SB0437: SUMMARY OF SUBSTITUTE BILL IN COMMITTEE (Date Completed: 4-28-16)

-- Require the Utility Consumer Participation Board, in determining whether to award a grant to an applicant, to consider whether the applicant's activities in a proceeding would duplicate the anticipated involvement of the Attorney General.

-- Provide that disbursements from the Fund could be used only to advocate the interests of residential customers.

-- Require the Attorney General to consider primarily the interests of the residential and small business customer classes when using Fund money to advocate on behalf of utility customers.

The bill also would establish a sunset of December 31, 2018, on provisions allowing an electric utility to apply to the PSC for a certificate of necessity (CON) for increased generation capacity and requiring each utility applying for a CON to file an integrated resource plan (IRP). Before the sunset, the bill would reduce from $500.0 million to $100.0 million the minimum cost threshold for a CON application. Instead of a CON application, each electric utility whose rates are regulated by the PSC would have to file an IRP within two years after the bill took effect. Specifically, the bill would do the following:

-- Require the PSC to commence a proceeding every four years to establish the modeling scenarios and assumptions to be used in IRPs, among other requirements.

-- Require the PSC, within 300 days after an IRP was filed, to issue an order approving it or denying it with recommended changes.

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

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

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

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

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

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

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

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

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

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

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

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

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

-- Require the PSC to conduct a proceeding at least every five years to reevaluate the procedures and rate schedules, including avoided cost rates, established in the Commission's order in case no. U-6798.

-- Require each regulated electric utility, municipally owned or cooperative electric utility, and alternative electric supplier (AES) to demonstrate annually that it had sufficient dedicated and firm electric generation capacity to meet a prescribed share of the local clearing requirement (LCR).

-- Allow an AES or municipally owned or cooperative utility to meet its generation capacity requirements by using a capacity auction operated by an independent system operator, under certain circumstances.

-- Authorize the PSC to limit the amount of electricity provided by an AES that failed to demonstrate that it could meet the prescribed capacity requirements.

-- Require the PSC to report annually to the Governor and the Legislature a minimum five-year forecast of capacity resource adequacy, and include in the forecast a planning reserve margin requirement, LCR for each local resource zone, and proportional share of the LCRs for each electric provider in the State.

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

-- Require the PSC to monitor whether any entity engaged in market manipulation related to the LCRs, and authorize the Commission to disallow cost recovery for any excess capacity withheld unreasonably.

-- Require the PSC to authorize a shared savings mechanism for certain utilities in order to ensure equivalent consideration of energy waste reduction resources within the integrated resource planning process.

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

-- Delete the Act's title.

-- Revise the Act's purposes.

-- For fiscal year 2016-17, appropriate money to several State departments and agencies to hire a number of full-time equated positions to implement the bill's provisions.

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

-- Provide that a customer on an enrollment queue for retail open access service as of December 31, 2015, would remain on the queue unless the customer's prospective AES submitted an enrollment request to the customer's utility or the customer notified 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 could take service from an AES, and require the AES to notify the utility within five business days after being notified that the customer would take AES service.

-- Require the PSC, within 180 days after the bill took effect, to determine the appropriate generation capacity service costs for each electric utility to be assessed to any customer for the next 10 planning years after the customer elected to receive AES service.

-- Require an AES to meet the bill's requirements regarding firm and dedicated 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 were met.

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

-- Extend to all utilities a 2.5% per-year limitation on the customer rate impact resulting from the adoption of cost of service rates.

-- Allow the PSC, upon the request of an electric utility with at least 1.0 million retail customers in Michigan, to authorize the development, implementation, and full cost recovery of a cost-effective energy waste reduction portfolio or cost-based rates for educational institutions.

Senate Bill 438 (S-2) would repeal provisions of the Clean, Renewable, and Efficient Energy Act that establish a renewable energy standard, consisting of a renewable energy capacity portfolio and a renewable energy credit portfolio, under which 10% of an electric provider's energy must come from renewable sources by 2015; and would amend the Act with respect to energy optimization programs, net metering, renewable energy credits, and other matters.

In regard to energy optimization, the bill would provide for the transition of energy optimization programs to energy waste reduction programs and generally would repeal energy waste reduction requirements on or by January 1, 2019, except that natural gas providers would be subject to revised or additional requirements beginning on that date. In particular, the bill would do the following:

-- Establish a goal of meeting at least 30% of the State's electric needs through energy waste reduction and renewable energy by 2025.

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

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

-- Provide for the termination of an energy waste reduction standard by January 1, 2019.

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

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

-- Repeal provisions related to energy waste reduction credits on January 1, 2019.

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

-- Require a natural gas provider to submit to the PSC an annual report on its actions taken to comply with energy waste reduction standards.

-- Until January 1, 2019, provide for redress of violations of the waste reduction provisions by a member-regulated cooperative electric utility or a municipally owned electric utility.

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

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

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

In regard to net metering, the bill would replace the net metering program with a distributed generation program under which an electric customer could generate up to 100% of the customer's electricity consumption for the previous 12 months. An electric utility or alternative electric supplier would not have to allow for distributed generation that was greater than 10% of its average in-State peak load for the preceding five years, allocated as provided in the bill.

The bill also would do the following:

-- Revise provisions related to renewable energy credits.

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

-- With regard to the recovery of incremental costs of compliance with the renewable energy standard by a rate-regulated electric utility, eliminate a limit on the impact of the recovery on retail rates.

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

In addition, the bill would change the name of the Act to the "Clean and Renewable Energy and Energy Waste Reduction Act".

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

Senate Bill 437 (S-2)

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, concurrently with a utility's complete application to increase its rates or amend its rate schedules, a gas utility serving fewer than 1.0 million customers could file a motion seeking partial and immediate rate relief. After notifying the interested parties within the service area to be affected and affording them a reasonable opportunity to present written evidence and arguments relevant to the motion, the PSC would have to make a finding and enter an order granting or denying the relief within 180 days after the motion was submitted.

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

Time Frame for PSC Decision. The law requires the PSC to adopt rules and procedures for the filing, investigation, and hearing of petitions or applications to increase or decrease utility rates and charges as the Commission finds necessary or appropriate to enable it to reach a final decision within 12 months after a complete petition or application is filed. Except as otherwise provided, if the PSC fails to reach a final decision within that 12-month period, the petition or application is considered approved. If a utility makes any significant amendment to its filing, the PSC has an additional 12 months from the date of the amendment to reach a final decision. In both cases, the bill would reduce the time frame from 12 months to 10 months.

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

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

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

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

If the sales decreases were the result of implemented energy waste reduction, conservation, demand-side programs, and other waste reduction measures, the PSC would have to approve the decoupling mechanism or rate design. If sales decreased for other reasons, the bill would allow, but not require, the Commission to approve the decoupling mechanism or rate design.

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

In order to implement the PSCR clause, the utility annually must file a complete PSCR plan describing the expected sources of electric power supply and changes in the cost of power supply anticipated over a future 12-month period and requesting for each of those months a specific PSCR factor. Additionally, the utility must file a five-year forecast of the power supply requirements of its customers, its anticipated sources of supply, and projections of power supply costs, in light of its existing sources of electrical generation and sources under construction. The forecast must include a description of all relevant major contracts and power supply arrangements entered into or contemplated by the utility, as well as any other information required by the PSC. Under the bill, the forecast also would have to include a demonstration that the utility had enough dedicated and firm electric generation capacity to serve its retail electric customers' total current peak demand, including a reasonable projection of total peak demand growth, plus the applicable planning reserve margin requirement and the utility's proportional share of the local clearing requirement (described below) established by the PSC for the planning year beginning the following June 1 and the subsequent planning year.

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

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

Utility Consumer Participation Board

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

The bill would authorize the Attorney General to use Fund money to advocate on behalf of all energy utility customers, but require him or her to consider primarily the interests of residential and small business customers.

Electric Utility: Certificate of Necessity & Integrated Resource Plan

Filing of CON Application or IRP. The law allows an electric utility that proposes to construct an electric generation facility, make a significant investment in or purchase an existing generation facility, or enter into a power purchase agreement for the purchase of electric capacity for a period of at least six years to apply to the PSC for a certificate of necessity for the construction, investment, or purchase, if it costs more than $500.0 million and a portion of the cost would be allocable to Michigan retail customers. The PSC may not issue a CON for any environmental upgrades to existing generation facilities or for a renewable energy system. The PSC may implement separate review criteria and approval standards for electric utilities with fewer than 1.0 million retail customers who seek a CON for projects costing less than $500.0 million. The bill would reduce the threshold from $500.0 million to $100.0 million.

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

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

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

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

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

The bill specifies that these provisions would apply only until December 31, 2018.

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

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

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

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

-- Identify any required planning reserve margins and LCRs in areas of the State.

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

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

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

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

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

-- Any required planning reserve margins and LCRs.

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

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

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

-- Any regional infrastructure limitations in Michigan.

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

Within two years after the bill took effect, each electric utility whose rates were regulated by the PSC would have to file with the Commission an IRP that provided a five-year, 10-year, and 15-year projection of the utility's load obligations and a plan to meet them, to meet the utility's requirements to provide generation reliability, including meeting planning reserve margin and LCRs established by the PSC or the appropriate independent system operator, and to meet all applicable State and Federal reliability and environmental regulations over the term of the plan. The PSC would have to issue an order establishing filing requirements, including application forms and instructions, for an IRP. The utility's plan could include alternative modeling scenarios and assumptions other than those identified by the Commission. The PSC could issue an order implementing separate filing requirements, review criteria, and approval standards for an electric utility with fewer than 1.0 million customers and whose rates were regulated by the Commission.

PSC Order & Hearing. Within 270 days after a utility files a CON application, the PSC must issue an order granting or denying the requested CON. The Commission must hold a hearing, conducted as a contested case under the Administrative Procedures Act (APA), on the application. Also, the PSC must allow intervention by interested people. The bill would retain these provisions applicable to the CON process before the December 31, 2018, sunset.

Under the bill, within 300 days after an electric utility filed an IRP, the PSC would have to issue an order approving or denying it, with recommended changes. The utility could request to withdraw its plan for up to 45 days in order to amend it before the Commission's final determination. The time period for the Commission to make its decision would have to be extended by the number of days the plan was withdrawn. Up to 150 days after the utility made its initial filing, it could file to update its cost estimates if they had materially changed. No other aspect of the initial filing could be modified unless the application was withdrawn and refiled. A utility's filing updating its cost estimates would not extend the period for the PSC to issue an order approving or denying the IRP. An affiliate of an electric utility that served customers in Michigan and at least one other state could participate in the competitive bidding to provide services to that utility for a project covered under the bill. (Similar provisions apply to the current CON process.)The Commission would have to review the IRP in a contested case proceeding.

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

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

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

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

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

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

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

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

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

-- The proposed IRP represented the most reasonable and prudent means of meeting the electric utility's energy and capacity needs relative to other resource options for meeting them, including energy waste reduction programs, demand-side management, and transmission efficiencies.

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

-- The IRP was consistent with the renewable energy resources and waste reduction goal provided in the Clean and Renewable Energy and Energy Waste Reduction Act.

-- The IRP met the bill's requirements for IRP content (described below).

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

-- Resource adequacy and capacity to serve anticipated peak electric load, applicable planning reserve margin, and LCR.

-- Compliance with applicable State and Federal environmental regulations.

-- Competitive pricing.

-- Reliability.

-- Commodity price risks.

-- Diversity of generation supply.

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

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

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

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

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

If the finalized costs were found to be significantly higher than the initially approved costs, the PSC would have to review and approve the proposed costs in the same manner as the initial costs were determined.

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

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

Additionally, if the PSC denied the utility's IRP but the utility accepted the Commission's recommendations regarding the plan, the plan would be considered approved as modified by the utility consistent with those recommendations. If the utility did not accept the PSC's recommendations, within 60 days after the date of the final order denying the IRP, the utility could submit a revised IRP to the Commission for approval. The Commission would have to commence a contested case hearing under the APA. Within 90 days after the utility submitted the revised IRP, the PSC would have to issue a final order approving the plan or denying it with recommendations.

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

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

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

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

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

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

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

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

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

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

-- Electric transmission options for the utility.

The bill would retain this requirement with several changes.

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

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

Regarding transmission, the bill would refer to an analysis of potential new or upgraded options.

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

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

-- Plans for meeting current and future capacity needs with cost estimates for all proposed construction and major investments, including transmission or distribution infrastructure that would be required to support the proposed construction or investment, and power purchase agreements,

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

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

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

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

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

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

Performance-Based Regulation

Within 90 days after the bill took effect, the PSC would have to commence a study in collaboration with representatives of each customer class, utilities whose rates were regulated by the Commission, and other interested parties regarding performance-based regulation, under which a utility's authorized rate of return would depend on the utility's achieving targeted policy outcomes.

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

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

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

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

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

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

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

Reevaluation of PSC Order

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

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

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

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

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

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

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

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

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

Capacity Resource Adequacy

Demonstration of Sufficient Generation Capacity. The bill would require an electric utility to demonstrate to the PSC by November 1 of each that for the planning year beginning the following June 1 and the subsequent planning year, the utility owned or had contractual rights to sufficient dedicated and firm electric generation capacity to meet its proportional share of the local clearing requirement as established by the PSC.

("Dedicated and firm electric generation capacity" would mean capacity that is owned or under contract by the electric provider that is eligible to be used to satisfy the requirements of the appropriate independent system operator for the local resource zone in which the provider's demand is served and the LCR determined by the Commission under the bill.

"Electric provider" would mean any of the following:

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

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

-- A licensed alternative electric supplier.

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

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

Except as otherwise provided, an alternative electric provider (AEP), cooperative electric utility, and municipally owned electric utility would have to demonstrate to the PSC by November 1 of each year that for the planning year beginning the following June 1 and the subsequent planning year, the AEP or utility owned or had contractual rights to meet the equivalent of 50% of its proportional share of the LCR.

If the PSC determined in a proceeding that less than 105% of the capacity resources necessary to meet the LCR for each local resource zone was forecasted to be met for any year within a five-year forecast, an AEP or cooperative or municipally owned electric utility would have to demonstrate to the PSC by November 1 of each year that for the planning year beginning the following June 1 and the subsequent plan year, the provider or utility owned or had contractual rights to sufficient dedicated and firm electric generation capacity to meet the equivalent of 100% of its proportional share of the LCR. A provider or utility would have to make this demonstration for 12 planning years each time the Commission determined that less than 105% of the necessary capacity resources was forecasted to be met. If the Commission had not made such a determination within the last 12 planning years, the provider or utility would be subject to the 50% capacity demonstration requirement.

If the applicable independent system operator implemented an auction that expressly ensured that adequate dedicated and firm electric generation capacity existed and was fairly and accurately valued for both the planning reserve margin requirement and the LCR in all local resource zones for at least the planning year beginning the following June 1 and the subsequent planning year, an AEP or cooperative or municipally owned utility could propose to meet its requirements by using the capacity auction operated by the independent system operator where the provider's or utility's load was served. The PSC would have to determine through a contested case proceeding whether the auction established and implemented by the applicable system operator expressly ensured that adequate dedicated and firm generation capacity existed, that it was fairly and accurately valued, and that each provider actually acquired its required capacity, including its proportionate share of the planning reserve margin requirement and the LCR in all local resources zones for the two specified planning years.

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

By December 1 of each year, the PSC would have to notify each AES as to whether the supplier had demonstrated that it could meet the prescribed capacity requirements. If the Commission determined that an AES had failed to demonstrate that it could, the Commission immediately would have to commence a show cause proceeding, conducted as a contested case, to determine whether the AES should be limited to providing the amount of capacity the AES had demonstrated it had to meet the bill's requirements. If an AES failed to remedy the deficiency or otherwise demonstrate that it had sufficient capacity, the Commission could limit the electricity the AES could provide to an amount that did not exceed the amount of capacity the supplier had demonstrated it had for the planning years under review. All contracts for service between a customer in Michigan and an AES entered into after the bill's effective date would have to include a provision allowing the customer to withdraw without penalty if the PSC ordered a limitation of capacity that resulted in the AES being unable to supply the customer with the capacity required under the bill at any time during the two planning years under review. An AES could not serve more load during the two planning years than the load supported by the capacity it demonstrated under the bill.

Forecast of Capacity Resource Adequacy. By July 1 of each year, the PSC would have to report to the Governor and the Legislature a forecast of the capacity resource adequacy for a period of at least five years. For the covered planning years, the report would have to include a determination by the Commission of the planning reserve margin requirement, LCR for each local resource zone, and proportional share of the LCRs for each electric provider in the State. In making the determination, the PSC would have to consult with and consider any findings, projections, and other data of the appropriate independent system operator. The Commission would have to determine specifically whether 105% of the capacity resources needed to meet the LCR for each local resource zone was forecasted to be met for each year in the five-year forecasted period. A determination would have to be conducted as a contested case. All electric providers and unregulated generation providers in the State would have to submit prescribed data necessary for the PSC to make the required forecast and determinations.

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

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

Shared Savings Mechanism

In order to ensure equivalent consideration of energy waste reduction resources within the integrated resource planning process, the PSC would have to authorize a shared savings mechanism for an electric utility that had not otherwise capitalized the costs of the energy waste reduction, conservation, demand reduction, and other waste reduction measures. The mechanism could not exceed 20% of the utility's expenditures associated with implementing energy waste reduction programs for the year in which the mechanism was authorized.

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

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

Customer Choice and Electricity Reliability Act

Title. Currently, Sections 10 through 10bb of the PSC law are known as the "Customer Choice and Electricity Reliability Act". The bill would delete this title.

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

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

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

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

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

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

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

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

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

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

Under the bill, the orders also would have to provide that for an existing facility that was receiving 100% of its electric service from an AES on or after the bill's effective date, the facility owner could purchase electricity from an AES, regardless of whether the sales exceeded 10% of the servicing electric utility's average weather-adjusted retail sales, for both the existing electric choice load at the facility and any expanded load arising at that facility after the bill's effective date, as well as any new facility that was similar in nature to the existing facility, that was constructed or acquired by the customer on a site contiguous to the existing site or that would be contiguous to an existing site in the absence of an existing public right-of-way, and if the customer owned more than 50% of that facility.

The orders also must provide that any customer operating an iron ore mining and/or processing facility located in the Upper Peninsula may purchase all or any portion of its electricity from an AES, regardless of whether the sales exceed 10% of the serving electric utility's average weather-adjusted retail sales. Under the bill, this provision would apply if the customer were in compliance with the terms of a settlement agreement requiring it to facilitate construction of a new power plant located in the Upper Peninsula. The customer and the AES that provided electric service to the customer would not be subject to the bill's requirements and any administrative regulations adopted under the bill. The PSC's order establishing rates, terms, and conditions of retail access service issued before the bill's effective date would remain in effect with regard to retail open access provided under these provisions.

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

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

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

Further, the orders would have to provide that within 180 days after the bill's effective date, the PSC would have to determine the appropriate generation capacity service costs for each electric utility that would be assessed to any full service electric utility customer for the subsequent 10 planning years after the customer either elected to received AES service as described above or, for a utility that did not maintain a queue, elected to receive AES service after December 1, 2016, for any of its current full service electric load. The generation capacity costs would be the customer's pro rata share of the cost of generation capacity services that the customer continued to receive from the utility for the subsequent 10 planning years as determined by the Commission. The electric utility, and not the customer's AES, would be responsible for the customer's generation capacity requirements for the 10-year period that the generation capacity charge was assessed. The allocation of a utility's generation capacity service costs could not differentiate between customers on standard tariff service and customers electing to take service from an AES. The bill prescribes the factors the PSC would have to consider in determining the customer's pro rata share of the utility's generation capacity service costs.

Additionally, the orders would have to provide that as a condition of licensure, an AES would have to meet all of the bill's requirements regarding firm and dedicated generation capacity.

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

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

Currently, a utility offering an ASP must do all of the following:

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

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

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

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

The Act also contains provisions regarding the allocation of the utility's costs attributable to an ASP, inclusion of charges for the program on its monthly customer billings, and program marketing. Under the bill, similar requirements would apply to any unregulated value-added program or service offered by the utility, with several changes. The bill would eliminate a provision stating that a subsidy does not exist if the costs allocated as required do not exceed revenue from the program. Additionally, the bill would require a utility to provide upon request to a provider of a similar program or service any lists of its customers who receive both regulated service and unregulated programs and services within five business days, rather than two as currently required, on a nondiscriminatory basis.

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

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

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

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

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

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

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

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

Appropriations

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

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

-- $1.3 million to the PSC to hire 13 full-time equated (FTE) positions.

-- $400,000 to the Michigan Administrative Hearing System to hire 4.0 FTEs.

-- $100,000 to the DEQ to hire 1.0 FTE.

Customer Rate Impact

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

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

Rates for Educational Institutions

With regard to electric utilities with at least 1.0 million retail customers in the State, the law requires the PSC to establish rate schedules that ensure that public and private schools, universities, and community colleges are charged retail electric rates that reflect the actual cost of providing service to them. Regulated electric utilities must file with the PSC tariffs to ensure that these institutions are charged such rates. Under the bill, these provisions would apply to all regulated electric utilities, regardless of the number of customers.

Under the bill, upon the request of an electric utility with at least 1.0 million retail customers in Michigan, the PSC could authorize the development, implementation, and full cost recovery through the utility's general rates, tariffs, or surcharges or a reasonable cost-effective portfolio of energy waste reduction programs or cost-based rates for institutions that were designed to achieve reasonable and cost-effective electricity cost savings. Any waste reduction programs or cost-based rates approved by the PSC would have to be based on cost of service.

Senate Bill 438 (S-2)

Purpose

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

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

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

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

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

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

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

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

-- Energy efficiency.

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

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

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

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

The bill provides that, as a goal, at least 30% of the State's electric needs should be met through a combination of energy waste reduction and renewable energy by 2025, if the investments in these means were the most reasonable means of meeting an electric utility's energy and capacity needs relative to other resource options. Both of the following would count toward achievement of the goal:

-- All renewable energy that counted toward the renewable energy standard under the current law on the effective date of Senate Bill 438, as well as any investments made in renewable energy by the utility or a utility customer after that date.

-- All energy waste reduction measures implemented under an approved energy optimization plan or energy waste reduction plan (both described below).

Energy Optimization/Waste Reduction

Electricity Plan. The Act required a rate-regulated electric provider to file a proposed energy optimization plan with the PSC by March 3, 2009, and a member-regulated cooperative electric utility to file such a plan by April 2, 2009. The Act states that the overall goal of an energy optimization plan is to reduce the future costs of provider service to customers, in particular by delaying the need for constructing new electric generating facilities and thereby protecting consumers from incurring the costs. Under the bill, these energy optimization plans would remain in effect, subject to any amendments, as energy waste reduction plans. The bill would expand the goal of a plan to including helping the provider's customers reduce energy waste. All of the provisions that apply to energy optimization plans currently would apply to waste reduction plans. All of the provisions pertaining to electricity waste reduction plans would be repealed on January 1, 2019.

Natural Gas Plan. The bill states that a natural gas provider was required to file a proposed energy optimization plan with the PSC by March 3, 2009, and specifies that those plans would remain in effect as waste reduction plans.

Under the bill, the overall goal of a waste reduction plan would be to help the natural gas provider's customers reduce energy waste and to reduce the future costs of provider service to customers. The bill would establish requirements for a natural gas waste reduction plan similar to those that apply to an electricity waste reduction plan.

A natural gas waste reduction plan could do either or both of the following:

-- Use educational programs designed to alter consumer behavior or any other measures that could reasonably be used to meet the plan's goal.

-- Propose to the PSC measures that were designed to meet the plan's goal and that provided additional customer benefits.

Expenditures for these programs and measures could not exceed 3% of the costs of implementing the natural gas waste reduction plan. (Similar provisions apply to electricity waste reduction plans.)

All of the provisions regarding natural gas waste reduction plans would take effect on January 1, 2019.

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

The Act provides that an energy optimization plan must be enforced subject to the same procedures that apply to a renewable energy plan. Under the bill, the energy waste reduction plan of a provider whose rates are regulated by the PSC would have to be enforced by the Commission. For a provider whose rates are not regulated, the plan would have to be enforced through a civil action (described below).

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

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

Within 270 days after the bill took effect, an electric provider would have to file with the PSC a proposed plan amendment to reflect the termination of the energy waste reduction standard (described below).

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

All of these provisions would be repealed on January 1, 2019.

Provisions Applicable to Natural Gas Plans. The bill would require a natural gas provider's energy waste reduction plan to be filed with and reviewed, approved or rejected, and enforced by the PSC. The Commission could not approve a proposed waste reduction plan unless it determined that the plan met the utility system resource cost test and was reasonable and prudent. In determining whether the plan was reasonable and prudent, the Commission would have to review each element and consider whether it would reduce the future cost of service for the provider's customers.

The bill prescribes requirements for a two-year review of a natural gas provider's plan similar to those that would apply to the plans of other providers.

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

All of these provisions would take effect on January 1, 2019.

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

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

These provisions would be repealed on January 1, 2019; the bill, however, prescribes similar provisions that would apply specifically to a natural gas provider that would take effect on that date.

Waste Reduction Energy Savings Goals. The Act prescribed incremental energy savings that an electric provider's energy optimization programs had to collectively achieve annually beginning in 2008. The prescribed annual incremental energy savings in 2015 and each year after that are equivalent to 1% of total annual retail electricity sales in megawatt hours in the preceding year. Under the bill, this savings amount would apply every year from 2016 through 2018.

The bill would retain an annual incremental energy savings requirement for a natural gas provider's plan of 0.75% of total annual retail sales in the preceding year, but specifies that this would apply subject to the sales revenue expenditure limits prescribed in the Act. (A natural gas provider may not annually spend more than 2% of total retail sales revenue in the preceding two years to comply with the energy optimization performance standard without specific approval from the PSC. The bill would repeal this limit on January 1, 2019.)

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

All of these provisions would be repealed on January 1, 2019.

Natural Gas Energy Savings. Beginning in 2019 and subject to the sales revenue expenditure limits, a natural gas provider's energy waste reduction program would have to achieve annual incremental energy savings equivalent to 0.75% of total annual retail natural gas sales in the preceding year. The incremental savings for a year would have to be determined by a natural gas provider by adding the energy savings expected to be achieved by waste reduction measures implemented during that year under any energy waste reduction programs consistent with the provider's energy waste reduction plan.

For purposes of the calculations, total annual retail natural gas sales in a year would have to be based on one of two mechanisms at the option of the natural gas provider as specified in its energy waste reduction plan.

All of these provisions would take effect on January 1, 2019.

Alternative Waste Reduction Standards. If, over a two-year period, a natural gas provider could not achieve the energy waste reduction standard in a cost-effective manner, the provider could petition the PSC to establish alternative energy waste reduction standards for that provider. A petition would have to identify the provider's efforts to meet the standard, explain why the provider could not achieve the standard reasonably and cost-effectively, and propose a revised energy waste reduction to be achieved.

If the PSC determined, based on a review of the petition, that the provider had been unable to reasonably and cost-effectively achieve the energy waste reduction standard, the Commission would have to revise the standard as applied to that provider to a level that could reasonably and cost-effectively be achieved.

The Act contains similar provisions allowing a provider to petition the PSC for alternative energy optimization standards that apply to electric providers that serve a maximum of 200,000 Michigan customers and had average rates for residential customers using 1,000 kilowatt hours per month for all electric utilities in the State, according to a 2007 PSC compilation. The bill would refer to waste reduction rather than energy optimization in these provisions. The provisions concerning electric providers would be repealed on January 1, 2019.

Energy Waste Reduction Credits. The Act provides for one energy optimization credit to be granted to an electric provider for each megawatt hour of annual incremental energy savings achieved through energy optimization. The Act provides for the carrying forward of unused credits as well as their expiration upon use, and requires the PSC to establish a credit tracking system. The bill would refer to waste reduction rather than optimization. All of the provisions related to energy waste reduction credits would be repealed on January 1, 2019.

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

Costs must be recovered from all natural gas customers and from residential electric customers by volumetric charges, from all other metered electric customers by per-meter charges, and from unmetered electric customers by an appropriate charge, applied to utility bills as an itemized charge. Under the bill, costs would have to be recovered from all customers by volumetric charges or fixed, per-meter charges, which could vary by rate class. These charges could be itemized on utility bills.

All of these provisions would be repealed on January 1, 2019. Beginning on that date, similar provisions would continue to apply to natural gas providers. Additionally, for customers of a natural gas provider with an aggregate billing demand of more than 100,000 decatherms or equivalent MCFs for all sites in the utility's service territory, the cost recovery could not exceed 1.7% of total retail sales revenue for that customer class. For residential customers, the cost recovery could not exceed 2.2% of total retail sales revenue for that customer class.

Also, beginning on January 1, 2019, upon petition by a rate-regulated natural gas provider, the PSC would have to authorize the provider to capitalize all energy efficiency and conservation equipment, materials, and installation costs with an expected economic life greater than one year incurred in implementing its energy waste reduction plan, including the costs paid to third parties such as customer rebates and incentives. The provider also would have to propose depreciation treatment with respect to its capitalized costs in its plan, and the PSC would have to order reasonable depreciation treatment related to these costs. A natural gas provider could not capitalize payments made to an independent energy waste reduction program administrator.

The established funding level for low-income residential programs would have to be provided from each customer rate class in proportion to its funding of the natural gas provider's total energy waste reduction programs. Charges would have to be applied to distribution customers regardless of the source of their natural gas supply.

The PSC would have to authorize a natural gas provider that spent a minimum 0.5% of total natural gas retail sales revenue in a year on PSC-approved energy waste reduction programs to implement a symmetrical revenue decoupling true-up mechanism that adjusted for sales that were above or below the projected levels that were used to determine the revenue requirement authorized in the provider's most recent rate case.

Effective January 1, 2019, a natural gas provider could not spend in any year more than 2% of total utility retail sales revenue for the second year preceding to comply with the energy waste reduction performance standard without specific approval from the PSC.

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

Under the Act, an alternative compliance payment received from a provider by the program administrator must be used to administer the provider's energy efficiency program. The PSC must allow a provider to recover such a payment.

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

All of the provisions related to a waste reduction program run by an administrator would be repealed on January 1, 2019. The bill, however, would reenact similar provisions applicable specifically to a natural gas provider, which would take effect on that date.

Self-Directed Waste Reduction Plan. The Act exempts certain commercial and industrial electric customers that implement a self-directed plan from energy optimization charges. All of these provisions would be repealed on January 1, 2019.

Load Management: Voluntary Shut-Down. The Act requires the PSC to promote load management in appropriate circumstances. Under the bill, this would include encouraging the establishment of load management programs in which an electric provider could remotely shut down air conditioning or other energy intensive systems of participating customers. Provider participation and customer enrollment in such programs would have to be voluntary. The programs could provide incentives for customer participation and would have to include customer protection provisions as required by the PSC.

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

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

-- Promote energy efficiency and conservation.

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

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

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

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

Natural Gas Provider Report. The bill would require each natural gas provider, by a time determined by the PSC, to submit to the Commission an annual report that provided information related to the actions taken by the provider to comply with the energy waste reduction standards. The report would have to include specific information.

The PSC would have to submit to the standing committees of the Senate and House of Representatives with primary responsibility for energy and environmental issues a report that evaluated and determined whether the Act's energy waste reduction provisions had been cost-effective. The report also would have to make recommendations to the Legislature. The report could be combined with the required annual report summarizing the PSC's activities during the preceding year.

These provisions would take effect on January 1, 2019.

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

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

Upon receiving a complaint by a customer of a municipally owned electric utility or upon the PSC's own motion, the Commission could review allegations that the utility had violated the waste reduction requirements or a related order or rule. If the PSC found, after notice and hearing, that the utility had committed a violation, the Commission would have to advise the Attorney General. The Attorney General could commence a civil action for injunctive relief against the utility.

In issuing a final order regarding an alleged violation by a cooperative or municipally owned electric utility, the court could award costs of litigation, including reasonable attorney and expert witness fees, to the prevailing or substantially prevailing party.

These provisions would be repealed on January 1, 2019.

Distributed Generation & Net Metering

Within 90 days after the bill's effective date, the PSC would have to establish a distributed generation program by order. An electric customer of any class would be eligible to interconnect an eligible electric generator with the customer's local electric utility and operate it in parallel with the distribution system. The program would have to be designed for a period of at least 10 years and limit each customer to generation capacity designed to meet up to 100% of the customer's electricity consumption for the previous 12 months.

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

Currently, an electric utility or alternative electric supplier (AES) is not required to allow for net metering that is greater than 1% of its in-State peak load for the preceding calendar year. Under the bill, an electric utility or AES would not have to allow for distributed generation that was greater than 10% of its average in-State peak load for the preceding five years. The 10% limit would have to be allocated as follows:

-- Not more than 5% for customers with a generator capable of generating a maximum of 20 kilowatts.

-- Not more than 2.5% for customers with a generator capable of generating more than 20 but not more than 150 kilowatts.

-- Not more than 2.5% for customers with a methane digester capable of generating more than 150 kilowatts.

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

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

Electric meters would have to be used to determine the amount of a customer's electricity use in each billing period and the amount of electricity produced by the generator on the customer's site. An electric utility would have to give its customers participating in the distributed generation program, at cost, a meter or meters capable of measuring the flow of energy in both directions and the energy produced by the eligible electric generator.

A customer participating in the distributed generation program would have to purchase from the electric utility or AES at the applicable retail electricity rates and charges all of the imputed customer usage. Under the program, electricity generated by an eligible generator during a billing period would have to offset power supply charges at the variable power supply portion of the retail rate for electricity up to the imputed customer usage for that customer during that billing period. ("Imputed customer usage" would mean the amount of electricity that is consumed by a distributed generation customer during a billing period and is calculated as the sum of the metered on-site generation and the net of the bidirectional flow of power across the customer interconnection during the billing period.)

If the quantity of electricity generated by an eligible generator during a billing period exceeded imputed customer usage during that period, a supplier of electric generation service would have to credit the eligible customer for the excess kilowatt hours generated. Any excess kilowatt hours not used to offset retail electricity charges in the next billing period would have to be carried forward to subsequent billing periods. For an electric utility serving more than 1.0 million customers in Michigan or an AES, the bill credit would be the sum of the following, as applicable:

-- The value of the energy avoided, which would be determined by the average real-time locational marginal price for energy at the commercial pricing node within the utility's distribution service territory.

-- The value of the capacity avoided.

For an electric utility serving fewer than 1.0 million customers in Michigan, the bill credit could be determined at the utility's option either by the method set forth for larger utilities and AESs or through application of an avoided cost rate determined annually by the PSC after notice and hearing. The PSC would have to establish the avoided cost rate at one of the following:

-- The average marginal price of energy paid by the provider during the previous year.

-- The estimated electric generation and purchased power costs each provider avoided by purchasing the distributed generation.

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

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

Renewable Energy Credits

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

An electric provider is responsible for demonstrating that a renewable energy credit used to comply with a renewable energy credit standard is derived from a renewable energy source and that the provider has not previously used or traded, sold, or otherwise transferred the credit. A provider may use the same credit to comply with both a Federal standard for renewable energy and the renewable energy standard prescribed in the Act. An electric provider that uses a renewable energy credit to comply with another state's renewable energy standard may not use the same credit to comply with the renewable energy credit standard prescribed in the Act. The bill would delete these provisions.

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

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

The Act defines "renewable energy" as electricity generated using a renewable energy system. "Renewable energy system" means a facility, electricity generation system, or set of generation systems that use one or more renewable energy resources to generate electricity. The term does not include the following:

-- A hydroelectric pumped storage facility.

-- A hydroelectric facility that uses a dam constructed after October 6, 2008, unless the dam is a repair or replacement of a dam existing on that date that increases its energy efficiency.

-- An incinerator, unless it is a municipal solid waste incinerator that was brought into service before October 6, 2008.

"Renewable energy resource" means a resource that replenishes naturally over a human, not a geological, time frame and that ultimately is derived from solar power, water power, or wind power. A renewable energy resource comes from the sun or from thermal inertia of the Earth and minimizes the output of toxic material in the conversion of the energy. The term includes municipal solid waste, which the bill specifies would include the biogenic and anthropogenic factions. Additionally, under the bill, "renewable energy resource" would include fuel that has been manufactured from waste, including municipal solid waste. The bill would exclude pet coke, hazardous waste, coal waste, and scrap tires.

Voluntary Green Pricing Program

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

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

Rate-Regulated Electric Provider: Renewable Energy Plan Compliance Cost Recovery

The Act required electric providers to file with the PSC a renewable energy plan describing how the providers would meet the Act's renewable energy standards. 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.

Subject to these rate impact limits, the PSC must consider all actual costs reasonably and prudently incurred in good faith to implement a PSC-approved renewable energy plan by a rate regulated provider to be a cost of service to be recovered by the provider. Also subject to the rate impact limits, a rate-regulated provider must recover through its retail electric rates all of the 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 that period. Under the bill, these requirements would apply regardless of the rate impact limits. Also, for a rate-regulated provider, the PSC would have to determine the appropriate charges, which would have to be included in the provider's tariffs, to permit recovery of the incremental cost of compliance.

The bill would repeal the section establishing the rate impact limits.

The Act requires the recovery to include the provider's authorized rate of return on equity for approved costs, which remain fixed at the rate of return and debt-to-equity ratio that was in effect in the provider's base rates when the renewable energy plan was approved. Under the bill, the recovery also would have to include costs associated with a facility approved for cost recovery before the bill's effective date.

If an electric provider's incremental costs of compliance with the renewable energy standard in any given month during the 20-year period beginning when the provider's renewable energy plan is approved by the PSC exceed the adjusted revenue recovery mechanism and in excess of the balance of any accumulated reserve funds, subject to the minimum balance established under the Act, the provider immediately must notify the PSC. The PSC promptly must commence a contested case hearing and modify the revenue recovery mechanism so that the minimum balance is restored. If the PSC determines, however, that recovery of the incremental costs of compliance would otherwise exceed the prescribed maximum retail rate impacts, it must set the revenue recovery mechanism for that provider to correspond to those rate impacts. Excess costs must be accrued and deferred for recovery. Within the 20-year period after a rate-regulated provider's plan is approved, the PSC must determine the amount of deferred costs to be recovered under the recovery mechanism and the recovery period, which may not extend more than five years beyond the expiration of the 20-year period. The recovery of excess costs may not exceed the retail rate impact limits for each customer class. The bill would delete these provisions.

The Act provides that after achieving compliance with the renewable energy standard for 2015, the actual costs reasonably and prudently incurred to continue to comply with renewable energy provisions both during and after the conclusion of the 20-year period after the provider's plan was approved by the PSC are considered costs of service. The PSC must determine a mechanism for a rate-regulated provider to recover these costs in its retail electric rates, subject to the prescribed retail rate impact limits. The bill would delete these provisions.

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

-- A gasification facility.

-- An industrial cogeneration facility.

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

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

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

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

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

Exemption from Energy Standards

The Act provides that electricity or natural gas used in the installation, operation, or testing of any pollution control equipment is exempt from the requirements of and calculations of compliance required under the Act's energy standards. The bill would eliminate the exemption for electricity effective January 1, 2019.

Residential Energy Improvements

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

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

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

-- The estimated costs of program administration.

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

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

-- An application form.

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

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

-- Provisions for marketing and participant education.

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

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

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

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

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

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

460.1001 et al. (S.B. 438)

FISCAL IMPACT

Senate Bill 437 (S-2)

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

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