creditworthiness, and past performance. In reviewing an application, the PSC could consider any alternative proposals that were submitted. These provisions would not limit the PSC's authority to grant standing to interested parties to intervene in the proceeding; would not restrict interested parties from submitting evidentiary alternatives to the construction, investment, or purchase for which the CON was sought; and would not authorize the PSC to order or otherwise require an electric utility to adopt any submitted alternative proposals.

A PSC order following a hearing related to a CON would be subject to judicial review as provided under the State Constitution and the APA, except that a petition for review would have to be filed in the Court of Appeals within 30 days after the PSC's order was issued and the Court would have to conduct the review as expeditiously as possible with lawful precedence over other matters.

Performance-Based Regulation Study

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 whose rates are regulated by the Commission, and other interested parties regarding performance-based regulation, under which a utility's authorized rate of return would depend on the utility's achieving targeted policy outcomes.

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.

In reviewing various performance-based regulation systems, the PSC would have to evaluate all of the following factors:

-- Methods 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.

-- Methods to increase 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 extended payback periods.

-- Options for establishing incentives and penalties that pertained to issues such as customer satisfaction, safety, reliability, environmental impact, and social obligations.

-- 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.

Within one year 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.

These provisions would not limit the PSC's authority to authorize performance-based regulation.

Capacity Resource Adequacy

Demonstration of Sufficient Generation Capacity. Under the bill, if the appropriate independent system operator (ISO) proposed to implement a resource adequacy tariff that included the option for a state to implement a prevailing state compensation mechanism for capacity and Federal Energy Regulatory Commission (FERC) put that tariff into effect, the PSC would have to implement the mechanism. "Prevailing state compensation mechanism" would mean an option for a state to elect a prevailing compensation rate for capacity consistent with the requirements of the appropriate independent system operator's resource adequacy tariff.

The charge to be assessed under the mechanism would have to be determined in the same manner as the generation capacity charge and would have to be included in the customer's retail rates. If the appropriate ISO determined that at any point within the next four-year planning period there would be insufficient capacity to meet the local clearing requirement in Michigan or that the resource adequacy tariff that was put into effect did not include a prevailing state compensation mechanism, the PSC immediately would have to hold a contested case hearing to determine if the tariff would result in sufficient capacity to meet the LCR in Michigan. In order to determine whether a tariff that did not include a prevailing state compensation mechanism would result in sufficient capacity to meet the LCR, the PSC would have to find that the tariff would result in at least the same capacity as that which would be achieved as described below.

If FERC had not put into effect by October 1, 2017, a resource adequacy tariff for the appropriate ISO that included an option for a state to implement a prevailing state compensation mechanism for capacity, or the PSC had not determined that the tariff of the ISO would result in sufficient capacity to meet the LCR, the following provisions would apply

Beginning in 2017, an electric utility would have to demonstrate to the PSC by October 1 of each year that for the planning year beginning the following June 1 and the subsequent planning year, the utility owned or had contractual rights to sufficient dedicated and firm electric capacity to meet 90% of its proportional share of the local clearing requirement as determined by the PSC.

An alternative electric supplier, cooperative electric utility, and municipally owned electric utility would have to demonstrate to the PSC by October 1, 2017, that for the planning year beginning June 1, 2018, the AES or utility owned or had contractual rights to meet the equivalent of 50% of its proportional share of the LCR. The AES could meet this requirement by demonstrating that its customers would pay a generation capacity charge that was determined, assessed, and applied as prescribed in the bill.

An AES or cooperative or municipally owned electric utility annually would have to demonstrate to the PSC by October 1 beginning in 2018 that for the planning year beginning the following June 1 and the subsequent planning year, the AES or utility owned or had contractual rights to sufficient dedicated and firm electric capacity to meet the equivalent of 90% of its proportional share of the LCR. The AES could meet this requirement by demonstrating that its customers would pay a generation capacity charge that was determined, assessed, and applied as prescribed in the bill.

The utility or AES could meet the applicable requirement through any resource, including one acquired through a three-year capacity auction, that the appropriate ISO allowed to qualify for meeting the LCR.

("Dedicated and firm electric capacity" would mean capacity that is owned or is a resource, including a resource acquired through a three-year capacity auction, that the appropriate independent system operator allows to qualify for meeting the LCR.

"Local clearing requirement" or "LCR" would mean the amount of capacity resources that must be present in the local resource zone in which the electric provider's demand is served to ensure reliability in that zone as required by the appropriate ISO for the local resource zone in which the provider's demand is served and as determined by the Commission (as described below).

"Electric provider" would mean any of the following:

-- Any person or entity that is regulated by the PSC for the purpose of selling electricity to retail customers in Michigan.

-- A municipally owned or cooperative electric utility in Michigan.

-- A licensed alternative electric supplier.

"Proportional share of the LCR" would mean the minimum amount of capacity an electric provider must own or have contractual rights to that equals the provider's share of the capacity requirement for the local resource zone in which the provider's demand is served.)

A provider's payment of an auction price related to a capacity deficiency as part of the auction would not by itself satisfy the resource adequacy requirements unless the appropriate ISO could tie that payment directly to a capacity resource that met the requirements. In addition, beginning June 1, 2018, if the ISO determined that for any planning year the applicable resource zone did not meet the LCR, all electric providers in the zone would have to meet 100% of their proportional share for the next three planning years through ownership or contractual rights to any resource, including one acquired through a three-year capacity auction, that the ISO allowed to qualify for meeting the LCR. A provider's demonstration that it met 100% of its proportional share of the LCR for the next three planning years would apply only for the three planning years after the ISO determined that the applicable resource zone did not meet the LCR, unless the PSC determined that the provider needed to continue making that demonstration for additional planning years. The PSC could not require more than an additional three planning years for each determination. An AES could demonstrate that it met its proportional share of the LCR by having its customer pay a generation capacity charge that was determined, assessed, and applied as prescribed in the bill. An electric provider could meet these requirements through any resource that the ISO allowed to qualify for meeting the LCR.

One or more municipally owned or cooperative utilities could aggregate their generation capacity resources that were located in the same local resource zone to meet the bill's requirements.

After receiving a submission from an AES, the PSC would have to notify each AES as to whether the supplier had demonstrated that it could meet the prescribed capacity requirements. If the Commission determined that an AES had failed to demonstrate that it could, the Commission would have to commence a show cause proceeding, conducted as a contested case, to limit the AES to providing the amount of capacity the AES had demonstrated it had obtained to meet the bill's requirements. If an AES failed to remedy the deficiency or otherwise demonstrate that it had sufficient capacity, the Commission could limit, on a pro rata basis, the electricity the AES could provide to an amount consistent with the amount of capacity the supplier had demonstrated it had for the planning years under review. All contracts for service between a customer in Michigan and an AES entered into after the bill's effective date would have to include a provision allowing the customer to withdraw without penalty if the PSC ordered a limitation of capacity that resulted in the AES being unable to supply the customer with the capacity required under the bill at any time during the planning years under review. An AES could not serve more load during the planning years than the prorated load supported by the capacity it demonstrated.

Forecast of Capacity Resource Adequacy. By July 1 of each year, the PSC would have to report to the Governor and the Legislature a forecast of the capacity resource adequacy for a period of at least five years. For the covered planning years, the report would have to include a determination by the Commission of the LCR for each local resource zone and the proportional share of the LCRs for each electric provider in the State, as well as a projection of the planning reserve margin requirement for each local resource zone. In making the determination or projection, the PSC would have to consult with and consider any findings, projections, and other data of the appropriate ISO. The Commission could adjust the proportional share of the LCR for an AES as part of a show cause hearing to make it consistent with any findings of the independent system operator. The Commission would have to determine specifically whether 100% of the capacity resources needed to meet the LCR for each local resource zone was forecasted to be met for each year in the five-year forecasted period. A determination would have to be conducted as a contested case. To the extent practicable, the PSC's determination of the LCR would have to be consistent with independent system operator's policies and procedures. All electric providers and unregulated generation providers in the State would have to submit prescribed data necessary for the PSC to make the required forecast and determinations. Information and materials submitted by an entity under these provisions would be exempt from disclosure under the Freedom of Information Act. The PSC would have to issue protective orders as necessary to protect the information and materials. The bill specifies that these provisions should not be read to tamper with or otherwise impede the setting of an LCR by an ISO or FERC that differed from a determination of the PSC.

Civil Action. The Attorney General or any customer of a municipally owned or cooperative electric utility could commence a civil action for injunctive relief against the utility if it failed to meet the applicable requirements related to resource capacity. The Attorney General or customer could not file an action unless he or she gave the utility at least 60 days' written notice of the intent to sue, the basis for the suit, and the relief sought. Within 30 days after receiving the notice, the utility and the Attorney General or customer would have to meet and make a good-faith attempt to determine whether there was a credible basis for the action. The utility would have to take all reasonable and prudent steps necessary to comply with the bill's requirements within 90 days after the meeting if there were a credible basis for the action. If the parties did not agree as to whether there was a credible basis, the Attorney General or customer could proceed to file the suit.

Market Manipulation. The PSC would have to monitor whether any entity had engaged in market manipulations related to the LCRs. An AES or an AES customer could file a complaint with the PSC if the supplier or customer believed that available capacity had been unreasonably withheld from the LCRs by an electric utility or an unregulated generation provider based in Michigan. If the PSC found evidence of an unreasonable withholding by an unregulated generation provider, the Commission immediately would have to forward the evidence to the Attorney General, the market monitor for the appropriate ISO, and appropriate Federal authorities for enforcement. If the Commission determined after notice and hearing that an electric utility had unreasonably withheld excess capacity, it could disallow cost recovery for the utility-owned excess capacity.

Shared Savings Mechanism

In order to ensure equivalent consideration of energy waste reduction resources within the integrated resource planning process, by January 1, 2021, the PSC would have to authorize a shared savings mechanism for an electric utility to the extent that the utility had not otherwise capitalized the costs of the energy waste reduction, conservation, demand reduction, and other waste reduction measures.

For an electric utility that achieved annual electric energy savings of at least 1% but not more than 1.25% of the total annual weather-adjusted retail sales in the previous year, the shared savings incentive would be 15% of the net benefits validated as a result of the programs implemented by the utility related to energy waste reduction, conservation, demand reduction, and other waste reduction. The mechanism could not exceed 20% of the utility's expenditures associated with implementing energy waste reduction programs for the year in which the mechanism was authorized.

For an electric utility that achieved annual electric energy savings of more than 1.25% but not more than 1.5% of the total annual weather-adjusted retail sales in the previous year, the shared savings incentive would have to be 17.5% of the net benefits validated as a result of the programs implemented by the utility related to energy waste reduction, conservation, demand reduction, and other waste reduction. A shared savings mechanism authorized under this provision could not exceed 22.5% of the utility's expenditures associated with implementing energy waste reduction programs for the year in which the mechanism was authorized.

For an electric utility that achieved annual electric savings greater than 1.5% of the total annual weather adjusted retail sales in the previous year, the shared savings incentive would have to be 20% of the net benefit validated as a result of the utility's programs related to energy waste reduction, conservation, demand reduction, and other waste reduction. The shared savings mechanism could not exceed 25% of the utility's expenditures associated with implementing the programs for the year in which the mechanism was authorized.

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". The bill would delete this title (although the following provisions refer to these sections as the 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 that 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 retail customers of an electric utility or provider" to choose an alternative electric supplier.

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 are 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.

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.

Under the bill, the orders also would have to provide that for an existing facility that was receiving 100% of its electric service from an AES on or after the bill's effective date, the facility owner could purchase electricity from an AES, regardless of whether the sales exceeded 10% of the servicing electric utility's average weather-adjusted retail sales, for both the existing electric choice load at the facility and any expanded load arising at that facility after the bill's effective date, as well as any new facility that was similar in nature to the existing facility, that was constructed or acquired by the customer on a site contiguous to the existing site or that would be contiguous to an existing site in the absence of an existing public right-of-way, and if the customer owned more than 50% of that facility. This provision would not authorize or permit an existing facility being served by an electric utility on standard tariff service on the bill's effective date to be served by an AES.

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 customer were in compliance with the terms of a settlement agreement requiring it to facilitate construction of a new power plant located in the Upper Peninsula. The customer and the AES that provided electric service to the customer would not be subject to the bill's requirements and any administrative regulations adopted under the bill. The PSC's order establishing rates, terms, and conditions of retail access service issued before the bill's effective date would remain in effect with regard to retail open access provided under these provisions.

The bill would require the PSC's orders to provide that a customer on an enrollment queue waiting to take retail open access service as of December 31, 2015, would continue on the queue and an electric utility would have to add a new customer to the queue if the customer's prospective AES submitted an enrollment request to the utility. A customer would have to be removed from the queue by notifying the utility electronically or in writing.

Additionally, the orders would have to require each electric utility to file with the PSC by January 15 of each year a rank-ordered queue of all customers awaiting retail open access service. The filing would have to include the estimated amount of electricity used by each customer in the queue. All customer-specific information would be exempt from the Freedom of Information Act, and the PSC would have to treat it as confidential. The Commission could release aggregated information as part of its annual report as long as individual customer information or data were not released.

The bill also would require the orders to provide that if the prospective AES of a customer next on the queue were notified after the bill's effective date that less than 10% of an electric utility's average weather-adjusted retail sales were taking services from an AES and that the amount of electricity needed to serve the customer's electric load was available under the 10% allocation, the customer could take service from an AES. The customer would be subject to any generation capacity service costs assessed as described below. The prospective AES would have to notify the utility within five business days after being notified whether the customer would take service from an AES. If the prospective AES failed to notify the utility or the customer chose not to take retail open access service, the customer would have to be removed from the queue. The customer subsequently could be added to the queue as a new customer. A customer that elected to take service from an AES would have to become service-ready under rules established by the PSC and the utility's approved retail open access service tariffs.

Further, the orders would have to require the PSC, within one year after the bill's effective date, to determine the appropriate generation capacity service costs for each electric utility that would be assessed as a nonbypassable charge to any full service electric utility customer for the subsequent 10 planning years after the customer either elected to receive AES service as described above or, for a utility that did not maintain a queue, elected to receive AES service after December 1, 2016, for any of its current full service electric load. A generation capacity charge would have to be determined and assessed as prescribed in the bill. If the appropriate ISO did not implement a resource adequacy tariff that met the bill's requirements, a generation capacity charge would have to be applied to retail customers for 10 years if, as a result of the additional required capacity, the utility had to make a significant acquisition of investment in incremental generation capacity resources. If the utility did not need to acquire or invest in incremental capacity resources, the generation capacity charge would be applied to retail customers for only four years. The PSC could make a determination of the charge in an electric utility's pending rate case or PSCR proceeding. The generation capacity costs would be the customer's pro rata share of the cost of generation capacity services that the customer continued to receive from the utility for the subsequent 10 planning years as determined by the Commission. The electric utility, and not the customer's AES, would be responsible for that customer's share of the generation capacity requirements for the 10-year period that the generation capacity charge was assessed. The charge would have to be the same for AES customers as the charge for customers on standard tariff service.

The PSC's orders also would have to provide that a generation capacity charge implemented by an electric utility as authorized by PSC order of September 25, 2012, case no. U-17032, would remain in effect until the Commission authorized that utility to collect the charge required by the bill and that charge went into effect. The Commission would have to establish that utility's generation capacity service costs charge in the utility's next general rate case, as long as the utility filed its next general rate case by December 31, 2019. If the utility did not file by that date, the PSC would have to adopt an order initiating a case in which the charge would be determined. When the utility finally imposed the charge under the bill, the authority to impose the charge under case no. U-17032 would be terminated.

In addition, the orders would have to provide all of the following:

-- That a customer subject to a capacity charge would not also be subject to a charge based on a prevailing state compensation mechanism implemented under the bill.

-- That the PSC would ensure that, if a customer were notified that the customer's service from an AES would be terminated or restricted as a result of the AES limiting service in Michigan, the customer would have 60 days, or 180 days in the case of a customer that was a public entity, to acquire service from a different AES.

-- As a condition of licensure, an AES would have to meet all of the bill's requirements regarding firm and dedicated generation capacity.

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. Under the bill, it would apply to an electric or natural gas utility regulated by the PSC. Also, the bill would refer to a utility's regulated electric or natural gas services and unregulated programs and services.

Appliance Service Program & Value Added Programs. The Act allows an electric utility to offer its customers an appliance service program (ASP) (i.e., a subscription program for the repair and servicing of heating and cooling systems or other appliances). Under the bill, instead, an electric or natural gas utility regulated by the PSC could offer its customers value-added programs and services if they did not harm the public interest by unduly restraining trade or competition in an unregulated market. A utility would have to notify the PSC of its intent to offer these programs and services before offering them to its customers. "Value-added programs and services" would mean programs and service that are utility or energy related, including home comfort and protection, appliance service, building energy performance, alternative energy options, or engineering and construction services. The term would not include energy optimization or energy waste reduction programs paid for by utility customers as part of their regulated rates.

Currently, 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.

Under the bill, these provisions would apply to a utility offering a value-added program or service rather than an ASP. Rather than making the books and records available to the PSC upon request, however, the utility would have to report annually to the Commission on how all of the utility's costs associated with the unregulated value-added program or service were allocated to that program or service. The report would have to show the extent to which the utility's rates were affected by the allocations. The utility could include this report as part of a request for rate relief. The bill also would require the utility to give the Commission written notice and a description of any newly offered value-added program or service.

The Act also contains provisions regarding the allocation of the utility's costs attributable to an ASP, inclusion of charges for the program on monthly customer billings, and program marketing. Under the bill, similar requirements would apply to any unregulated value-added program or service offered by the utility, with several changes.

The PSC could initiate informal proceedings to determine if any value-added program or service violated the bill's provisions. If the PSC determined that a potential violation existed, it would have to conduct formal proceedings to determine whether a violation had occurred and order corrective actions. An informal proceeding would not be required as a prerequisite to a formal complaint.

The Act states that it does not prohibit the PSC from requiring a utility to include revenue from an ASP in establishing base rates. If the PSC includes this revenue, the Commission also must include all of the program's costs. The bill would delete these provisions. Instead, the Commission could include only the revenue received by the utility in the allocation of costs in determining the utility's base rates. The utility would have to file with the Commission the percentage of additional revenue over the amount that was allocated to recover costs directly attributable to a value-added program or service that the utility wished to include as an offset to its base rates. Following a notice and hearing, the Commission would have to approve or modify the amount to be included as an offset.

In addition to any penalties allowed under the Act, for violations of the code of conduct and value-added program and service provisions, an electric utility would have to pay all reasonable costs incurred by the prevailing party.

An electric utility that offered value-added programs or services would have to file with the PSC an annual report that provided a list of the programs and services, the estimated share occupied by each program and service, and a detailed accounting of how the costs for the programs and services were apportioned between them and the utility. The utility would have to certify to the PSC that it was complying with these requirements. The PSC could conduct an audit of the utility's books and records and the value-added programs and services to ensure compliance.

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 Renewable Energy and Energy Waste Reduction Act. (Senate Bill (S-7) 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.

-- Information regarding the customer's right to contest the shutoff.

Appropriations

Under Public Act 299 of 1972 (which governs the costs of regulating public utilities), within 30 days after the enactment into law of any appropriation to the Department of Licensing and Regulatory Affairs, the Department must ascertain the amount of the appropriation attributable to the regulation of public utilities (i.e., a steam, heat, electric, power, gas, water, wastewater, telecommunications, telegraph, communications, pipeline, or gas producing company regulated by the PSC, whether private, corporate, or cooperative, except a municipally owned utility). The amount must be assessed against the utilities and must be apportioned among them according to a formula prescribed in the Act. The money must be credited to a special account to be used solely to finance the cost of regulating public utilities.

To implement the bill's provisions, for the 2016-17 fiscal year, the bill would appropriate from these assessments the following amounts:

-- $1.95 million to the PSC to hire 13 full-time equated (FTE) positions.

-- $150,000 to the Attorney General to hire 1.0 FTE.

-- $600,000 to the Michigan Administrative Hearing System to hire 4.0 FTEs.

-- $150,000 to the DEQ to hire 1.0 FTE.

-- $260,000 to the Michigan Agency for Energy to hire 1.0 FTE.

Utility Rates

Rate Changes. 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. Under the bill, this prohibition also would apply to a steam utility. "Steam utility" would mean a steam distribution company regulated by the PSC.

The bill would require a utility to coordinate with PSC staff before filing its general rate case application to avoid resource challenges with applications being filed at the same time as applications filed by other utilities. In the case of electric utilities serving more than 1.0 million customers in Michigan, the PSC could order a delay in filing an application, if necessary, to establish a 21-day spacing between filings of electric utilities serving more than 1.0 million Michigan customers.

Concurrently with or at any time after filing a complete application to increase its rates or amend its rate schedules, a gas utility serving fewer than 1.0 million customers in Michigan could file a motion seeking partial and immediate rate relief. After notifying the interested parties within the service area to be affected and giving them a reasonable opportunity to present written evidence and arguments relevant to the motion, the PSC would have to make a finding and enter an order granting or denying the relief within 180 days after the motion was submitted. The Commission would have 12 months to issue a final order in a case in which a gas utility had filed a motion seeking partial and immediate rate relief.

Currently, 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 specifies that these provisions would apply only to completed applications filed with the PSC before the bill took effect.

The law provides that the rate case provisions do not impair the PSC's ability to issue a show cause order as part of its rate-making authority. A utility may not increase its rates based upon changes in cost of fuel or purchased gas unless notice has been given within the service area to be affected and there has been an opportunity for a full and complete hearing on the cost. The rates charged by a utility under an automatic fuel or purchased gas adjustment clause may not be altered, changed, or amended unless notice has been given in the affected service area and there has been an opportunity for a full and complete hearing on the cost. The bill also would refer to the cost of purchased steam in these provisions.

Time Frame for PSC Decision. 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. If a utility makes any significant amendment to its filing, the PSC has an additional 12 months from the date of the amendment to reach a final decision. In both cases, the bill would reduce the time frame from 12 months to 10 months.

Under the law, the PSC may not authorize or approve adjustment clauses that operate without notice and an opportunity for a full and complete hearing. The Commission may hold a hearing to determine the cost of fuel, purchased gas, or purchased power separately from or concurrently with a hearing on a general rate case. The PSC must authorize a utility to recover the cost of fuel, purchased gas, or purchased power only to the extent that the purchases are reasonable and prudent. The bill also would refer to the cost of purchased steam in these provisions.

Energy Savings Decoupling Mechanism. The bill provides for approval by the PSC, upon a natural gas or electric utility's request, of an appropriate revenue decoupling mechanism or rate design that adjusted for decreases in actual sales compared to the projected levels used in the utility's most recent rate case, if the utility first demonstrated the following to the Commission:

-- That the projected sales forecast in the utility's most recent rate case was reasonable.

-- For an electric utility serving more than 200,000 customers in Michigan, that it had achieved annual incremental energy savings equal to at least 1% of its total annual retail electricity sales in the previous year.

-- In the case of an electric utility serving a maximum of 200,000 customers in Michigan, that it had achieved annual incremental energy savings at least equal to the lesser of 1% of its total annual retail electricity sales in the previous year, or the amount of any incremental savings yielded by energy waste reduction, conservation, demand-side programs, and other waste reduction measures approved by the PSC in the utility's most recent integrated resource plan (described below).

-- For a natural gas utility, that it had achieved incremental energy savings at least equal to 0.75% of its total annual natural gas sales in the previous year or any alternative minimum gas energy savings target established by the PSC under the Clean and Renewable Energy and Energy Waste Reduction Act.

If the sales decreases were the result of implemented energy waste reduction, conservation, demand-side programs, and other waste reduction measures, the PSC would have to approve the decoupling mechanism or rate design. If sales decreased for other reasons, the bill would allow the Commission to approve the decoupling mechanism or rate design.

A natural gas utility that implemented revenue decoupling under the Clean and Renewable Energy and Energy Waste Reduction Act, as proposed by Senate Bill 438 (S-7), could not also implement a revenue decoupling mechanism under these provisions.

The PSC would have to consider the aggregate revenue attributable to the revenue decoupling mechanisms and shared savings mechanisms the Commission had approved for an electric or natural gas utility relative to energy waste reduction, conservation, demand-side programs, peak load reduction, and other waste reduction measures. The PSC could approve an alternative methodology for a decoupling mechanism or a shared savings mechanism if it determined that the resulting aggregate revenue from those mechanisms would not result in a reasonable and cost-effective method to ensure that investments in energy waste reduction, demand-side programs, peak load reduction, and other waste reduction measures were not disfavored when compared to utility supply-side investments. The PSC's consideration of an alternative methodology would have to be conducted as a contested case pursuant to the APA.

Grid Charge. In determining an electric utility's rates, the PSC, by December 1, 2017, would have to establish a nondiscriminatory, fair, and equitable grid charge to apply to customers who participated in a net metering or distributed generation program under the Clean and Renewable Energy and Energy Waste Reduction Act after the bill's effective date. The grid charge would have to ensure recovery of the customers' allocated cost-based share of all costs associated with the utility's distribution system, transmission costs, and fixed generation capacity costs. In determining the grid charge, the PSC also would have to consider the costs to utility revenue requirements, net of any benefits of incorporating additional distributed generation resources onto the grid, including reduced distribution system capacity and reduced generation capacity costs that were attributed to the generating technology used by the customer. The grid charge could not be reduced by the credits given to customers pursuant to a net metering or distributed generation program. The charge would not apply to customers participating in a net metering program before the PSC established the charge who continued to participate at their current site or facility.

"Utility" and "electric utility" would not include a municipally owned electric utility.

Electric Utility: Power Supply Cost Recovery. Under the law, the PSC may incorporate a power supply cost recovery (PSCR) clause in the electric rates or 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. The plan must describe all major contracts and power supply arrangements entered into by the utility for providing power supply during the specified 12-month period. For gas fuel supply contracts or arrangements, the bill would require the description to include whether the supply contracts or arrangements included firm gas transportation and, if not, an explanation of how the utility proposed to ensure reliable and reasonably priced gas fuel supply to its generation facilities during the 12-month period. "Firm gas transportation" would mean a binding agreement entered into between the electric utility and a natural gas transmission provider for a set period of time to provide guaranteed delivery of natural gas to an electric generation facility.

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. The bill would delete the forecast requirement and several related provisions on January 1, 2019.

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.

Reevaluation of PSC Order

Notwithstanding any existing power purchase agreement, at least every five years, the PSC would have to conduct a proceeding as a contested case to reevaluate the procedures and rate schedules including avoided cost rates, as originally established by the Commission in an order dated March 17, 1981, in case no. U-6798, to implement Title II, Section 210, of the Public Utility Regulatory Policies Act (PURPA) as it relates to qualifying facilities from which utilities in Michigan have an obligation to purchase energy and capacity. The bill provides that it would not supersede the provisions of PURPA or the Federal Energy Regulatory Commission's regulations and orders implementing PURPA.

"Qualifying facility" or "facilities" would mean qualifying cogeneration facilities or small power production facilities from which an electric utility in Michigan has an obligation to purchase energy and capacity under PURPA and associated Federal regulations and orders.

After an initial contested case, for a utility serving fewer than 1.0 million electric customers in Michigan, the PSC could conduct any periodic reevaluations of the procedures, rate schedules, and avoided cost rates for that utility using notice and comment procedures instead of a full contested case. The PSC would have to conduct the periodic reevaluation in a contested case under the APA if a qualifying facility filed a comment disputing the utility filing and requesting a contested case.

An order issued by the PSC under these provisions would have to do all of the following:

-- Ensure that the rates for purchases by an electric utility from, and rates for sales to, a qualifying facility would be just and reasonable and in the public interest over the term of a contract.

-- Ensure that an electric utility did not discriminate against a qualifying facility with respect to the conditions or price for provision of maintenance, backup, interruptible, and supplementary power or for any other service.

-- Require that any prices charged by an electric utility for the listed types of power and all other such services were cost-based and just and reasonable.

-- Establish a schedule of avoided costs price updates for each electric utility.

-- Require electric utilities to publish on their websites template contracts for power purchase agreements for qualifying facilities of less than three megawatts.

Within one year after the bill's effective date and then every two years, the PSC would have to issue a report to the Michigan Agency on Energy and the standing committees of the Legislature with primary responsibility for energy and environmental issues. The report would have to provide a description and status of qualifying facilities in the State, the current status of power purchase agreements of each facility, and the PSC's efforts to comply with the PURPA requirements.

Northern Michigan Reliability Task Force

Within 150 days after the bill took effect, the Michigan Agency for Energy, in coordination with the PSC, would have to form a special task force named the "Northern Michigan Electric Reliability Task Force". The Task Force would have to create a comprehensive public report that identified existing and potential issues affecting the availability, reliability, and affordability of electricity for residents and businesses in the affected area as well as potential options and cost estimates to resolve those issues. "Affected area" would mean the Upper Peninsula and northern Lower Peninsula of Michigan.

The Task Force's report would have to identify all of the following:

-- Existing and potential electric generation and transmission resources serving the affected area.

-- Existing or potential electric reliability issues in the affected area and potential solutions.

-- Opportunities and impediments to using existing resources or assets owned or controlled by the State that could have an impact on electric service or reliability in the affected area.

-- Specific projects or actions that could be taken to enhance the availability, reliability, and affordability of electricity for residents and businesses in the affected area.

The report also would have to include the following:

-- An evaluation of the advantages, disadvantages, and cost effectiveness of increasing or enhancing electrical connectivity between the State's two peninsulas compared to increasing or enhancing connectivity between Michigan and another state or province.

-- Analysis of potential cost impacts and benefits to ratepayers, both within and outside the affected area, of any projects or actions identified by the Task Force.

-- A recommendation regarding any projects the Task Force believed would have a positive impact on the availability, reliability, and affordability of electricity for residents and businesses in the affected area, as well as appropriate actions that the State should take.

The Task Force would have to be made up of individuals with the relevant experience and expertise to evaluate the required report elements properly. The Executive Director of the Michigan Agency for Energy would serve as the Task Force's chair.

The Task Force could request that the appropriate independent system operator initiate a review and conduct modeling if the Task Force found a more in-depth analysis was warranted.

The Task Force would have to consult with the PSC, the North American Electric Reliability Corporation, the appropriate ISO, and any other body dedicated to maintaining electric reliability in the affected area concerning available data, plans, studies, and information related to reliability issues in that area. This requirement would not restrict the Commission's or Agency's ability to request studies, data, or any other analysis from the appropriate ISO.

The Task Force would have to request information and feedback from all relevant load serving entities and transmission companies operating in the affected area regarding issues and recommendations affecting the availability, reliability, and affordability of electricity in that area, as well as any efforts currently being taken or that were proposed by the entity to address those issues.

The Task Force would be subject to the Open Meetings Act. Privileged or proprietary information submitted in connection with the bill by a load serving entity or transmission company and clearly designated as confidential would be exempt from disclosure under the Freedom of Information Act.

Within one year after the bill's effective date, the Task Force's report would have to be delivered to the Governor, the Legislature, the House and Senate committees with jurisdiction over energy issues, and the PSC. The PSC and the Michigan Agency for Energy also would have to make the report available to the public on their websites.

Utility Consumer Participation Board

Currently, except as otherwise provided, each "energy utility" (a natural gas or electric company regulated by the PSC) that has applied to the Commission for the initiation of an energy cost recovery proceeding must remit to the Utility Consumer Representation Fund before or upon filing its initiation application, and by the first anniversary of that application, an amount of money determined by the Utility Consumer Participation Board based on a formula prescribed in the law. This requirement applies only to utilities serving at least 100,000 Michigan customers and at least 100,000 residential Michigan customers. Under the bill, the amount of money would have to be determined as follows and adjusted annually by a factor set by the Board based on the change in the consumer price index (CPI):

-- In the case of a utility serving at least 100,000 Michigan customers, its proportional share of $900,000.

-- In the case of a utility serving at least 100,000 residential Michigan customers, its proportional share of $650,000.

-- In the case of a utility serving fewer than 100,000 Michigan customers, its proportional share of $100,000.

-- In the case of a utility serving fewer than 100,000 residential customers, its proportional share of $100,000.

The CPI-adjusted amount would become the new base amount to which the CPI factor applied in the following year.

The money remitted by utilities meeting the threshold for residential customers must be used for grants to nonprofit organizations and local units of government to participate in administrative or judicial proceedings that serve the interests of residential utility consumers. The Board must make the money submitted by the other utilities available to the Attorney General for various administrative and judicial proceedings under the PSC law.

The bill would delete a requirement that a utility annually remit to the Board an amount equal to five-sixths of the amount prescribed above.

With the regard to the grant program, the bill would require each applicant to identify on the application any additional funds or resources, other than the grant funds being requested, that were to be used to participate in the proceeding for which the grant was being requested and how those funds or resources would be used. Currently, for the purposes of making grants, the Board may consider protection of the environment, energy conservation, the creation of employment and a healthy economy in Michigan, and the maintenance of adequate energy resources. The bill would delete the references to environmental protection, employment creation, and a healthy economy, and instead would refer to energy waste reduction, demand response, and rate design options to encourage energy conservation, waste reduction, and demand response.

The bill would expand the criteria the Board must consider and balance in determining whether to make a grant to an applicant, to include the anticipated involvement of the Attorney General in a proceeding and whether the applicant's activities would duplicate or supplement those of the Attorney General. Also, when considering the uniqueness or innovativeness of an applicant's position or point of view and the probability and desirability of that position or point of view prevailing, the Board would have to make this consideration in relation to advocating for residential utility consumers concerning energy costs or rates.

The law allows the annual receipts of the Fund and the interest earned, less administrative costs, to be used only for participation in administrative and judicial proceedings related to gas and power supply cost recovery and in Federal administrative and judicial proceedings that directly affect the energy costs paid by Michigan energy utilities. The bill also would allow the money to be used for a proceeding for a change in utility rates, a CON application, and a PSC proceeding conducted in consultation with the Michigan Agency for Energy, the DEQ, and other interested parties (described below). Additionally, the bill would refer to proceedings that directly affect the energy costs or rates paid by Michigan energy utility customers, rather than Michigan energy utilities.

Currently, amounts that have been in the Fund for more than 12 months may be retained in the Fund for future grants or may be returned to utility companies or used to offset their future remittances to the Fund, as the Board determines will best serve the interests of consumers. The bill would refer to proceedings rather than grants, and would allow any unspent money to be reserved to fulfill the purposes for which it was appropriated, in addition to utility company refunds or future remittance offsets. Also, the Board and the Attorney General would make the determination as to how consumer interests would best be served.

Under the law, disbursements from the Fund may be used only to advocate the interests of energy utility customers or classes of customers, and not for representation of merely individual interests. The bill specifies that these disbursements could be used only to advocate the interests of residential customers concerning energy costs or rates.

The law requires the Board to coordinate the funded activities of grant recipients with those of the Attorney General to avoid duplication of effort. Under the bill, this requirement would apply particularly as it related to the hiring of expert witnesses.

The bill would require a grant recipient to prepare for and participate in all discussions among the parties designed to facilitate settlement or narrowing of the contested issues before a hearing in order to minimize litigation costs for all parties.

A grant recipient must file with the Board a report including an account of all grant expenditures the recipient made and any additional information required by the Board concerning uses of the grant. Under the bill, the report also would have to include a detailed list of the regulatory issues raised by the recipient and how each issue was determined by the PSC, court, or other tribunal. The bill also would require the Board to include each report from a grant recipient as part of the Board's annual report to the Legislature.

Energy Ombudsman

The bill would establish the Ombudsman in the Michigan Agency for Energy effective January 1, 2017. The individual serving as the Ombudsman would have to understand the rate-making process and instruments to enable him or her to provide rate information and track trends related to energy costs for businesses and individuals in Michigan. He or she also would have to possess the knowledge necessary to measure historic, ongoing, and future energy costs for businesses and individuals in Michigan based on the actions of the executive, legislative, and judicial branches of State government.

The Ombudsman would have to do all of the following:

-- Serve as a liaison for businesses and individuals in Michigan by guiding energy issues, problems, and disputes from businesses and individuals to the appropriate entity, agency, or venue for resolution.

-- Monitor the activities of the PSC, the Michigan Agency for Energy, and other State regulatory entities whose decisions affect businesses and individuals with respect to energy, and communicate those entities' decisions, policy changes, and developments to businesses and individuals in Michigan.

-- Convene regular meetings in Michigan to share information and developments pertaining to energy issues, policies, and administrative processes affecting businesses and individuals in Michigan.

-- Monitor the implementation of the code of conduct and compile and annually publish statistics of unregulated services provided by utilities and their affiliates.

Customer Rate Impact

The PSC is required to ensure the establishment of electric rates equal to the cost of providing service to each customer class. With regard to electric utilities serving fewer than 1.0 million retail customers in Michigan, if the PSC determines that the impact of imposing cost of service rates on customers will have a material impact on customer rates, the Commission may approve an order that implements the rates over a suitable number of years. The bill would extend these provisions to all utilities, and would delete a requirement that the PSC ensure that the impact on residential and industrial metal melting rates due to the cost of service requirement is not more than 2.5% per year. In establishing cost of service rates, the Commission would have to ensure that each class or sub-class was assessed for its fair and equitable use of the electric grid.

The bill would require the Commission to ensure that the cost of providing service to each customer class was based on the allocation of production-related costs based on using the 75-0-25 method of cost allocation and transmission costs based on using the 100% demand method. The Commission could modify either of these methods if it determined that the method did not ensure that rates were equal to the cost of service.

Rates for Low-Income & Senior Citizen Customers & Educational Institutions

With regard to electric utilities with at least 1.0 million retail customers in the State, the law requires the PSC to establish eligible low-income customer or eligible senior citizen customer rates. Upon filing a rate increase request, a utility must include the proposed rates and a method to allocate the revenue shortfall attributed to their implementation upon all customer classes. Also with regard to electric utilities with at least 1.0 million retail customers in the State, the PSC must establish rate schedules that ensure that public and private schools, universities, and community colleges are charged retail electric rates that reflect the actual cost of providing service to them. Regulated electric utilities must file with the PSC tariffs to ensure that these institutions are charged such rates. Under the bill, these provisions would apply to all regulated electric utilities, regardless of the number of customers.

Senate Bill 438 (S-7)

Purpose

The Clean, Renewable, and Efficient Energy Act states that its purpose is to promote the development of clean energy, renewable energy, and energy optimization through the implementation of a clean, renewable, and energy efficient standard that will cost-effectively do all of the following:

-- Diversify the resources used to reliably meet the energy needs of Michigan consumers.

-- Provide greater energy security through the use of indigenous energy resources available within the State.

-- Encourage private investment in renewable energy and energy efficiency.

-- Provide improved air quality and other benefits to Michigan energy consumers and citizens.

Under the bill, the Act's purpose would be to promote the development and use of clean and renewable energy resources and the reduction of energy waste through programs to cost-effectively achieve the prescribed goals. The goals would be the same as those listed above except that, under the bill, the third goal would be to encourage private investment in renewable energy and energy waste reduction (rather than energy efficiency), and the fourth goal would be to coordinate with Federal regulations to provide improved air quality and other benefits to energy consumers and citizens. The bill also would add the goal of removing unnecessary burdens on the appropriate use of solid waste as a clean energy source.

The Act defines "energy efficiency" as a decrease in customer consumption of electricity or natural gas achieved through measures or programs that target customer behavior, equipment, devices, or materials without reducing the quality of energy services. The bill would refer to measures or programs "including prepay programs" that target customer behavior, equipment, etc.

The bill would define "energy waste reduction" as all of the following:

-- Energy efficiency.

-- Load management, to the extent that it reduces provider costs.

-- Energy conservation, but only to the extent that the decreases in electricity consumption are objectively measureable and attributable to an energy waste reduction plan.

The term would not include electric provider infrastructure projects that are approved for cost recovery by the PSC other than as provided in the Act.

Currently, this definition applies to the term "energy optimization", referring to "optimization" where the bill refers to "waste reduction". Additionally, the definition currently refers to load management to the extent that it reduces overall energy usage, rather than provider costs.

35% Goal for 2025

The bill provides that, as a goal, at least 35% of the State's electric needs should be met through a combination of energy waste reduction and renewable energy by 2025, if the investments in these means were the most reasonable means of meeting an electric utility's energy and capacity needs relative to other resource options. Both of the following would count toward achievement of the goal:

-- All renewable energy, including renewable energy credits purchased or otherwise acquired with or without the associated renewable energy, and ay banked renewable energy credits, that counted toward the renewable energy standard under the current law on the bill's effective date, as well renewable energy credits granted as a result of any investments made in renewable energy by the utility or a utility customer after that date.

-- The sum of the annual electricity savings since October 6, 2008, as recognized by the PSC through annual reconciliation proceedings, that resulted from energy waste reduction measures implemented under an energy optimization plan or energy waste reduction plan.

Renewable Energy Plans

Plan Criteria; Approval. The Act required electric providers whose rates are regulated by the PSC, AESs, member-regulated cooperative electric utilities, and municipally owned electric utilities to file with the PSC a renewable energy plan that, among other things, described how the electric provider would meet the Act's renewable energy standard.

Under the bill, renewable energy plans and associated revenue recovery mechanisms filed by an electric provider, approved or found by the PSC to comply with the Act and in effect on the bill's effective date, would remain in effect, subject to amendments described below.

For an electric provider whose rates are regulated by the PSC, amended renewable energy plans would have to establish a nonvolumetric mechanism for the recovery of incremental costs of compliance within the provider's customer rates. The mechanism could not result in rate impacts that exceeded the monthly maximum retail rate impacts specified in the Act. (Under the Act, an electric provider may not comply with the standards to the extent that recovery of the incremental cost of compliance will have a retail rate impact that exceeds the following:

-- $3 per month per residential customer meter.

-- $16.58 per month per commercial secondary customer meter.

-- $187.50 per month per commercial primary or industrial customer meter.)

The mechanism would be subject to adjustment as provided in the Act currently.

Within one year after the bill's effective date, the PSC would have to review each electric provider's plan. For a provider whose rates are regulated by the Commission, the Commission would have to conduct a contested case hearing. Afterward, the Commission would have to approve, with any changes the provider consented to, or reject the plan and any amendments to it. For all other electric providers, the Commission would have to provide an opportunity for public comment on the plan. Following that opportunity, the Commission would have to determine whether any amendment to the plan proposed by the provider complied with the Act. For AESs, the Commission would have to approve, with any changes the provider consented to, or reject any proposed amendments to the plan. For cooperative and municipally owned utilities, the proposed amendment would be adopted if the Commission determined that it complied with the Act.

If an electric provider proposed to amend its renewable energy plan after the review process, the provider would have to file the proposed amendment with the PSC. For a provider whose rates are regulated, if the proposed amendment would modify the revenue recovery mechanism, the PSC would have to conduct a contested case hearing. After the hearing and within 90 days after the amendment was filed, the PSC would have to approve, with any changes the provider consented to, or reject the plan and the proposed amendment or amendments. After the applicable opportunity for public comment and within 90 days after the amendment was filed, the PSC would have to determine whether the proposed amendment complied with the Act. For AESs and cooperative utilities, the PSC would have to approve, with any changes consented to by the provider, or reject any proposed amendments. For municipally owned utilities, the proposed amendment would be adopted if the PSC determined that it complied with the Act.

For an electric provider whose rates are regulated, the PSC would have to approve the plan or amendments to it, or determine that the plan or amendments complied with the Act, as appropriate, if the Commission determined that the plan was reasonable and prudent, and was consistent with the Act's prescribed purpose and the 35% renewable energy goal and met the prescribed renewable energy credit standard. In determining whether the plan was reasonable and prudent, the PSC would have to consider projected costs and whether projects costs in prior plans were exceeded.

If the PSC rejected a proposed renewable energy plan or amendment, it would have to explain in writing the reasons for its determination.

Renewable Energy Credit Portfolio. The bill would require an electric provider to achieve a renewable energy credit portfolio as follows:

-- In 2016 through 2018, a portfolio that consisted of at least the same number of renewable energy credits as required under current law.

-- In 2019 through 2021, a portfolio of at least 12.5%.

-- In 2021, a portfolio of at least 15%.

("Renewable energy credit portfolio" means the sum of the renewable energy credits achieved by a provider for a particular year.)

An electric provider's renewable energy credit portfolio would have to be calculated by determining the number of renewable energy credits used to comply with these requirements during the applicable year. That number would have to be divided by one of the following, at the option of the provider as specified in its renewable energy plan:

-- The number of weather-normalized megawatt hours of electricity sold by the provider during the previous year to Michigan retail customers.

-- The average number of megawatt hours of electricity sold by the provider annually during the previous three years to Michigan retail customers.

This quotient would have to be multiplied by 100.

Each electric provider would have to meet the renewable energy credit standards with renewable energy credits obtained by one or more of the following means:

-- Generating electricity from renewable energy systems for sale to retail customers.

-- Purchasing or otherwise acquiring renewable energy credits with or without the associated renewable energy.

("Renewable energy system" means a facility, electricity generation system, or set of electricity generations systems that use at least one renewable energy resource to generate electricity. The term excludes certain hydroelectric facilities and incinerators. "Renewable energy resource" means a resource that replenishes naturally over a human, not a geological, time frame and that ultimately is derived from solar power, water power, or wind power. A renewable energy resource comes from the sun or from thermal inertia of the Earth and minimizes the output of toxic material in the conversion of the energy. The term includes municipal solid waste, which the bill specifies would include the biogenic and anthropogenic factions. Additionally, under the bill, "renewable energy resource" would include fuel that has been manufactured from waste, including municipal solid waste. The bill would exclude pet coke, hazardous waste, coal waste, and scrap tires.)

An electric provider whose rates are regulated by the PSC would have to submit a contract entered into for the purposes of meeting the renewable energy credit standards to the Commission for review and approval. If the Commission approved the contract, it would have to be considered consistent with the provider's renewable energy plan. The Commission could not approve a contract based on an unsolicited proposal unless the Commission determined that it provided opportunities that might not otherwise be available or commercially practical through a competitive bid process.

A provider could substitute energy waste reduction credits for renewable energy credits otherwise required to meet the renewable energy credit standards if the PSC approved the substitution. Under the bill, one energy waste reduction credit would have to be granted to an electric provider for each megawatt hour of annual incremental energy savings achieved through energy waste reduction. A provider could not use energy waste reduction credits to meet more than 10% of the renewable energy credit standard. One renewable energy credit would have to be awarded per one energy waste reduction credit.

Renewable Energy System; Credits. Under the Act, a renewable energy system that is the source of renewable energy credits used to satisfy the renewable energy standards must be either located outside of Michigan in the retail electric customer service territory of any provider that is not an AES, or located anywhere in the State. The location requirements do not apply under certain circumstances, including when the electricity generated from the renewable energy system is sold by a not-for-profit entity located in Indiana or Wisconsin to a municipally-owned or cooperative electric utility in Michigan, under a contract in effect on January 1, 2008, and the electricity is not being used to meet another state's standard for renewable energy. The bill would refer to Ohio in addition to Indiana or Wisconsin in this provision, and would delete the reference to a contract in effect on January 1, 2008.

The bill would delete an exemption from the location requirements in the case of electricity generated from a renewable energy system that is sold by a not-for-profit entity located in Ohio to a municipally owned electric utility in Michigan under a contract approved by resolution of the utility's governing body before January 1, 2008, and is not being used to meet another state's renewable energy standard.

Except as otherwise provided, one renewable energy credit must be granted to the owner of a renewable energy system for each megawatt hour of electricity generated from the system. If a system uses both a renewable energy resource and a nonrenewable energy resource to generate electricity, the number of credits granted must be based on the percentage of the electricity generated from the renewable resource.

Currently, a renewable energy credit may not be granted for renewable energy generated from a municipal solid waste incinerator to the extent that the renewable energy was generated by operating the incinerator in excess of specified nameplate capacity ratings. The bill would delete this provision.

Currently, a renewable energy credit expires at the earliest of the following times:

-- When used by an electric provider to comply with the renewable energy standard.

-- When substituted for an energy optimization credit.

-- Three years after the end of the month in which the credit was granted.

The bill would refer to energy waste reduction rather than energy optimization. Additionally, the bill would extend the expiration date from three years to five years after the credit was granted. Also, under the bill, the credit would expire when an electric provider whose rates are regulated by the PSC used it to contribute to achievement of the 35% renewable energy goal.

The bill would delete a provision allowing a credit associated with renewable energy generated within 120 days after the start of a calendar year to be used to satisfy the previous year's renewable energy standard.

The bill would eliminate a provision stating that an electric provider is responsible for demonstrating that a renewable energy credit used to comply with a renewable energy credit standard is derived from a renewable energy source and that the provider has not previously used or traded, sold, or otherwise transferred the credit. Additionally, the bill would delete provisions stating that the same renewable energy credit may be used by a provider to comply with both a Federal renewable energy standard and the State's renewable energy standard, and that a provider that uses a credit to comply with another state's renewable energy standard may not use the same credit to comply with Michigan's standard.

Also, the bill would delete a provision stating that a renewable energy credit purchased from a renewable energy system in Michigan does not have to be used in Michigan.

Tracking Program. The Act provides that renewable energy credits may be traded, sold, or otherwise transferred, and requires the PSC to establish a renewable energy credit certification and tracking program.

The bill would delete a requirement that the program include a method for ensuring that both a renewable energy credit and an advanced cleaner energy credit are not awarded for the same megawatt hour of energy.

Energy Optimization/Waste Reduction

Energy Optimization/Waste Reduction Plan. The Act required a rate-regulated electric or natural gas provider to file a proposed energy optimization plan with the PSC by March 3, 2009, and a member-regulated cooperative electric utility or municipally owned electric utility to file such a plan by April 2, 2009. The Act states that the overall goal of an energy optimization plan is to reduce the future costs of provider service to customers, in particular by delaying the need for constructing new electric generating facilities and thereby protecting consumers from incurring the costs. Under the bill, these energy optimization plans would remain in effect, subject to any amendments, as energy waste reduction plans. The bill would expand the goal of a plan to include helping the provider's customers reduce energy waste. Generally, the current provisions that apply to energy optimization plans would apply to waste reduction plans.

A plan must describe how the provider's actual costs of implementing an energy optimization or waste reduction plan will be recovered. Under the bill, this would include specifying whether the charges to recover the costs would be volumetric or fixed per-meter charges.

Additionally, a plan must provide for the practical and effective administration of the proposed programs. The PSC must allow providers flexibility in designing their programs and administrative approach. Under the bill, this would include the flexibility to determine the relative amount of effort to be devoted to each customer class based on the specific characteristics of the provider's service territory.

Approval of Energy Optimization/Waste Reduction Plans. The Act contains provisions applicable to the filing, review, and approval of an electric or natural gas provider's energy optimization plan. The bill would refer to an energy waste reduction plan rather than an energy optimization plan.

The Act provides that an energy optimization plan must be enforced subject to the same procedures that apply to a renewable energy plan. Under the bill, the energy waste reduction plan of a provider whose rates are regulated by the PSC would have to be enforced by the Commission. For a provider whose rates are not regulated, the plan would have to be enforced through a civil action (described below). Notwithstanding any other provision related to energy waste reduction plans, the PSC would have to allow municipally owned electric utilities to design and administer their plans in a manner consistent with the administrative changes approved in the Commission's April 17, 2012, order in case nos. U-16688 to U-16728 and U-17008.

Every two years after initial approval of an energy waste reduction plan, the PSC would have to review it. For a rate-regulated provider, the Commission would have to review the plan by conducting a contested case hearing under the Administrative Procedures Act. After the hearing, the Commission would have to approve the plan with any changes consented to by the provider, or reject the plan and any proposed amendments.

If a provider proposed to amend its plan at a time other than during the biennial review process, the provider would have to file the proposed amendment with the PSC. After the hearing and within 90 days after the amendment was filed, the Commission would have to approve the plan with any changes consented to by the provider or reject the plan and any proposed amendments.

If the PSC rejected a proposed plan or amendment, it would have to explain in writing the reasons for its determination.

After December 31, 2020, these provisions would not apply to an electric provider whose rates are not regulated by the PSC.

Provider Incentives. Under the Act, the energy optimization plan of an electric or natural gas provider whose rates are regulated by the PSC may authorize a commensurate financial incentive for the provider for exceeding the energy optimization performance standard. Payment of such an incentive is subject to the PSC's approval.

The total amount of the incentive may not exceed the lesser of 25% of the net cost reductions experienced by the provider's customers as a result of plan implementation, or 15% of the provider's actual energy efficiency program expenditures for the past year. The bill would refer to waste reduction rather than optimization and efficiency. Additionally, the bill would change the amount of the incentive to the lesser of 20% of the net cost reductions experienced by customers due to plan implementation, or 25% of the provider's actual program expenditures for the year.

Waste Reduction Energy Savings Goals. The Act prescribed incremental energy savings that an electric provider's energy optimization programs had to collectively achieve annually between 2008 and 2015. The prescribed annual incremental energy savings in 2015 and each year after that are equivalent to 1% of total annual retail electricity sales in megawatt hours in the preceding year. Under the bill, this savings amount would apply every year through 2020.

Currently, if an electric provider uses load management to achieve energy savings under its plan, the required minimum energy savings must be adjusted so that the ratio of the minimum savings to the sum of maximum expenditures for implementing the provider's approved waste reduction plan and the load management expenditures remains constant. The bill would refer to "actual" rather than "maximum" expenditures.

The bill would retain an annual incremental energy savings requirement for a natural gas provider's plan of 0.75% of total annual retail sales in the preceding year.

The Act provides for an electric provider's substitution of certain renewable energy credits, advanced cleaner energy credits, load management, or a combination of these methods for energy optimization credits otherwise required to meet up to 10% of the energy optimization performance standard, if approved by the PSC. The bill would delete the reference to advanced cleaner energy credits.

Energy Waste Reduction Plan Amendment. By January 1, 2021, and then every two years, the bill would require a rate-regulated electric provider to file with the PSC an energy waste reduction plan amendment detailing the amount of energy waste reduction it proposed to achieve for the next two years. If the provider proposed a reduction level that differed from the level specified in the provider's current plan, the PSC could approve the proposed level if the Commission found that it was the most reasonable and prudent. If the Commission found that a proposed lower reduction level was not the most reasonable and prudent, the level of waste reduction to be achieved for the next two-year period would have to be the same as the level specified in the provider's current plan.

Alternative Waste Reduction Standards. If, over a two-year period, a rate-regulated electric provider could not achieve the energy waste reduction standard in a cost-effective manner, the provider could petition the PSC in a contested case hearing to establish an alternative energy waste reduction level for that provider.

A natural gas provider that could not achieve the energy waste reduction standard in a cost-effective manner over a two-year period also could petition the PSC to establish alternative energy waste reduction standards for that provider. A natural gas provider's petition would have to identify the provider's efforts to meet the standard, explain why the provider could not achieve the standard reasonably and cost-effectively, and propose a revised energy waste reduction to be achieved. If the PSC determined, based on a review of the petition, that the provider had been unable to reasonably and cost-effectively achieve the energy waste reduction standard, the Commission would have to revise the standard as applied to that provider to a level that could reasonably and cost-effectively be achieved.

The Act contains similar provisions allowing a provider to petition the PSC for alternative energy optimization standards that apply to electric providers that serve a maximum of 200,000 Michigan customers and had average rates for residential customers using 1,000 kilowatt hours per month for all electric utilities in the State, according to a 2007 PSC compilation. The bill would refer to waste reduction rather than energy optimization in these provisions. The provisions concerning these particular electric providers would be repealed on January 1, 2021.

Energy Waste Reduction Credits. The Act provides for one energy optimization credit to be granted to an electric provider for each megawatt hour of annual incremental energy savings achieved through energy optimization. The Act provides for the carrying forward of unused credits as well as their expiration upon use, and provides that a credit is not transferable to another entity. The bill would refer to waste reduction rather than optimization.

The Act requires the PSC to establish an energy optimization credit tracking system. The bill would refer to waste reduction rather than optimization, and require one credit to be granted to an electric provider for each megawatt hour of annual incremental energy savings achieved through waste reduction.

Waste Reduction Plan Cost Recovery. The PSC must allow a rate-regulated electric or natural gas provider to recover the actual costs of implementing its approved energy optimization plan (waste reduction plan, under the bill).

Costs must be recovered from all natural gas customers and from residential electric customers by volumetric charges, from all other metered electric customers by per-meter charges, and from unmetered electric customers by an appropriate charge, applied to utility bills as an itemized charge. Under the bill, instead, costs would have to be recovered from all customers by volumetric charges or fixed, per-meter charges as specified in the energy waste reduction plan. Fixed, per-meter charges could vary by rate class. These charges could be itemized on utility bills until January 1, 2021.

Currently, for the electric primary customer rate class customers of electric providers and customers of natural gas providers with an aggregate annual natural gas billing demand of more than 100,000 decatherms or equivalent MCFs for all sites in the natural gas utility's service territory, the cost recovery may not exceed 1.7% of the total retail sales revenue for that customer class. For electric secondary customers and residential customers, the cost recovery may not exceed 2.2% of total retail sales revenue for those customer classes. The bill would delete the cost recovery limits upon its effective date.

Under the Act, the PSC must authorize a natural gas provider that spends a minimum 0.5% of total natural gas retail sales revenue in a year on PSC-approved energy optimization programs to implement a symmetrical revenue decoupling true-up mechanism that adjusted for sales that are above or below the projected levels that were used to determine the revenue requirement authorized in the provider's most recent rate case. Under the bill, a natural gas provider could not implement revenue decoupling under this provision if it had implemented revenue decoupling as proposed by Senate Bill 437 (S-7). Also, the bill would refer to energy waste reduction programs rather than energy optimization programs.

Waste Reduction Program Administrator. Many of the Act's energy optimization requirements do not apply to an electric or natural gas provider that pays 2% of total sales revenue each year to an independent energy optimization program administrator selected by the PSC. The bill would refer to 2% of total retail sales revenue for the second year preceding.

Under the Act, an alternative compliance payment received from a provider by the program administrator must be used to administer the provider's energy efficiency program. The PSC must allow a provider to recover such a payment. This cost must be recovered from residential customers by volumetric charges, from all other metered customers by per meter charges, and from unmetered customers by an appropriate charge, applied to utility bills. Under the bill, instead, the cost would have to be recovered from all customers by volumetric or fixed, per meter charges, which could vary by rate class. The charges could be itemized on utility bills until January 1, 2021.

Currently, money unspent by the program administrator in a year must be carried forward to be spent in the subsequent year. The bill would delete this provision.

Self-Directed Waste Reduction Plan. The Act exempts certain commercial and industrial electric customers that implement a self-directed plan from energy optimization charges. The bill would retain all of the provisions related to these customers, but would refer to energy waste reduction rather than energy optimization.

Load Management: Voluntary Shut-Down. The Act requires the PSC to promote load management in appropriate circumstances. Under the bill, this would include expansion of existing and establishment of new load management programs in which an electric provider could manage the operation of energy-consuming devices and remotely shut down air conditioning or other energy intensive systems of participating customers, demand response programs that use time of day pricing and dynamic rate pricing, and similar programs, for utility customers that had advanced metering infrastructure. Provider participation and customer enrollment in such programs would have to be voluntary; however, rate-regulated providers whose rates included the cost of advanced metering infrastructure would have to offer Commission-approved demand response programs. The programs could provide incentives for customer participation and would have to include customer protection provisions as required by the PSC. To participate in a program, a customer would have to agree to remain in it for at least one year.

("Load management" means measures or programs that target equipment or devices to result in decreased peak electricity demand such as by shifting demand from a peak to an off-peak period. The bill would refer to behavior rather than devices.)

The bill provides that the load management provisions could not be construed to prevent a utility from doing either of the following:

-- Recovering the full cost associated with providing electric service and load management programs.

-- Installing metering and retrieving metering data necessary to properly, accurately, and efficiently bill for the utility's services without manual intervention or calculation.

PSC Responsibilities. The bill would delete a requirement that the PSC do all of the following:

-- Promote energy efficiency and conservation.

-- Actively pursue increasing public awareness of energy conservation and efficiency.

-- Actively engage in energy conservation and efficiency efforts with providers.

-- Engage in regional efforts to reduce demand for energy through conservation and efficiency.

-- Submit to the Legislature an annual report on the effort to implement energy conservation and efficiency programs or measures.

Suspension of Waste Reduction Program. If the PSC determines that an electric or natural gas provider's energy waste reduction program has not been cost-effective, the provider's program is suspended beginning 180 days after the determination. If a provider's program is suspended, the provider must maintain cumulative incremental energy savings in subsequent years at the level actually achieved during the year before the Commission's determination is made. Additionally, the provider may not impose energy waste reduction charges in subsequent years except to the extent necessary to recover unrecovered program expenses incurred before suspension of the program. Under the bill, these provisions would not apply to an electric provider beginning January 1, 2021.

Civil Action. The bill would allow the Attorney General or any customer of a municipally owned or member-regulated cooperative electric utility to commence a civil action for injunctive relief against the utility if it failed to meet the applicable energy waste reduction requirements or a related order or rule.

The bill would prescribe requirements for notice to the defendant and a good faith attempt to resolve the dispute before the complaint could be filed.

Distributed Generation & Net Metering

Within 90 days after the bill's effective date, the PSC would have to establish a distributed generation program by order. The program would have to apply to all electric utilities whose rates are regulated by the PSC and AESs in Michigan.

An electric customer of any class would be eligible to interconnect an eligible electric generator with the customer's local electric utility and operate it in parallel with the distribution system. The program would have to be designed for a period of at least 10 years and limit each customer to generation capacity designed to meet up to 100% of the customer's electricity consumption for the previous 12 months.

Similar requirements apply to a net metering program authorized under the current law, but each customer's generation capacity is limited to the customer's electric needs. The distributed generation program would replace the net metering program, and would be subject to many of the existing provisions.

Currently, an electric utility or AES is not required to allow for net metering that is greater than 1% of its in-State peak load for the preceding calendar year. Under the bill, an electric utility or AES would not have to allow for a distributed generation program that was greater than 1% of its average in-State peak load for the preceding five years. The 1% limit would have to be allocated as follows:

-- Not more than 0.5% for customers with a generator capable of generating a maximum of 20 kilowatts.

-- Not more than 0.25% for customers with a generator capable of generating more than 20 but not more than 150 kilowatts.

-- Not more than 0.25% for customers with a methane digester capable of generating more than 150 kilowatts.

If necessary to promote reliability or safety, the PSC could promulgate rules that required the use of inverters that performed specific automated grid-balancing functions to integrate distributed generation onto the electric grid. Inverters that interconnected distributed generation resources could be owned and operated by electric utilities.

An electric utility or AES could charge a maximum fee of $50 to process an application to participate in the distributed generation program. (The fee to apply for net metering is $100.) As currently required, the customer would have to pay all interconnection costs. The bill would delete a requirement that a customer pay standby costs if the customer has a system capable of generating more than 20 kilowatts.

Electric meters would have to be used to determine the amount of a customer's energy use in each billing period, net of any excess energy the customer's generator delivered to the utility distribution system during that period. For a customer with a generation system capable of generating more than 20 kilowatts, the utility would have to install and use a generation meter and a meter capable of measuring the flow of energy in both directions. A customer with a system capable of generating more than 150 kilowatts would have to pay the costs of installing any new meters. An electric utility serving more than 1.0 million customers in Michigan would be permitted, but not required, to give its customers participating in the distributed generation program, at no additional charge, a meter or meters capable of measuring the flow of energy in both directions.

An electric utility serving fewer than 1.0 million Michigan customers would have to give a meter or meters capable of measuring the flow of energy in both directions to participating customers at cost. The eligible customer would have to pay only the incremental cost above that for meters provided by the utility to similarly situated nongenerating customers.

If the quantity of electricity generated and delivered to the utility distribution system by an eligible generator during a billing period exceeded the quantity of electricity supplied from the utility or AES during that period, a supplier of electric generation service would have to credit the eligible customer for the excess kilowatt hours generated. Any excess kilowatt hours not used to offset electric generation charges in the next billing period would have to be carried forward to subsequent billing periods.

Notwithstanding any law or regulation, distributed generation customers could not receive credits for electric utility transmission or distribution charges. The credit per kilowatt hour for kilowatt hours delivered into the utility's distribution system would have to be either of the following:

-- The monthly average real-time locational marginal price for energy at the commercial pricing node within the utility's distribution service territory, or for distributed generation customers on a time-based rate schedule, the monthly average real-time locational marginal price for energy at the commercial pricing node within the utility's distribution service territory during the time-of-use pricing period.

-- The utility's or AES's power supply component, excluding transmission charges, of the full retail rate during the billing period or time-of-use pricing method.

(The credit under the existing net metering program is calculated similarly.)

The grid use charge established under Senate Bill 437 (S-7) could not be reduced by any credit or other ratemaking mechanism for distributed generation.

A customer participating in a PSC-approved net metering program before the bill's effective date could elect to continue to receive service under the terms and conditions of that program for up to 10 years from the date of enrollment. This provision would not apply to an increase in the generation capacity of the customer's eligible generator beyond the capacity on the bill's effective date.

The bill specifies that, notwithstanding any other provision of the Act, the Act would not limit or restrict an industrial customer's ability to build, own, operate, or have a third party build, own, and operate one or more self-generation or cogeneration facilities.

Voluntary Green Pricing Program

The bill would require an electric provider to offer to its customers the opportunity to participate in a voluntary green pricing program, under which the customer could specify, from the options made available by the provider, the amount of electricity attributable to the customer that would be renewable energy. If the provider's rates are regulated by the PSC, the program, including the rates paid for renewable energy, also would have to be approved by the Commission. The customer would be responsible for any additional costs incurred and would accrue any additional savings realized by the provider as a result of the customer's participation in the program.

If an electric provider had not yet fully recovered the incremental costs of compliance with the renewable energy standard, a customer that received at least 50% of that customer's average monthly electricity consumption through the program would be exempt from paying surcharges for incremental costs of compliance. Also, before entering into an agreement to participate in an approved green pricing program with a customer that would receive less than 50% of average monthly consumption through the program, the provider would have to notify the customer that the customer would be responsible for the full applicable charges for the incremental costs of compliance and for participation in the voluntary renewable energy program.

Report to Residential Customers

Currently, in its billing statements for a residential customer, each provider must report to the customer all of the following:

-- Itemized monthly charges collected from the customer for implementing the Act's renewable energy and energy optimization program requirements.

-- An estimated monthly savings for that customer to reflect the reductions in the monthly energy bill produced by the energy optimization program, as well as the avoided long-term, life-cycle, levelized costs of building and operating new conventional coal-fired electric generating power plants.

The bill would eliminate these requirements.

Advanced Cleaner Energy System

The Act requires the PSC, subject to retail rate impact limits, to consider all actual costs reasonably and prudently incurred in good faith to implement a Commission-approved renewable energy plan by a rate-regulated electric provider to be a cost of service to be recovered by the provider. The provider must recover through its retail electric rates all of the provider's incremental costs of compliance during the 20-year period beginning when the provider's plan is approved and all reasonable and prudent ongoing costs of compliance during and after the period.

The calculation of incremental costs of compliance includes, among other factors, various costs related to renewable energy systems or advanced cleaner energy systems used to meet or maintain renewable energy standards, or attributable to renewable energy standards. "Advanced cleaner energy system" means any of the following:

-- A gasification facility.

-- An industrial cogeneration facility.

-- A coal-fired electric generating facility if at least 85% of the carbon dioxide emissions are captured and permanently geologically sequestered.

-- An electric generating facility or system that uses technologies not in commercial operation on October 6, 2008.

The bill would refer to a cogeneration facility rather than an industrial cogeneration facility. "Cogeneration facility" would mean a facility that produces both electricity and another form of useful thermal energy, such as heat or steam, in a way that is more efficient than the separate production of those forms of energy.

Under the bill, a coal-fired electric generating facility also would be included in the definition of "advanced cleaner energy system" if at least 85% of the emissions were used for other commercial or industrial purposes that did not result in release of carbon dioxide to the atmosphere. With regard to a facility that uses technologies not in commercial operation on October 6, 2008, the bill would require the PSC to determine that the technology has carbon dioxide emissions benefits or will significantly reduce other regulated air emissions.

The bill also would include in the definition a hydroelectric pumped storage facility.

Exemption from Energy Standards

Currently, electricity or natural gas used in the installation, operation, or testing of any pollution control equipment is exempt from the requirements of and calculations of compliance required under the Act's energy standards. The bill would eliminate the exemption for electricity effective January 1, 2021.

Residential Energy Improvements

The bill would add Part 7 to the Act to authorize a rate-regulated provider to establish a residential energy projects program. Under such a program, if a record owner of privately owned residential real property in the provider's service territory obtained financing or refinancing of an energy project on the property from a commercial lender or other legal entity, the loan would be repaid through itemized charges on the provider's utility bill for that property. The charges could cover the cost of materials and labor necessary for installation, home energy audit costs, permit fees, inspection fees, application and administrative fees, bank fees, and all other fees that the record owner could incur for the installation on a specific or pro rata basis, as determined by the provider.

"Energy project" would mean the installation or modification of an energy waste reduction improvement or the acquisition, installation, or improvement of a renewable energy system.

A residential energy projects program could be established and implemented only pursuant to a plan approved by the PSC. A provider seeking to establish a program would have to file a proposed plan with the Commission. A plan would have to include the following:

-- The estimated costs of program administration.

-- Whether the program would be administered by a third party.

-- An application process and eligibility requirements for a record owner to participate in the program.

-- An application form.

-- A description of any fees to cover application, administration, or other program costs to be charged to a participating owner.

-- Provisions for billing customers any fees and the monthly installment payments as a per-meter charge on the bill for electric or natural gas services.

-- Provisions for marketing and participant education.

The PSC could not approve a provider's proposed plan unless it determined that the plan was reasonable and prudent. If the PSC rejected a proposed plan, it would have to explain its reasons in writing. Every four years after initial approval of a plan, the PSC would have to review it.

A baseline home energy audit would have to be conducted before an energy project that would be paid for through utility bill charges was undertaken. After the project was completed, the provider would have to obtain verification that it was properly installed and was operating as intended.

Electric or natural gas service could be shut off for nonpayment of the per-meter charge in the same manner and pursuant to the same procedures as used to enforce nonpayment of other charges for the provider's electric or natural gas service. If notice of a loan under the program were recorded with the county register of deeds, the obligation to pay the charge would run with the land and be binding on future customers contracting for electric or natural gas service to the property.

The term of a loan paid through the program could not exceed the anticipated useful life of the energy project financed by the loan or 180 months, whichever was less. The loan would have to be repaid in monthly installments.

The PSC would have to promulgate rules to implement Part 7 within one year after the bill took effect. Every five years after promulgating the rules, the PSC would have to submit to the standing committees of the Legislature with primary responsibility for energy issues a report on the implementation of Part 7 and any recommendations for legislation to amend it. The report could be combined with the PSC's annual report summarizing its activities over the preceding year.

The bill provides that the Act would not limit a provider's right to propose a residential energy improvement program with elements that differed from those required for a residential energy projects program under proposed Part 7 or the PSC's authority to approve such a program as reasonable and prudent.

MCL 460.6a et al. (S.B. 437) Legislative Analyst: Julie Cassidy

460.1001 et al. (S.B. 438)

FISCAL IMPACT

Senate Bill 437 (S-7)

The bill would require the Public Service Commission and the Michigan Agency for Energy to promulgate rules, make rulings, issue orders, and take other administrative actions to implement a number of proposed or amended sections of the PSC law, which would introduce new administrative costs. The PSC's regulation of public utilities is primarily funded through assessments on utilities that reflect the PSC's costs, so increased costs would presumably be mitigated by increased assessments. Any cases in which amendments to the Act served to reduce the amount of work required of the PSC presumably would lower assessments accordingly. To provide some perspective, in fiscal year (FY) 2014-15, the PSC collected a total of about $29.1 million in public utility assessments.

The bill would increase revenue received by the Utility Consumer Representation Fund by about $550,000 annually. In FY 2014-15, approximately $1.2 million was deposited into the Fund; the bill would increase that amount to $1,750,000, which would be adjusted annually for inflation. Money in the Fund is currently split evenly between the Utility Consumer Representation Board and Attorney General for grants. The bill would change this allocation to $1.0 million for the Board and $750,000 for the Attorney General. In addition, the bill would