Senate Bill 437 as enacted

Public Act 341 of 2016

Sponsor:  Sen. Mike Nofs

House Committee:  Placed directly on Second Reading

Senate Committee:  Energy and Technology

Complete to 2-14-17


Senate Bill 437 amends the Michigan Public Service Commission Enabling Act to address a number of issues, at the forefront of which is electric reliability. The changes made to the bill take effect April 20, 2017.  The bill amends the act to do the following:

v Maintain the 10 percent cap on retail open access (ROA)—sometimes referred to as customer choice—for electricity service, and preserve the ability for customers to move between an alternative electric supplier (AES) and an electric utility to receive electricity service.

v Reduce, for most circumstances, the timeframe for deciding rate cases from 12 months to 10 months.

v Eliminate the ability of utilities to self-implement rate changes.

v Establish, with some exemptions, a tariff for electric customers in a net metering or distributed generation program.

v Increase funding to the Utility Consumer Representation Fund.

v Lower the threshold of projects triggering a certificate of necessity (CON).

v Enhance standards for integrated resource plans (IRP) to include a 5, 10, and 15-year projection of a utility's load obligations and a plan to meet those obligations.

v Require, depending on the situation, certain mechanisms to be implemented to address resource adequacy.

v Create incentives for energy waste reduction efforts by energy utilities.

v Require a covered utility to file an abandonment application and obtain PSC approval before discontinuing service to a geographic area.

v Revise the Code of Conduct and apply the provisions to natural gas utilities.

v Allow utility shut-offs for failure to pay monthly installment payments under a residential energy project program created under related legislation, Senate Bill 438, which became Public Act 342 of 2016.

v Provide appropriations for Fiscal Year 2017 for additional staffing for state agencies to implement the act.

v Establish an Energy Ombudsman.

v Clarify that the PSC is to establish rates based on cost-of-service.

v Move the Michigan Renewables Energy Program from the PSC to the Michigan Agency for Energy.

v Repeal and delete obsolete provisions.


Senate Bill 437 amends Public Act 3 of 1939, known as the Michigan Public Service Commission Enabling Act.  As noted above, the changes take effect April 20, 2017.  A brief description of some of the bill's more significant revisions follows.


The title of an act describes what the act is intended to accomplish.  The bill adds to the current description that the act is to provide for the powers and duties of certain state governmental officers and entities.  The bill also strikes as an objective of the act that it is to provide for a restructuring of the manner in which energy is provided in the state.

Utility Rates

Under the act, a gas or electric utility is prohibited from increasing its rates and charges or altering, changing, or amending any rate or rate schedules which would result in the increase of the cost of its services without first receiving PSC approval as provided in the act.  (Municipally owned electric utilities are not subject to PSC regulation with the exception of the filing of a renewable energy plan as required by the Clean, Renewable, and Efficient Energy Act, Public Act 295 of 2008.  The PSC does not regulate the retail rates of electric cooperatives whose rates are member-regulated.) 

Section 6a:

Revisions include the following:

Ø  Expands provisions to apply also to a steam utility and requires a gas, electric, or steam utility to coordinate with the PSC prior to filing a general rate case application to avoid resource challenges that result when multiple utilities file applications at the same time.  For large utilities (more than one million customers in the state), the bill allows the PSC to order a delay to establish a 21-day spacing between filings.

Ø  Allows a small gas utility (fewer than one million customers) to seek partial and immediate rate relief.

Ø  Sunsets the provision allowing utilities to self-implement a rate increase or decrease if the PSC does not issue an order regarding the rate case within 180 days of the utility filing a completed application.  The bill applies the provision to self-implement only to completed applications filed with the PSC before the bill's effective date of April 20, 2017.

Ø  Reduces the timeframe for the PSC to decide a rate case from 12 months to 10 months in most circumstances.

Ø  Allows an electric utility with less than 200,000 Michigan customers to request, and requires the PSC to approve, a revenue decoupling mechanism to adjust for decreases in lost sales resulting from the implementation of energy waste reduction, conservation, demand-side programs, and other waste reduction measures, if certain conditions are met by the utility.  The PSC may consider an alternative methodology for an approved revenue decoupling mechanism than that described in the bill, a financial incentive authorized under Section 75 of the Clean and Renewable Energy and Energy Waste Reduction Act, or a shared savings mechanism authorized under Section 6x of the act under certain circumstances.

Ø  Requires, within one year of the bill's effective date, the PSC to conduct a study on an appropriate tariff that will reflect an equitable cost of service for utility revenue requirements for customers participating in a net metering or distributed generation program under the Clean and Renewable Energy and Energy Waste Reduction Act (Senate Bill 437).  Such a tariff must be approved by the PSC for inclusion in the rates of all customers participating in either of those programs in any rate case filed after June 1, 2018.  This tariff will not apply to customers participating in a net metering program under the Clean and Renewable Energy and Energy Waste Reduction Act prior to the commission establishing a tariff if they continue to participate in the program at their current site or facility.  ("Tariff" refers to the method a utility uses to charge a customer for energy consumption.)

Ø  Specifies that in general, "utility" and "electric utility" as used in the act do not include a municipally owned electric utility.


Power Supply Cost Recovery

This is an element of the electric service charge that reflects power supply costs incurred by an electric utility and made under a power supply cost recovery clause in the utility's electric rates or rate schedule.

Section 6j:

The bill makes numerous technical changes of an editorial nature for clarity but largely maintains existing provisions.  The bill also:

Ø  Requires electric utilities, in the annual power supply cost recovery plan, to include whether the contract includes long-term firm oil transportation and if not, how the utility proposes to ensure reliable and reasonably priced gas fuel supply to its generation facilities during the specified 12-month period. "Long-term firm gas transportation" means a binding agreement entered into between the electric utility and a natural gas transmission provider for a set period of time to provide guaranteed delivery of natural gas to an electric generation facility.

Ø  Eliminates a provision requiring the Legislature to review power supply cost recovery factors every five years.

Utility Consumer Participation Board (UCPB)

Sections 6l and 6m of the act provide a means of ensuring equitable representation of the interests of energy utility customers for the purpose of implementing certain sections of the act.  The Utility Consumer Representation Fund (UCRF) receives funds generated by an annual assessment on certain regulated utilities.  A portion of the revenue from the Fund is reserved for use by the attorney general to represent consumers in state and federal administrative and judicial proceedings.  Revenue is also used to cover the operational costs and expenses of the Utility Consumer Participation Board (UCPB), with the net grant proceeds used to finance a grant program with grants awarded by the UCPB to nonprofit entities and local units of government that advocate on behalf of the interests of the residential consumer groups that they represent.   

Section 6l:

Revises the provisions under which applicants may receive grants from the UCPB for interventions so as to include Sections 6a (rate cases, decoupling, tariff for distributed generation customers), 6h (gas cost recovery), 6j (power supply cost recovery), 6s (Certificate of Need), and 6t (integrated resource plan).  References to Sections 6i (gas cost recovery plans) and 6k (power supply cost recovery plans) were deleted and Sections 6a, 6s, and 6t added. 

Section 6m:

Ø  Specifies that disbursements for grants from the Utility Consumer Representation Fund (UCRF) are restricted to the purpose of advocating for the interests of residential energy utility customers concerning energy costs or rates and not for representation of merely individual interests.

Ø  Increases the base amount of revenues remitted to the UCRF; requires all regulated energy utilities to participate; and changes the amounts dedicated to the attorney general and the grant program. 

Currently, the base amount of revenues sent to the UCRF is established in statute, and is adjusted annually for inflation, and utilities pay a share of that amount based on formulas contained in the act.  Under the bill, the base amount from utilities serving at least 100,000 Michigan customers, will increase to $900,000; these revenues are dedicated to the attorney general.  The base amount from energy utilities serving at least 100,000 Michigan residential customers will be $650,000; these revenues are used for grants. 

The bill also adds a requirement for small energy utilities (fewer than 100,000 Michigan customers) so that they will pay a proportional share of $100,000 (dedicated to the attorney general); and small utilities serving fewer than 100,000 residential customers so that they will pay a proportional share of $100,000 (used for grants). 

Thus, the new total for the base amount will be $1.75 million, with the attorney general receiving a larger portion of the funds, instead of all available funds being split evenly, as previously. (See Fiscal Impact section, beginning on Page 20.)

Ø  Revises what the UCPB shall consider when making grants to include energy conservation; energy waste reduction; demand response; and rate design options to encourage energy conservation, energy waste reduction, and demand response, as well as maintenance of adequate energy resources. Protection of the environment and the creation of employment and a healthy state economy are removed as elements for the Board to consider.

Ø  Encourages greater collaboration between the UCPB and the attorney general, particularly as it relates to the hiring of expert witnesses and also in determining the use of unexpended money in the Fund.  In addition, the bill requires the UCPB to consider the anticipated involvement of the attorney general in a proceeding and whether the activities of a grant applicant will be duplicative or supplemental to those of the attorney general.

Ø  Requires grant applicants to identify in an application any additional funds or resources that will be used to participate in the proceeding for which the grant is being requested and how those funds or resources will be utilized.

Ø  Requires grant recipients 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.

Ø  Requires a grant recipient to include in its report about how the grant was spent, a detailed list of the regulatory issues raised by the grant recipient and how each issue was determined by the PSC, court, or other tribunal.

Ø  Requires the Board to include in its annual report the reports currently required from grant recipients regarding grant expenditures.  

Electric Generation Facility/CON

Under the act, an electric utility that proposes to construct an electric generation facility, to purchase or make a significant investment in an existing electric generation facility, or to enter into a power purchase agreement for the purchase of electric capacity for a period of at least six years may submit an application to the PSC seeking a certificate of necessity (CON) for that construction, investment, or purchase, if the project costs at least $500 million and a portion of the costs would be allocable to retail customers in Michigan. 

As amended, Section 6s:

Ø  Lowers the threshold of projects triggering application for a certificate of necessity (CON) to those costing $100 million or more; for small electric utilities (fewer than one million retail customers), it lowers the threshold from less than $500 million to less than $100 million. 

Ø  If the CON application is for a project that requires an integrated resource plan under the new Section 6t, the PSC must consolidate the proceedings.  If Section 6s provisions regarding CON conflict with Section 6t, Section 6s will prevail.

Ø  Allows the PSC to authorize a financial incentive that does not exceed the utility's weighted average cost of capital for power purchase agreements that a utility enters into with an entity that is not affiliated with it after the bill's effective date.

Ø  Revises provisions regarding cost-overruns to specify that the portion of the cost of a plant, facility, or power purchase agreement exceeding the PSC-approved cost is presumed to have been incurred due to a lack of prudence (currently the threshold is the cost exceeding 110 percent of the approved costs).

The PSC must disallow costs incurred as the result of fraud, concealment, gross mismanagement, or lack of quality controls amounting to gross mismanagement.  The PSC must require refunds, with interest, to ratepayers of any of these costs already recovered through the electric utility's rates and charges.

The bill also provides a process by which a review may be made if the assumptions underlying an approved CON materially change to determine if it is reasonable and prudent to complete an unfinished project, and allows the PSC to modify or cancel approval of the CON if the commission finds the project is no longer reasonable and prudent.  Recovery of reasonable and prudent costs already incurred could not be disallowed by the PSC (but could be disallowed for fraud, concealment, gross mismanagement, or lack of quality controls leading to gross mismanagement); future costs could be limited by the PSC to those costs that could not have been reasonably avoided.

Ø  Specifies that the PSC standards for an integrated resource plan (IRP) filed by a utility when requesting a CON do not apply to utilities having an approved IRP under the new Section 6t.

Ø  Allows an electric supplier producing at least 200 megawatts of firm electric generation capacity, which is located in the utility's independent system operator's (ISO) zone, to directly submit a proposal as an alternative to the utility's CON project; allows the entity standing to intervene in the CON proceeding; requires the PSC to consider the cost of the alternative proposal as well as the entity's qualifications, competence, and reliability, among other things; and specifies that the PSC is not authorized to order or otherwise require an electric utility to adopt any alternative proposal submitted under this provision.

Ø  Requires that the filing of a petition for judicial review of a PSC order issued following a hearing on a CON must be filed in the Court of Appeals within 30 days of the order's issuance and requires the COA to conduct the review as expeditiously as possible with lawful precedence over other matters.

Integrated Resource Plan (IRP)

The bill adds Section 6t, which requires a more robust set of standards for IRPs.  New standards include requiring, not later than two years after the bill's effective date, each PSC-regulated electric utility to file a 5, 10, and 15-year projection of the utility's load obligations to provide generation reliability and a plan to meet those obligations, as detailed in the bill, with reviews of the IRP not later than 5 years after the effective date of the most recent PSC order approving a plan, an amendment to the plan, or a plan review.

In addition, among other things, Section 6t will:

Ø  Require the PSC, within 120 days of the bill's effective date and every five years thereafter, to commence a proceeding to gather certain information ahead of the IRP process, pertaining to relevant state and federal environmental laws, assessment of the potential for energy waste reduction and demand response programs, and establishment of modeling scenarios and assumptions electric utilities should include in an IRP (in addition to its own scenarios and assumptions), among other requirements.

Ø    Require IRPs to include, among other listed requirements:

o  Projected energy purchased or produced by the electric utility from a renewable energy resource.  If the level of renewable energy purchased or produced is projected to drop over the planning periods set forth in the 5, 10, and 15 year projection of load obligations, the utility must demonstrate why the reduction is in the best interest of the ratepayers. 

o  An analysis of how the combined amounts of renewable energy and energy waste reduction achieved under the plan compare to the renewable energy resources and energy waste reduction goal of 35 percent by 2025 under the Clean and Renewable Energy and Energy Waste Reduction Act.

o  Long-term forecast of the electric utility's sales and peak demand under reasonable scenarios.

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

o   Plans for meeting current and future capacity needs along with cost estimates for proposed construction and major investments.

o   Details regarding the utility's plan to eliminate energy waste.

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

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

Ø  Require a utility to issue a request for proposals (RFP) for any new supply-side generation capacity resources needed to serve its projected electric load, applicable planning reserve margin, and local clearing requirement before filing an integrated resource plan (IRP).  Submitted RFPs must be included with the IRP.  Certain existing suppliers of electric generation capacity located in the utility's independent system operator's zone and which produce at least 200 megawatts could submit a written proposal directly to the PSC as an alternative to any supply-side resources included in the IRP, and would have standing to intervene in the IRP case.  (This provision would not limit any other person from submitting an alternative proposal under Section 6t and to petition for/be granted leave to intervene in the contested case proceeding.)

Ø  Require the PSC to approve an IRP if it meets all the following: 

o   The IRP represents the most reasonable and prudent means of meeting the electric utility's energy and capacity needs.  In making a determination, the PSC must consider such things as compliance with applicable state and federal environmental regulations, competitive pricing, reliability, diversity of generation supply, and whether the proposed levels of peak load reduction and energy waste reduction are reasonable and cost effective.

o   To the extent practicable, the construction or investment in a new or existing capacity resource is completed using a workforce composed of Michigan residents, with an exception for border counties.

o   The plan meets the bill's requirements for a completed IRP.

Ø  Provide a process by which a utility can submit revisions to an IRP that was denied, and require, after a new contested case hearing, the commission to approve or deny the revised plan.  However, if an IRP is denied, the bill allows an electric utility to proceed with a proposed construction, purchase, investment, or power purchase agreement contained in the IRP but without the assurances granted under Section 6t.

Ø  Consider costs included in an approved IRP that are begun within three years of PSC approval reasonable and prudent for cost recovery purposes. 

Ø  Finalize approved costs for a new electric generation facility only after the utility completes several listed requirements and filed the results with the PSC.  Requirements include implementing a competitive bidding process for construction of the facility and demonstrating that the finalized costs are not significantly higher than the costs initially approved during the IRP process.  If the costs are higher, the PSC must review and approve the costs only if it determines the higher costs are reasonable and prudent.

Ø  Require a utility to apply for a CON if the capacity resource is for construction of an electric generation facility of 225 megawatts or more.

Ø  Offer a financial incentive to a utility that enters into a new power purchase agreement with an entity with which it is not affiliated.

Ø  Include all reasonable and prudent costs for an approved IRP in the utility's retail rates.  If the actual costs exceed the approved amount, the utility must prove, by a preponderance of the evidence, that the costs are reasonable and prudent, otherwise excess costs will be deemed to have been incurred due to a lack of prudence.  Costs incurred as a result of fraud, concealment, gross mismanagement will be disallowed. 

Ø  Allow the PSC to modify or cancel approval of a project if the assumptions underlying an approved IRP change materially, or if the commission believes it is unlikely that a project or program will become commercially operational, and the PSC finds that completion of the project is no longer reasonable and prudent.

Performance-based Regulation Study

The bill adds Section 6u to do the following:

Ø  Require the PSC (within 90 days of the bill's effective date and in collaboration with representatives of each customer class, regulated utilities, and other interested parties) to study performance-based regulation systems under which a utility's authorized rate of return would depend on the utility achieving targeted policy outcomes.

Ø  Within one year of the bill's effective date, require the PSC to submit recommendations based on the study's results to the governor and Legislature.

Public Utility Regulatory Policies Act (PURPA)/Qualifying Facilities

Under state and federal law, electric utilities are obligated to purchase energy and capacity from "qualifying facilities."  The bill adds Section 6v to:

Ø  Define "qualifying facility" as qualifying cogeneration facilities or qualifying small power production facilities from which an electric utility in the state has an obligation to purchase energy and capacity within the meaning of Sections 201 and 210 of PURPA and associated federal regulations and orders.

Ø  Require the PSC to, at least every five years, conduct a contested case proceeding to reevaluate the procedures and rate schedules, including avoided cost rates to implement provisions of PURPA as it relates to QFs.

Ø  Allow, for small utilities (less than one million electric customers), the PSC to conduct periodic reevaluations using notice and comment procedures instead of a full contested case.

Ø  Specify the requirements of an order issued by the PSC under these provisions.

Ø  Require, within one year of the bill's effective date and every two years thereafter, the PSC to issue a report to the Michigan Agency for Energy and legislative committees with primary responsibility for energy and environmental issues.  The report must include a description and status of qualifying facilities in the state, current status of power purchase agreements of each QF, and the PSC's efforts to comply with PURPA requirements.

Resource Adequacy

Simply speaking, resource adequacy refers to having enough electricity on any given day to supply the needs (demand) of all of the customers of a utility or AES.  Of great importance, therefore, is the reliability of the system—knowing that the light will turn on when the switch is flipped.  Resource adequacy is an important component of reliability.  Meeting this goal is a rather complex dance, so to speak, between demand, generation, and transmission/distribution.   Variables such as extreme weather, equipment failures, closures of old or openings of new generation facilities, and unexpected demand, can all impact the availability of electricity and/or an electric provider's ability to obtain or deliver that electricity to customers. 

The bill adds Section 6w to address concerns regarding resource adequacy.  Briefly, as background, the Midcontinent Independent System Operator (MISO), which manages the bulk of the flow of electricity in the state, recently filed an application with the Federal Energy Regulatory Commission (FERC) to revise certain current models, and to propose a new model, pertaining to resource adequacy that, if approved, would have allowed MISO to establish a forward resource auction that would have operated in conjunction with the current Planning Reserve Auction.  Included in the filing was an option for a state in the MISO footprint to choose to employ a prevailing state compensation mechanism (PSCM) if it were more cost-effective and prudent than MISO's capacity forward auction.  If FERC did not approve the filing, Section 6w will require the PSC to determine if a state reliability mechanism (SRM) would be the cost-effective and prudent way to go instead of the capacity forward auction.  In addition, if FERC does not establish a resource adequacy tariff that includes a capacity forward auction or a PSCM by September 30, 2017, Section 6w will require that the commission establish a SRM.  (Information gleaned from Case No. U-18248 currently before the PSC.)  On February 2, 2017, FERC issued an order rejecting MISO's proposal.  According to a spokesperson for the PSC in response to the ruling by FERC, under provisions of Senate Bill 437, "[e]lectric choice providers will have the option to have customers pay a capacity charge determined by the MPSC or they can contract for the needed electric capability."

In more detail, the bill adds Section 6w to provide the following:

Ø  Prevailing state compensation mechanism 

The bill requires the PSC to examine whether the prevailing state compensation mechanism [an option for a state to elect a prevailing compensation rate for capacity consistent with the requirements of the Midcontinent Independent System Operator (MISO) resource adequacy tariff] would be more cost-effective, reasonable, and prudent than a capacity forward auction before ordering the prevailing state compensation mechanism (PSCM) to be implemented in any utility service territory in which the mechanism is not yet effective.  This would apply if MISO receives approval from the Federal Energy Regulatory Commission (FERC) to implement a resource adequacy tariff that provides for a capacity forward auction and includes the option to implement a prevailing state compensation mechanism for capacity.  A "capacity forward auction" means an auction-based resource adequacy construct and the associated tariffs developed by MISO for at least a portion of Michigan for three years forward or more. 

Before ordering implementation of the PSCM in a utility service territory, a contested case hearing must be held and intervention allowed by interested persons, alternative energy suppliers (AES), and the customers of an AES and the utility under consideration.  Findings for each utility under consideration as to whether or not the PSCM would be more cost-effective, reasonable, and prudent than the use of the capacity forward auction in meeting the local clearing requirement and the planning reserve margin requirement must be based on clear and convincing evidence.  "Local clearing requirement" (LCR) means the amount of capacity resources required to be in the local resource zone in which the provider's demand is served to ensure reliability in that zone as determined by the appropriate ISO for the local resource zone in which the electric provider's demand is served and by the PSC under provisions of subsection (8).  "Planning reserve margin requirement" means the amount of capacity equal to the forecasted coincident peak demand that occurs when the MISO footprint peak demand occurs plus a reserve margin that meets an acceptable loss or load expectation as set by the PSC or the MISO under provisions of subsection (8).


If a PSCM is implemented in a utility service territory, it must be implemented for a minimum of four consecutive planning years (unless it conflicts with the federal tariff).  The PSC must establish the charge as a capacity charge under provisions of Section 6w consistent with the approved resource adequacy tariff of MISO.

Ø  State reliability mechanism

"State reliability mechanism" means a plan adopted by the PSC in the absence of a prevailing state compensation mechanism to ensure reliability of the electric grid in the state consistent with provisions of subsection (8) described below.  If an option to implement a PSCM for capacity was not included as described above, the PSC must examine whether a state reliability mechanism would be more cost-effective, reasonable, and prudent than the capacity forward auction.  A contested case hearing must be held before the PSC could order implementation of the state reliability mechanism in one or more utility territories, and a determination by the PSC whether or not to implement the state reliability mechanism must be made in the same manner described for the prevailing state compensation mechanism. 

If FERC doesn't put into effect a resource adequacy tariff that includes a capacity forward auction or a prevailing state compensation mechanism by September 30, 2017, the PSC must establish a state reliability mechanism.  If implemented, it must be for at least four consecutive years beginning in the upcoming planning year.  A state reliability charge must be established in the same manner as a capacity charge.

Under subsection 8, if a state reliability mechanism is required to be established under the bill, the PSC must do all of the following:

o   Require, by December 1 of each year, each electric utility to demonstrate to the PSC that for the planning year beginning four years after the beginning of the current planning year, that it owns or has contractual rights to sufficient capacity to meet its capacity obligations as set by MISO or the PSC, as applicable.

o   Require, by the seventh business day of February each year, that each AES, cooperative electric utility, or municipally owned electric utility demonstrate to the PSC that the entity owns or has contractual rights to sufficient capacity to meet its capacity obligations as set by MISO or the PSC, as applicable. 

One or more municipally owned electric utilities, or one or more cooperative electric utilities, could aggregate their respective members' capacity resources that are located in the same local resource zone to meet the requirements described above.  Either entity could meet the capacity obligations through any resource, including a resource acquired through a capacity forward auction that MISO allows to qualify for meeting the local clearing requirement.  However, an entity's payment of an auction price related to a capacity deficiency as part of a capacity forward auction conducted by MISO does not by itself satisfy the resource adequacy resource that meets this provision's requirements. 

o   Require an AES to demonstrate to the PSC, by the seventh business day of February, 2018, that for the planning year beginning June 1, 2018, and for the subsequent three planning years, that the AES owns or has contractual rights to sufficient capacity to meet its capacity obligations as set by MISO or the PSC, as applicable.  If the PSC finds an AES has failed to demonstrate it can meet a portion or all of its capacity obligation, the PSC must do all of the following:

§  For alternative electric load, require the payment of a capacity charge determined, assessed, and applied in the same manner as under subsection (3) of Section 6w, described below, for that portion of the load not covered as required by the bill.  If a capacity charge must be paid under subsection 8 in the planning year beginning June 1, 2018 or any of the three subsequent planning years, the capacity charge is applicable for each of those planning years.

§  For a cooperative or municipally owned electric utility, recommend to the attorney general that suit be brought (consistent with the bill's provisions) to require that procurement.

§  For an electric utility, require any audits and reporting as the PSC considers necessary to determine if sufficient capacity is procured.  If an electric utility fails to meet its capacity obligations, the PSC may assess appropriate and reasonable fines, penalties, and customer refunds under the act.  

o   Request, in order to determine the capacity obligations, that MISO provide technical assistance in determining the local clearing requirement and planning reserve margin requirement.  If MISO declines, or has not made a determination by October 1 of that year, the commission must set—consistent with federal reliability requirements—any required local clearing requirement and planning reserve margin requirement.

o   Request, in order to determine if resources put forward will meet such federal reliability requirements, technical assistance from MISO to assist with assessing resources to ensure that any resources will meet federal reliability requirements.  If the technical assistance is rendered, the PSC must accept MISO's determinations unless the commission finds adequate justification to deviate from the determinations related to the qualification of resources.  If MISO declines or has not made a determination by February 28, the PSC must make those determinations.

Ø  Capacity charge 

The bill requires the PSC to hold a contested case hearing (to conclude by December 1 of each year) to determine a capacity charge.  Notice of the single capacity charge as determined for each territory must be provided to the public.  No new capacity charge would be required to be paid before June 1, 2018.  The capacity charge is applied to alternative electric load that isn't exempt under the bill.  If a capacity forward auction is implemented by the PSC, then a capacity charge does not apply beginning in the first year that such an auction is effective.

In determining the capacity charge, subsection (3) requires the PSC to do both of the following for the applicable term of the capacity charge to ensure that the resulting capacity charge does not differ for full service load and alternative electric supplier load:

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

o   Subtract all non-capacity related electric generation costs.  Costs include, but are not limited to, those previously set for recovery through net stranded cost recovery and securitization and the projected revenues, net of projected fuel costs, from all of the following:

§  All energy market sales.

§  Off-system energy sales.

§  Ancillary services sales.

§  Energy sales under unit-specific bilateral contracts.


Ø  The PSC is required to provide for a true-up mechanism that results in a utility charge or credit for the difference between the projected net revenues and the actual net revenues reflected in the capacity charge.  The true-up must be reflected in the capacity charge in the subsequent year. The methodology used to set the capacity charge must be the same as that used in the true-up for the applicable planning year.

Ø  The commission also must review or amend the capacity charge in all subsequent rate cases, power supply cost recovery cases, or separate proceedings established for that purpose.  This must be done at least once every year.

Ø  A capacity charge could not be assessed for any portion of capacity obligations for each planning year for which an AES can demonstrate that it can meet its capacity obligations through owned or contractual rights to any resource allowed for that purpose by MISO.  This provision could not be applied in any way that conflicts with an applicable federal resource adequacy tariff. 

Ø  Any electric provider that previously demonstrated it could meet all or portion of its capacity obligations must give notice to the PSC if it does not expect to meet those obligations and instead expects to pay a capacity charge.  The notice must be given by September 1 of the year that is four years before the beginning of the applicable planning year. 

"Electric provider" means any of the following:

o   Any person or entity regulated by the PSC for the purpose of selling electricity to retail customers in the state.

o   A municipally owned utility in the state.

o   A cooperative electric utility in the state.

o   An AES licensed under Section 10a of the act.

Ø  An electric provider must provide capacity to meet the capacity obligation for the portion of that load taking service from an AES that is covered by the capacity charge during the period that such charge is effective. The AES is obligated to provide capacity for the portion of the load for which it demonstrated an ability to meet its capacity obligations. If an AES ceases to provide service for a portion or all of its load, the AES must allow, at a cost no higher than the determined capacity charge, the assignment of any right to that capacity in the applicable planning year to whatever electric provider accepts that load.

Ø  The dates under Section 6w would have to be adjusted if needed to ensure proper alignment with MISO's procedures and requirements, though changes must ensure providers still meet applicable reliability requirements.

Ø  The PSC would be prohibited from permitting a capacity charge to be assessed under Section 6w for any year in which it elects the capacity forward auction instead of the prevailing state compensation mechanism or the state reliability mechanism.

Ø  The bill specifies that nothing in the act could prevent the PSC from determining a generation capacity charge under the reliability assurance agreement, rate schedule FERC No. 44 of PJM Interconnection, LLC (an independent system operator), as approved by FERC in Docket No. ER10-2710 or similar successor tariff.

Ø  The attorney general or a customer of a cooperative or municipally owned electric utility could bring a civil action for injunctive relief in the circuit court against the utility if it fails to meet applicable reliability requirements, as provided in the bill.

Energy Waste Reduction Incentives

The bill adds Section 6x to ensure equivalent consideration of energy waste reduction (EWR) resources within the IRP process, and will require, by January 1, 2021, the PSC to authorize a shared savings mechanism for an electric utility to the extent the utility has not otherwise capitalized the costs of the EWR, conservation, demand reduction, and other waste reduction measures as follows:

Ø  A savings of 1 percent to 1.25 percent of the utility's total annual weather-adjusted retail sales in megawatt hours in the previous calendar year equals a shared savings incentive of 25 percent of the net benefits validated as a result of the programs implemented by the electric utility related to EWR, conservation, demand reduction, and other waste reduction, but not to exceed 15 percent of the utility's expenditures associated with implementing EWR programs for the calendar year in which the shared savings mechanism was authorized.  The bill details how the PSC is to determine the net benefits.

Ø  Greater than 1.25 percent to 1.5 percent savings equals a shared savings incentive of 27.5 percent of the net benefits, with a cap at 17.5 percent of expenditures.

Ø  Greater than 1.5 percent savings equals a shared savings incentive of 30 percent of the net benefits, with a cap of 20 percent of expenditures.

Discontinuance of Service by a Covered Utility

The bill adds Section 6z to prevent a covered utility from discontinuing utility service to a geographic area without first filing an abandonment application with the PSC and obtaining the commission's approval to discontinue that service after notice and a contested case hearing.  The PSC must determine there is clear and convincing evidence that all affected customers would have access to affordable, reliable, and safe utility service from an alternative source before an abandonment application could be approved.  An abandonment application would not have to be filed if a covered utility providing service was discontinuing that service to a specific parcel or parcels in order to enable a different covered utility (which is legally permitted to provide such service) to provide the service.

  "Covered utility" is defined to mean any of the following:

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

Ø  A rural gas cooperative.

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

Further, not less than 30 days after an electric utility files a proposal to retire an electric generation plant, the utility must provide the proposal in its entirety to the PSC.  Not less than 60 days before an electric utility applies to the Operating Reliability Corporation Subcommittee of the North American Electric Reliability Corporation for approval of a proposal to revise an existing load balancing authority, the utility must:

o   File with the PSC a full and complete report of the proposed revision.

o   Serve a copy of that report on all other electric utilities in the state.

Revision of Purpose of Customer Choice Act

Currently, Sections 10 through 10bb are known as the Customer Choice and Electricity Reliability Act; this title will be eliminated.  Several of the stated purposes of the act will also be deleted, including:  to ensure all retail customers of electric power have a choice of suppliers; to allow and encourage the MPSC to foster competition in the provision of electric supply and maintain regulation of electric supply for customers who continue to choose supply from incumbent electric utilities; and to encourage the development and construction of merchant plants which will diversify the ownership of electric generation.

Retail Open Access (ROA)

The bill amends Section 10a (electric choice) to do the following, among other things:

Ø  Retain the provision allowing retail customers of an electric utility or provider to take service from an alternative electric supplier (AES) and keep the current 10 percent cap of an electric utility's average weather-adjusted retail sales that may take service from an AES at any time.

Ø  Require the PSC, if fewer than 10 percent of a utility's customers take service from AESs in the preceding calendar year, to set the utility's cap for the current year and five subsequent calendar years at the percentage amount of weather-adjusted retail sales for the preceding calendar year rounded up to the nearest whole percentage.  If the cap is not adjusted for six consecutive calendar years, the cap must return to the 10 percent in the calendar year following the sixth consecutive year.

If a utility serving fewer than 200,000 Michigan customers has not had any load served by an AES in the preceding four years, the PSC must adjust the cap in accordance with this provision for no more than two consecutive calendar years.

Ø  Allow an existing facility receiving 100 percent of its electric service from an AES on or after the bill's effective date to continue to purchase electricity from an AES, even if the sale exceeds 10 percent of the servicing utility's average weather-adjusted retail sales.  This applies for both the facility's existing electric choice load and any expanded load that arises after the bill's effective date, as well as for any new facility similar in nature to the existing facility that is constructed or acquired by the customer on a contiguous site, including a site separated by a public right-of-way, if the customer owns more than 50 percent of that facility.  This provision does not authorize or permit an existing facility served by an electric utility on standard tariff on the bill's effective date to be served by an alternative electric supplier.

Ø  Accommodate the settlement agreement with Cliffs Natural Resources, operator of the Tilden Mining Company, for the WEC Energy Group, Inc. to build power plants in the Upper Peninsula and exempt customers and the AES providing electric service to them from being subject to the requirements contained in the bill that added Section 6t and any administrative regulations adopted under the bill's provisions.  PSC orders establishing rates, terms, and conditions of retail open access (ROA) issued before the bill's effective date (April 20, 2017) remain in effect with regard to ROA provided under this provision.

Ø  Keep all customers on an enrollment queue waiting to take retail open access (ROA) as of December 31, 2015, on that queue and allow prospective ROA customers to be added; a customer may be removed from the queue by notifying the utility.  If a spot opens up, and the customer chooses to take service from an AES, the prospective AES must notify the electric utility within five business days after being notified by the customer that the customer is choosing ROA.  If the AES fails to notify the utility within the five business days, or the customer chooses not to take ROA, the customer will be removed from the queue.  A customer can return to the queue if the prospective AES submits an enrollment request to the utility. 

Ø  Require each electric utility to file with the PSC not later than January 15 of each year a rank-ordered queue of all customers awaiting ROA, including the estimated amount of electricity used by each of customers on the queue.  Customer-specific information contained in the filing is confidential and exempt from release under the Freedom of Information Act, though aggregated information could be released in the PSC's annual report as long as individual customer information or data is not released. 

Ø  If an AES notifies a customer that it cannot provide service, allow the customer 60 days to acquire service from a different AES (and 180 days if the customer is a public entity).

Ø  As a condition of licensure, require an AES to meet all of the requirements of the act.

Ø  Preserve the right of persons to obtain self-service power or to engage in affiliate wheeling.

Ø  Preserve the ability of customers to switch from receiving service from an AES to receiving service from the electric utility under PSC-approved procedures.

Penalties for Non-compliance

Section 10c authorizes the PSC to impose fines and order other remedies for violations of the act by an electric utility or alternative electric supplier (AES); the bill applies the penalties and remedies to natural gas utilities that have not complied with a provision or order issued under Section 10ee of the act (Section 10ee is added by the bill to require the PSC to establish a code of conduct that applies to all utilities.)

Shut-off Protections

The bill amends Section 10t to allow utilities to shut off service, after proper notice, to customers who failed to pay the monthly installment payments under a residential energy projects program added to the Clean and Renewable Energy and Energy Waste Reduction Act by Senate Bill 438, Public Act 342 of 2016.  Service may also be shut off to a customer who has not paid the per-meter charge described in Section 205 of the Clean and Renewable Energy and Energy Waste Reduction Act.

Fiscal Year 2017 Appropriations

For the fiscal year ending September 30, 2017, the bill makes the following appropriations from the assessments imposed against public utilities under Public Act 299 of 1972 to implement provisions of the bill:

Ø  $1,950,000 to the PSC for 13.0 full-time equated (FTE) positions.

Ø  $150,000 to the attorney general for 1.0 FTE.

Ø  $600,000 to the Michigan Administrative Hearing System for 4.0 FTEs.

Ø  $150,000 to the Department of Environmental Quality for 1.0 FTE.

Ø  $260,000 to the Michigan Agency for Energy for 2.0 FTEs.

Utility Code of Conduct

The bill adds Section 10ee which replaces and modifies current provisions in Section 10a requiring the PSC to establish a Code of Conduct for all electric utilities and AES.  The purpose of the Code of Conduct remains the same except for some modifications.  Among the changes, the new Section 10ee does the following:

Ø  Applies the Code of Conduct also to a natural gas utility.

Ø  Allows utilities to offer value-added programs and services if the public interest is not harmed by unduly restraining trade or competition in an unregulated market.

Ø  Defines "value-added programs and services" to mean programs and services that are utility or energy related; included are home comfort and protection, appliance service, building energy performance, alternative energy options, or engineering and construction services. The term does not include energy optimization or energy waste reduction programs paid for by utility customers as part of their regulated rates.

Ø  Allows assets of a utility to be used in the operation of an unregulated value-added program or service if the utility is compensated for the proportional use of the utility's assets.

Ø  Requires notification by a utility to the PSC of its intent to offer value-added programs and services before offering them to customers, as well as a description of the program or services.

Ø  Requires the utility to maintain separate books, records, and office space for the program or service and provide an annual report to the PSC that includes the extent to which the utility's rates were affected by the allocations from the utility to the program or service.  The report may be included in a request for rate relief.

Ø  Prohibits the program or service from being marketed or promoted on a customer's utility bill or as an insert with the bill.  However, a utility could include charges for the program or service on monthly utility bills if it complies with requirements as specified in the bill.

Ø  Requires utilities marketing programs or services to the public to adhere to requirements listed in the bill; these include allowing competitors to request and receive lists of customers receiving regulated service in the same manner as for value-added programs or services and also information that must be provided to potential customers (e.g., that the program or service is not regulated by the PSC).

Ø  Requires the PSC to include only the revenues received by a utility to recover costs directly attributable to a value-based program or service in determining a utility's base rates. The bill requires PSC approval to use revenue received from value-added programs or services to offset a utility's base rates.

Ø  Requires a utility to pay all reasonable costs to a prevailing party, in addition to allowable penalties, for violations of the Code of Conduct.

Ø  Requires a utility offering value-added programs or services to file an annual report with the PSC. The report must provide a list of offered programs and services, estimated market share of each program or service, and a detailed accounting of how the costs for the programs or services were apportioned between the utility and the programs and services.  The PSC may conduct an audit of the books and records of the utility and programs and services to ensure compliance with the Code of Conduct.

Energy Ombudsman

Section 10ff is added to establish, as of January 1, 2017, an Energy Ombudsman within the Michigan Agency for Energy.  The bill:

Ø  Establishes requirements for the office.

Ø  Requires the Ombudsman to:

o   Serve as liaison for businesses and individuals by guiding energy issues, problems, and disputes to the appropriate entity, agency, or venue for resolution.

o   Monitor activities of the PSC, Michigan Agency for Energy, and other state regulatory entities, and communicate those entities' decisions, policy changes, and developments to businesses and individuals. Issues to be monitored include renewable sources of energy, energy efficiency, and net metering, among others.

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

o   Monitor implementation of the Code of Conduct and compile and annually publish statistics on unregulated services provided by utilities and their affiliates.


Cost of Service Rates

The bill amends Section 11 to require the PSC to ensure the establishment of electric rates equal to the cost of providing service to each customer class. To that end, the PSC must ensure that each class or sub-class is assessed for its fair and equitable use of the electric grid.  If doing so would have a material impact on customer rates, the PSC could approve an order implementing those rates over a suitable number of years.

The cost of providing service to each class must be based on allocating production-related costs using the 75-0-25 method of cost allocation and transmission costs and using the 100 percent demand method (instead of the 50-25-25 method) of cost allocation.  (These costs allocation formulas were approved by the PSC in implementing provisions of Public Act 169 of 2014.)  The PSC could modify this method if it does not ensure that rates are equal to the cost of service.

Further, the bill deletes provisions of Public Act 169 of 2014, as well as other provisions, made obsolete by the amendments contained in the bill.


The following sections of the act will be repealed:

Ø  Section 6c, which pertained to a now-defunct energy conservation program, and energy conservation loan program, for residential customers of electric and gas utilities.

Ø  Section 6e, which required a report be submitted by March 25, 1983.


Ø  Moves the Michigan Renewables Energy Program from the jurisdiction of the PSC to the Michigan Agency for Energy.

Ø  Deletes numerous obsolete provisions; for example, dates by which a report was to be submitted.

The bill takes effect 120 days after enactment (April 20, 2017).  Senate Bill 437 and Senate Bill 438 were tie-barred to each other; both have been enacted.

MCL 460.6a et al.



Senate Bill 437 would have a significant fiscal impact on the Department of Licensing and Regulatory Affairs and a minimal fiscal impact to the Attorney General. The bill would create a variety of additional responsibilities for the Public Service Commission (PSC), increasing administrative costs for the Department of Licensing and Regulatory Affairs. The PSC would need to promulgate rules and make administrative changes in order to comply with new requirements created by the bill. These additional responsibilities are likely to result in an indeterminate fiscal impact, since fees collected by the department are likely to be adjusted in order to cover the expenditures necessary to fund the PSC's activities. The activities of the PSC are funded mainly through public utility assessments, so the increased administrative costs would ostensibly be covered by increases in public utility assessments.

The bill would also create some responsibilities for the Michigan Agency for Energy; namely, their oversight of the Michigan Renewables Energy Program and the establishment of the energy ombudsman within the agency. The fiscal impact of these changes on the LARA is indeterminate.

The bill would provide an estimated $500,000 increase in revenue to the Utility Consumer Representation Fund. The fund is used by the Utility Consumer Representation Board (UCRB) and the Attorney General for issuing grants to support ratepayer advocacy cases. Revenue from the fund is currently split evenly between the UCRB and the Attorney General, with each receiving approximately $600,000 for FY 2016-17. The bill would increase the fund and change the allocation with $1 million to the Attorney General and $750,000 to the UCPB as a new base adjusted annually according to the fund's current method of using the Consumer Price Index (CPI) of the metro Detroit area. The bill allows unspent funds to be carried over into following years as the current law allows.

The bill will save approximately $400,000 annually from the General Fund. According to the Attorney General, the bill's expansion of the statutory scope of the fund's use for general consumer rate cases would permit it to use restricted revenue from the Utility Consumer Representation Fund instead of using approximately $400,000 annually from GF/GP revenue. Despite the funding increase from the bill the Attorney General will only be able to provide a comparable level or ratepayer services as before due to the rising costs of expert testimony, the potential increased number of cases from the bill, the transfer of the use of the Utility Consumer Representation Fund instead of GF/GP, and the diminishing availability of representation funds retained from much earlier, lower-cost years.

The bill would appropriate $1,950,000 to the Public Service Commission for the hiring of 13.0 FTEs; $150,000 to the Department of Attorney General for the hiring of 1.0 FTE; $600,000 to the Michigan Administrative Hearing System for the hiring of 4.0 FTEs; $150,000 to the Department of Environmental Quality for the hiring of 1.0 FTE; and $260,000 to the Michigan Agency for Energy for the hiring of 2.0 FTEs, all to implement the provisions of the amendatory act that added Section 6T. These funds are appropriated from public utility assessments imposed under Public Act 299 of 1972, MCL 460.111 to 460.120.


Senate Bill 437 would have a neutral fiscal impact on the Department of Environmental Quality (DEQ).  The bill includes a provision that would require DEQ to collaborate with the Public Service Commission to implement an integrated resource plan within four months of the new act's taking effect and every five years thereafter. The bill appropriates $150,000 to DEQ for FY 2016-17 from an unspecified fund source to hire 1.0 FTE to facilitate this implementation on behalf of DEQ.  It is unclear whether this appropriation would fully cover costs incurred by the department during plan implementation.

                                                                                        Legislative Analyst:   Susan Stutzky

                                                                                                Fiscal Analyst:   Marcus Coffin

                                                                                                                           Michael Cnossen

                                                                                                                           Austin Scott

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