SB0437: SUMMARY AS ENACTED (Date Completed: 11-16-17) - UTILITY SERVICE; CLEAN/RENEWABLE ENERGY

-- Specifies information to be included in an IRP.

-- Requires an IRP to include projected energy purchased or produced by the electric utility from renewable energy resources, and, beginning January 1, 2022, requires the projected amount to equal at least 15%.

-- Requires an IRP to include an analysis of how the combined amounts of renewable energy and energy waste reduction achieved under the plan compare to the renewable energy resources and waste reduction goal established by Senate Bill 438, as well as projected energy and capacity purchased or produced by the utility from a cogeneration resource.

-- Requires each electric utility, before filing an IRP, to issue a request for proposals (RFP) to provide any new supply-side generation capacity resources needed to serve the utility's projected load, applicable planning reserve margin, and local clearing requirement or the utility's customers in Michigan and other states during the initial three-year planning period to be considered in each IRP.

-- Requires a utility that issues an RFP to use the resulting proposals to inform its IRP.

-- Requires the PSC, within 300 days after an IRP is filed, to recommend changes to the plan or issue a final, appealable order approving or denying it.

-- Prescribes procedures by which a utility may consider any changes recommended by the PSC and submit a revised IRP, and requires the PSC to issue a final, appealable order within 360 days after an IRP is filed.

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

-- Prescribes conditions under which the PSC must approve an IRP.

-- Authorizes an electric utility, if the PSC denies its IRP, to proceed with a proposed generation construction, investment, or power purchase without the assurances of cost recovery.

-- Allows a utility that does not accept the PSC's recommendations to submit a revised IRP, and requires the Commission to commence a contested case hearing and issue a final order on the plan within 90 days if the revisions are not substantial or inconsistent with the original IRP, or 150 days if they are.

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

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

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

-- Authorizes the PSC, on its own motion or at the request of an electric utility, to order the utility to file a plan review, and allows the Department of Environmental Quality to request the PSC to issue such an order to address changes in environmental regulations and requirements.

Regarding the provisions that allow an electric utility to apply to the PSC for a CON for increased generation capacity, the bill does the following:

-- Reduces the minimum cost threshold for a CON application from $500.0 million to $100.0 million.

-- Deletes a provision prohibiting the PSC from issuing a CON for a renewable energy system.

-- Requires the PSC, for power purchase agreements that an electric utility enters into with an unaffiliated entity after the bill's effective date, to consider a financial incentive that does not exceed the utility's weighted average cost of capital, and allows the PSC to authorize that financial incentive.

-- Provides that any portion of an electric utility's cost that exceeds the cost approved by the PSC in a CON, rather than the portion that exceeds 110% of the approved cost, will be presumed to have been incurred due to a lack of prudence.

With respect to capacity resource adequacy, the bill does the following:

-- Allows the Attorney General or a customer of a municipally owned or cooperative electric utility to commence a civil action against the utility if it fails to meet the resource capacity requirements.

-- If the Midcontinent Independent System Operator (MISO) implements a resource adequacy tariff that provides for a capacity forward auction, requires the PSC to determine whether a prevailing state compensation mechanism or state reliability mechanism for capacity would be more cost-effective, reasonable, and prudent than a capacity forward auction, and which utility service territories will be subject to the mechanism.

-- Requires the PSC to establish a state reliability mechanism if the Federal Energy Regulatory Commission did not put into effect by September 30, 2017, a resource adequacy tariff that included a capacity forward auction or prevailing state compensation mechanism.

-- Requires the PSC to establish a capacity charge that must be applied to alternative electric load in each utility service territory, unless an alternative electric supplier (AES) can demonstrate that it can meet its capacity obligations; and requires an electric provider to provide capacity to meet the capacity obligation for the portion of the load taking service from an AES in the provider's service territory that is covered by the capacity charge.

-- Requires each regulated electric utility, municipally owned or cooperative electric utility, and AES to demonstrate annually that it has sufficient capacity to meet its capacity obligations.

-- Requires the PSC to take certain actions, depending on the type of electric provider, if a provider fails to demonstrate that it can meet the prescribed capacity requirements.

The bill amended the sections of the PSC law known as the Customer Choice and Electricity Reliability Act to do the following:

-- Delete that title and revise the purposes of those sections.

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

-- Require the PSC, if the portion of a utility's average retail sales taking service from AESs falls below 10%, to set that percentage as the cap for the current year and the next five years; and provide that the cap will return to 10% in the sixth year if it is not adjusted in the interim.

-- Provide that a customer on an enrollment queue for retail open access service as of December 31, 2015, will remain on the queue unless the customer's prospective AES submits an enrollment request to the customer's utility or the customer notifies the utility of the desire to be removed from the queue.

-- Require each electric utility annually to file with the PSC a rank-ordered queue of all customers awaiting retail open access service, including the estimated amount of electricity used by each customer.

-- Prescribe the conditions under which a customer on the queue may take service from an AES, and require the AES to notify the utility within five business days after being notified that the customer will take AES service.

-- Require an AES to meet the bill's requirements regarding generation capacity as a condition of licensure.

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

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

-- Require the PSC, in establishing cost of service rates, to ensure that each customer class or sub-class is assessed for its fair and equitable use of the electric grid.

In addition, the bill does the following with respect to rates:

-- Extends to a steam utility a requirement that a gas or electric utility obtain approval from the PSC before increasing rates or charges or amending any rate or rate schedules in a way that increases the cost of services to its customers.

-- Allows a gas utility serving fewer than 1.0 million customers, when filing or after filing a complete application to the PSC to change its rates, to seek partial and immediate rate relief; requires the PSC to enter an order granting or denying the motion within 180 days; and requires the PSC to issue a final order in the case within 12 months.

-- Specifies that provisions allowing a gas, electric, or steam utility to implement a proposed rate increase if the PSC has not issued an order within 180 days after the utility filed its application for the increase, and requiring the utility to refund to customers the difference between the increased rate and the rate ultimately approved, apply only to completed applications filed before the bill's effective date.

-- Provides that a gas or electric utility's petition or application to alter its rates will be considered approved if the PSC does not make a final decision within 10 months, rather than 12 months, after the petition or application is filed; and also refers to a steam utility in this provision.

-- Requires the PSC to approve a revenue decoupling mechanism for an electric utility with fewer than 200,000 Michigan customers that adjusts for changes in actual sales compared to the projected levels used in the utility's rate case, if the utility demonstrates that its projected sales forecast is reasonable and the utility has achieved specified energy savings goals as a result of energy waste reduction measures.

-- Allows 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.

-- Requires 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.

-- Deletes 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 repealed provisions of the Clean, Renewable, and Efficient Energy Act that established 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 had to come from renewable sources by 2015. Instead, the bill requires each electric provider to maintain its mandated renewable energy credit portfolio through 2018; and achieve a renewable energy credit portfolio of at least 12.5% in 2019 through 2020 and at least 15% in 2021. Additionally, the bill amended the Act with respect to energy optimization programs, net metering, renewable energy credits, and other matters.

In relation to renewable energy, the bill does the following:

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

-- Requires the PSC, within one year after bill's effective date, to review each electric provider's plan.

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

-- Revises provisions related to renewable energy credits.

-- Revises the definition of "renewable energy resource".

-- Provides that none of the Act's renewable energy provisions abrogate the powers granted to local units of government under the Michigan Zoning Enabling Act.

Also, effective January 1, 2023, the bill repeals requirements that each electric provider submit to the PSC an annual report on the provider's actions to comply with the renewable energy standards, and that the PSC submit to the Legislature an annual report including a summary of the provider data and recommendations for statutory revisions.

In regard to energy optimization, the bill provides for the transition of energy optimization programs to energy waste reduction programs. In particular, the bill does the following:

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

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

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

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

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

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

-- Eliminates a 2% limit on 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.

-- Requires the PSC to conduct an annual energy waste reduction cost reconciliation for each rate-regulated provider to reconcile its recorded revenue with the amounts associated with the provider's plan to comply with the energy waste reduction standard.

-- Exempts an electric provider from provisions regarding the suspension of a cost-ineffective energy waste reduction program, beginning January 1, 2022.

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

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

-- Transfers from the PSC to the Michigan Agency for Energy responsibility for certain activities related to energy efficiency and conservation.

-- Includes 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 allows the programs to provide incentives for customer participation.

-- Requires the PSC to submit an annual report to the Legislature on whether the energy waste reduction provisions have been cost-effective.

In regard to net metering, the bill replaced the net metering program with a distributed generation program under which an electric customer may generate up to 100% of the customer's electricity consumption for the previous 12 months. Under the bill, an electric utility or alternative electric supplier does not have to allow for distributed generation that is 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 establishment of a net metering or distributed generation tariff under Senate Bill 437 may elect to continue to receive service under the terms and conditions of that program for up to 10 years from the date of enrollment.

Senate Bill 438 also does the following:

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

-- Allows an electric provider to establish a residential energy projects program under which property owners may finance energy projects through an itemized charge on their utility bills.

In addition, the bill repealed requirements that the PSC report annually to the Governor and the Legislature regarding wind energy.

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

Each bill took effect on April 20, 2017.

Senate Bill 437

Assessment Proceeding

Within 120 days after the bill took effect and then every five years, the PSC must 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 is economically and technologically feasible, as well as what is reasonably achievable.

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

-- Identify any formally proposed State or Federal environmental regulation, law, or rule that has been published in the Michigan Register or the Federal Register and how it will 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 must use in developing its integrated resource plan.

-- 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 must account expressly for advanced metering infrastructure that has already been installed in Michigan and seek to maximize potential benefits to ratepayers in lowering utility bills.

The established scenarios and assumptions must include all of the following:

-- Any required planning reserve margins and local clearing requirements (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 can 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 must be completed within 120 days and will not be a contested case under the Administrative Procedures Act (APA). The determination of the modeling assumptions for IRPs will not be considered a final order for purposes of judicial review. The determination will 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 added 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 provides 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 (i.e., MISO), and to meet all applicable State and Federal reliability and environmental regulations over the term of the plan. The PSC must 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 may include alternative modeling scenarios and assumptions in addition to those identified by the Commission. The PSC may 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 files an IRP, the PSC must state whether it has any recommended changes and, if so, describe them in sufficient detail to allow their incorporation in the IRP. If the Commission does not recommend changes, it must issue a final, appealable order approving or denying the plan. If the Commission recommends changes, it may 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 incorporates them. If the utility submits a revised plan, the Commission must issue a final, appealable order approving or denying it. The Commission must issue a final, appealable order within 360 days after the utility files the IRP. Up to 150 days after the utility makes its initial filing, it may file to update its cost estimates if they have materially changed. No other aspect of the initial filing may be modified unless the application is withdrawn and refiled. A utility's filing updating its cost estimates will not extend the period for the PSC to issue an order approving or denying the IRP. The Commission must review the IRP in a contested case proceeding.

The PSC must allow intervention by interested people, and request an advisory opinion from the DEQ regarding whether any potential decrease in emissions of sulfur dioxide, oxides of nitrogen, mercury, and particulate matter would reasonably be expected to result if the proposed IRP were approved and whether the plan can reasonably be expected to achieve compliance with Federal and State regulations, laws, and rules. The PSC may take official notice of the DEQ's opinion pursuant to State administrative rules. Information submitted by the DEQ will be advisory and not binding on future determinations by the DEQ or the Commission in any proceeding or permitting process. These provisions do not prevent an electric utility from applying for, or receiving, any necessary permits from the DEQ. The PSC may 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. Under the bill, a similar requirement applies 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 requires the PSC to approve a proposed IRP if it determines all of the following:

-- The IRP represents 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 borders another state) is completed using a workforce composed of Michigan residents.

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

To determine whether the IRP is the most reasonable and prudent means of meeting capacity needs, the PSC must consider whether it appropriately balances 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 are reasonable and cost effective.

Exceeding the renewable energy resources and energy waste reduction goal established by Senate Bill 438 will not, in and of itself, be grounds for determining that the proposed levels of peak load reduction, renewable energy, and energy waste reduction are not reasonable and cost effective.

Under the law, 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 applies to the approval of an IRP. Also, among the approved costs that the Commission must specify, the bill includes those associated with other investments or resources used to meet capacity needs that are included in the approved IRP. For power purchase agreements that a utility enters into after the bill's effective date with an unaffiliated entity, the PSC must consider and may authorize a financial incentive that does not exceed the utility's weighted average cost of capital. The costs for specifically identified investments included in an approved IRP that are commenced within three years after the PSC's order approving the initial plan, amended plan, or plan review will be considered reasonable and prudent for cost recovery purposes.

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

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

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

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

If the finalized costs are found to be significantly higher than the initially approved costs, the PSC must review and approve the proposed costs if it determines they are reasonable and prudent.

If the capacity resource is 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 must apply to the PSC for a CON.

IRP Standards. The bill requires an IRP under 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 from a renewable energy resource.

-- 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 compare 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 Section 6t also must 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 will 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 options available to meet projected energy and capacity needs.

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

-- How the utility will 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 proposes to take to reduce it, and the projected cost of compliance.

-- The projected long-term firm gas transportation contracts or natural gas storage the electric utility will hold to provide an adequate supply of natural gas to any new generation facility.

If the level of renewable energy purchased or produced is projected to drop over the five-, 10-, and 15-year planning periods, the utility must demonstrate why the reduction is in the best interest of ratepayers.

Denial of Relief. 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 applies in the case of the PSC's denial of a utility's IRP.

In addition, within 60 days after the date of the PSC's final order denying the IRP, the utility may submit plan revisions to the Commission for approval. The Commission must commence a contested case hearing under the APA. Within 90 days after the utility submits the revised IRP, the PSC must issue a final order approving the plan or denying it with recommendations, if the revisions are not substantial or inconsistent with the original IRP that was filed. If the revisions are substantial or inconsistent, the PSC will have up to 150 days to issue an order approving or denying the plan with recommendations.

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

Retail Rates. The bill requires the PSC to include in an electric utility's retail rates all reasonable and prudent specified costs that are incurred to implement an approved IRP. The PSC may not disallow recovery of costs a utility incurs in implementing an approved IRP, if the costs do 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 exceed the approved costs, the utility will have the burden of proving by a preponderance of the evidence that the costs are reasonable and prudent. The portion of cost that exceeds the approved cost will be presumed to have been incurred due to lack of prudence. (Similar provisions apply regarding a CON.)

The bill requires the PSC to disallow costs that it finds were incurred as the result of fraud, concealment, gross mismanagement, or lack of quality controls amounting to gross mismanagement. The PSC also must 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 have materially changed, or if the PSC believes it is unlikely that a project or program will become commercially operational, a utility may request, or the PSC on its own motion may initiate, a proceeding to review whether it is reasonable and prudent to complete an unfinished project or program included in an approved plan. If the PSC finds that completion is no longer reasonable and prudent, the Commission may modify or cancel approval of the project or program and unincurred costs in the utility's IRP. Except for costs the PSC finds a utility incurred as the result of fraud, concealment, gross mismanagement, or lack of quality controls amounting to gross mismanagement, if its approval is modified or canceled, the Commission may not disallow reasonable and prudent costs already incurred or committed to by contract by a utility. Once it finds that completion is no longer reasonable and prudent, the Commission may limit future cost recovery to those costs that cannot be reasonably avoided.

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

The bill requires 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 must 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 will have the same effect as an order approving an IRP.

In addition, the bill allows the PSC, on its own motion or at the electric utility's request, to order a utility to file a plan review. The DEQ may request the PSC to order a plan review to address material changes in environmental regulations and requirements that occur after the PSC approves an IRP. A utility must file a plan review within 270 days after the PSC orders it.

Status Reports. Under the law, an electric utility must 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 applies 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 $100.0 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 that seek a CON for projects costing less than $100.0 million. The threshold previously was $500.0 million.

The bill deleted a provision prohibiting the PSC from issuing a CON for a renewable energy system, but retains a prohibition against issuing a CON for environmental upgrades to existing generation facilities. Under the bill, if the application is 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 must consolidate its proceedings under the CON provisions and new Section 6t. If the PSC approves or denies an application for a generation facility under Section 6s that has been submitted as required under Section 6t, Section 6s will prevail in a conflict with Section 6t.

Under the law, 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 include alternative proposals submitted by existing suppliers of electric generation capacity (as described below) or other intervenors. In the case of an application for construction of an electric generation facility of at least 225 megawatts, the bill requires the PSC to issue its order granting or denying the CON concurrently with a final order approving or denying an IRP.

The law requires the PSC to hold a hearing on a CON application, conducted as a contested case, and to allow intervention by interested people. The bill requires the Commission to allow intervention under its rules of practice and procedure. The bill also requires the Commission to allow intervention by existing suppliers of electric generation capacity and people allowed to intervene in the contested case 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 does not apply to a utility that has 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 enters into with an entity that is not affiliated with that utility after the bill's effective date, the PSC must consider and may authorize a financial incentive for the utility that does 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. Previously, the portion of the cost of a plant, facility, or power purchase agreement that exceeded 110% of the cost approved by the PSC was presumed to have been incurred due to a lack of prudence. The bill instead provides that any cost that exceeds the cost approved by the PSC will be presumed to have been incurred due to a lack of prudence.

The bill requires the PSC to disallow costs that it finds were incurred as the result of fraud, concealment, gross mismanagement, or lack of quality controls amounting to gross mismanagement. The PSC also must require refunds with interest to ratepayers of any of these costs already recovered through the utility's rates and charges. If there is a material change in the assumptions underlying an approved CON, other than one approved for a power purchase agreement for the purchase of electric capacity, an electric utility may request, or the Commission may initiate, a proceeding to review whether it is reasonable and prudent to complete an unfinished project for which a CON has been granted. If it finds that completion is no longer reasonable and prudent, the Commission may modify or cancel approval of the CON. Except for costs the PSC finds a utility incurred as the result of fraud, concealment, gross mismanagement, or lack of quality controls amounting to gross mismanagement, if approval is modified or canceled, the Commission may not disallow reasonable and prudent costs the utility already has incurred or committed to by contract. Once the PSC finds that completion of a project is no longer reasonable and prudent, it may limit future cost recovery to those costs that cannot be reasonably avoided.

The bill permits 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. Previously, the PSC was required to allow such cost recovery.

The bill allows 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 is served that seeks 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 is sought. The submitting entity will have standing to intervene and the PSC must allow reasonable discovery in the contested case proceeding. In evaluating an alternative proposal, the PSC must 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 may consider any alternative proposals that are submitted. These provisions do not limit the ability of any other person to submit to the PSC an alternative proposal to the construction, investment, or purchase for which a CON is sought and to petition for and be granted leave to intervene in the contested case proceeding under the Commission's rules of practice and procedure. These provisions also do 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 will be subject to judicial review as provided under the State Constitution and the APA, except that a petition for review must be filed in the Court of Appeals within 30 days after the PSC's order is issued and the Court must 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 was required to begin 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 depends on the utility's achieving targeted policy outcomes.

In the study, the PSC must 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 must 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 uses 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 have extended payback periods.

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

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

Within one year after the bill took effect, the PSC must report and make written recommendations to the Legislature and the Governor based on the result of the study.

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

Capacity Resource Adequacy

Resource Adequacy Tariff & Capacity Mechanism. Under the bill, if MISO receives approval from the Federal Energy Regulatory Commission (FERC) to implement a resource adequacy tariff that provides for a capacity forward auction, and includes the option for a state to implement a prevailing state compensation mechanism for capacity, the PSC must examine whether the prevailing state compensation mechanism will be more cost-effective, reasonable, and prudent than the auction for Michigan, before the Commission may order implementation of the mechanism in any utility service territory in which the mechanism is not yet effective.

(The bill defines "capacity forward auction" as an auction-based resource adequacy construct and the associated tariffs developed by MISO for at least a portion of Michigan for at least three years forward. "Prevailing state compensation mechanism" means an option for a state to elect a prevailing compensation rate for capacity consistent with the requirements of MISO's resource adequacy tariff.)

Before the PSC orders implementation of the mechanism in any utility service territory, it must hold a contested case hearing pursuant to the APA, and allow intervention by interested people, AESs, and customers of AESs and the utility under consideration. At the conclusion of the proceeding, the PSC must make a finding for each service territory under consideration, based on clear and convincing evidence, as to whether the mechanism will be more cost-effective, reasonable, and prudent than the use of the capacity forward auction for Michigan in meeting the local clearing requirement (LCR) and the planning reserve margin requirement.

(As used in these provisions, the bill defines "local clearing requirement" as the amount of capacity resources required to be in the local resource zone in which the electric provider's demand is served to ensure reliability in that zone as determined by MISO for that zone and by the PSC. "Planning reserve margin requirement" means the amount of capacity equal to the forecasted coincident peak demand that occurs when the MISO footprint peak demand occurs plus a reserve margin that meets acceptable loss of load expectation as set by the PSC or MISO. "Electric provider" means 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.)

The contested case must be scheduled for completion by December 1 before MISO's capacity forward auction for Michigan, and the PSC's decision must identify which service territories will be subject to the prevailing state compensation mechanism. If the PSC implements the mechanism, it must be for a minimum of four consecutive planning years unless that period conflicts with the Federal tariff. The PSC must establish the charge as a capacity charge (described below) and determine that charge consistent with MISO's approved resource adequacy tariff.

If MISO receives approval from FERC to implement a resource adequacy tariff that provides for a capacity forward auction and does not include the option for a state to implement a prevailing state compensation mechanism for capacity, the PSC must examine whether a state reliability mechanism will be more cost-effective, reasonable, and prudent than the auction for Michigan, before the Commission may order that mechanism to be implemented in any utility service territory.

("State reliability mechanism" means a plan adopted by the PSC in the absence of a prevailing state compensation mechanism to ensure reliability of the electric grid in Michigan.)

The bill's requirements applicable to the PSC's proceeding regarding a prevailing state compensation mechanism also apply to a proceeding regarding a state reliability mechanism.

If FERC did not put into effect by September 30, 2017, a resource adequacy tariff that included a capacity forward auction or a prevailing state compensation mechanism, the PSC must establish a state reliability mechanism (as described below). If the Commission implements such a mechanism, it must be for a minimum of four consecutive planning years beginning in the upcoming planning year. A state reliability charge must be established in the same manner as a capacity charge and be determined consistent with the bill's requirements. (Please note: The requirement that the PSC establish a state reliability mechanism is in effect.)

Capacity Charge & Capacity Obligations. The bill requires the PSC to establish a capacity charge. A determination of the charge must be conducted as a contested case under the APA after interested people are given notice and a reasonable opportunity for a full and complete hearing, and must conclude by December 1 of each year. The PSC must allow intervention by interested people, AESs, and customers of AESs and the utility under consideration. The PSC must provide notice to the public of the single capacity charge as determined for each territory. No new capacity charge will have to be paid before June 1, 2018. The charge must be applied to alternative electric load that is not otherwise exempt. If the PSC elects to implement a capacity forward auction for Michigan, a capacity charge will not apply beginning in the first year that the auction is effective. In order to ensure that noncapacity electric generation services are not included in the charge, in determining the charge, the PSC must do both of the following for the applicable term of the capacity charge and ensure that the resulting charge does not differ for full service load and AES load:

-- Include the capacity-related generation costs included in the utility's base rates, surcharges, and power supply cost recovery factors, regardless of whether those costs result from utility ownership of the capacity resources or their purchase or lease from a third party.

-- Subtract all noncapacity-related electric generation costs, including costs previously set for recovery through net stranded cost recovery and securitization and the projected revenue, net of projected fuel costs, from all energy market sales, off-system energy sales, ancillary service sales, and energy sales under unit-specific bilateral contracts.

The PSC must provide for a true-up mechanism that results in a utility charge or credit for the difference between the projected net revenue and the actual net revenue reflected in the capacity charge. The true-up must be reflected in the capacity charge in the subsequent year.

At least once a year, the PSC must review or amend the capacity charge in all subsequent rate cases, power supply cost recovery cases, or separate proceedings established for that purpose.

A capacity charge may not be assessed for any portion of capacity obligations for each planning year for which an AES can demonstrate that it can meet its capacity obligations through owned or contractual rights to any resources that MISO allows to meet the electric provider's capacity obligation. This provision may not be applied in any way that conflicts with a Federal resource adequacy tariff, when applicable. Any electric provider that has previously demonstrated that it can meet all or a portion of its capacity obligations must notify the PSC by September 1 four years before the beginning of the applicable planning year if it does not expect to meet that obligation and instead expects to pay a capacity charge. The charge in the utility service territory must be paid for the portion of the utility's load taking service from the AES not covered by capacity during the period that the charge is effective.

An electric provider must provide capacity to meet the capacity obligation for the portion of that load taking service from an AES in the provider's service territory that is covered by a capacity charge during the period that the charge is effective. The AES will be obligated to provide capacity for the portion of the load for which it has demonstrated an ability to meet its capacity obligations. If an AES ceases to provide service for some or all of its load, it must allow, at a cost not higher than the determined capacity charge, the assignment of any right to that capacity in the applicable planning year to whatever electric provider accepts that load.

State Reliability Mechanism & Demonstration of Capacity. Under the bill, if a state reliability mechanism is required to be established, the PSC must require each electric utility, AES, and cooperative or municipally owned electric utility to demonstrate annually to the PSC that for the planning year beginning four years after the beginning of the current planning year, the utility or AES owns or has contractual rights to sufficient capacity to meet its capacity obligations as set by MISO or the PSC, as applicable. An electric utility must make this determination by December 1 of each year and an AES or cooperative or municipally owned utility must make it by the seventh business day of February.

A cooperative or municipally owned electric utility may meet this requirement through any resource, including one acquired through a capacity forward auction, that MISO allows to qualify for meeting the LCR. A cooperative or municipally owned utility's payment of an auction price related to a capacity deficiency as part of a MISO auction will not by itself satisfy the bill's resource adequacy requirements unless MISO can tie that payment directly to a capacity resource that does meet the requirements.

By the seventh business day of 2018, an AES must demonstrate to the PSC that for the planning year beginning June 1, 2018, and the subsequent three planning years, the AES owns or has contractual rights to sufficient capacity to meet its capacity obligations as set by MISO or the PSC, as applicable.

If the PSC finds that an electric provider has failed to demonstrate that it can meet some or all of its capacity obligation, the PSC will have to do all of the following:

-- For alternative electric load, require the payment of a capacity charge that is determined, assessed, and applied as prescribed in the bill for that portion of the load not covered.

-- For a cooperative or municipally owned electric utility, recommend to the Attorney General that suit be brought to require procurement.

-- For an electric utility, require any audits and reporting the Commission considers necessary to determine if sufficient capacity is procured.

With regard to alternative electric load, if a capacity charge is required to be paid in the planning year beginning June 1, 2018, or any of the three subsequent planning years, the charge will apply for each of those planning years.

If an electric utility fails to meet its capacity obligations, the PSC may assess appropriate and reasonable fines, penalties, and customer refunds under the law.

If an electric provider fails to demonstrate that it can meet a portion or all of its capacity obligation, in order to determine the capacity obligations, the PSC will have to request that MISO provide technical assistance in determining the LCR and planning reserve margin requirement. If MISO declines or does not make a determination by October 1 of that year, the PSC will have to set any required LCR and planning reserve margin requirement, consistent with Federal reliability requirements. In order to determine if resources put forward will meet Federal reliability requirements, the PSC also will have to request technical assistance from MISO to assist with assessing resources to ensure that any resources will meet those requirements. If the assistance is rendered, the PSC will have to accept MISO's determinations unless it finds adequate justification to deviate from them related to the qualification of resources. If MISO declines, or does not make a determination by February 28, the PSC will have to make those determinations.

The PSC may not permit a capacity charge to be assessed for any year in which it has elected the capacity forward auction instead of the prevailing state compensation mechanism or the state reliability mechanism.

The bill states that nothing in the PSC law prevents the Commission from determining a generation capacity charge under the Reliability Assurance Agreement, Rate Schedule FERC No. 44 of the independent system operator known as PJM Interconnection, LLC, as approved by FERC, or a similar successor tariff.

Civil Action. The bill allows the Attorney General or any customer of a municipally owned or cooperative electric utility to commence a civil action for injunctive relief against the utility if it fails to meet the applicable requirements related to resource capacity. The Attorney General or customer may not file an action without giving 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 must meet and make a good-faith attempt to determine whether there is a credible basis for the action. The utility must take all reasonable and prudent steps necessary to comply with the bill's requirements within 90 days after the meeting if there is a credible basis for the action. If the parties do not agree as to whether there is a credible basis, the Attorney General or customer may proceed to file the suit.

Shared Savings Mechanism

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

For an electric utility that achieves 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 will be 25% 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 may not exceed 15% of the utility's expenditures associated with implementing energy waste reduction programs for the year in which the mechanism is authorized.

For an electric utility that achieves 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 will be 27.5% 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 may not exceed 17.5% of the utility's expenditures associated with implementing energy waste reduction programs for the year in which the mechanism is authorized.

For an electric utility that achieves annual electric savings greater than 1.5% of the total annual weather adjusted retail sales in the previous year, the shared savings incentive will be 30% 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 may not exceed 20% of the utility's expenditures associated with implementing the programs for the year in which the mechanism is authorized.

Customer Choice and Electricity Reliability Act

Title. Sections 10 through 10bb of the PSC law previously were known as the "Customer Choice and Electricity Reliability Act". The bill deleted this title (although the following provisions refer to these sections as the Act).

Purpose. The bill deleted 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.

Under the bill, another stated purpose of the Act is to ensure that all people in the State are afforded safe, reliable electric power at a competitive rate. The Act previously referred to a reasonable rate.

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 applies except as described below.

The orders also must set forth procedures necessary to 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 Act previously required procedures necessary to administer as well as allocate that amount of load.

Also, the bill deleted requirements 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 be given next priority with the remaining available load, if any, allocated on a first-come, first-served basis. The PSC could not allocate additional energy allotments at any time when the total annual allotments for the utility's distribution service territory were greater than 10% of the utility's weather-adjusted retail sales in the calendar year preceding the date of allocation.

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 retains this provision.

The bill requires the orders to provide that, if the PSC determines that less than 10% of an electric utility's average weather-adjusted retail sales for the preceding year are taking service from AESs, the Commission must set as a cap on those sales that may take service from an AES, for the current year and five subsequent years, the percentage amount of those sales for the preceding year rounded up to the nearest whole percentage. If the cap is not adjusted for six consecutive years, it will return to 10% in the year following that sixth year. If a utility that serves fewer than 200,000 Michigan customers does not have any load served by an AES in the preceding four years, the PSC must adjust the cap in accordance with the bill for not more than two consecutive years.

The bill also requires the orders to provide that for an existing facility receiving 100% of its electric service from an AES on or after the bill's effective date, the facility owner may purchase electricity from an AES, regardless of whether the sales exceed 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 is similar in nature to the existing facility, that is constructed or acquired by the customer on a site that is 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 owns more than 50% of that facility. This provision does 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.

Under the Act, the orders must provide that any customer operating an iron ore mining and/or processing facility located in the Upper Peninsula may purchase some or all 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 applies if the customer is 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 provides electric service to the customer will 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 will remain in effect with regard to retail open access provided under these provisions.

The bill requires 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, will continue on the queue and an electric utility must add a new customer to the queue if the customer's prospective AES submits an enrollment request to the utility. A customer must be removed from the queue if the customer notifies the utility electronically or in writing.

Additionally, the bill requires the orders 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 must include the estimated amount of electricity used by each customer in the queue. All customer-specific information is exempt from the Freedom of Information Act, and the PSC must treat it as confidential. The Commission may release aggregated information as part of its annual report as long as individual customer information or data are not released.

The bill also requires the orders to provide that if the prospective AES of a customer next on the queue is notified after the bill's effective date that less than 10% of an electric utility's average weather-adjusted retail sales are taking services from an AES and that the amount of electricity needed to serve the customer's electric load is available under the 10% allocation, the customer may take service from an AES. The prospective AES must notify the utility within five business days after being notified whether the customer will take service from an AES. If the prospective AES fails to notify the utility or the customer chooses not to take retail open access service, the customer must be removed from the queue and subsequently may be added to it as a new customer. A customer that elects to take service from an AES must become service-ready under rules established by the PSC and the utility's approved retail open access service tariffs.

In addition, the bill requires the orders to provide both of the following:

-- The PSC will ensure that, if a customer is notified that the customer's service from an AES will be terminated or restricted because the AES is limiting service in Michigan, the customer will have 60 days, or 180 days in the case of a customer that is a public entity, to acquire service from a different AES.

-- As a condition of licensure, an AES must meet all of the bill's requirements for generation capacity.

Electric Utility Code of Conduct. The Act required the PSC to establish a code of conduct applicable to all electric utilities. The bill requires the PSC to establish a code of conduct that applies to all utilities. As previously required, 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.

Appliance Service Program & Value Added Programs. The Act previously allowed 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, steam, or natural gas utility regulated by the PSC may offer its customers value-added programs and services if they do not harm the public interest by unduly restraining trade or competition in an unregulated market. A utility must notify the PSC of its intent to offer these programs and services before offering them to its customers. The bill defines "value-added programs and services" as programs and services 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 does not include energy optimization or energy waste reduction programs paid for by utility customers as part of their regulated rates.

Previously, a utility offering an ASP had to 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 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 must report annually to the Commission on how all of the utility's costs associated with the unregulated value-added program or service are allocated to that program or service. The report must show the extent to which the utility's rates are affected by the allocations. The utility may include this report as part of a request for rate relief. The bill also requires the utility to give the Commission written notice and a description of any newly offered value-added program or service.

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

The bill authorizes the PSC to initiate informal proceedings to determine if any value-added program or service violates the bill's provisions. If the PSC determines that a potential violation exists, it must conduct formal proceedings to determine whether a violation has occurred and order corrective actions. An informal proceeding is not required as a prerequisite to a formal complaint.

The Act stated that it did not prohibit the PSC from requiring a utility to include revenue from an ASP in establishing base rates. If the PSC included this revenue, the Commission also had to include all of the program's costs. The bill deleted these provisions. Instead, except as otherwise provided, the Commission may include only the revenue received by the utility to recover costs directly attributable to a value-based program or service in determining the utility's base rates. The utility must file with the Commission the percentage of additional revenue over the amount that is allocated to recover costs directly attributable to a value-added program or service that the utility wishes to include as an offset to its base rates. Following a notice and hearing, the Commission must 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, the bill requires an electric utility to pay all reasonable costs incurred by the prevailing party.

An electric utility that offers value-added programs or services must file with the PSC an annual report that provides 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 are apportioned between them and the utility. The utility must certify to the PSC that it is complying with these requirements. The PSC may conduct an audit of the utility's books and records and the value-added programs and services to ensure compliance.

Service Shutoff. The bill authorizes 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 438 added Part 7 to that Act to allow an electric provider to establish a residential energy projects program under which property owners may finance energy projects through an itemized charge on their utility bills.)

If a customer fails to comply with the applicable terms and conditions, an electric utility may 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 has not paid the per-meter charge for a residential energy projects program.

-- That, unless the customer makes the past due payments within 10 days of the date of mailing, the utility or AES may 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 appropriated 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 applies to a steam utility (a steam distribution company regulated by the PSC).

The bill requires 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 may 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.

Under the bill, when filing or 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 may 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 must make a finding and enter an order granting or denying the relief within 180 days after the motion is submitted. The Commission will have 12 months to issue a final order.

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

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 refers to the cost of purchased steam.

Time Frame for PSC Decision. As amended by the bill, 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 the period of time allotted by law to issue a final order after the filing of the complete petitions or applications (rather than within a period of 12 months from the filing of the complete petitions or applications).

Except as otherwise provided, if the PSC fails to reach a final decision within 10 months, the petition or application is considered approved. If a utility makes any significant amendment to its filing, the PSC has an additional 10 months from the date of the amendment to reach a final decision. Previously, in both cases, the time frame was 12 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 refers to the cost of purchased steam.

Energy Savings Decoupling Mechanism. The bill requires the PSC, upon request by an electric utility with fewer than 200,000 Michigan customers, to approve an appropriate revenue decoupling mechanism that adjusts for decreases in actual sales compared to the projected levels used in the utility's most recent rate case, if the utility first demonstrates the following to the Commission:

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

-- That the utility has 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.

The PSC must consider the aggregate revenue attributable to the revenue decoupling mechanisms, financial incentives, and shared savings mechanisms the Commission has approved for an electric utility relative to energy waste reduction, conservation, demand-side programs, peak load reduction, and other waste reduction measures. The PSC may approve an alternative methodology for a decoupling mechanism, a financial incentive authorized under the Clean and Renewable Energy and Energy Waste Reduction Act, or a shared savings mechanism if it determines 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 are not disfavored when compared to utility supply-side investments. The PSC's consideration of an alternative methodology must be conducted as a contested case pursuant to the APA.

Net Metering/Distributed Generation Tariff. Within one year after the bill took effect, the PSC must conduct a study on an appropriate tariff reflecting equitable cost of service for utility revenue requirements for customers who participate in a net metering or distributed generation program under the Clean and Renewable Energy and Energy Waste Reduction Act. In any rate case filed after June 1, 2018, the PSC will have to approve such a tariff for inclusion in the rates of all participating customers. The tariff will not apply to customers participating before establishment of the tariff who continue to participate at their current site or facility.

"Utility" and "electric utility" do 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. A PSCR clause 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 requires the description to include whether the supply contracts or arrangements include long-term firm gas transportation and, if not, an explanation of how the utility proposes to ensure reliable and reasonably priced gas fuel supply to its generation facilities during the 12-month period. The bill defines "long-term firm gas transportation" as a binding agreement entered into between the electric utility and a natural gas transmission provider for a set period of time to provide firm delivery of natural gas to an electric generation facility.

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.

Previously, in its reconciliation order, the PSC was required to disallow any capacity charges associated with power purchased for periods longer than six months unless the utility had obtained the Commission's prior approval. The bill deleted this requirement.

Reevaluation of PSC Order

Under the bill, notwithstanding any existing power purchase agreement, at least every five years, the PSC must 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 does not supersede the provisions of PURPA or the Federal Energy Regulatory Commission's regulations and orders implementing PURPA.

The bill defines "qualifying facility" or "facilities" as 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 bill allows the PSC to 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 must conduct the periodic reevaluation in a contested case under the APA if a qualifying facility files a comment disputing the utility filing and requesting a contested case.

An order issued by the PSC under these provisions must do all of the following:

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

-- Ensure that an electric utility does 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 are 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 must 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 must 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.

Utility Consumer Participation Board

Under the law, 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 previously applied only to utilities serving at least 100,000 Michigan customers and utilities serving at least 100,000 residential Michigan customers.

The bill requires the amount of money 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 will become the new base amount to which the CPI factor applies in the following year.

The bill deleted a requirement that a utility remit to the Board in subsequent years an amount equal to five-sixths of the amount prescribed.

Under the law, the money remitted by utilities serving at least 100,000 residential customers in Michigan 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 money submitted by the other utilities serving at least 100,000 Michigan customers must be made available to the Attorney General for various administrative and judicial proceedings under the PSC law. Under the bill, the money remitted by the remaining utilities also must be used for grants.

With regard to the grant program, the bill requires each applicant to identify on the application any additional funds or resources, other than the grant funds being requested, that are to be used to participate in the proceeding for which the grant is being requested and how those funds or resources will be used. For the purposes of making grants, the law allows the Board to 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 also permits the Board to consider energy waste reduction, demand response, and rate design options to encourage energy conservation, waste reduction, and demand response.

Under the bill, the criteria the Board must consider and balance in determining whether to make a grant to an applicant are expanded to include the anticipated involvement of the Attorney General in a proceeding and whether the applicant's activities will 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 must 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 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 allows 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).

Amounts that have been in the Fund for more than 12 months may be retained in the Fund for future grants or (under the bill) proceedings, or may be returned to utility companies or used to offset their future remittances to the Fund, as the Board and (under the bill) the Attorney General determine will best serve the interests of consumers. The bill requires any unspent money to be reserved to fulfill the purposes for which it is appropriated, and permits the money to be refunded to utility companies or used to offset future remittances.

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

The law requires the Board to coordinate the funded activities of grant recipients with those of the Attorney General to avoid duplication of effort. The bill adds, "particularly as it relates to the hiring of expert witnesses".

The bill requires 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.

The law requires a grant recipient to 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 must 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 requires 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 establishes the Ombudsman in the Michigan Agency for Energy. The individual serving as the Ombudsman must 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 must 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 must 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 the State.

-- 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 bill requires the PSC to ensure the establishment of electric rates equal to the cost of providing service to each customer class. If the PSC determines that the impact of imposing cost of service rates on customers of an electric utility will have a material impact on customer rates, the Commission may approve an order that implements the rates over a suitable number of years. (Previously, these requirements applied to electric utilities serving fewer than 1.0 million retail customers in Michigan.) In establishing cost of service rates, the Commission must ensure that each class or sub-class is assessed for its fair and equitable use of the electric grid.

In addition, the bill requires the PSC to ensure that the cost of providing service to each customer class is 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 50-25-25 100% demand method of cost allocation. The Commission may modify this method if it determines that the method does not ensure that rates are equal to the cost of service.

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

The law permits 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. The law requires the PSC to 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.

Previously, these provisions applied only to electric utilities with at least 1.0 million retail customers in the State.

Other Provisions

The bill prohibits a covered utility from discontinuing service to a geographic area the utility serves without first filing an abandonment application with the PSC and obtaining Commission approval to discontinue the service after notice and a contested case proceeding. The bill defines "covered utility" as any of the following:

-- A cooperative electric utility subject to the PSC's jurisdiction for its service area, distribution performance standards, and quality of service.

-- A rural gas cooperative.

-- An electric, natural gas, or steam utility subject to the PSC's rate-making jurisdiction.

At least 30 days after it files a proposal to retire an electric generating plant with a regional transmission organization, an electric utility must give that proposal in its entirety to the PSC.

At least 60 days before an electric utility applies to the Operating Reliability Subcommittee of the North American Electric Reliability Corporation for approval of a proposal to revise an existing load balancing authority, the utility must file with the PSC a full and complete report of the proposed revision and serve a copy of the report on all other electric utilities in Michigan

Senate Bill 438

Purpose

As amended by the bill, the purpose of the Clean and Renewable Energy Act and Energy Waster Reduction is to promote the development and use of clean and renewable energy resources and the reduction of energy waste through programs 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 waste reduction.

-- Coordinate with Federal regulations to provide improved air quality and other benefits to energy consumers and citizens.

-- Remove unnecessary burdens on the appropriate use of solid waste as a clean energy source.

Previously, the purpose of the Clean, Renewable, and Efficient Energy Act was to promote the development of clean energy, renewable energy, and energy optimization through the implementation of a clean, renewable energy efficient standards that would cost-effectively do generally the same things.

The bill defines "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 does not include electric provider infrastructure projects that are approved for cost recovery by the PSC other than as provided in the Act.

Previously, the term "energy optimization" had generally the same definition. Where the Act had referred to "optimization", the bill refers to "waste reduction".

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 energy waste reduction and renewable energy are the most reasonable means of meeting an electric utility's energy and capacity needs relative to other resource options. Both of the following will 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 any banked renewable energy credits, that counted toward the renewable energy standard under the law on the bill's effective date, as well as 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.

Repealed Sections: Renewable Energy

The bill repealed sections of the PSC law that did the following:

-- Required electric providers whose rates are regulated by the PSC, alternative electric suppliers, cooperative electric utilities, and municipally owned electric utilities to file with the PSC a renewable energy plan that, among other things, described how the provider would meet the Act's renewable energy standard.

-- Provided for PSC approval of a plan.

-- Required an electric provider to achieve a renewable energy credit portfolio under which 10% of the provider's energy had to come from renewable resources by 2015, and required an electric provider with 1.0 million or more retail customers in the State also to achieve a renewable energy credit capacity portfolio (based on megawatts) by December 31, 2015.

-- Allowed the PSC to grant two one-year extensions of the 2015 deadline.

-- Described how renewable energy credits were to be obtained by an electric provider with 1.0 million or more retail customers in the State.

-- Required the PSC to make certain determinations if a rate-regulated electric provider entered into a renewable energy contract or a contract to purchase renewable energy credits without the associated renewable energy.

-- Required one advanced cleaner energy credit to be granted for each megawatt hour of electricity generated from an advanced cleaner energy system, and required the PSC to establish an advanced cleaner energy credit certification and tracking program.

-- Required a rate-regulated electric provider to purchase renewable energy credits if it failed to meet a renewable energy credit standard by the applicable deadline, and provided for other consequences.

-- Provided for the location of advanced cleaner energy systems that were the source of advanced cleaner energy credits.

Renewable Energy Plans

Plan Criteria; Approval. As noted above, 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 described how the electric provider would meet the Act's renewable energy standard.

"Renewable energy standard" means the minimum renewable energy capacity portfolio, if applicable, and the renewable energy credit portfolio required to be achieved under a former section of the Act or under the bill. "Renewable energy credit portfolio" means the sum of the renewable energy credits achieved by a provider for a particular year.

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, remain in effect, subject to amendments described below.

For an electric provider whose rates are regulated by the PSC, amended renewable energy plans must establish a nonvolumetric mechanism for the recovery of incremental costs of compliance within the provider's customer rates. The mechanism may not result in rate impacts that exceed 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 is subject to adjustment as provided in the Act.

Within one year after the bill's effective date, the PSC must review each electric provider's plan pursuant to a filing schedule established by the Commission. For a provider whose rates are regulated by the Commission, it must conduct a contested case hearing. Afterward, the PSC must approve, with any changes the provider consents to, or reject the plan and any amendments to it. For all other electric providers, the Commission must provide an opportunity for public comment on the plan. The PSC then must determine whether any amendment to the plan proposed by the provider complies with the Act. For AESs, the Commission must approve, with any changes the provider consents to, or reject any proposed amendments to the plan. For cooperative and municipally owned utilities, the proposed amendment will be adopted if the PSC determines that it complies with the Act.

If an electric provider proposes to amend its renewable energy plan after the review process, the provider must file the proposed amendment with the PSC. For a provider whose rates are regulated, if the proposed amendment will modify the revenue recovery mechanism, the PSC must conduct a contested case hearing. After the hearing and within 90 days after the amendment is filed, the PSC must approve, with any changes the provider consents 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 is filed, the PSC must determine whether the proposed amendment complies with the Act. For AESs, the PSC must approve, with any changes consented to by the provider, or reject any proposed amendments. For cooperative and municipally owned utilities, the proposed amendment will be adopted if the PSC determines that it complies with the Act.

For an electric provider whose rates are regulated, the PSC must approve the plan or amendments to it, if the Commission determines that the plan is reasonable and prudent, and is consistent with the Act's prescribed purpose and the 35% renewable energy goal and meets the prescribed renewable energy credit standard through 2021. In determining whether the plan is reasonable and prudent, the PSC must consider projected costs and whether projected costs in prior plans were exceeded.

If the PSC rejects a proposed renewable energy plan or amendment, it must explain in writing the reasons for its determination.

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

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

-- In 2019 through 2020, a portfolio of at least 12.5%.

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

(As noted above, the Act defines "renewable energy credit portfolio" as the sum of the renewable energy credits achieved by a provider for a particular year.)

The bill requires an electric provider's renewable energy credit portfolio to be calculated by determining the number of renewable energy credits used to comply with these requirements during the applicable year. That number must 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 must be multiplied by 100.

Each electric provider must 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 generation systems that use at least one renewable energy resource to generate electricity or, under the bill, to generate steam. 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, wind power, or, under the bill, a geothermal heat pump. The term also includes municipal solid waste, landfill gas produced by municipal solid waste, and, under bill, fuel that has been manufactured from waste, including municipal solid waste, and excluding pet coke, hazardous waste, coal waste, and scrap tires.)

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

The bill allows a provider to substitute energy waste reduction credits for renewable energy credits otherwise required to meet the renewable energy credit standards if the PSC approves the substitution. One energy waste reduction credit must be granted to an electric provider for each megawatt hour of annual incremental energy savings achieved through energy waste reduction. A provider may not use energy waste reduction credits to meet more than 10% of the renewable energy credit standard. One renewable energy credit must 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 requirement does 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, Ohio, or Wisconsin to a municipally owned or cooperative electric utility in Michigan, and the electricity is not being used to meet another state's standard for renewable energy. (Previously, this provision did not include an entity in Ohio, although a similar exception applied to electricity generated from a renewable energy system that was sold by a nonprofit entity located in Ohio to a municipally owned electric utility in Michigan. Also, the bill deleted a requirement that the electricity be sold by a not-for-profit entity under a contract in effect on January 1, 2008.)

Except as otherwise provided, the Act requires one renewable energy credit to 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. The bill refers to steam in addition to electricity.

The Act provides for additional renewable energy credits, known as Michigan incentive renewable energy credits, to be granted under certain circumstances. These include two credits for each megawatt hour of electricity from solar power. Under the bill, this electricity must be generated by a renewable energy system that was approved in a renewable energy plan before the bill's effective date.

Previously, a renewable energy credit expired at the earliest of the following:

-- 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.

Under the bill, a renewable energy credit expires at the earliest of the following:

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

-- When substituted for an energy waste reduction credit.

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

-- When an electric provider whose rates are regulated by the PSC uses it to contribute to achievement of the 35% renewable energy goal.

The bill deleted 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 also deleted a provision under which a renewable energy credit could 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.

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 required a member-regulated cooperative electric utility or municipally owned electric utility to file such a plan by April 2, 2009. The Act stated that the overall goal of an energy optimization plan was 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 remain in effect, subject to any amendments, as energy waste reduction plans. The bill expands the goal of a plan to include helping the provider's customers reduce energy waste. Generally, the previous provisions that applied to energy optimization plans 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. 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 includes 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 contained provisions applicable to the filing, review, and approval of an electric or natural gas provider's energy optimization plan. The bill refers to an energy waste reduction plan rather than an energy optimization plan.

The Act required an energy optimization plan to be enforced subject to the same procedures applicable to a renewable energy plan. Under the bill, the energy waste reduction plan of a provider whose rates are regulated by the PSC must be enforced by the Commission. For a provider whose rates are not regulated, the plan must be enforced through a civil action (described below). Notwithstanding any other provision related to energy waste reduction plans, the PSC must 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.

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

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

If it rejects a proposed plan or amendment, the PSC must explain in writing the reasons for its determination.

After December 31, 2021, these provisions will not apply to an electric provider whose rates are not regulated by the PSC.

Cost Reconciliation. The bill requires the PSC to commence as a contested case an annual proceeding known as an energy waste reduction cost reconciliation for each rate-regulated provider (similar to requirements in the Act for an annual renewable cost reconciliation). Reasonable discovery must be permitted before and during the reconciliation to assist in obtaining evidence concerning reconciliation issues, including the reasonableness and prudence of expenditures and the amounts collected pursuant to energy waste reduction charges set by the PSC. At the reconciliation, a provider may propose any necessary modifications of the charges previously set by the Commission to ensure the provider's recovery of its costs to comply with the energy waste reduction standards.

The PSC must reconcile the pertinent revenue recorded with the amounts actually expensed and projected according to the provider's plan for compliance. The PSC must consider any issue regarding the reasonableness and prudence of expenses for which customers were charged in the relevant reconciliation period. In its order, the PSC must determine a provider's compliance with the energy waste reduction standards and, if necessary, adjust the previously set energy waste reduction charges.

Provider Incentives. Under the bill, as previously provided for an energy optimization plan, the energy waste reduction 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 waste reduction standard. Payment of such an incentive is subject to the PSC's approval.

Previously, the total amount of the incentive could 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 revised the amount of the incentive based on the amount of incremental energy savings a provider achieves in one year, as described below.

For an electric provider that achieves annual incremental savings of greater than 1.5% of its total annual retail electricity sales in megawatt hours in the preceding year or a natural gas provider that achieves annual incremental savings of greater than 1% of its total annual retail gas sales in decatherms in the preceding year, the financial incentive is limited to the lesser of 30% of the net present value (NPV) of life-cycle cost reductions experienced by customers due to plan implementation during the year for which the incentive is paid, or 20% of the provider's actual program expenditures for the year.

For an electric provider that achieves annual incremental savings of greater than 1.25% but not greater than 1.5% of its total annual retail sales in the preceding year or a natural gas provider that achieves annual incremental savings of greater than 0.875% but not greater than 1% of its total annual retail sales in the preceding year, the total amount of the financial incentive may not exceed the lesser of 27.5% of the NPV of life-cycle cost reductions experienced by customers as a result of plan implementation during the year for which the incentive is paid, or 17.5% of the provider's actual energy waste reduction program expenditures for the year.

For an electric provider that achieves annual incremental savings of at least 1% but not greater than 1.25% of its total annual retail sales in the preceding year or a natural gas provider that achieves annual incremental savings of at least 0.75% but not greater than 0.875% of its total annual retail sales in the preceding year, the total amount of the incentive may not exceed the lesser of 25% of the NPV of life-cycle cost reductions experienced by customers as a result of plan implementation during the year for which the incentive is paid, or 15% 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 annual incremental energy savings in 2015 and each year after that had to be equivalent to 1% of total annual retail electricity sales in megawatt hours in the preceding year. Under the bill, a provider's energy waste reduction programs must achieve that level of incremental savings every year through 2021.

Under the bill, 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 actual expenditures for implementing the provider's approved waste reduction plan and the load management expenditures remains constant. (Previously, the Act contained this requirement but referred to "maximum" rather than "actual" expenditures.)

The bill retains 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.

Energy Waste Reduction Plan Amendment. By January 1, 2022, and then every two years, the bill requires a rate-regulated electric provider to file with the PSC, pursuant to a filing schedule established by the Commission, an energy waste reduction plan amendment detailing the amount of energy waste reduction it proposes to achieve for the next two years. If the provider proposes a reduction level that differs from the level specified in the provider's current plan, the PSC may approve the proposed level if the Commission finds that it is the most reasonable and prudent. If the Commission finds that a proposed lower reduction level is not the most reasonable and prudent, the level of waste reduction to be achieved for the next two-year period must 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 cannot not achieve the energy waste reduction standard in a cost-effective manner, the bill allows the provider to petition the PSC in a contested case hearing to establish an alternative energy waste reduction level for that provider.

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

The Act contained similar provisions allowing a provider to petition the PSC for alternative energy optimization standards that applied 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 retains these provisions but refers to waste reduction rather than energy optimization. The provisions concerning these particular electric providers will be repealed on January 1, 2022.

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

In addition, the Act required the PSC to establish an energy optimization credit tracking system.

The bill retains these provisions but refers to waste reduction rather than optimization.

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

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. The bill deleted a requirement that the charge be applied to utility bills as an itemized charge. Instead, these charges may be itemized on utility bills until January 1, 2021. The bill allows fixed, per-meter charges to vary by rate class.

The bill deleted certain cost recovery limits that applied to different customer classes based on total retail sales revenue.

Waste Reduction Program Administrator. Previously, many of the Act's energy optimization requirements did not apply to an electric or natural gas provider that paid 2% of total utility sales revenue each year to an independent energy optimization program administrator selected by the PSC. Under the bill, many of the energy waste reduction requirements do not apply to an electric or natural gas provide that pays 2% of total utility sales revenue for the second year preceding to an independent energy waste reduction program administrator.

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. The bill deleted a requirement that the charges be applied to utility bills. Instead, the charges may be itemized on utility bills until January 1, 2021. The bill allows fixed, per meter charges to vary by rate class.

The bill deleted a requirement that money unspent by the program administrator in a year be carried forward to be spent in the subsequent year.

Load Management: Voluntary Shut-Down. The Act requires the PSC to promote load management in appropriate circumstances. Under the bill, this includes expansion of existing and establishment of new load management programs in which an electric provider may 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 have advanced metering infrastructure. Provider participation and customer enrollment in such programs must be voluntary; however, rate-regulated providers whose rates include the cost of advanced metering infrastructure must offer Commission-approved demand response programs. The programs may provide incentives for customer participation and must include customer protection provisions as required by the PSC. To participate in a program, a customer must agree to remain in it for at least one year.

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

The bill provides that the load management provisions may 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 requires the Michigan Agency for Energy, rather than the PSC, to 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.

The bill also deleted a requirement that the PSC submit to the Legislature an annual report on the effort to implement energy conservation and efficiency programs or measures.

Suspension of Waste Reduction Program. Under the Act, 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. The provider then 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 will not apply to an electric provider beginning January 1, 2022.

Civil Action. The bill allows 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 fails to meet the applicable energy waste reduction requirements or a related order or rule.

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

Distributed Generation & Net Metering

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

An electric customer of any class will 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 must 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 previously applied to a net metering program authorized under the Act, but each customer's generation capacity was limited to the customer's electric needs. The distributed generation program replaces the net metering program, and is subject to many of the provisions already in the Act.

Previously, an electric utility or AES was not required to allow for net metering that was greater than 1% of its in-State peak load for the preceding calendar year. Under the bill, an electric utility or AES does not have to allow for a distributed generation program that is greater than 1% of its average in-State peak load for the preceding five years. The 1% limit must 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 bill authorizes the PSC to promulgate rules that require the use of inverters that perform specific automated grid-balancing functions to integrate distributed generation onto the electric grid. Electric utilities may own and operate inverters that interconnect distributed generation resources.

The bill permits an electric utility or AES to charge a maximum fee of $50 to process an application to participate in the distributed generation program. (The fee to apply for net metering was $100.) As formerly required, the customer must pay all interconnection costs. The bill deleted a requirement that a customer pay standby costs if the customer had a system capable of generating more than 20 kilowatts.

The bill requires the use of electric meters 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 must 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 must pay the costs of installing any new meters. An electric utility serving more than 1.0 million customers in Michigan is 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.

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

Under the bill, if the quantity of electricity generated and delivered to the utility distribution system by an eligible generator during a billing period exceeds the quantity of electricity supplied from the utility or AES during that period, a supplier of electric generation service must 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 must be carried forward to subsequent billing periods.

Notwithstanding any law or regulation, distributed generation customers may 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 must 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 former net metering program was calculated similarly.)

A charge for net metering and distributed generation established under Senate Bill 437 may 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 PSC established a tariff under Senate Bill 437 may 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 does not apply to an increase in the generation capacity of the customer's eligible generator beyond the capacity on the bill's effective date.

Senate Bill 438 specifies that, notwithstanding any other provision of the Act, the Act does not limit or restrict an industrial customer's ability to build, own, or operate, or have a third party build, own, and operate one or more self-generation or cogeneration facilities, and none of the Act's distributed generation provisions may be construed or interpreted to apply to such facilities.

Voluntary Green Pricing Program

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

If an electric provider has not yet fully recovered the incremental costs of compliance, a customer that receives at least 50% of that customer's average monthly electricity consumption through the program is 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 will receive less than 50% of average monthly consumption through the program, the provider must notify the customer that the customer is 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

Previously, in its billing statements for a residential customer, each provider had 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 eliminated this requirement.

Renewable Energy Plan Costs; 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. As amended by the bill, "advanced cleaner energy system" means any of the following:

-- A gasification facility.

-- A cogeneration facility (rather than 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 defines "cogeneration facility" as 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.

The bill also includes a coal-fired electric generating facility in the definition of "advanced cleaner energy system" if at least 85% of the emissions are used for other commercial or industrial purposes that do 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 requires the PSC to determine that the technology has carbon dioxide emissions benefits or will significantly reduce other regulated air emissions.

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

Exemption from Energy Standards

Under the Act, 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 eliminates the exemption for electricity effective January 1, 2021.

Residential Energy Improvements

The bill added 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 obtains financing or refinancing of an energy project on the property from a commercial lender or other legal entity, the loan will be repaid through itemized charges on the provider's utility bill for that property. The charges may 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 owner incurs for the installation on a specific or pro rata basis, as determined by the provider.

The bill defines "energy project" as 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 may be established and implemented only pursuant to a plan approved by the PSC. A provider seeking to establish a program must file a proposed plan with the Commission. A plan must include the following:

-- The estimated costs of program administration.

-- Whether the program will 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 may not approve a provider's proposed plan unless it determines that the plan is reasonable and prudent. If the PSC rejects a proposed plan, it must explain its reasons in writing. Every four years after initial approval of a plan, the PSC must review it.

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

Electric or natural gas service may 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 is recorded with the county register of deeds, the obligation to pay the charge will 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 may not exceed the anticipated useful life of the energy project financed by the loan or 180 months, whichever is less. The loan must be repaid in monthly installments.

The PSC must promulgate rules to implement Part 7 within one year after the bill takes effect. Every five years after promulgating the rules, the PSC must 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 may be combined with the PSC's annual report summarizing its activities over the preceding year.

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

Reporting Requirements

Section 155 of the Act required the PSC to 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 repealed this section.

Section 51 requires each electric provider to report annually to the PSC on actions taken to comply with the renewable energy standards, and specifies the information that a report must include. The PSC is required to submit to the Governor and the Legislature an annual report that summarizes the data collected and contains additional information. The bill repeals Section 51 on January 1, 2023.

MCL 460.6a et al. (S.B. 437) Legislative Analyst: Suzanne Lowe

460.1001 et al. (S.B. 438)

FISCAL IMPACT

Senate Bill 437

The bill requires the Public Service Commission and the Michigan Agency for Energy, both within the Department of Licensing and Regulatory Affairs, to promulgate rules, make rulings, issue orders, and take other administrative actions to implement a number of new or amended sections of the PSC law, which will 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 presumably will be mitigated by increased assessments. Any cases in which amendments to the Act serve to reduce the amount of work required of the PSC presumably will lower assessments accordingly. To provide some perspective, in fiscal year (FY) 2016-17, the PSC collected a total of about $29.1 million in public utility assessments.

The bill will increase revenue received by the Utility Consumer Representation Fund by about $550,000 annually. In FY 2015-16, approximately $1.2 million was deposited into the Fund; the bill will increase that amount to $1,750,000, which will be adjusted annually for inflation. Money in the Fund previously was split evenly between the Utility Consumer Representation Board and Attorney General for grants. The bill changed this allocation to $1.0 million for the Board and $750,000 for the Attorney General. In addition, the bill allows unspent amounts allocated to either the Board or the Attorney General to be retained by the entity originally allocated those amounts for use in a subsequent fiscal year, rather than lapsing back to the Fund.

The bill also appropriated $1,950,000 to the PSC, $150,000 to the Attorney General, $600,000 to the Michigan Administrative Hearing System, $150,000 to the Department of Environmental Quality, and $260,000 to the Michigan Agency for Energy to implement the bill. The appropriations were effective for FY 2016-17, and were funded from public utility assessments.

The bill will have no fiscal impact on local units of government.

Senate Bill 438

The bill will have an indeterminate fiscal impact on the Public Service Commission and no fiscal impact on local units of government. The bill requires the PSC to approve energy waste reduction plans for natural gas providers initially, and then every two years. This will result in some increased costs for the PSC. As noted above, the PSC's regulation of public utilities is primarily funded through assessments on utilities that reflect the PSC's costs, so increased costs presumably will be mitigated by increased assessments. Any cases in which amendments to the Act reduce the amount of work required of the PSC presumably will lower assessments accordingly.

The bill also requires the PSC to promulgate rules related to the distributed generation program, which will result in some likely minor costs for the PSC.

Finally, the bill requires the PSC to review residential energy project program plans, review those plans every four years, and establish rules regarding the establishment of the programs. These requirements will result in some new, likely minor costs for the PSC.

Fiscal Analyst: Josh Sefton

This analysis was prepared by nonpartisan Senate staff for use by the Senate in its deliberations and does not constitute an official statement of legislative intent.