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On October 1, 2026, parties filed comments on Phase 2 Straw Proposal on reliability-plus updates and next steps.

As background, the Michigan Public Service Commission (PSC) issued a press release announcing that it had released a straw proposal to facilitate discussion on the second phase of its performance incentive initiative, which is exploring challenges to utility readiness to accommodate and leverage growth of distributed generation (DG), electric vehicles, and other cost-effective distributed energy resources (DERs).  The second phase of the Commission’s performance incentive initiative, called Reliability-Plus.

The Michigan Commission originally opened this proceeding to establish the Financial Incentives and Disincentives Workgroup as part of its “reliability-plus” initiative. The PSC is now in the second phase of that initiative, which will focus on considering challenges to the grid’s ability to accommodate and leverage the rise in adoption of distributed generation (DG), electric vehicles (EVs), and other distributed energy resources (DERs).

Selected comments are presented below.

Great Lakes Renewable Energy Association: (i) emphasized the “need for quarterly public reporting of all performance metrics”; (ii) recommended Michigan PSC leverage “areas where the Distribution System Plan (DSP) and Integrated Resource Plan (IRP) processes naturally reinforce each other,” such as DSP reliability outcomes influencing IRP long-term resource adequacy (RA), DSP hosting capacity constraints affecting IRP modeling of DERs and VPPs, and “DSP circuit-level planning and IRP capacity planning” both including non-wires alternatives (NWAs)/VPP deployment strategies; (iii) emphasized the need to set incentives and penalties “at levels that meaningfully influence utility financial outcomes, and management action,” recommending that incentives “only be awarded when utilities are demonstrably on a path to top-quartile national performance” and penalties apply “when utilities remain in the bottom quartile”; and (iv) recommended MIPSC “develop a new DSP-linked performance metric that measures how quickly customer service is restored through distribution system switching” and a new quarterly public metric of utility spending on outage restoration.

Michigan Energy Innovation Business Council and Advanced Energy United: (i) recommended MIPSC treat the “metrics, scorecards, and [performance incentive mechanisms (PIMs)] as dynamic and establish a process to review, revise, and update these items on an annual or semi-annual basis”; (ii) recommended Michigan PSC clarify the parameters of the proposed penalty for delays in energization of projects due to deviations from the Michigan Interconnection and DG Standards (MIXDG rules) and incorporate the penalty into a symmetrical PIM with a potential reward of a similar scale; (iii) supported the proposed “initial target of 75 days for the processing of Level 4 and 5” interconnection applications; (iv) “update its reporting requirements to gather more data to understand the challenges associated with flexible interconnection and load energization timelines”; (v) disagreed with the claim that “the DER Interconnection PIM [would be] a sufficient method to improve hosting capacity maps going forward,” since “hosting capacity maps assist customers prior to an application being filed with the utility,” and instead recommended MIPSC “establish enhanced metrics and a scorecard that rewards real-time updates to combined hosting capacity and load-carrying capacity maps with sufficient granularity to enable DER and EV deployment”; (vi) disagreed with providing a utility “an incentive simply for achieving the VPP deployment targets… in an IRP without consideration of benefits beyond peak load reduction and the verification of specific benefits associated with VPP use,” and encouraged “exploration of a VPP PIM that contains tiered incentives based on benefits that a group of aggregated DERs can provide”; (vii) supported “the proposed AMI Utilization and Grid Modernization metrics,” and requested “that Staff set an accelerated reporting schedule for these metrics that provides a current and actionable view of each utility’s distribution grid infrastructure”; (viii) recommended “requiring reporting that is frequent and granular enough to support operational accountability and informed planning (e.g., on a monthly basis),” arguing that “Annual or high-level summary data may not reveal short-duration constraints, recurring operational issues, delayed interconnections, or the realized benefits of DER, DR, and other grid investments”; (ix) supported “restructuring DR PIMs around verified performance rather than utility spending”; and (x) argued that “further data collection should occur within, and not postpone, a date-certain PIM implementation process,” recommending that MIPSC at least “establish a date-certain schedule and framework for adopting an Outage Restoration PIM”

Association of Businesses Advocating Tariff Equity: (i) said that PSC “should confine Phase 2 of the Reliability-Plus framework to reporting metrics and scorecards,” arguing that MIPSC “has not identified statutory authority for shareholder incentives outside the service quality and reliability standards” and objecting that “the Straw Proposal does not specify how any incentive would be capped, recovered, or allocated among customer classes” and that “the proposed incentives depart from each of the customer protections [MIPSC] adopted for the Phase 1 reliability mechanism”; (ii) said that, while the “Straw Proposal’s rejection of PIMs and financial incentives for 4.8 kV conversion, data access and hosting capacity, outage response and notification, and Level 4 and 5 interconnection performance is reasonable… [its] introduction of PIMs for Level 1, 2, and 3 DER interconnection timelines, and for VPP/DER deployment should not be adopted”; (iii) objected that the “PIM proposals are not symmetrical”; (iv) objected that the proposal “lacks details regarding the cost treatment” of DER interconnection penalties, recommending MIPSC “specify the credit mechanism and class allocation,” “confirm that a penalty determination should follow notice and an opportunity to be heard rather than an administrative annual review,” and “define the specific criteria that it will apply to a penalty determination”; (v) argued that the proposed “DER interconnection PIM would only benefit a narrow group of utility customers — small customers and developers seeking to interconnect new DERs smaller than 150 kWac in size — rather than ratepayers as a whole,” since “the volume of DER interconnections is overwhelmingly small solar and solar-plus-storage” but the proposal lacks “a class-specific recovery mechanism”; (vi) argued that the issue of flexible interconnections “does not need a PIM” and “should be referred to the Interconnection Technical Workgroup… to develop specific criteria to determine whether flexible interconnections introduce reliability risks” and determine their cost-effectiveness, and to assign associated costs to interconnecting customers; (vii) argued that utility pursuit “of NWA projects such as VPPs that involve the deployment of aggregated DERs as an alternative to new distribution infrastructure… should be part of that utility’s normal course of business and its legal obligation to plan its system to provide reliable electric service at the lowest reasonable cost,” and not dealt with via PIM; (viii) supported the proposed grid utilization metrics, but opposed any PIM based thereon, arguing that “Effectively utilizing existing distribution assets is part and parcel of the utility’s basic obligation to provide reliable service to its customers at the lowest reasonable cost” and is sufficiently addressed by the traditional regulatory model; (ix) agreed that the current DR “incentive tied to program spending is the wrong design, since it rewards expenditure regardless of delivered capacity,” but argued that, rather than the proposal to tie the incentive to DR performance, “The better course is to eliminate the spending-based incentive and address DR performance through the utility’s least-cost planning obligation”; and (x) said that it “supports the scorecard-only recommendation of the Straw Proposal for outage restoration.”

Next Steps:

Reply comments on Phase 2 Straw Proposal are due by November 5, 2026.