DEPARTMENT OF LICENSING AND REGULATORY AFFAIRS  
PUBLIC SERVICE COMMISSION  
INTERCONNECTION AND DISTRIBUTED GENERATION STANDARDS  
Filed with the secretary of state on April 25, 2023  
These rules take effect immediately upon filing with the secretary of state unless adopted  
under section 33, 44, or 45a(9) of the administrative procedures act of 1969, 1969 PA  
306, MCL 24.233, 24.244, or 24.245a. Rules adopted under these sections become  
effective 7 days after filing with the secretary of state.  
(By authority conferred on the public service commission by section 7 of 1909 PA 106,  
MCL 460.557, section 5 of 1919 PA 419, MCL 460.55, sections 4, 6, and 10e of 1939 PA  
3, MCL 460.4, 460.6, and 460.10e, and section 173 of the clean and renewable energy  
and energy waste reduction act, 2008 PA 295, MCL 460.1173)  
R 460.901a, R 460.901b, R 460.902, R 460.904, R 460.906, R 460.908, R 460.910, R  
460.911, R 460.920, R 460.922, R 460.924, R 460.926, R 460.928, R 460.930, R  
460.932, R 460.934, R 460.936, R 460.938, R 460.942, R 460.944, R 460.946, R  
460.948, R 460.950, R 460.952, R 460.954, R 460.956, R 460.958, R 460.960, R  
460.962, R 460.964, R 460.966, R 460.968, R 460.970, R 460.974, R 460.976, R  
460.978, R 460.980, R 460.982, R 460.984, R 460.986, R 460.988, R 460.990, R  
460.991, R 460.992, R 460.1001, R 460.1004, R 460.1006, R 460.1008, R 460.1010, R  
460.1012, R 460.1014, R 460.1016, R 460.1018, R 460.1020, R 460.1022, R 460.1024,  
and R 460.1026 are added to the Michigan Administrative Code, as follows:  
PART 1. GENERAL PROVISIONS  
R 460.901a Definitions; A-I.  
Rule 1a. As used in these rules:  
(a) “AC” means alternating current at 60 Hertz.  
(b) “Affected system” means another electric utility’s distribution system, a municipal  
electric utility’s distribution system, the transmission system, or transmission system-  
connected generation which may be affected by the proposed interconnection.  
(c) “Affiliate” means that term as defined in R 460.10102(1)(a).  
(d) “Alternative electric supplier” means that term as defined in section 10g of 1939 PA  
3, MCL 460.10g.  
(e) “Alternative electric supplier distributed generation program plan” means a  
document supplied by an alternative electric supplier that provides detailed information to  
an applicant about the alternative electric supplier's distributed generation program.  
(f) “Alternative electric supplier legacy net metering program plan” means a document  
supplied by an alternative electric supplier that provides detailed information to an  
applicant about the alternative electric supplier's legacy net metering program.  
January 31, 2023  
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(g) “Applicant” means the person or entity submitting an interconnection application, a  
legacy net metering program application, or a distributed generation program application.  
An applicant is not required to be an existing customer of an electric utility. An electric  
utility is considered an applicant when it submits an interconnection application for a  
DER that is not a temporary DER or a substation backup energy storage device.  
(h) “Application” means an interconnection application, a legacy net metering program  
application, or a distributed generation program application.  
(i) “Area network” means a location on the distribution system served by multiple  
transformers interconnected in an electrical network circuit.  
(j) “Business day” means Monday through Friday, starting at 12:00:00 a.m. and ending  
at 11:59:59 p.m., excluding electric utility holidays and any day where electric service is  
interrupted for 10% or more of an electric utility’s customers.  
(k) “Calendar day” means every day, including Saturdays, Sundays, and holidays.  
(l) “Certified” means an inverter-based system has met acceptable safety and reliability  
standards by a nationally recognized testing laboratory in conformance with IEEE  
1547.1-2020 and the UL 1741 September 28, 2021 edition except that prior to  
commercial availability, inverter-based systems which conform to the UL 1741SA  
September 7, 2016 edition are acceptable.  
(m) “Commission” means the Michigan public service commission.  
(n) “Commissioning test” means the test and verification procedure that is performed  
on a device or combination of devices forming a system to confirm that the device or  
system, as designed, delivered, and installed, meets the interconnection and  
interoperability requirements of IEEE 1547-2018 and IEEE 1547.1-2020. A  
commissioning test must include visual inspections and may include, as applicable, an  
operability and functional performance test and functional tests to verify interoperability  
of a combination of devices forming a system.  
(o) “Conforming” means the information in an interconnection application is consistent  
with the general principles of distribution system operation and DER characteristics.  
(p) “Customer” means a person or entity who receives electric service from an electric  
utility’s distribution system or a person who participates in a legacy net metering or  
distributed generation program through an alternative electric supplier or electric utility.  
(q) “DC” means “direct current.”  
(r) “Distributed energy resource” or “DER” means a source of electric power and its  
associated facilities that is connected to a distribution system. DER includes both  
generators and energy storage devices capable of exporting active power to a distribution  
system.  
(s) “Distributed generation program” means the distributed generation program  
approved by the commission and included in an electric utility’s tariff pursuant to section  
6a(14) of 1939 PA 3, MCL 460.6a, or established in an alternative electric supplier  
distributed generation program plan.  
(t) “Distribution system” means the structures, equipment, and facilities owned and  
operated by an electric utility to deliver electricity to end users, not including  
transmission and generation facilities that are subject to the jurisdiction of the federal  
energy regulatory commission.  
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(u) “Distribution upgrades” mean the additions, modifications, or improvements to  
the distribution system necessary to accommodate a DER’s connection to the distribution  
system.  
(v) “Electric utility” means any person or entity whose rates are regulated by the  
commission for selling electricity to retail customers in this state. For purposes of R  
460.901a through R 460.992 only, “electric utility” includes cooperative electric utilities  
that are member regulated as provided in section 4 of the electric cooperative member-  
regulation act, 2008 PA 167, MCL 460.34.  
(w) “Electrically coincident” means that 2 or more proposed DERs associated with  
pending interconnection applications have operating characteristics and nameplate  
capacities which require that distribution upgrades will be necessary if the DERs are  
installed in electrical proximity with each other on a distribution system.  
(x) “Electrically remote” means a proposed DER is not electrically coincident with a  
DER that is associated with a pending interconnection application.  
(y) “Eligible electric generator” means a methane digester or renewable energy system  
with a generation capacity limited to a customer’s electric need and that does not exceed  
either of the following:  
(i) 150 kWac of aggregate generation at a single site for a renewable energy system.  
(ii) 550 kWac of aggregate generation at a single site for a methane digester.  
(z) “Energy storage device” means a device that captures energy produced at one time,  
stores that energy for a period of time, and delivers that energy as electricity for use at a  
future time. For purposes of these rules, an energy storage device may be considered a  
DER.  
(aa) “Export capacity” means the amount of power that can be transferred from the DER  
to the distribution system. Export capacity is either the nameplate rating or a lower  
amount if limited using an acceptable means that is defined in an electric utility’s  
interconnection procedures.  
(bb) “Facilities study” means a study to specify and estimate the cost of the equipment,  
engineering, procurement, and construction work if distribution upgrades or  
interconnection facilities are required.  
(cc) “Fast track” means the procedure used for evaluating a proposed interconnection  
that makes use of screening processes, as described in R 460.944 to R 460.950.  
(dd) “Force majeure event” means an act of God; labor disturbance; act of the public  
enemy; war; insurrection; riot; fire, storm, or flood; explosion, breakage, or accident to  
machinery or equipment; an emergency order, regulation or restriction imposed by  
governmental, military, or lawfully established civilian authorities; or another cause  
beyond a party’s control. A force majeure event does not include an act of negligence or  
intentional wrongdoing.  
(ee) “Full retail rate” means the power supply and distribution components of the cost  
of electric service. Full retail rate does not include a system access charge, service  
charge, or other charge that is assessed on a per meter, premise, or customer basis.  
(ff) “Good standing” means an applicant has paid in full all undisputed bills rendered  
by the interconnecting electric utility and any alternative electric supplier in a timely  
manner and none of these bills are in arrears.  
(gg) “Governmental authority” means any federal, state, local, or other governmental  
regulatory or administrative agency, court, commission, department, board, or other  
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governmental subdivision, legislature, rulemaking board, tribunal, or other governmental  
authority having jurisdiction over the parties, their respective facilities, or the respective  
services they provide, and exercising or entitled to exercise any administrative, executive,  
police, or taxing authority or power; provided, however, that this term does not include  
the applicant, interconnection customer, electric utility, or any affiliate thereof.  
(hh) “GPS” means global positioning system.  
(ii) “Grid network” means a configuration of a distribution system or an area of a  
distribution system in which each customer is supplied electric energy at the secondary  
voltage by more than 1 transformer.  
(jj) “High voltage distribution” means those parts of a distribution system that operate  
within a voltage range specified in the electric utility’s interconnection procedures. For  
purposes of these rules, the term “subtransmission” means the same as high voltage  
distribution.  
(kk) “IEEE” means institute of electrical and electronics engineers.  
(ll) “IEEE 1547-2018” means “IEEE Standard for Interconnection and Interoperability  
of Distributed Energy Resources with Associated Electric Power Systems Interfaces,” as  
adopted by reference in R 460.902.  
(mm) “IEEE 1547.1-2020” means IEEE “Standard Conformance Test Procedures for  
Equipment Interconnecting Distributed Energy Resources with Electric Power Systems  
and Associated Interfaces,” as adopted by reference in R 460.902.  
(nn) “Inadvertent export” means unscheduled export of active power from a DER,  
exceeding a specified magnitude and for a limited duration, due to fluctuations in load-  
following behavior.  
(oo) “Independent system operator” means an independent, federally-regulated entity  
established to coordinate regional transmission in a non-discriminatory manner and to  
ensure the safety and reliability of the transmission and distribution systems.  
(pp) “Initial review” means the fast track initial review screens described in R 460.946.  
(qq) “Interconnection” means the process undertaken by an electric utility to construct  
the electrical facilities necessary to connect a DER with a distribution system so that  
parallel operation can occur.  
(rr) “Interconnection agreement” means an agreement containing the terms and  
conditions governing the electrical interconnection between the electric utility and the  
applicant or interconnection customer. Where construction of interconnection facilities or  
distribution upgrades are necessary, the agreement, or amendments, shall specify  
estimated timelines, cost estimates, and payment milestones for construction of facilities  
and distribution upgrades to interconnect a DER into the distribution system, and shall  
identify design, controls, settings, procurement, installation, and construction  
requirements associated with installation of the DER. Standard level 1, 2, and 3  
interconnection agreements and level 4 and 5 interconnection agreements are types of  
interconnection agreements.  
(ss) “Interconnection coordinator” means a person or persons designated by the electric  
utility who shall serve as the point of contact from which general information on the  
application process and on the affected system or systems can be obtained through  
informal request by the applicant or interconnection customer.  
(tt) “Interconnection customer” means the person or entity, which may include the  
electric utility, responsible for ensuring a DER is operated and maintained in compliance  
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with all local, state, and federal laws, as well as with all rules, standards, and  
interconnection procedures. An electric utility is not considered an interconnection  
customer for temporary DER or a substation backup energy storage device project.  
(uu) “Interconnection facilities” mean any equipment required for the sole purpose of  
connecting a DER with a distribution system.  
(vv) “Interconnection procedures” mean the requirements that govern project  
interconnection adopted by each electric utility and approved by the commission.  
(ww) “Interconnection study agreement” means an agreement between an applicant and  
an electric utility for the electric utility to study a proposed DER.  
R 460.901b Definitions; J-Z.  
Rule 1b. As used in these rules:  
(a) “kW” means kilowatt.  
(b) “kWac” means the electric power, in kilowatts, associated with the alternating  
current output of a DER at unity power factor.  
(c) “kWh” means kilowatt-hours.  
(d) “Legacy net metering program” means the true net metering or modified net  
metering programs in place prior to commission approval of a distributed generation  
program tariff pursuant to section 6a(14) of 1939 PA 3, MCL 460.6a, and prior to the  
establishment of an alternative electric supplier distributed generation plan.  
(e) “Level 1” means a certified project of 20 kWac or less.  
(f) “Level 2” means a certified project of greater than 20 kWac and not more than 150  
kWac.  
(g) “Level 3” means a project of 150 kWac or less that is not certified, or a project  
greater than 150 kWac and not more than 550 kWac.  
(h) “Level 4” means a project of greater than 550 kWac and not more than 1 MWac.  
(i) “Level 5” means a project of greater than 1 MWac.  
(j) “Level 4 and 5 interconnection agreement” means an interconnection agreement  
applicable to level 4 and 5 interconnection applications.  
(k) “Limited export” means the exporting capability of a DER whose export capacity is  
limited by means specified in an electric utility’s interconnection procedures.  
(l) “Low voltage distribution” means those parts of a distribution system that operate  
with a voltage range specified in the electric utility’s interconnection procedures.  
(m) “Mainline” means a conductor that serves as the three-phase backbone of a low  
voltage distribution circuit.  
(n) “Material modification” means a modification to the DER nameplate rating, DER  
export capacity, electrical size of components, bill of materials, machine data, equipment  
configuration, or the interconnection site of the DER at any time after receiving  
notification by the electric utility of a complete interconnection application. Replacing a  
component with another component that has near-identical characteristics does not  
constitute a material modification when agreed to by the electric utility. For the proposed  
modification to be considered material, it shall have been reviewed and been determined  
to have or anticipated to have a material impact on 1 or more of the following:  
(i) The cost, timing, or design of any equipment located between the point of common  
coupling and the DER.  
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(ii) The cost, timing, or design of any other application.  
(iii) The electric utility’s distribution system or an affected system.  
(iv) The safety or reliability of the distribution system.  
(o) “Methane digester” means a renewable energy system that uses animal or  
agricultural waste for the production of fuel gas that can be burned for the generation of  
electricity or steam.  
(p) “Modified net metering” means an electric utility billing method that applies the  
power supply component of the full retail rate to the net of the bidirectional flow of kWh  
across the customer interconnection with the electric utility’s distribution system during a  
billing period or time-of-use pricing period.  
(q) “MW” means megawatt.  
(r) “MWac” means the electric power, in megawatts, associated with the alternating  
current output of a DER at unity power factor.  
(s) “Nameplate rating” means the sum total of maximum rated power output of all a  
DER’s constituent generating units and energy storage units as identified on the  
manufacturer nameplate, regardless of whether it is limited by any approved means.  
Nameplate rating includes all of the following:  
(i) Nominal voltage (V).  
(ii) Current (A).  
(iii) Maximum active power (kWac).  
(iv) Apparent power (kVA).  
(v) Reactive power (kvar).  
(t) “Nationally recognized testing laboratory” means any testing laboratory recognized  
by the accreditation program of the United States Department of Labor Occupational  
Safety and Health Administration.  
(u) “Network protector” means those devices associated with a secondary network used  
to automatically disconnect a transformer when reverse power flow occurs.  
(v) “Non-export track” means the procedure for evaluating a proposed interconnection  
that will not inject electric energy into an electric utility’s distribution system, as  
described in R 460.942.  
(w) “Parallel operation” means the operation, for longer than 100 milliseconds, of a  
DER while connected to the energized distribution system.  
(x) “Party” or “parties” means an electric utility, applicant, or interconnection customer.  
(y) “Point of common coupling” means the point where the DER connects with the  
electric utility’s distribution system.  
(z) “Power control system” means systems or devices that electronically limit or control  
steady state currents to a programmable limit.  
(aa) “Radial supply” means a configuration of a distribution system or an area of a  
distribution system in which each customer can only be supplied electric energy by 1  
substation transformer and distribution line at a time.  
(bb) “Readily available” means no creation of data is required, and little or no  
computation or analysis of data is required.  
(cc) “Regional transmission operator” means a voluntary organization of electric  
transmission owners, transmission users, and other entities approved by the federal  
energy regulatory commission to efficiently coordinate electric transmission planning,  
expansion, operation, and use on a regional and interregional basis.  
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(dd) “Renewable energy credit” means a credit granted pursuant to the commission's  
renewable energy credit certification and tracking program in section 41 of the clean and  
renewable energy and energy waste reduction act, 2008 PA 295, MCL 460.1041.  
(ee) “Renewable energy resource” means that term as defined in section 11(i) of the  
clean and renewable energy and energy waste reduction act, 2008 PA 295, MCL  
460.1011.  
(ff) “Renewable energy system” means that term as defined in section 11(k) of the clean  
and renewable energy and energy waste reduction act, 2008 PA 295, MCL 460.1011.  
(gg) “Secondary network” means those areas of a distribution system that operate at a  
secondary voltage level and are networked.  
(hh) “Site” means a contiguous site, regardless of the number of meters at that site. A  
site that would be contiguous but for the presence of a street, road, or highway is  
considered to be contiguous for the purposes of these rules.  
(ii) “Spot network” means a location on the distribution system that uses 2 or more  
inter-tied transformers to supply an electrical network circuit, such as a network circuit in  
a large building.  
(jj) “Standard level 1, 2, and 3 interconnection agreement” means the statewide  
interconnection agreement approved by the commission and applicable to levels 1, 2 and  
3 interconnection applications. A cover sheet including modifications to address any  
special operating conditions may be added.  
(kk) “Study track” means the procedure used for evaluating a proposed interconnection  
as described in R 460.952 to R 460.962.  
(ll) “Supplemental review” means the fast track supplemental review screens described  
in R 460.950.  
(mm) “System impact study” means a study to identify and describe the impacts to the  
electric utility’s distribution system that would occur if the proposed DER were  
interconnected exactly as proposed and without any modifications to the electric utility’s  
distribution system. A system impact study also identifies affected systems.  
(nn) “Temporary DER” means a DER that is installed on the distribution system by the  
electric utility with the intention of not operating at the site permanently.  
(oo) “True net metering” means an electric utility billing method that applies the full  
retail rate to the net of the bidirectional flow of kWh across the customer interconnection  
with the electric utility’s distribution system, during a billing period or time-of-use  
pricing period.  
(pp) “UL” means underwriters laboratory.  
(qq) “UL 1741” means the September 28, 2021 edition of “Standard for Inverters,  
Converters, Controllers and Interconnection System Equipment for Use With Distributed  
Energy Resources,” as adopted by reference in R 460.902.  
(rr) "UL 1741 CRD for PCS" means the Certification Requirement Decision for Power  
Control Systems for the standard titled Inverters, Converters, Controllers and  
Interconnection System Equipment for Use With Distributed Energy Resources, March 8,  
2019, as adopted by reference in R 460.902(b).  
R 460.902 Adoption of standards by reference.  
Rule 2. (1) The standards specified in these rules are adopted by reference as follows:  
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(a) UL 1741 Standard for Inverters, Converters, Controllers and Interconnection  
System Equipment for Use With Distributed Energy Resources, September 28, 2021  
edition, is available from Underwriters Laboratories at the internet website:  
https://standardscatalog.ul.com/ProductDetail.aspx?productId=UL1741 at a cost of  
$798.00 at the time of adoption of these rules.  
(b) UL 1741 Standard for Inverters, Converters, Controllers and Interconnection  
System Equipment for Use With Distributed Energy Resources, January 28, 2010 edition,  
is available from Underwriters Laboratories at the internet  
website: https://standardscatalog.ul.com/ProductDetail.aspx?productId=UL1741 at a  
cost of $716.00 at the time of adoption of these rules.  
(c) ANSI C84.1 – 2016 Electric Power Systems and Equipment – Voltage Ratings (60  
Hz), June 9, 2016, is available from the American National Standards Institute, Inc. at the  
internet website https://webstore.ansi.org/ at a cost of $111.24 at the time of adoption of  
these rules.  
(d) The following standards adopted by reference are available from IEEE at the  
internet website https://standards.ieee.org at the time of adoption of these rules.  
(i) The IEEE 1453-2015, IEEE Recommended Practice for the Analysis of Fluctuating  
Installations on Power Systems, October 30, 2015, is available at a cost of $99.00 -  
$147.00 at the time of adoption of these rules.  
(ii) The IEEE 1547 - 2018, IEEE Standard for Interconnection and Interoperability of  
Distributed Energy Resources with Associated Electric Power System Interfaces, April 6,  
2018, is available at a cost of $149.00 - $224.00 at the time of adoption of these rules.  
(iii) The IEEE 1547.1-2020 IEEE Standard Conformance Test Procedures for  
Equipment Interconnecting Distributed Energy Resources with Electric Power Systems  
and Associated Interfaces, May 21, 2020, is available at a cost of $197.00 - $296.00 at the  
time of adoption of these rules.  
(iv) The IEEE 519-2014 IEEE Recommended Practice and Requirements for  
Harmonic Control in Electric Power Systems, June 11, 2014, is available at a cost of  
$52.00 - $66.00 at the time of adoption of these rules.  
(2) The commission has copies of the standards specified in subrule (1) of this rule  
available for review at its offices located at 7109 W. Saginaw Hwy., Lansing, Michigan  
48917-1120. The mailing address is Michigan Public Service Commission, P.O. Box  
30221, Lansing, Michigan 48909-0221.  
R 460.904 Informal mediation.  
Rule 4. (1) In the event that parties are unable to resolve a dispute arising out of the  
interconnection process, as defined by R 460.901a through R 460.992, privately, the  
parties may, by mutual agreement, make a written request for informal mediation to the  
commission staff. The informal mediation must commence within 10 business days after  
submission of the written request or a mutually agreeable timeframe and be conducted by  
an interconnection ombudsperson who shall be a member of the commission staff and  
designated by the commission. Both parties may choose to have attorneys or appropriate  
representation present.  
(2) During informal mediation, the parties shall discuss relevant facts pertaining to the  
dispute and the relief being sought. The interconnection ombudsperson and relevant  
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commission staff shall be present to facilitate the discussion and provide guidance among  
the parties. Parties shall operate in good faith and use best efforts to resolve the dispute.  
(3) If a resolution is reached by the end of the meeting or meetings, the parties may draft  
a resolution of the dispute.  
(4) If the parties reach impasse and are unable to resolve the dispute, the parties shall  
proceed to the formal mediation process described in R 460.906.  
R 460.906 Formal mediation.  
Rule 6. (1) If the parties have been unable to resolve a dispute,  
the complaining party may file a written notice of dispute with the commission. The  
notice of dispute must state the specific grounds for the dispute, sufficient facts to support  
the allegations, the relief requested, and must contain all information, testimony, exhibits,  
or other documents and information within the party’s possession on which the party  
intends to rely to support the party’s position. After the filing of the written notice of  
dispute, the following must occur:  
(a) The complaining party shall give notice that it is invoking the procedures in this  
rule. The complaining party shall send the notice to the non-complaining party’s email  
address and file the notice with the commission.  
(b) The non-complaining party shall acknowledge the notice of dispute within 10  
business days of its receipt and identify a representative with the authority to make  
decisions on its behalf with respect to the dispute.  
(c) An administrative law judge shall serve as the mediator in these proceedings. The  
administrative law judge may request and receive assistance from commission staff.  
(d) Within 60 business days from the date the non-complaining party acknowledges the  
dispute, the mediator shall issue a recommended settlement.  
(e) Within 5 business days after the date the recommended settlement is issued, each  
party shall file with the commission a written acceptance or rejection of the  
recommended settlement. If the parties accept the recommendation, then the  
recommendation shall become an order. If a party rejects or fails to respond within 5  
business days to the recommended settlement, then the dispute may proceed to a  
contested case hearing before the commission as provided in R 792.10415.  
(2) Nothing in these rules precludes a disputing party from filing a formal complaint  
with the commission, either instead of or after pursuing informal mediation or formal  
mediation pursuant to these rules.  
(3) The initiation of any form of dispute resolution by a party tolls any applicable  
deadlines under these rules until the dispute is resolved.  
R 460.908 Timelines for electric utilities serving fewer than 1,000,000 in-state customers.  
Rule 8. An electric utility serving fewer than 1,000,000 in-state customers shall have an  
additional 10 business days to comply with the timelines in R 460.911 to R 460.1026.  
This rule does not apply to applicants or interconnection customers.  
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R 460.910 Waivers.  
Rule 10. An electric utility, customer, alternative electric supplier, applicant, or  
interconnection customer may apply to the commission for a waiver from 1 or more  
provisions of these rules and may request expeditious processing. The commission may  
grant a waiver upon a showing of good cause and a finding that the waiver is in the public  
interest.  
PART 2. INTERCONNECTION STANDARDS  
R 460.911 Applicability.  
Rule 11. These rules apply to all interconnection applications filed on or after the  
effective date of these rules. The electric utility shall complete work on any  
interconnection study agreement executed prior to the effective date of these rules,  
pursuant to the terms and conditions of that interconnection study agreement. Any new  
studies or other additional work must be completed pursuant to these rules. An electric  
utility or an alternative electric supplier shall not restrict access to interconnection for  
level 1, level 2, and level 3 DERs that are not participants in the legacy net metering or  
distributed generation programs.  
R 460.920 Electric utility interconnection procedures.  
Rule 20. (1) An electric utility shall file applications for approval of interconnection  
procedures and forms within 120 calendar days of the effective date of these rules.  
(2) The commission shall issue its order approving, rejecting, or modifying an electric  
utility’s proposed interconnection procedures and forms within 360 calendar days of the  
electric utility filing an application for approval of interconnection procedures and forms.  
If the commission finds the procedures and forms proposed by the electric utility to be  
inadequate or unacceptable, the commission may either adopt procedures and forms  
proposed by another person in the proceeding or modify and accept the procedures and  
forms proposed by the electric utility.  
(3) Until the commission accepts, rejects, or modifies an electric utility’s  
interconnection procedures and forms, the electric utility may use the proposed  
interconnection procedures and forms when processing interconnection applications with  
the exception of fixed fees and fee caps. An electric utility shall only charge fees that  
comply with the requirements of R 460.926 until the commission accepts, rejects, or  
modifies the proposed interconnection procedures and forms, unless the commission  
approves different fees pursuant to R 460.926(5).  
(4) Two or more electric utilities may file a joint application proposing interconnection  
procedures for use by the joint applicants. The proposed interconnection procedures must  
ensure compliance with these rules.  
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(5) The proposed interconnection procedures must, at a minimum, include all of the  
following:  
(a) All necessary applications, forms, and relevant template agreements.  
(b) A schedule of all applicable fixed fees and fee caps.  
(c) Voltage ranges for high voltage distribution and low voltage distribution.  
(d) Required initial review screens.  
(e) Required supplemental review screens.  
(f) The process for conducting system impact studies and facilities studies on DERs  
when there is an affected system issue.  
(g) Testing and certification requirements of DER telecommunications, cybersecurity,  
data exchange, and remote control operation.  
(h) Parallel operation requirements.  
(i) A method to estimate the expected annual kWh output of the generator or  
generators.  
(j) If an electric utility uses alternative methods for power limited export DER pursuant  
to R 460.980(3), a description of those methods.  
(k) A cost allocation methodology for study track DERs.  
(l) An evaluation of an interconnection application for a project that includes single or  
multiple types of DERs at a site for which the applicant seeks a single point of common  
coupling.  
(m) Details describing how an energy storage device may be integrated into an existing  
legacy net metering program system without impacting the 10-year grandfathering period  
or participation in the distributed generation program.  
(n) For electric utilities that are member-regulated electric cooperatives, a procedure for  
fairly processing applications in instances in which the number of applications exceed the  
capacity of the electric cooperative to timely meet the deadlines in these rules.  
(o) Examples of modifications that are not material modifications.  
(p) The procedure for performing a material modification review to determine if a  
modification is material.  
(q) Any required terms and conditions that must be specified in the general liability  
insurance for level 3, 4, and 5 projects.  
(r) A list of the electric utility’s holidays.  
(s) If an electric utility uses an alternative process pursuant to R 460.956, a description  
of that process.  
(t) Fast track eligibility criteria for applications proposing to interconnect DERs with  
4.8 kV distribution systems.  
(u) In the event daytime loading data is not available for the initial screen provided in R  
460.946(5)(b), the date when the data will be collected.  
(6) An electric utility shall obtain commission approval to revise its interconnection  
procedures.  
R 460.922 Online applications and electronic submission.  
Rule 22. (1) An electric utility shall allow pre-application report requests,  
interconnection applications, and interconnection agreements to be submitted  
electronically, such as, through the electric utility’s website or via email.  
12  
(2) An electric utility shall dedicate a page on its website or direct customers to a linked  
website with information on these rules. The relevant information available to an  
applicant or interconnection customer via a website must include all of the following:  
(a) These rules and interconnection procedures in an electronically searchable format.  
(b) The electric utility’s applications and all associated forms in a format that allows for  
electronic entry of data.  
(c) Sample documents including, at a minimum, a 1-line diagram with required labels.  
(d) Contact information for the electric utility’s DER interconnection coordinator,  
including an email address and a phone number.  
(e) Directions for the submission of applications.  
R 460.924 Communications.  
Rule 24. (1) An electric utility shall designate 1 or more interconnection coordinators.  
The telephone number and e-mail address of the interconnection coordinator or  
coordinators must be made available on the electric utility’s website. The interconnection  
coordinator or coordinators must be available to provide reasonable assistance to the  
applicant or interconnection customer but is not responsible to directly answer or resolve  
all of the issues that may arise in the interconnection process.  
(2) An applicant may designate an application agent. An application agent may serve as  
the single point of contact for the applicant and may coordinate with the electric utility on  
the applicant’s behalf. Designation of an application agent does not absolve the applicant  
from signing interconnection documents or from complying with the requirements in  
these rules and the interconnection agreement.  
(3) An electric utility must be indemnified by the applicant and its application agent  
with respect to assistance provided by an interconnection coordinator or coordinators.  
R 460.926 Fees.  
Rule 26. (1) After the effective date of these rules, fees for the pre-application report,  
the non-export track and the fast track must be established as listed in subrule (2) of this  
rule. Initial fees for the study track must not exceed initial fee caps as established in  
subrule (3) of this rule. Fees must remain in effect until interconnection procedures are  
approved by the commission under R 460.920.  
(2) The fee amounts for the pre-application report, non-export track, and fast track for  
all levels of DERs are as follows:  
(a) The pre-application report fee may not exceed $300.  
(b) The non-export track fee may not exceed $100 + $1/kWac for certified DERs and  
$100 + $2/kWac for non-certified DERs.  
(c) The fast track initial review fee is $100 + $1/kWac for certified DERs and $100 +  
$2/kWac for non-certified DERs.  
(d) Any applicable legacy net metering program application fee pursuant to R  
460.1004(7) or distributed generation program application fee pursuant to R 460.1006(6),  
in combination with any applicable fast track initial review fee, fast track supplemental  
review fees and any study track fees, must not exceed a total of $50.  
13  
(3) The initial fee caps for a fast track supplemental review and the study track for all  
levels of DERs are as follows:  
(a) The fee for a fast track supplemental review including all review screens may not  
exceed $1,000.  
(b) The study track fee for interconnection application review and the scoping meeting  
may not exceed $300.  
(c) The system impact study fee may not exceed $10,000.  
(d) The facilities study fee may not exceed $15,000.  
(4) The fees listed in subrule (2) and initial fee caps listed in subrule (3) of this rule,  
must be displayed prominently on the electric utility’s interconnection website.  
(5) An electric utility that expects to incur costs greater than the fees listed in subrule  
(2) or initial fee caps listed in subrule (3) of this rule in the evaluation of an  
interconnection application may file a request for a waiver pursuant to R 460.910.  
R 460.928 Fee and fee cap modifications.  
Rule 28. (1) An electric utility shall include in its proposed interconnection procedures  
fixed fees to replace the fees specified in R 460.926(2)(a), (b), and (c), and add any  
other fixed fees the electric utility considers necessary.  
(2) An electric utility shall include in its proposed interconnection procedures adjusted  
fee caps to replace the initial fee caps specified in R 460.926(3)(a), (b), (c), and (d), and  
add any other fee caps the electric utility considers necessary. An electric utility may  
charge actual costs up to the fee caps.  
(3) The fixed fees must be specific to level size and be based on estimates of reasonable  
costs to perform the applicable service or study. The fee caps must be specific to level  
size and be based on a reasonable range of costs for performing the applicable study.  
(4) The most recently approved fixed fees and fee caps must be listed in the electric  
utility’s interconnection procedures and displayed prominently on the electric utility’s  
interconnection website.  
(5) The fixed fees and fee caps that are approved for inclusion in the electric utility’s  
interconnection procedures by the commission may be reviewed at any time by the  
electric utility and adjusted, if necessary, subject to commission review and approval.  
(6) Any modification of fees may not be applicable to fees already paid.  
(7) An electric utility that expects to incur costs greater than its prevailing fee caps in  
the evaluation of an interconnection application may file a request for a waiver pursuant  
to R 460.910.  
R 460.930 Pre-application report request form.  
Rule 30. (1) An applicant shall submit a completed pre-application report request form  
and the required fee for a pre-application report on a proposed level 4 or level 5 DER.  
(2) The pre-application report request form must include all of the following  
information:  
(a) Project contact information, including name, address, phone number, and email  
address.  
14  
(b) Project location, as accurately as can be identified, which may be given by any of  
the following:  
(i) Street address with nearby cross streets and town.  
(ii) An aerial map with location clearly marked.  
(iii) GPS coordinates.  
(c) Account number, meter number, structure number, or other equivalent information  
identifying the proposed point of common coupling, if available.  
(d) Whether the DER is any of the following:  
(i) Solar.  
(ii) Wind.  
(iii) Cogeneration.  
(iv) Storage.  
(v) Solar with storage.  
(vi) Other type of DER.  
(e) Capacity of the DER types in alternating current kW, direct current kW, kVA, and  
kWh for storage.  
(f) Whether the DER configuration is single or 3-phase.  
(g) Whether the DER will be a stand-alone generator, meaning no onsite load other than  
station service.  
(h) Whether the DER will be certified.  
(i) Whether new service is requested. If there is existing service, the customer account  
number and site minimum and maximum current or proposed electric loads in kW, if  
available, must be included, and how the load is expected to change must be specified.  
(j) Whether the location is new construction.  
(k) If applicable, whether the coupling between the generation and storage is alternating  
current or direct current and whether separate inverters will be used.  
R 460.932 Pre-application report.  
Rule 32. (1) Using the information provided in the pre-application report request form  
described in R 460.930, an electric utility shall identify the substation bus, bank, or  
circuit most likely to serve the point of common coupling. This identification by the  
electric utility does not necessarily indicate that this would be the circuit to which the  
project ultimately connects.  
(2) An applicant may request additional pre-application reports if information about  
multiple points of common coupling is requested. No more than 10 pre-application  
report requests may be submitted by an applicant and its affiliates during a 1-week  
period. An electric utility may reject additional pre-application report requests.  
(3) The pre-application report must include all of the following information:  
(a) Total capacity, in MW, of substation bus, bank, or circuit based on normal or  
operating ratings likely to serve the proposed point of common coupling.  
(b) Existing aggregate generation capacity, in MW, interconnected to a substation bus,  
bank, or circuit likely to serve the proposed point of common coupling.  
(c) Aggregate capacity, in MW, of generation not yet built but found in previously  
accepted interconnection applications, for a substation bus, bank, or circuit likely to serve  
the proposed point of common coupling.  
15  
(d) Available capacity, in MW, of substation bus, bank, or circuit likely to serve the  
proposed point of common coupling.  
(e) Substation nominal distribution voltage.  
(f) Nominal distribution circuit voltage at the proposed point of common coupling.  
(g) Label, name, or identifier of the distribution circuit on which the proposed point of  
common coupling is located.  
(h) Approximate circuit distance between the proposed point of common coupling and  
the substation.  
(i) The actual or estimated peak load and minimum load data at any relevant line  
section or sections, including daytime minimum load and absolute minimum load, when  
available. If not readily available, the report must indicate whether the generator is  
expected to exceed minimum load on the circuit.  
(j) Whether the point of common coupling is located behind a line voltage regulator and  
whether the substation has a load tap changer.  
(k) Limiting conductor ratings from the proposed point of common coupling to the  
distribution substation.  
(l) Number of phases available at the primary voltage level at the proposed point of  
common coupling, and, if a single phase, distance from the 3-phase circuit.  
(m) Whether the point of common coupling is located on a spot network, area network,  
grid network, radial supply, or secondary network.  
(n) Based on the proposed point of common coupling, the report must indicate whether  
power quality issues may be present on the circuit.  
(o) Whether or not the area has been identified as having a prior affected system.  
(p) Whether or not the site will require a system impact study for high voltage  
distribution based on size, location, and existing system configuration.  
(4) The pre-application report may include only existing and readily available data. A  
request for a pre-application report does not obligate an electric utility to conduct a study  
or other analysis of the proposed DER if data is not readily available. The pre-  
application report must also indicate any information listed in subrule (3) of this rule that  
is not readily available. An electric utility may, at its discretion, return any portion of the  
pre-application report fee because some or all information does not exist.  
(5) Pre-application report requests must be processed in the order in which an electric  
utility received the requests.  
(6) An electric utility shall provide the data required in the pre-application report to the  
applicant within 20 business days of receipt of the completed request form and payment  
of the fee. The pre-application report produced by the electric utility is non-binding and  
does not confer any rights on the applicant.  
R 460.934 Site control.  
Rule 34. (1) Documentation of site control must be submitted with the application by  
the applicant.  
(2) For level 3, 4, or 5 DERs, site control may be demonstrated by providing  
documentation that shows any of the following:  
(a) Ownership of, a leasehold interest in, or a right to develop a site for the purpose of  
constructing and operating the DER.  
16  
(b) An enforceable option to purchase or acquire a leasehold site for this purpose.  
(c) A legally binding agreement transferring a present real property right to specified  
real property along with the right to construct and operate a DER on the specified real  
property for a period of time not less than 5 years.  
(3) For level 1 or 2 DERs, proof of site control may be demonstrated by the site owner’s  
signature and contact information on the application.  
(4) An applicant may redact commercially sensitive information from site control  
documents.  
R 460.936 Interconnection applications.  
Rule 36. (1) An electric utility shall provide an interconnection application for an  
applicant to complete, including for those applicants whose DERs will be configured to  
be non-exporting.  
(2) All documents required for a complete interconnection application must be listed on  
the interconnection application. For level 4 and 5 interconnection applications, the list of  
required documents must include a completed pre-application report.  
(3) For interconnection applications with proposed DERs that fall into level 1, an  
applicant shall provide a 1-line diagram and a site diagram.  
(4) For interconnection applications with proposed DERs that fall into levels 2 and 3, an  
applicant shall provide a 1-line diagram that is either sealed by a professional engineer  
licensed in this state or signed by an electrical contractor who is licensed in this state with  
the electrical contractor’s license number noted on the diagram. An applicant shall also  
provide a site diagram.  
(5) For interconnection applications with proposed DERs that fall into levels 4 and 5, an  
applicant shall provide a 1-line diagram that is sealed by a professional engineer who is  
licensed in this state. An applicant shall also provide a site diagram.  
(6) Applications shall be reviewed to assess whether they are complete and conforming  
in the order in which they were received. An application is considered received when an  
electric utility receives the application, the application’s attachments, and the application  
fee. The application must be date-stamped for the first business day when the electric  
utility has received the interconnection application, the application attachments, and  
payment of the application fee. An electric utility shall notify the applicant of receipt of  
the application by the end of the third business day following the date of the date stamp.  
(7) The electric utility shall notify the applicant that the interconnection application is  
either complete and conforming, or incomplete, or non-conforming, within 10 business  
days of the date stamp.  
(a) If an interconnection application is determined to be complete and conforming by the  
electric utility, the applicant must be notified that the interconnection application is  
accepted. The electric utility shall also indicate whether the interconnection application  
will be processed using the non-export track, fast track, or study track.  
(b) If the application is incomplete or non-conforming, the electric utility shall provide  
to the applicant a written list of all deficiencies with the notification. The applicant shall  
have 60 business days from the date of electric utility notification to submit the necessary  
information and may provide up to 2 submissions during this time period. After each  
submission of information, the electric utility shall have 10 business days to notify the  
17  
applicant that the interconnection application is either accepted or rejected due to  
continuing deficiencies. If the applicant does not meet the timelines required by this rule,  
the utility may withdraw the application.  
(8) An electric utility shall comply with part 2 of these rules, R 460.911 to R 460.992,  
and its interconnection procedures when interconnecting DERs that it owns and operates  
onto its distribution system, with the exception of temporary DERs and substation backup  
batteries.  
(9) An electric utility shall use the same process when processing and studying  
interconnection applications from all applicants, whether the DER is owned or operated  
by the electric utility, its subsidiaries or affiliates, or others, with the exception of  
temporary DERs and substation backup batteries.  
(10) An electric utility shall review and update interconnection applications periodically  
to reflect new information required to properly review DERs, subject to commission  
review and approval.  
R 460.938 Public interconnection list.  
Rule 38. (1) An electric utility shall maintain a publicly available interconnection list,  
which is available in a sortable spreadsheet format. The sortable spreadsheet must be  
provided to the public upon request. An electric utility that has received not less than  
100 complete interconnection applications in a year shall publish this list on the electric  
utility’s website. The public interconnection list must be updated monthly. If no changes  
to the spreadsheet have occurred in that month, a note to that effect must be clearly  
indicated on the spreadsheet. The date of the most recent update must be clearly  
indicated.  
(2) The public interconnection list must include all of the following: (a) An  
application identifier.  
(b) The date that the electric utility received the application. (c) The date that the  
electric utility considered the application to be complete and conforming.  
(d) Whether the application is on the non-export track, fast track, or study track.  
(e) The proposed DER nameplate rating. (f) The proposed DER interconnection size  
level.  
(g) The DER technology type.  
(h) The county and township in which the proposed point of common coupling will be  
located.  
(i) The current status of the application’s progress in the interconnection process.  
(j) The labels, names, or identifiers of the distribution circuit and substation.  
R 460.942 Non-export track review.  
Rule 42. (1) Interconnection applications for DERs that will not inject electric energy  
into an electric utility’s distribution system are eligible for evaluation under the non-  
18  
export track. Non-export eligibility requires an existing electrical service at the  
applicant’s premise.  
(2) Subject to review and approval by the commission, an electric utility may limit the  
eligibility of the non-export track in its interconnection procedures based on the  
characteristics of its distribution system.  
(3) Before submitting an interconnection application, a non-export track applicant may  
contact the electric utility for reasonable assistance in determining whether a non-export  
track review will be sufficient or the study track is necessary. The electric utility shall  
provide the applicant assistance based on available information. If the applicant chooses  
to proceed, an interconnection application shall be submitted pursuant to R 460.936.  
(4) Within 20 business days after being notified that the application was accepted, the  
electric utility shall perform an initial review by using some or all of the initial review  
screens specified in the electric utility’s interconnection procedures pursuant to R  
460.946 and notify the applicant of the results. If an electric utility chooses to perform a  
review using a subset of the initial review screens, the exclusion of 1 or more screens  
may not be the only basis for the electric utility to require further study.  
(5) If the proposed interconnection passes the initial review screens, or if the proposed  
interconnection fails the screens but the electric utility determines that the DER may be  
interconnected consistent with safety, reliability, and power quality standards, the electric  
utility shall notify the applicant as follows:  
(a) If the notification indicates that no interconnection facilities, distribution upgrades,  
further study, or application modifications are required, the electric utility shall provide  
specifications for any equipment the applicant is required to install within 20 business  
days after the applicant being notified. Within 10 business days after receiving the  
equipment specifications, the applicant shall notify the electric utility whether the  
applicant will proceed under R 460.964 to an interconnection agreement or will withdraw  
the application. The applicant’s failure to notify the electric utility within the required  
time period shall result in the interconnection application being withdrawn by the electric  
utility.  
(b) If a facilities study is required, the interconnection application must proceed under  
R 460.962.  
(6) If the proposed interconnection fails any of the initial review screens, and the electric  
utility does not or cannot determine that the DER may be interconnected consistent with  
safety, reliability, and power quality standards, the electric utility shall notify the  
applicant, provide the applicant with the results of the application of the initial review  
screens, and offer all of the following options:  
(a) Attend a customer options meeting, as described in R 460.948.  
(b) Proceed to supplemental review under R 460.950.  
(c) Submit within 60 business days after the date of the electric utility notification, with  
up to 2 submissions during this time period, a complete and conforming revised  
interconnection application that includes application modifications offered or required by  
the electric utility. If the applicant does not make the submittal within the required 60  
days, then the electric utility may consider the application withdrawn. Submission of  
interconnection applications shall be governed by the following requirements:  
(i)The application modifications must mitigate or eliminate the factors that caused the  
interconnection application to fail 1 or more of the initial review screens.  
19  
(ii) After each submission of information, the electric utility has 10 business days to  
notify the applicant that the interconnection application is either accepted or rejected due  
to continuing deficiencies.  
(iii) After the electric utility determines the application is accepted, the revised  
interconnection application must proceed under subrule (4) of this rule.  
(d) Withdraw the interconnection application.  
(7) If the applicant does not select a course of action under subrule (6) of this rule within  
10 business days after notice from the electric utility, the electric utility shall withdraw  
the interconnection application.  
(8) When an applicant changes from a non-exporting system to an exporting system, the  
applicant shall submit a new interconnection application.  
R 460.944 Fast track applicability.  
Rule 44. (1) Level 1, level 2, level 3, level 4 applications, and level 5 applications as  
large as 5 MWac in which the DER is not proposing to interconnect with the electric  
utility’s high voltage distribution system are eligible for the fast track. Level 5  
applications proposing to interconnect to a utility’s distribution system at 4.8 kV or less  
are not eligible for the fast track. Projects using an acceptable method for limited export  
are eligible for fast track.  
(2) An applicant that is eligible for the fast track may forgo the fast track and proceed  
directly to the study track.  
(3) An applicant with an application that is outside the limitations specified in subrule  
(1) of this rule may petition the electric utility to have its application evaluated under fast  
track. The electric utility may approve or reject this request at its discretion.  
(4) In determining fast track eligibility, an electric utility may aggregate all proposed  
new generation on a site regardless of the existence of a shared point of common  
coupling or multiple points of common coupling.  
R 460.946 Fast track; initial review.  
Rule 46. (1) An electric utility shall list in its interconnection procedures the initial  
review screens specified in subrule (5) of this rule. An electric utility may add additional  
details to each of these screens in the interconnection procedures.  
(2) An electric utility may include additional initial review screens in its  
interconnection procedures. In its application requesting approval of interconnection  
procedures, an electric utility shall provide a detailed technical rationale for including  
each additional screen. If an additional screen conflicts with or undermines any of the  
initial review screens specified in subrule (5) of this rule, the rationale must include an  
explanation of how it does so.  
(3) The electric utility may waive application of 1, some, or all of the initial review  
screens.  
(4) Within 10 business days after an electric utility receives a complete and conforming  
level 1 or level 2 application and associated payment, or within 20 business days after an  
electric utility receives a complete and conforming level 3, level 4, or level 5 application  
and associated payment, the electric utility shall perform an initial review and notify the  
20  
applicant of the results. The initial review must consist of applying the initial review  
screens selected by the electric utility pursuant to subrule (3) of this rule to the proposed  
DER. The electric utility shall not require a supplemental review or a system impact  
study if the DER passes the applied initial review screens.  
(5) The initial review screens are all of the following:  
(a) The entire proposed DER, including all aggregated site generation and point or  
points of interconnection, must be located within the electric utility’s service territory.  
(b) For interconnection of a proposed DER to a radial distribution circuit, the  
aggregated generation, including the proposed DER, on the circuit may not exceed 15%  
of the line section annual peak load as most recently measured or calculated if measured  
data is not available. A line section is that portion of an electric utility’s distribution  
system connected to a customer bounded by automatic sectionalizing devices or the end  
of the distribution line. The electric utility shall consider 100% of applicable loading, if  
available, instead of 15% of line section peak load for level 1 and level 2 DER. In the  
event daytime loading data is not available, the data must be collected by a date specified  
in interconnection procedures approved by the commission, and is not considered as part  
of the aggregate generation, for purposes of this screen, DER capacity known to be  
already reflected in the minimum load data. This screen does not apply to level 1 and  
level 2 non-export DER applications.  
(c) For interconnection of a proposed DER to the load side of network protectors, the  
proposed DER must utilize an inverter-based equipment package and, together with the  
aggregated other inverter-based DERs, may not exceed the smaller of 5% of a network’s  
maximum load or 50 kWac.  
(d) The proposed DER, in aggregation with other DERs on the distribution circuit, may  
not contribute more than 10% to the distribution circuit’s maximum fault current at the  
point on the primary voltage nearest the proposed point of common coupling. This  
screen does not apply to level 1 applications.  
(e) The proposed DER, in aggregate with other DERs on the distribution circuit, may  
not cause any distribution protective devices and equipment or interconnection customer  
equipment on the system to exceed 87.5% of the short circuit interrupting capability. An  
interconnection may not be proposed for a circuit that already exceeds 87.5% of the short  
circuit interrupting capability. Distribution protective devices and equipment include, but  
are not limited to, substation breakers, fuse cutouts, and line reclosers. This screen does  
not apply to level 1 applications.  
(f) The initial review screen determines the type of interconnection to a primary  
distribution line for the proposed DER, according to the requirements specified in the  
table in this subdivision. This screen includes a review of the type of electrical service  
provided to the applicant, including line configuration and the transformer connection to  
limit the potential for creating over-voltages on the electric utility’s distribution system  
due to a loss of ground during the operating time of any anti-islanding function.  
Primary Distribution Line  
Type  
Type of Interconnection to  
Primary Distribution Line  
3-phase or single phase,  
phase-to-phase  
Result  
3-phase, 3 wire  
Pass screen  
21  
3-phase, 4 wire  
Effectively-grounded 3- phase  
or single-phase, line-to-neutral  
Pass screen  
(g) If the proposed DER is to be interconnected on single-phase shared secondary, the  
aggregate generation capacity on the shared secondary, including the proposed DER  
export capacity, may not exceed 20 kWac or 65% of the transformer nameplate rating.  
(h) If the proposed DER is single-phase and is to be interconnected on a center tap  
neutral of a 240 volt service, its addition may not create an imbalance between the 2 sides  
of the 240 volt service of more than 20% of the nameplate rating of the service  
transformer.  
(i) If the proposed DER is single-phase and is to be interconnected to a 3-phase service,  
its nameplate rating may not exceed 10% of the service transformer nameplate rating.  
(j) If the proposed DER’s point of common coupling is behind a line voltage regulator,  
the DER’s nameplate rating must be less than 250 kWac. This screen does not include  
substation voltage regulators.  
(6) If the proposed interconnection passes the initial review screens, or if the proposed  
interconnection fails the screens but the electric utility determines that the DER may be  
interconnected consistent with safety, reliability, and power quality standards, the electric  
utility shall notify the applicant. If a facilities study is not required, the interconnection  
application must proceed under R 460.964 to an interconnection agreement. If a facilities  
study is required, the interconnection application must proceed under R 460.962.  
(7) If the proposed interconnection fails any of the initial review screens, and the electric  
utility does not or cannot determine that the DER may be interconnected consistent with  
safety, reliability, and power quality standards, the electric utility shall notify the  
applicant, provide the applicant with the results of the application of the initial review  
screens, and offer all of the following options:  
(a) Attend a customer options meeting, as described in R 460.948.  
(b) Proceed to supplemental review under R 460.950.  
(c) Submit within 60 business days from the date of the electric utility notification, with  
up to 2 submissions during this time period, a complete and conforming revised  
interconnection application that includes application modifications offered or required by  
the electric utility. The application modifications must mitigate or eliminate the factors  
that caused the interconnection application to fail 1 or more of the initial review screens.  
After each submission of information, the electric utility has 10 business days to notify  
the applicant that the interconnection application is either accepted or rejected due to  
continuing deficiencies. If the applicant does not meet the timelines required by this  
subrule, the electric utility may withdraw the application. After the electric utility  
determines the application is accepted, the revised interconnection application must  
proceed under subrule (4) of this rule.  
(d) Withdraw the interconnection application.  
(8) If the applicant does not select a course of action under subrule (7) of this rule within  
10 business days of notice from the electric utility, the electric utility shall withdraw the  
interconnection application.  
R 460.948 Fast track; customer options meeting.  
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Rule 48. (1) Upon an applicant’s request, the electric utility and the applicant shall  
schedule a customer options meeting between the electric utility and the applicant to  
review possible facility modifications, screen analysis, and related results to determine  
what further steps are needed to permit the DER to be connected safely and reliably to the  
distribution system. The customer options meeting must take place within 30 business  
days of the date of notification pursuant to R 460.946(7).  
(2) At the customer options meeting, the electric utility shall offer all of the following  
options:  
(a) Proceed to a supplemental review pursuant to R 460.950.  
(b) Continue evaluating the interconnection application under the study track pursuant  
to R 460.952.  
(c) Submit within 60 business days from the date of the customer options meeting, with  
up to 2 submissions during this time period, a complete and conforming revised  
interconnection application that includes application modifications offered or required by  
the electric utility, which mitigates or eliminates the factors that caused the  
interconnection application to fail 1 or more of the initial review screens. After each  
submission of information, the electric utility has 10 business days to notify the applicant  
that the interconnection application is either accepted or rejected due to continuing  
deficiencies. If the applicant does not meet the timelines required by this subrule, the  
electric utility may withdraw the application. After the electric utility accepts the revised  
interconnection application, it must proceed under R 460.946(4).  
(d) Withdraw the interconnection application.  
(3) Following the customer options meeting, the applicant has up to 20 business days to  
decide on a course of action and notify the electric utility. In the absence of this  
notification within the required time, the electric utility shall withdraw the application.  
(4) The customer options meeting may take place in person or via telecommunications.  
R 460.950 Fast track; supplemental review.  
Rule 50. (1) An electric utility shall list in its interconnection procedures the  
supplemental review screens specified in subrule (6) of this rule. An electric utility may  
add additional details to each of these screens in the interconnection procedures.  
(2) An electric utility may include additional supplemental review screens in its  
interconnection procedures. In its application requesting approval of interconnection  
procedures, the electric utility shall provide a detailed technical rationale for the inclusion  
of each supplemental review screen. If an additional screen negates or undermines any of  
the supplemental review screens specified in subrule (6) of this rule, the rationale must  
include an explanation of the technical justification for the additional screen.  
(3) An electric utility may waive application of 1, some, or all of the supplemental  
review screens.  
(4) To receive a supplemental review, an applicant shall submit payment of the  
supplemental review fee within 20 business days of agreeing to a supplemental review. If  
payment of the fee has not been received by the electric utility within 25 business days,  
the electric utility shall withdraw the interconnection application.  
(5) Within 30 business days after the applicant pays the applicable supplemental review  
fee or fees, and provides reasonable requested data, an electric utility shall perform a  
23  
supplemental review and notify the applicant of the results. The supplemental review  
must consist of applying the supplemental review screens selected by the electric utility  
pursuant to subrule (3) of this rule to the proposed DER. The electric utility shall not  
require a system impact study if the DER passes the applied supplemental review screens.  
(6) The supplemental review screens must include all of the following:  
(a) Minimum load screen. Where 12 months of line section minimum load data,  
including onsite load but not station service load served by the proposed DER, are  
available, can be calculated, can be estimated from existing data, or can be determined  
from a power flow model, the aggregate DER capacity on the line section must be less  
than 100% of the minimum load for all line sections bounded by automatic sectionalizing  
devices upstream of the proposed DER. If minimum load data are not available, or cannot  
be calculated, estimated, or determined, an electric utility shall include the reason or  
reasons that it is unable to calculate, estimate, or determine minimum load in its  
supplemental review results notification under subrules (7) and (8) of this rule. All of the  
following must be applied by the electric utility:  
(i) The type of generation used by the proposed DER will be considered when  
calculating, estimating, or determining circuit or line section minimum load relevant for  
the application of the minimum load screen specified in this subrule. Solar photovoltaic  
generation systems with no battery storage must use daytime minimum load. All other  
generation must use absolute minimum load unless an operating schedule is provided.  
(ii) When this screen is being applied to a DER that serves some station service load,  
only the net injection of electric energy into the electric utility’s distribution system may  
be considered as part of the aggregate generation.  
(iii) The electric utility shall not consider as part of the aggregate generation, for  
purposes of this supplemental screen, DER capacity known to be already reflected in the  
minimum load data.  
(b) Voltage and power quality screen. In aggregate with existing generation on the line  
section, all of the following conditions must be met:  
(i) The voltage regulation on the line section can be maintained in compliance with  
relevant requirements under all system conditions.  
(ii) The voltage fluctuation is within acceptable limits as defined by the IEEE Standard  
1453-2015, IEEE Recommended Practice for the Analysis of Fluctuating Installations on  
Power Systems.  
(c) Safety and reliability screen. The location of the proposed DER and the aggregate  
generation capacity on the line section may not create impacts to safety or reliability that  
require application of the study track to address. An electric utility shall consider all of  
the following when determining potential impacts to safety and reliability in applying this  
screen:  
(i) Whether the line section has significant minimum loading levels dominated by a  
small number of customers, such as several large commercial customers.  
(ii) Whether the loading along the line section is uniform.  
(iii) Whether the proposed DER is located less than 0.5 electrical circuit miles for less  
than 5 kV or less than 2.5 electrical circuit miles for greater than 5 kV from the  
substation. In addition, whether the line section from the substation to the point of  
common coupling is a mainline rated for normal and emergency ampacity.  
24  
(iv) Whether the proposed DER incorporates a time delay function to prevent  
reconnection of the DER to the distribution system until distribution system voltage and  
frequency are within normal limits for a prescribed time.  
(v) Whether operational flexibility is reduced by the proposed DER, such that transfer  
of the line section or sections of the DER to a neighboring distribution circuit or  
substation may trigger overloads, power quality issues, or voltage issues.  
(vi) Whether the proposed DER employs equipment or systems certified by a  
recognized standards organization to address technical issues including, but not limited  
to, islanding, reverse power flow, or voltage quality.  
(7) If the proposed interconnection passes the supplemental review, or if the proposed  
interconnection fails the review but the electric utility determines that the DER may be  
interconnected consistent with safety, reliability, and power quality standards, the electric  
utility shall notify the applicant and the interconnection application must proceed  
pursuant to both of the following:  
(a) If the proposed interconnection requires a facilities study, the interconnection  
application must proceed under R 460.962.  
(b) If the proposed interconnection does not require further study, the interconnection  
application must proceed under R 460.964 to an interconnection agreement.  
(8) If the proposed interconnection fails any of the supplemental review screens or the  
electrical utility is unable to perform a supplemental review screen, and the electric utility  
does not or cannot determine that the DER may be interconnected consistent with safety,  
reliability, and power quality standards, the electric utility shall notify the applicant,  
provide the applicant with the results of the application of the supplemental review  
screens, and offer both of the following options:  
(a) Stop the supplemental review and continue evaluating the proposed interconnection  
under the study track under R 460.952.  
(b) Withdraw the interconnection application.  
(9) For subrules (7) and (8) of this rule, if an applicant does not select a course of action  
within 10 business days of notice from the electric utility, the electric utility shall  
withdraw the interconnection application.  
R 460.952 Study track.  
Rule 52. (1) An electric utility shall use the study track to evaluate an interconnection  
application that has been accepted under R 460.936 if 1 or more of the following  
conditions is met:  
(a) The DER is not eligible for the non-export track or fast track.  
(b) The DER did not pass the initial review screens as part of the fast track and the  
applicant selected the study track option in the customer options meeting.  
(c) The DER did not pass 1 or more supplemental review screens.  
(d) The DER was evaluated under the non-export track and further study is required.  
(e) The DER is eligible for the fast track, but the applicant elected the study track.  
(2) If the interconnection application must be evaluated under the study track because it  
meets the criteria of subrule (1)(a) of this rule, within 10 business days after the electric  
utility notifies the applicant that the interconnection application has been accepted  
25  
pursuant to R 460.936, the electric utility shall provide to the applicant an individual  
study agreement or an agreement for an alternative process pursuant to R 460.956.  
(3) If the interconnection application must be evaluated under the study track because it  
meets the criteria of subrule (1)(b), (c), or (d), of this rule, within 10 business days after  
the applicant has notified the electric utility to proceed to the study track, the electric  
utility shall provide to the applicant an individual study agreement or an agreement for an  
alternative process. (4) An electric utility’s interconnection procedures may include a  
provision for determining appropriate milestone payments to include with the system  
impact study fee and facilities study fee.  
R 460.954 Individual study.  
Rule 54. (1) An electric utility that is evaluating DERs in the study track individually  
shall process the interconnection applications in the order in which the applications were  
placed into the study track, taking into account withdrawn interconnection applications  
and electrically remote DERs. An electrically remote DER in an individual study may be  
studied on an expedited schedule relative to electrically coincident DERs. Electrically  
remote DERs must be studied in the order the interconnection applications were  
considered complete.  
(2) When an interconnection application is delayed due to an affected system issue,  
informal mediation pursuant to R 460.904, formal mediation pursuant to R 460.906, or a  
complaint pursuant to R 792.10439 to R 792.10446, other interconnection applications  
that were placed into the study track on a later date may progress in the order in which  
the interconnection applications were placed into the study track.  
(3) An individual study process must consist of a system impact study pursuant to R  
460.960 and a facilities study pursuant to R 460.962. An electric utility may waive 1 or  
both studies for a particular interconnection application. An electric utility may specify  
additional studies it may perform on an interconnection application in its interconnection  
procedures, provided the electric utility is able to meet all applicable timelines associated  
with an individual study process.  
(4) Interconnection applications that meet all of the following requirements must be  
admitted into an individual study:  
(a) An electric utility determined the application to be complete and conforming.  
(b) An application qualifies for study track pursuant to R 460.952.  
(c) An interconnection application has a pre-application report, when required by R  
460.936(2).  
(d) An applicant has paid all required fees.  
(e) An applicant has signed and returned an individual study agreement.  
R 460.956 Alternative process.  
Rule 56. An electric utility may use a process to study interconnection applications that  
is different from the process described by R 460.954 and R 460.958 to R 460.962. If an  
electric utility elects to use an alternative process, this process must be described in the  
electric utility’s interconnection procedures.  
26  
R 460.958 Scoping meeting for interconnection applications that are to be studied  
individually.  
Rule 58. (1) This rule applies only to interconnection applications proceeding pursuant  
to an individual study agreement.  
(2) Upon request of the applicant, the electric utility and the applicant shall schedule a  
scoping meeting between the electric utility and the applicant to discuss the  
interconnection application and review existing fast track results, if any. The scoping  
meeting must take place within 20 business days after the interconnection application is  
considered complete by the electric utility or, if applicable, the fast track has been  
completed and the applicant has elected to continue with the system impact study or  
facilities study.  
(3) Scoping meetings are limited to 1 hour per application. Multiple applications by the  
same applicant may be addressed in the same meeting.  
(4) The scoping meeting may occur in-person or via telecommunications.  
(5) During the scoping meeting, the electric utility shall identify and communicate to the  
applicant whether the applicant must proceed to a system impact study, a facilities study,  
or an interconnection agreement and the basis for that decision, and 1 of the following  
must occur:  
(a) If a system impact study must be performed, the interconnection application  
proceeds to R 460.960.  
(b) If a facilities study must be performed, the interconnection application proceeds to  
R 460.962.  
(c) If a system impact study is not required and a facilities study is not required, the  
interconnection application must proceed to R 460.964 for an interconnection agreement.  
R 460.960 System impact study agreement, scope, procedure, and review meeting.  
Rule 60. For all DERs being studied individually, all of the following apply:  
(a) An electric utility shall provide the applicant a system impact study agreement  
within 5 business days of proceeding to this rule.  
(b) A system impact study agreement must include all of the following:  
(i) An outline of the scope of the study.  
(ii) The applicable fee, including appropriate credit for any studies previously  
completed pursuant to the fast track or non-export track.  
(iii) If necessary, a list of any additional and reasonable technical data needed from the  
applicant to perform the system impact study.  
(iv) A timeline for completion of the system impact study.  
(v) A list of the information that must be provided to the applicant in the system impact  
study report.  
(c) An applicant who has requested a system impact study shall return the completed  
system impact study agreement, provide any additional technical data requested by the  
electric utility, and pay the required fee within 20 business days. An electric utility may  
consider the application withdrawn if the system impact study agreement, payment, and  
required technical data are not returned within 20 business days.  
27  
(d) A system impact study must identify and describe the electric system impacts that  
would result if the proposed DER was interconnected without electric system  
modifications. A system impact study must provide a non-binding good faith list of  
facilities that are required as a result of the application and non-binding estimates of costs  
and time to construct these facilities.  
(e) An electric utility shall explain in its interconnection procedures the process for  
conducting system impact studies on DERs when there is an affected system issue.  
(f) The electric utility shall complete the system impact study and transmit a system  
impact study report to the applicant within 60 business days after the receipt of the signed  
system impact study agreement, payment of the system impact study fee, and any necessary  
technical data. If necessary, the electric utility shall transmit a facilities study agreement to  
the applicant within 60 business days of receipt of the signed system impact study  
agreement, payment of all applicable fees, and any necessary technical data.  
(g) An electric utility may request reasonable additional data from the applicant within  
20 business days of beginning the system impact study. The electric utility and the  
applicant shall work together to resolve the additional data request so that the electric  
utility will be able to complete the system impact study within 60 business days as  
specified in subdivision (f) of this rule. If the applicant does not provide the requested  
additional data in a timely manner, the electric utility shall notify the applicant that the  
system impact study is on hold and the date the hold started. The electric utility shall  
resume work on the study on the date the additional data is received.  
(h) Within 15 business days of receiving the system impact study report, the applicant  
shall notify the electric utility that it plans to pursue a system impact study review  
meeting, proceed to a facilities study pursuant to R 460.962, or withdraw the application.  
If the applicant fails to notify the electric utility within 15 business days, the electric  
utility may consider the application to be withdrawn.  
(i) Upon request by the applicant pursuant to subdivision (h) of this rule, the electric  
utility and the applicant shall schedule a system impact study review meeting between the  
electric utility and the applicant to review system impact study results and determine  
what further steps are needed to permit the DER to be connected safely and reliably to the  
distribution system. The system impact study review meeting must take place within 25  
business days of the electric utility receiving notification that the applicant plans to attend  
a system impact study review meeting.  
(j) At the system impact study review meeting, the electric utility shall offer the applicant  
the option to withdraw the interconnection application, and 1 of the following options:  
(i) Proceed to a facilities study pursuant to R 460.962.  
(ii) Proceed directly to R 460.964 for an interconnection agreement.  
(k) Following the meeting, the applicant has not more than 45 business days to  
decide on a course of action. If an applicant fails to notify the electric utility within 45  
business days, the electric utility may consider the application to be withdrawn.  
(l) The system impact study review meeting may occur in-person or via  
telecommunications.  
R 460.962 Facilities study agreement, scope, procedure; review meeting.  
Rule 62. For DERs being studied individually, all of the following apply:  
28  
(a) If construction of facilities is required to provide interconnection and  
interoperability of the DER with the electric utility’s distribution system, the electric  
utility shall provide the applicant a facilities study agreement and the results of the  
applicant’s system impact study pursuant to R 460.960, if applicable. The electric utility  
shall provide a facilities study agreement within 10 business days of proceeding to this  
rule.  
(b) The facilities study agreement must include the following:  
(i) An outline of the scope of the study.  
(ii) The applicable fee, including appropriate credit for any studies previously  
completed pursuant to the fast track or non-export track.  
(iii) A timeline for completion of the facilities study.  
(iv) A list of the information that will be provided to the applicant in the facilities study  
report.  
(c) The applicant shall return the signed facilities study agreement and pay the required  
facilities study fee within 20 business days. The electric utility may withdraw the  
application if the facilities study agreement and payment are not returned within 20  
business days.  
(d) A facilities study must specify and estimate the cost of the required equipment,  
engineering, procurement, and construction work, including overheads, needed to  
interconnect the DER, and an estimated timeline for the completion of construction. The  
electric utility shall provide cost estimates that are detailed and itemized.  
(e) The electric utility shall explain in its interconnection procedures the process for  
conducting facilities studies on DERs while there is an affected system issue.  
(f) The electric utility shall complete the facilities study and transmit a facilities study  
report to the applicant within 80 business days of the receipt of the signed facilities study  
agreement and payment of the facilities study fee.  
(g) Within 10 business days of receiving a facilities study report from the electric  
utility, the applicant shall select 1 option from the following options:  
(i) Request a facilities study review meeting with the electric utility.  
(ii) Proceed to an interconnection agreement pursuant to R 460.964.  
(iii) Withdraw the interconnection application.  
If the applicant fails to inform the electric utility within 10 business days of its chosen  
course of action, the electric utility may consider the application withdrawn.  
(h) Upon request by the applicant pursuant to subdivision (g)(i) of this rule, the electric  
utility and the applicant shall schedule a facilities study review to review the facilities  
study results and determine what further steps are needed to permit the DER to be  
connected safely and reliably to the distribution system. The facilities study review  
meeting must take place within 25 business days of the electric utility receiving  
notification that the applicant will attend a facilities study review meeting.  
(i) At the facilities study review meeting, the electric utility shall offer both of the  
following options:  
(i) Proceed to an interconnection agreement pursuant to R 460.964.  
(ii) Withdraw the interconnection application.  
(j) Following the meeting, the applicant has no more than 20 business days to decide on  
a course of action and notify the electric utility of this course of action. If the applicant  
29  
fails to notify the electric utility within 20 business days, the electric utility may withdraw  
the application.  
(k) The facilities study review meeting may be conducted in-person or via  
telecommunications.  
R 460.964 Interconnection agreement.  
Rule 64. (1) For level 1, 2, or 3 interconnection applications, where no construction of  
interconnection facilities or distribution upgrades is required, an electric utility shall  
transmit its standard level 1, 2, and 3 interconnection agreement, which may include  
modifications to address any special operating conditions, to an applicant within 3  
business days of reaching this stage.  
(2) For level 1, 2, or 3 interconnection applications, where construction of  
interconnection facilities or distribution upgrades is required, an electric utility shall  
provide its standard level 1, 2, and 3 interconnection agreement with modifications to  
address any special operating conditions, required construction activities, estimated  
construction milestone timing, and estimated cost to an applicant within 5 business days  
of reaching this stage. The applicant and electric utility shall mutually agree on the  
timing of construction milestones.  
(3) For an applicant with level 1, 2, or 3 interconnection applications, the applicant shall  
sign and return the standard level 1, 2, and 3 interconnection agreement with payment, if  
applicable, within 20 business days of receiving the agreement.  
(a) If the applicant did not sign and return the standard level 1, 2, and 3 interconnection  
agreement and payment, if applicable, within 20 business days, the electric utility shall  
notify the applicant of the missed deadline and grant an extension of 15 business days. If  
the electric utility did not receive the signed standard level 1, 2, and 3 interconnection  
agreement and any applicable payment during the 15-business-day extension, the electric  
utility may consider the interconnection application withdrawn subject to subdivision (b)  
of this subrule.  
(b) If the applicant begins either the informal mediation pursuant to R 460.904, the  
formal mediation pursuant to R 460.906, or the complaint process pursuant to R  
792.10439 to R 792.10446 within the 20 business days, the outcome of that process must  
establish a time frame for the applicant to return the signed interconnection agreement  
and any applicable payment.  
(4) For level 1, 2, or 3 projects, the electric utility shall countersign and provide a  
completed copy of the standard level 1, 2, and 3 interconnection agreement within 10  
business days of the applicant returning the signed standard level 1, 2, and 3  
interconnection agreement and the interconnection application must proceed under R  
460.966.  
(5) For level 4 or 5 projects, the electric utility shall provide its level 4 and 5  
interconnection agreement, which may include modifications to address any special  
operating conditions, within 15 business days of reaching this stage. When construction  
of interconnection facilities or distribution upgrades is necessary, the level 4 and 5  
interconnection agreement must contain either estimated timelines for completion of  
activities and estimates of construction costs or a timetable when these requirements can  
be determined. The interconnection agreement must include a payment schedule that  
30  
corresponds to the milestones established and must require the electric utility to refund  
any unspent and unobligated funds if the agreement is terminated.  
(6) For an applicant with level 4 or 5 DERs, the applicant shall sign and return with  
payment, if applicable, a level 4 and 5 interconnection agreement within 30 business  
days.  
(a) If the applicant does not sign and return the level 4 and 5 interconnection agreement  
with payment within 30 business days, an electric utility shall notify the applicant of the  
missed deadline and grant an extension of 15 business days. If the electric utility does not  
receive the signed level 4 and 5 interconnection agreement and payment, if applicable,  
during the 15-business-day extension, the electric utility may consider the interconnection  
application withdrawn, subject to subdivision (b) of this subrule.  
(b) If the applicant begins either the informal mediation pursuant to R 460.904, formal  
mediation pursuant to R 460.906, or the complaint process pursuant to R 792.10439 to R  
792.10446 within 30 business days, the outcome of that process must establish a time  
frame for the applicant to return the signed interconnection agreement and applicable  
payment. There is a rebuttable presumption in the complaint proceeding that the electric  
utility’s standard construction, procurement, installation, design, and cost practices are  
lawful, reasonable, and prudent.  
(i) For study track interconnection applications filed with an electric utility conducting  
individual studies, electrically coincident applications filed after the interconnection  
application must be placed on hold for not more than 60 business days. If either informal  
mediation pursuant to R 460.904, formal mediation pursuant to R 460.906, or the  
complaint process pursuant to R 792.10439 to R 792.10446 does not result in the  
applicant returning a signed interconnection agreement with any applicable payment  
within 60 business days and there are electrically coincident interconnection applications  
in progress behind this application, the electric utility may require the withdrawal of the  
interconnection application.  
(7) For level 4 or 5 projects, an electric utility shall countersign and provide a completed  
copy of the level 4 and 5 interconnection agreement within 10 business days of the  
applicant returning a mutually agreed-upon and signed level 4 and 5 interconnection  
agreement and the interconnection application must proceed under R 460.966.  
(8) An applicant shall pay the actual cost of the interconnection facilities and  
distribution upgrades. The cost to the applicant for interconnection facilities and  
distribution upgrades may not exceed 110% of the estimate without an itemized summary  
and explanation of cost increases being provided to the applicant. If the costs are  
expected to exceed 125% of the estimate, the electric utility shall provide further  
explanation to the applicant prior to the costs being incurred. If the applicant does not  
consent in writing to pay the additional costs within 20 business days after receiving  
further explanation from the electric utility, the electric utility shall initiate informal  
mediation pursuant to R 460.904 no later than 5 business days after the conclusion of the  
20-business day applicant consent period. The applicant may dispute the expected costs  
pursuant to either informal mediation pursuant to R 460.904, formal mediation pursuant  
to R 460.906, or the complaint process pursuant to R 792.10439 to R 792.10446. If there  
is a dispute, the applicant shall make payment within 30 business days after final  
resolution of the dispute.  
31  
(9) A party’s obligations under the interconnection agreement may be extended by  
agreement. If a party anticipates that it will be unable to meet a milestone for any reason  
other than an unforeseen event, the party shall do all of the following:  
(a) Immediately notify the other party of the reason or reasons for not meeting the  
milestone.  
(b) Propose the earliest alternate date when it can attain this and future milestones.  
(c) Request amendments to the interconnection agreement, if needed to address the  
changed milestones.  
(10) The party affected by the failure to meet a milestone shall not withhold agreement  
to any amendments proposed in subrule (9)(c) of this rule unless 1 of the following  
applies:  
(a) The party affected will suffer significant uncompensated economic or operational  
harm from the amendment or amendments.  
(b) The milestone under question has been previously delayed and the affected party  
has reason to believe that the delay in meeting the milestone is intentional or unwarranted  
notwithstanding the circumstances explained by the party proposing the amendment.  
(11) If the party affected by the failure to meet a milestone disputes the proposed  
extension, the affected party may pursue either informal mediation pursuant to R  
460.904, formal mediation pursuant to R 460.906, or the complaint process pursuant to R  
792.10439 to R 792.10446.  
(12) The electric utility shall provide the applicant with a final accounting report of any  
difference between costs charged to the applicant and previous payments to the electric  
utility for interconnection facilities or distribution upgrades. Both of the following apply  
to a final accounting:  
(a) If the costs charged to the applicant exceed its previous aggregate payments, the  
electric utility shall bill the applicant for the amount due and the applicant shall make a  
payment to the electric utility within 20 business days of the final accounting report. The  
applicant may dispute the invoice pursuant to either informal mediation pursuant to R  
460.904, formal mediation pursuant to R 460.906, or the complaint process pursuant to R  
792.10439 to R 792.10446. If there is a dispute, the applicant shall make payment within  
30 business days of final resolution of the dispute. Failure by the applicant to pay its costs  
is cause for disconnection of the applicant’s DER.  
(b) If the applicant’s previous aggregate payments exceed its costs under the  
interconnection agreement, the electric utility shall refund to the applicant an amount  
equal to the difference within 20 business days of the final accounting report.  
(13) The electric utility is responsible for specifying requirements in interconnection  
agreements to support independent system operator regulations or regional transmission  
operator regulations.  
(14) The electric utility may propose to the commission that a signed interconnection  
agreement be modified to require compliance with changes to an independent system  
operator, a regional transmission operator, or the state’s regulations. Unless the electric  
utility has the consent of the applicant or interconnection customer in writing, an electric  
utility shall not modify a signed interconnection agreement without commission approval.  
32  
R 460.966 Inspection, testing, and commissioning.  
Rule 66. (1) If the interconnection application requires telecommunications, cybersecurity,  
data exchange or remote controls operation, successful testing and certification of these  
items must be completed prior to or during testing. The electric utility’s interconnection  
procedures must describe the technical requirements of common items, but site-specific  
requirements may be included in the interconnection agreement.  
(2) An applicant shall notify the electric utility when installation of a DER and any  
required local code inspection and approval is complete. The applicant shall provide any  
test reports or configuration documents as defined in the standard level 1, 2, and 3  
interconnection agreement or level 4 and 5 interconnection agreement.  
(3) The electric utility shall review the applicant’s inspection, test reports, or configuration  
documents, and communicate its intent to perform a witness or commissioning test, or  
waive its right to perform a witness test and commissioning test within 10 business days.  
If the electric utility finds the applicant’s inspection, test reports, or configuration  
documents to be incomplete, insufficient, or unsatisfactory, the electric utility shall provide  
the reasons for doing so in writing and the applicant shall have not less than 20 business  
days or a mutually agreed upon timeframe with the utility to implement corrections to those  
documents. The applicant, after taking corrective action, shall request the electric utility to  
reconsider the inspection, test reports, or configuration documents.  
(4) Subsequent to completion of the items in subrule (3), if the electric utility intends to  
witness or perform commissioning tests required to comply with the interconnection  
agreement or the interconnection procedures and inspect the DER, the electric utility shall  
witness or perform the commissioning tests and inspect the DER within the following:  
(a) Ten business days of receiving the notification from the applicant pursuant to  
completion of subrules (2) and (3) of this rule for level 1 applications.  
(b) Twenty business days after receiving the notification from the applicant pursuant to  
completion of subrules (2) and (3) of this rule for level 2 and level 3 applications.  
(c) A mutually-agreed upon timeframe after receiving the notification from the  
applicant pursuant to completion of subrules (2) and (3) of this rule for level 4 and 5  
applications.  
(5) The electric utility may waive its right to visit the site and inspect the DER or  
perform the commissioning tests. The following requirements apply:  
(a) If the electric utility waives this right, it shall provide a written waiver to the  
applicant within 10 business days from receiving the notification from the applicant  
pursuant to subrule (2) of this rule.  
(b) The applicant shall provide the electric utility with the completed commissioning  
test report within 20 business days of receipt of the electric utility’s written waiver.  
(6) If the electric utility attempts to conduct the inspection and testing pursuant to  
subrule (4) of this rule at the arranged time and is unable to access the DER or complete  
the testing, the DER must remain disconnected until the applicant and the electric utility  
can complete the inspection and testing.  
(7) If the electric utility witnessed or performed commissioning tests and inspected the  
DER pursuant to subrule (4) of this rule, within 5 business days of the receipt of the  
completed commissioning test report, the electric utility shall notify the applicant whether  
33  
it has accepted or rejected the commissioning test report and found the site to be  
satisfactory or unsatisfactory. The following requirements apply:  
(a) If the commissioning test report is accepted and the site was found satisfactory, the  
electric utility shall provide the notification of acceptance in writing, and the  
interconnection application proceeds to R 460.968.  
(b) If the electric utility rejects the commissioning test report or did not find the site  
satisfactory, the electric utility shall provide its reasons for doing so in writing and the  
applicant has not less than 20 business days to implement corrections. The applicant, after  
taking corrective action, shall request the electric utility to reconsider its findings. The  
applicant may be billed the actual cost of any re-inspections.  
(8) If the electric utility waived its right to witness or perform commissioning tests and  
inspect the DER pursuant to subrule (5) of this rule, within 5 business days of the receipt  
of the completed commissioning test report, the electric utility shall notify the applicant  
whether it has accepted or rejected the commissioning test report. The following  
requirements apply:  
(a) If the commissioning test report is accepted, the electric utility shall provide  
notification of acceptance, and the interconnection application proceeds to R 460.968.  
(b) If the electric utility rejects the commissioning test report, the electric utility shall  
provide its reasons for doing so in writing and the applicant has not less than 20 business  
days to implement corrections. The applicant, after taking corrective action, may then  
request the electric utility to reconsider its findings.  
(9) The cost of testing and inspection for applicants participating in an electric utility’s  
distributed generation program, as described in part 3 of these rules, R 460.1001 to R  
460.1026, are considered a cost of operating a distributed generation program and must  
be recovered pursuant to section 175(1) of the clean and renewable energy and energy  
waste reduction act, 2008 PA 295, MCL 460.1175.  
(10) If the applicant does not notify the electric utility that the DER is installed and  
ready to test pursuant to subrule (2) of this rule, the electric utility may, in writing, query  
the status of the interconnection. If the applicant does not provide a written response  
within 10 business days or no progress is evident, the electric utility may consider the  
interconnection application withdrawn.  
R 460.968 Authorization required prior to parallel operation.  
Rule 68. (1) The electric utility shall provide to the applicant written authorization to  
operate in parallel with the electric utility within 5 business days of all of the following  
conditions being met:  
(a) The electric utility notified the interconnection applicant that the commissioning test  
and inspection, where applicable, are accepted.  
(b) The applicant has executed a standard level 1, 2, and 3 interconnection agreement  
or level 4 and 5 interconnection agreement and complied with all applicable parallel  
operation requirements as set forth in the electric utility’s interconnection procedures and  
applicable interconnection agreement.  
(c) The applicant complied with all applicable local, state, and federal requirements.  
(d) The electric utility received full payments for all outstanding bills.  
34  
(2) With the written authorization, interconnection of the DER is considered approved  
for parallel operation, the DER may begin operating, and the applicant is considered an  
interconnection customer.  
(3) The applicant shall not operate its DER in parallel with the electric utility’s  
distribution system without prior written permission to operate from the electric utility.  
(4) Subject to reasonable timing and other conditions, including completion of  
conditions in the interconnection agreement or interconnection procedures, the electric  
utility shall allow for reasonable but limited testing before written authorization has  
occurred.  
R 460.970 Cost allocation of interconnection facilities, distribution upgrades, and  
associated operation and maintenance costs.  
Rule 70. Costs for interconnection facilities, distribution upgrades, and associated  
operation and maintenance costs must be classified into 1 of the following categories:  
(a) Site-specific costs, which include, but are not limited to, costs of interconnection  
facilities and distribution upgrades that are caused by 1 DER, whether that DER is  
electrically co-incident with other DERs or not. These costs must be assigned to the cost-  
causing applicant.  
(b) Shared interconnection facilities costs, which are costs caused by DERs which  
together necessitate the construction of interconnection facilities. The interconnection  
facilities costs, including any associated operation and maintenance costs, that should be  
shared must be allocated to each applicant based on a methodology described in the  
electric utility’s interconnection procedures.  
(c) Shared distribution upgrade costs, which are costs caused by electrically co-incident  
DERs that together necessitate a distribution upgrade. The distribution upgrade costs,  
including any associated operation and maintenance costs, that should be shared must be  
allocated to each applicant based on a methodology described in the electric utility’s  
interconnection procedures.  
R 460.974 Interconnection metering and communications.  
Rule 74. (1) Any metering and communications requirements necessitated by use of the  
DER must be installed at the applicant’s expense. The electric utility may furnish this  
equipment at the applicant’s expense.  
(2) The electric utility may charge the interconnection customer reasonable ongoing fees  
to maintain the metering and communications equipment. These fees must be listed in the  
interconnection agreement.  
R 460.976 Post commissioning remedy.  
Rule 76. (1) If the electric utility finds that the DER is operating outside the terms of the  
interconnection agreement but does not find immediate disconnection pursuant to R  
460.978(1)(f) and (g) warranted, the electric utility shall promptly inform the  
interconnection customer or its agent of this finding. The interconnection customer is  
responsible for bringing the DER into compliance within 30 business days or a mutually  
35  
agreed-upon time period. The electric utility may perform an inspection of the DER after  
a remedy is applied.  
(2) If the DER is not brought into compliance within 30 business days or the mutually  
agreed-upon time period, the electric utility may apply a remedy and bill the  
interconnection customer. The interconnection customer shall pay this bill within 5  
business days.  
R 460.978 Disconnection.  
Rule 78. (1) An electric utility may refuse to connect or may disconnect a project from  
the distribution system if any of the following conditions apply:  
(a) Failure of the interconnection customer to bring a DER into compliance pursuant to  
R 460.976(1).  
(b) Failure of the interconnection customer to pay costs of remedy pursuant to R  
460.976(2).  
(c) Termination of interconnection by mutual agreement.  
(d) Distribution system emergency, but only for the time necessary to resolve the  
emergency.  
(e) Routine maintenance, repairs, and modifications performed in a reasonable time and  
with prior notice to the interconnection customer.  
(f) Noncompliance with technical or contractual requirements in the interconnection  
agreement that could lead to degradation of distribution system reliability, electric utility  
equipment, and electric customers’ equipment.  
(g) Noncompliance with technical or contractual requirements in the interconnection  
agreement that presents a safety hazard.  
(h) Other material noncompliance with the interconnection agreement.  
(i) Operating in parallel without prior written authorization from the electric utility as  
provided for in R 460.968.  
(2) An electric utility may disconnect electric service, where applicable, pursuant to R  
460.136.  
R 460.980 Capacity of the DER.  
Rule 80. (1) If the interconnection application requests an increase in capacity for an  
existing DER, the electric utility shall evaluate the application based on the new export  
capacity of the DER. The maximum capacity of a DER is the aggregate nameplate rating.  
or may be limited as described in the electric utility’s interconnection procedures.  
(2) An interconnection application for a DER that includes single or multiple types of  
DERs at a site for which the applicant seeks a single point of common coupling must be  
evaluated as described in the electric utility’s interconnection procedures.  
(3) The electric utility’s interconnection procedures may describe acceptable methods  
for power limited export DER including, but not limited to, reverse power protection and  
utilizing inverters or control systems so that the DER capacity considered by the electric  
utility for reviewing the interconnection application is only the amount capable of being  
exported. These methods for power limited export DER may be used as alternatives to  
the method described in subrule (4) of this rule.  
36  
(4) An electric utility shall allow interconnection of limited-export or non-exporting  
DERs according to this subrule. If a DER uses any configuration or operating mode in  
this subrule to limit the export of electrical power across the point of common coupling,  
then the capacity must be only the amount capable of being exported, not including any  
inadvertent export. To prevent impacts on system safety and reliability, any inadvertent  
export from a DER must comply with the limits in subdivisions (e) or (f) of this subrule.  
The export capacity specified by the applicant in the application must be included as a  
limitation in the interconnection agreement. Other means not listed in this subrule may be  
utilized to limit export if mutually agreed upon by the electric utility and applicant.  
Interconnections of limited-export or non-exporting DERs are subject to the following  
options:  
(a) To ensure power is never exported across the point of common coupling, a reverse  
power protective function may be provided. The default setting for this protective  
function must be 0.1% export of the service transformer’s rating, with a maximum 2.0  
second time delay.  
(b)To ensure at least a minimum amount of power is imported across the point of  
common coupling at all times and, therefore, that power is not exported, an under-power  
protective function may be provided. The default setting for this protective function is 5%  
import of the DER’s total nameplate rating, with a maximum 2.0 second time delay.  
(c)The nameplate rating of the DER, minus any auxiliary load, must be so small in  
comparison to its host facility’s minimum load that the use of additional protective  
functions are not required to ensure that power is not exported to the distribution system.  
This option requires the DER capacity must be no greater than 50% of the applicant’s  
verifiable minimum host load over the past 12 months.  
(d) A reduced output rating utilizing the power rating configuration setting may be  
used to ensure the DER does not generate power beyond a certain value lower than the  
nameplate rating.  
(e) DERs may utilize a Nationally Recognized Testing Laboratory Certified Power  
Control System and inverter system that results in the DER disconnecting from the  
distribution system, ceasing to energize the distribution system, or halting energy  
production within 2 seconds if the period of continuous inadvertent export exceeds 30  
seconds. Failure of the control or inverter system for more than 30 seconds, resulting  
from loss of control or measurement signal, or loss of control power, must result in the  
DER entering an operational mode where no energy is exported across the point of  
common coupling to the distribution system.  
(f) DERs may be designed with other control systems or protective functions, or both,  
to limit export and inadvertent export to levels mutually agreed on by the applicant and  
the electric utility. The limits may be based on technical limitations of the applicant’s  
equipment or the distribution system’s equipment. To ensure inadvertent export remains  
within mutually agreed-upon limits, the applicant shall use an internal transfer relay,  
energy management system, or other customer facility hardware or software.  
R 460.982 Modification of the interconnection application.  
Rule 82. (1) At any point after an interconnection application is considered accepted  
but before the signing of an interconnection agreement, the applicant, the electric utility,  
37  
or the affected system owner may propose modifications to the interconnection  
application that may improve the costs and benefits of the interconnection, or that  
improve the ability of the electric utility to accommodate the interconnection. The  
applicant shall submit to the electric utility, in writing, all proposed modifications to any  
information provided in the interconnection application and the electric utility shall  
perform an evaluation to determine whether the proposed modification is a material  
modification and provide the results to the applicant within 10 business days.  
(2) The electric utility shall not be required to accept or implement a modification to the  
electric utility’s distribution system or generation assets that is proposed by an applicant or  
affected system operator.  
(3) The applicant may request a 1-hour consultation to discuss the results of the material  
modification review.  
(4) Neither the electric utility nor the affected system operator may unilaterally modify  
an accepted interconnection application. If the electric utility evaluates DERs using  
individual studies, the timelines specific to that interconnection application must be  
placed on hold while the proposed modification is being evaluated by the electric utility.  
(5) For a proposed modification which the electric utility has determined is a material  
modification and that further study is required, the applicant shall select 1 of the  
following options:  
(a) Withdraw the modification.  
(b) Withdraw the application.  
(c) Propose a different modification to the  
interconnection application for electric utility review, pursuant to subrule (1) of this rule,  
to determine whether the modification is material.  
(d) If the electric utility offers an expedited study of the application with the proposed  
material modification, the applicant may request the expedited study. If the electric  
utility offers an expedited study, the process of performing an expedited study must be  
described in the electric utility’s interconnection procedures.  
(e) Initiate informal mediation pursuant to R 460.904  
(f) Initial formal mediation pursuant to R460.906  
(g) File a complaint pursuant to R 792.10439 to R 792.10446.  
(6) The applicant shall notify the electric utility of its selection pursuant to subrule (5) of  
this rule within 10 business days of receiving the electric utility notification of the results  
or the modification may be considered withdrawn.  
(7) For a proposed modification that the electric utility has determined is a material  
modification, but does not require further study, the electric utility shall continue  
processing the interconnection application according to these rules.  
(8) Any modification to the interconnection application that could affect the operation  
of the distribution system, including but not limited to, changes to machine data,  
equipment configuration, or the interconnection site of the DER, not agreed to in writing  
by the electric utility and the applicant may be treated by the electric utility as a  
withdrawal of the interconnection application requiring submission of a new  
interconnection application.  
(9) At any point prior to the execution of an interconnection agreement, changes to  
ownership will cause the interconnection application to be put on hold until the new  
owner signs all necessary agreements and documents. An electric utility may not be  
38  
found in violation of these rules related to the processing of the interconnection  
application during such a transfer of ownership.  
(10) The electric utility’s interconnection procedures must provide a procedure for  
performing a material modification review.  
R 460.984 Modifications to the DER.  
Rule 84. After the execution of the interconnection agreement, the applicant shall notify  
the electric utility of any plans to modify the DER. The electric utility shall review the  
proposed modification to determine if the modification is considered a material  
modification. If the electric utility determines that the modification is a material  
modification, the electric utility shall notify the applicant, in writing of its determination  
and the applicant shall submit a new application and application fee along with all  
supporting materials that are reasonably requested by the electric utility. The applicant  
may not begin any material modification to the DER until an interconnection agreement  
incorporating the material modification is fully executed.  
R 460.986 Insurance.  
Rule 86. (1) An applicant interconnecting a level 1 or 2 project to the distribution  
system of an electric utility may not be required by the electric utility to obtain any  
additional liability insurance.  
(2) An electric utility shall not require an applicant interconnecting a level 1 or 2 project  
to name the electric utility as an additional insured party.  
(3) For a level 3 project, the applicant shall obtain and maintain general liability  
insurance of a minimum of $1,000,000.  
(4) For a level 4 project, the applicant shall obtain and maintain general liability  
insurance of a minimum of $2,000,000.  
(5) For a level 5 project, the applicant shall obtain and maintain general liability  
insurance of a minimum of $3,000,000.  
(6) For level 3, 4, and 5 projects, the electric utility may describe in its interconnection  
procedures required terms and conditions that must be specified in the general liability  
insurance.  
R 460.988 Easements and rights-of-way.  
Rule 88. If a line extension is required to accommodate an interconnection, the  
applicant is responsible for providing and obtaining the easements or rights of way,  
including all associated cost, in a form consistent with utility tariffs.  
R 460.990 Interconnection penalties.  
Rule 90. Pursuant to section 10e of 1939 PA 3, MCL 460.10e, an electric utility shall  
take all necessary steps to ensure that DERs are connected to the distribution systems  
within their operational control. If the commission finds, after notice and hearing, that an  
electric utility has prevented or unduly delayed the ability of a DER greater than 100 kW  
to connect to the distribution system of the electric utility, the commission may order  
remedies designed to make whole the applicant proposing the DER, including, but not  
39  
limited to, reasonable attorney fees. If the electric utility violates this rule, the  
commission may order fines of not more than $50,000 per calendar day, commensurate  
with the demonstrated impact of the violation.  
R 460.991 Business day exclusions.  
Rule 91. An electric utility shall notify the commission and all applicants that have in-  
process applications when timelines are being extended due to a business day where  
electric service is interrupted for 10% or more of an electric utility’s customers, pursuant  
to R 460.901a(k). The electric utility shall also notify the commission and all applicants  
that have in-process applications when application processing resumes.  
R 460.992 Electric utility annual reports.  
Rule 92. An electric utility shall file an annual interconnection report on a date and in a  
format determined by the commission.  
PART 3. DISTRIBUTED GENERATION PROGRAM STANDARDS  
R 460.1001 Application process.  
Rule 101. (1) An electric utility shall file initial distributed generation program tariff  
sheets in the first rate case filed after June 1, 2018.  
(2) Within 30 calendar days of a commission order approving an electric utility’s initial  
distributed generation tariff, or within 30 calendar days of the effective date of these  
rules, whichever is later, an alternative electric supplier serving customers in that electric  
utility’s service territory shall file an updated distributed generation program plan  
applicable to its customers in the affected electric utility’s service territory.  
(3) An electric utility and an alternative electric supplier shall annually file a legacy net  
metering program report and, if applicable, a distributed generation program report not  
later than March 31 of each year.  
(4) An electric utility and an alternative electric supplier shall maintain records of all  
applications and up-to-date records of all eligible electric generators participating in the  
legacy net metering program and distribution generation program.  
(5) Selection of customers for participation in the legacy net metering program or  
distributed generation program must be based on the order in which the applications are  
received.  
(6) An electric utility or alternative electric supplier shall not refuse to provide or  
discontinue electric service to a customer solely because the customer participates in the  
legacy net metering program or distributed generation program.  
(7) The legacy net metering program and distributed generation program provided by  
electric utilities and alternative electric suppliers must be designed for a period of not less  
than 10 years and limit each applicant to generation capacity designed to meet up to  
100% of the customer’s electricity consumption for the previous 12 months. All of the  
following requirements apply:  
40  
(a) The generation capacity must be determined by an estimate of the expected annual  
kWh output of the generator or generators as determined in an electric utility’s  
interconnection procedures and specified on an electric utility's legacy net metering  
program or distributed generation program tariff sheet or in the alternative electric  
supplier’s legacy net metering program or distributed generation program plan. For  
projects in which energy export controls are implemented pursuant to section R 460.980  
and utilized to limit the export to 100% of the customer’s electricity consumption for the  
previous 12 months, an electric utility shall not add the storage capacity to generation  
capacity for the purpose of the study. If a customer has multiple inverters capable of  
exporting to the distribution grid, the inverters must be configured in a way that prevents  
the cumulative maximum export at any given time to exceed the approved amount in the  
customer’s application.  
(b) A customer’s electric consumption must be determined by 1 of the following  
methods:  
(i) The customer’s annual energy consumption, measured in kWh, during the previous  
12-month period.  
(ii) If there is no data, incomplete data, or incorrect data for the customer’s energy  
consumption or the customer is making changes on-site that will affect total  
consumption, the electric utility or alternative electric supplier and the customer shall  
mutually agree on a method to determine the customer’s electric consumption.  
(c) A net metering or distributed generation customer using an energy storage device in  
conjunction with an eligible electric generator shall not design or operate the energy storage  
device in a manner that results in the customer’s electrical output exceeding 100% of the  
customer’s electricity consumption for the previous 12 months. The addition of an energy  
storage device to an existing approved legacy net metering program system or distributed  
generation program system is considered a material modification. The electric utility  
interconnection procedures must include details describing how energy storage equipment  
may be integrated into an existing legacy net metering program system without impacting  
the 10-year grandfathering period or participation in the distributed generation program.  
(8) An applicant shall notify the electric utility of plans for any material modification to  
the project. An applicant shall re-apply for interconnection pursuant to part 2 of these  
rules, R 460.911 to R 460.992, and submit revised legacy net metering program or  
distributed generation program application forms and associated fees. An applicant may  
be eligible to continue participation in the legacy net metering program or distributed  
generation program when a material modification is made to a customer’s previously  
approved system and it does not violate the requirements of subrule (7) of this rule or R  
460.1026. An applicant shall not begin any material modification to the project until the  
electric utility has approved the revised application, including any necessary system  
impact study or facilities study. The application must be processed pursuant to part 2 of  
these rules, R 460.911 to R 460.992.  
R 460.1004 Legacy net metering program application and fees.  
Rule 104. (1) An electric utility or alternative electric supplier may use an online legacy  
net metering program application process. An electric utility or alternative electric  
supplier not using an online application process, may utilize a uniform legacy net  
41  
metering program application form which must be approved by the commission. An  
electric utility’s legacy net metering program application may be combined with an  
electric utility’s interconnection application.  
(2) A customer taking retail electric service from an electric utility and applying to  
participate in the legacy net metering program shall concurrently submit a completed  
legacy net metering program application and interconnection application or indicate on  
the legacy net metering program application the date that the customer applied for  
interconnection with the electric utility and, if applicable, the date the customer received  
authorization to operate in parallel pursuant to R 460.968. All of the following  
requirements apply:  
(a) Where a legacy net metering program application is accompanied by an associated  
interconnection application, an electric utility shall complete its review of the legacy net  
metering program application in parallel with processing the interconnection application  
pursuant to part 2 of these rules, R 460.911 to R 460.992, pursuant to both of the  
following:  
(i) Combined with the notification of interconnection application completeness and  
conformance pursuant to R 460.936, the electric utility shall notify the customer whether  
the legacy net metering program application is accepted, and provide an opportunity for  
the customer to resolve any application deficiencies pursuant to the timelines in R  
460.936(7)(b) or withdraw the application, or the electric utility may consider the legacy  
net metering program application withdrawn without refund of the application fees.  
(ii) While processing the interconnection application, which may include, but is not  
limited to, R 460.946 fast track initial review, the electric utility shall determine whether  
the appropriate meter or meters, is installed for the legacy net metering program.  
(b) When a legacy net metering program application is filed with an already in-progress  
interconnection application, the utility may process the legacy net metering application in  
parallel with the interconnection application pursuant to part 2 of these rules, R 460.911  
to R 460.992, and subdivision (a) of this subrule, if practicable, or adopt the review  
process pursuant to subdivision (c) of this subrule.  
(c) When a legacy net metering program application is filed with an in-progress  
interconnection application and the electric utility determines it is not practicable to  
process the legacy net metering program application in parallel with the interconnection  
application, or when the legacy net metering application is filed subsequent to the  
customer receiving authorization to operate its eligible generator in parallel pursuant to R  
460.968, the electric utility shall process the legacy net metering program application  
pursuant to both of the following:  
(i) The electric utility shall review the legacy net metering program application and  
determine whether to accept the application pursuant to the timelines in R 460.936(6) and  
(7) within 10 business days. The timelines in R 460.936(7)(a) apply to electric utility  
notifications. The electric utility shall provide the customer an opportunity to resolve any  
application deficiencies pursuant to R 460.936(7)(b). If the customer fails to remedy the  
deficiency within the timelines pursuant to R. 460.936(7)(b), the electric utility may  
consider the legacy net metering application withdrawn without refund of the application  
fees.  
42  
(ii) Within 10 business days of notifying the customer that the legacy net metering  
application has been accepted, the electric utility shall determine whether the appropriate  
meter is installed for the legacy net metering program.  
(d) If a customer approved for participation in the legacy net metering program requires  
a new or additional meter or meters, the electric utility shall arrange with the customer to  
install the meter or meters at a mutually agreed upon time.  
(e) The electric utility shall complete changes to the customer’s account to permit the  
legacy net metering program credit to be applied to the account no more than 10 business  
days after the necessary meter is installed and all necessary steps in R 460.966 are  
completed.  
(3) A customer taking retail electric service from an alternative electric supplier shall  
submit a completed legacy net metering program application to the alternative electric  
supplier and provide a copy to the electric utility that provides distribution service. The  
following requirements apply:  
(a) The electric utility shall process the legacy net metering program application  
according to the applicable timelines in subrule (2)(a) through (d) of this rule.  
(b) The electric utility shall notify the alternative electric supplier when it has provided  
the applicant authorization to operate the eligible electric generator in parallel pursuant to  
R 460.968 and, if applicable, that installation of the appropriate meter or meters is  
completed.  
(c) Within 10 business days of the electric utility’s notification, the alternative electric  
supplier shall complete changes to the applicant's account to permit the legacy net  
metering program credit to be applied to the account.  
(4) If a legacy net metering program application is not approved by the alternative  
electric supplier, the alternative electric supplier shall notify the customer and the electric  
utility of the reasons for the disapproval. The alternative electric supplier shall provide  
the customer an opportunity to remedy the deficiency pursuant to the timelines in R  
460.936(7)(b) or withdraw the application. If the customer fails to remedy the deficiency  
within the timelines pursuant to R. 460.936(7)(b), the alternative electric supplier and  
electric utility may consider the legacy net metering application withdrawn without  
refund of the application fees.  
(5) If a customer’s application for the legacy net metering program is approved, the  
customer shall have a completed and approved installation within 6 months from the date  
the customer’s application is considered complete, or the electric utility or alternative  
electric supplier may terminate the application without refund and shall have no further  
responsibility with respect to the application.  
(6) Customers participating in a legacy net metering program approved by the  
commission before the commission establishes a tariff pursuant to section 6a(14) of 1939  
PA 3, MCL 460.6a, may elect to continue to receive service under the terms and  
conditions of that program for up to 10 years from the date of initial enrollment.  
(7) The legacy net metering program application fee for electric utilities and alternative  
electric suppliers may not exceed $50. The fee must be specified on the electric utility’s  
legacy net metering tariff sheet or in the alternative electric supplier's legacy net metering  
program plan.  
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R 460.1006 Distributed generation program application and fees.  
Rule 106. (1) An electric utility or alternative electric supplier may use an online  
distributed generation program application process. An electric utility or alternative  
electric supplier not using an online application process may utilize a uniform distributed  
generation program application form that must be approved by the commission. An  
electric utility’s distributed generation program application may be combined with an  
electric utility’s interconnection application.  
(2) A customer taking retail electric service from an electric utility and applying to  
participate in the distributed generation program shall concurrently submit a completed  
distributed generation program application and interconnection application or indicate on  
the distributed generation program application the date that the customer applied for  
interconnection with the electric utility and, if applicable, the date the customer received  
authorization to operate in parallel pursuant to R 460.968. All of the following  
requirements apply:  
(a) When a distributed generation program application is accompanied by an associated  
interconnection application, an electric utility may complete its review of the distributed  
generation program application before, during, or after processing the interconnection  
application pursuant to part 2 of these rules, R 460.911 to R 460.992. Both of the  
following requirements apply:  
(i) Combined with the notification of interconnection application completeness and  
conformance pursuant to R 460.936, an electric utility shall notify the customer whether  
the distributed generation program application is accepted, and provide an opportunity for  
the customer to remedy any application deficiencies pursuant to the timelines in R  
460.936(7)(b) or withdraw the application. If the customer fails to remedy the application  
deficiencies within the timelines in R 460.936(7)(b), the electric utility may consider the  
distributed generation program application withdrawn without refund of the application  
fees.  
(ii) While processing the interconnection application, which may include, but is not  
limited to, R 460.946 fast track initial review, the electric utility shall determine whether  
the appropriate meter is installed for the distributed generation program.  
(b) If a distributed generation program application is filed with an already in-progress  
interconnection application, the electric utility may process the distributed generation  
program application in parallel with the interconnection application pursuant to part 2 of  
these rules, R 460.911 to R 460.992, subdivision (2) of this subrule, if practicable, or  
adopt the review process pursuant to subdivision (c) of this subrule.  
(c) If a distributed generation program application is filed with an in-progress  
interconnection application and the electric utility determines it is not practicable to  
process the distributed generation program application in parallel with the  
interconnection application or the distributed generation application is filed subsequent to  
the customer receiving authorization to operate its eligible generator in parallel pursuant  
to R 460.968, the electric utility shall process the distributed generation program  
application pursuant to all of the following:  
(i) The electric utility has 10 business days to review the distributed generation  
program application and determine whether to accept the application pursuant to the  
timelines in R 460.936(6) and (7). The timelines in R 460.936(7)(a) apply to utility  
notifications. The electric utility shall provide the customer an opportunity to remedy any  
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application deficiencies pursuant to R 460.936(7)(b). If the customer fails to remedy the  
application deficiencies within the timelines in R 460.936(7)(b), the electric utility may  
consider the distributed generation program application withdrawn without refund of the  
application fees.  
(ii) Within 10 business days of providing notification to the customer that the  
distributed generation program application has been accepted, the electric utility shall  
determine whether the appropriate meter, or meters, is installed for the distributed  
generation program.  
(d) If a customer approved for participation in the distributed generation program  
requires a new or additional meter or meters, the electric utility shall arrange with the  
customer to install the meter or meters at a mutually agreed upon time.  
(e) The electric utility shall complete changes to the customer’s account to permit  
distributed generation program credit to be applied to the account no more than 10  
business days after the necessary meter is installed and all necessary steps in R 460.966  
are completed.  
(3) A customer taking retail electric service from an alternative electric supplier shall  
submit a completed distributed generation program application to the alternative electric  
supplier and provide a copy to the electric utility that provides distribution service. All of  
the following requirements apply:  
(a) The alternative electric supplier shall process the distributed generation program  
application according to the applicable timelines in subrule (2)(a) through (d) of this rule.  
(b) The electric utility shall notify the alternative electric supplier when it has provided  
the applicant authorization to operate the eligible electric generator in parallel pursuant to  
R 460.968 and, if applicable, that installation of the appropriate meter or meters is  
completed.  
(c) Within 10 business days of the electric utility’s notification, the alternative electric  
supplier shall complete changes to the applicant's account to permit distributed generation  
program credit to be applied to the account.  
(4) If a distributed generation program application is not approved by the alternative  
electric supplier, the alternative electric supplier shall notify the customer and the electric  
utility of the reasons for the disapproval. The alternative electric supplier shall provide  
the customer an opportunity to remedy the deficiency pursuant to the timelines in R  
460.936(7)(b) or withdraw the application. If the customer fails to remedy the application  
deficiencies within the timelines in R 460.936(7)(b), the alternative electric supplier and  
electric utility may consider the distributed generation program application withdrawn  
without refund of the application fees.  
(5) If a customer’s distributed generation program application is approved, the customer  
shall have a completed and approved installation within 6 months from the date the  
customer’s application is considered complete, or the electric utility or alternative electric  
supplier may consider the application withdrawn without refund and shall have no further  
responsibility with respect to the application.  
(6) The distributed generation program application fee for electric utilities and  
alternative electric suppliers shall not exceed $50. The electric utility shall specify the fee  
on the electric utility’s distributed generation program tariff sheet or in the alternative  
electric supplier’s distributed generation program plan.  
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(7) The customer shall pay all interconnection costs pursuant to part 2 of these rules, R  
460.911 to R 460.992, which include all electric utility costs associated with the  
customer’s interconnection that are not a distributed generation program application fee,  
excluding meter costs as described in R 460.1012 and R 460.1014.  
R 460.1008 Legacy net metering program and distributed generation program size.  
Rule 108. (1) If an electric utility or alternative electric supplier reaches the program  
sizes as defined in section 173(3) of the clean and renewable energy and energy waste  
reduction act, 2008 PA 295, MCL 460.1173, or a voluntarily expanded program above  
the requirements defined in section 173(3) of the clean and renewable energy and energy  
waste reduction act, 2008 PA 295, MCL 460.1173, as determined by combining both the  
distributed generation program and the legacy net metering program customer  
enrollments, the electric utility or alternative electric supplier shall notify the  
commission.  
(2) The electric utility or alternative electric supplier shall notify the commission of its  
plans to either close the program to new applicants or expand the program.  
(3) The electric utility shall file corresponding revised legacy net metering program or  
distributed generation program tariff sheets.  
(4) The alternative electric supplier shall file a revised legacy net metering program plan  
or distributed generation program plan.  
R 460.1010 Generation and legacy net metering program or distributed generation  
program equipment.  
Rule 110. New legacy net metering program or distributed generation program  
equipment and its installation must meet all current local and state electric and  
construction code requirements, and other standards as specified in part 2 of these rules,  
R 460.911 to R 460.992.  
R 460.1012 Meters for legacy net metering program.  
Rule 112. (1) For a customer with a generation system capable of generating 20 kWac  
or less, an electric utility may determine the customer’s net usage using the customer’s  
existing meter if it is capable of reverse registration or may install a single meter with  
separate registers measuring power flow in each direction. If the electric utility uses the  
customer’s existing meter, the electric utility shall test and calibrate the meter to assure  
accuracy in both directions. If the customer’s meter is not capable of reverse registration  
and if meter upgrades or modifications are required, the following apply:  
(a) An electric utility serving 1,000,000 or more customers in this state shall provide a  
meter or meters capable of measuring the flow of energy in both directions at no  
additional charge to the legacy net metering program customer. The cost of the meter or  
meter modification is considered a cost of operating the legacy net metering program.  
(b) An electric utility serving fewer than 1,000,000 customers in this state shall provide  
a meter or meters capable of measuring the flow of energy in both directions to customers  
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at cost. Only the incremental cost above that for the meter provided by the electric utility  
to similarly situated non-generating customers shall be paid by the eligible customer.  
(c) An electric utility shall provide a generator meter, if requested by the customer, at  
cost.  
(2) For a customer with a generation system capable of generating more than 20 kWac  
and not more than 150 kWac, the electric utility shall utilize a meter or meters capable of  
measuring the flow of energy in both directions and the generator output. If meter  
upgrades are necessary to provide this functionality, all of the following apply:  
(a) An electric utility serving 1,000,000 or more customers in this state shall provide a  
meter or meters capable of measuring the flow of energy in both directions at no  
additional charge to a legacy net metering program customer. The cost of the meter or  
meters is considered a cost of operating the legacy net metering program.  
(b) An electric utility serving fewer than 1,000,000 customers in this state shall provide  
a meter or meters capable of measuring the flow of energy in both directions to customers  
at cost. Only the incremental cost above that for meters provided by the electric utility to  
similarly situated non-generating customers shall be paid by the eligible customer.  
(c) An electric utility shall provide a generator meter. The cost of the meter is  
considered a cost of operating the legacy net metering program.  
(3) For a customer with a generation system capable of generating more than 150 kWac,  
the electric utility shall utilize a meter or meters capable of measuring the flow of energy  
in both directions and the generator output. If meter upgrades are necessary to provide  
this functionality, the customer shall pay the cost of providing any new meters.  
(4) An electric utility deploying advanced metering infrastructure shall not charge the  
cost of advanced meters to a legacy net metering program participant or the legacy net  
metering program.  
R 460.1014 Meters for distributed generation program.  
Rule 114. (1) For a customer with a generation system capable of generating 20 kWac  
or less, an electric utility shall determine the customer’s power flow in each direction  
using the customer's existing meter if it is capable of measuring and recording power  
flow in each direction. If the customer’s meter is not capable of measuring and recording  
the customer’s power flow in each direction and if meter upgrades or modifications are  
required, all of the following apply:  
(a) An electric utility serving 1,000,000 or more customers in this state shall provide a  
meter or meters capable of measuring and recording the customer’s power flow in each  
direction at no additional charge to the distributed generation program customer. The cost  
of the meter or meter modification is considered a cost of operating the distributed  
generation program.  
(b) An electric utility serving fewer than 1,000,000 customers in this state shall provide  
a meter or meters capable of measuring and recording the power flow in each direction to  
customers at cost. Only the incremental cost above the cost for the meter provided by the  
electric utility to similarly situated non-generating customers shall be paid by the eligible  
customer.  
(c) An electric utility shall provide a generator meter at cost, if requested by the  
customer.  
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(2) For a customer with a generation system capable of generating more than 20 kWac  
and not more than 150 kWac, an electric utility shall utilize a meter or meters capable of  
measuring and recording power flow in each direction and the generator output. If the  
customer’s meter is not capable of measuring and recording the customer’s power flow in  
each direction along with the generator output, and if meter upgrades or modifications are  
required, all of the following apply:  
(a) An electric utility serving 1,000,000 or more customers in this state shall provide a  
meter or meters capable of measuring the flow of energy in both directions at no  
additional charge to a distributed generation program customer. If the electric utility  
provides the upgraded meter at no additional charge to the customer, the cost of the meter  
is considered a cost of operating the distributed generation program.  
(b) An electric utility serving fewer than 1,000,000 customers in this state shall provide  
a meter or meters capable of measuring the flow of energy in both directions to customers  
at cost. Only the incremental cost above the cost for the meter provided by the electric  
utility to similarly situated non-generating customers shall be paid by the eligible  
customer.  
(c) An electric utility shall provide a generator meter. The cost of the meter shall be  
considered a cost of operating the distributed generation program.  
(3) For a customer with a methane digester generation system capable of generating  
more than 150 kWac, an electric utility shall utilize a meter or meters capable of  
measuring the flow of energy in both directions and the generator output. If meter  
upgrades are necessary to provide such functionality, the customer shall pay the cost of  
providing any new meters.  
(4) An electric utility deploying advanced metering infrastructure shall not charge the  
cost of advanced meters to a distributed generation program customer or the distributed  
generation program.  
R 460.1016 Billing and credit for legacy net metering program customers taking service  
under true net metering.  
Rule 116. (1) Legacy net metering program customers with a system capable of  
generating 20 kWac or less qualify for true net metering. For customers qualifying for  
true net metering, the net of the bidirectional flow of kWh across the customer  
interconnection with the electric utility distribution system during the billing period or  
during each time-of-use pricing period within the billing period, including excess  
generation, shall be credited at the full retail rate.  
(2) The credit for excess generation, if any, shall appear on the next bill. Any excess  
credit not used to offset current charges must be carried forward for use in subsequent  
billing periods.  
R 460.1018 Billing and credit for legacy net metering program customers taking service  
under modified net metering.  
Rule 118. (1) Legacy net metering program customers with a system capable of  
generating more than 20 kWac qualify for modified net metering. A negative net metered  
quantity during the billing period or during each time-of-use pricing period within the  
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billing period reflects net excess generation for which the customer is entitled to receive  
credit. Standby charges for customers on an energy rate schedule must equal the retail  
distribution charge applied to the imputed customer usage during the billing period. The  
imputed customer usage 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. The commission shall establish standby charges for customers on demand-  
based rate schedules that provide an equivalent contribution to electric utility system  
costs. Standby charges may not be applied to customers with systems capable of  
generating 150 kWac or less.  
(2) The credit for excess generation must appear on the next bill. Any excess kWh not  
used to offset current charges must be carried forward for use in subsequent billing  
periods.  
(3) A customer qualifying for modified net metering shall not have legacy net metering  
program credits applied to distribution charges.  
(4) The credit per kWh for kWh delivered into the electric utility’s distribution system  
must be either of the following as determined by the commission:  
(a) The monthly average real-time locational marginal price for energy at the  
commercial pricing node within the electric utility’s distribution service territory or for a  
legacy net metering program customer on a time-based rate schedule, the monthly  
average real time locational marginal price for energy at the commercial pricing node  
within the electric utility’s distribution service territory during the time-of-use pricing  
period.  
(b) The electric utility’s or alternative electric supplier’s power supply component,  
excluding transmission charges, of the full retail rate during the billing period or time-of-  
use pricing period.  
R 460.1020 Billing and credit for distributed generation program customers.  
Rule 120. As part of an electric utility’s rate case filed after June 1, 2018, the  
commission shall approve a tariff for a distributed generation program under the clean  
and renewable energy and energy waste reduction act, 2008 PA 295, MCL 460.1001 to  
460.1211. A tariff established under this rule does not apply to customers participating in  
a legacy net metering program under the clean and renewable energy and energy waste  
reduction act, 2008 PA 295, MCL 460.1001 to 460.1211, before the date that the  
commission establishes a tariff under this rule, who continue to participate in the program  
at their current site or facility, as described by R 460.1026.  
R 460.1022 Renewable energy credits.  
Rule 122. (1) An eligible electric generator shall own any renewable energy credits  
granted for electricity generated under the legacy net metering program and distributed  
generation program.  
(2) An electric utility may purchase or trade renewable energy credits from a legacy net  
metering program or distributed generation program customer if agreed to by the  
customer.  
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(3) The commission may develop a program for aggregating renewable energy credits  
from legacy net metering program and distributed generation program customers.  
R 460.1024 Penalties.  
Rule 124. Upon a complaint or on the commission’s own motion, if the commission  
finds after notice and hearing that an electric utility has not complied with a provision or  
order issued under part 5 of the clean and renewable energy and energy waste reduction  
act, 2008 PA 295, MCL 460.1171 to 460.1185, the commission shall order remedies and  
penalties as necessary to make whole a customer or other person who has suffered  
damages as a result of the violation.  
R 460.1026 Legacy net metering grandfathering clause.  
Rule 126. A customer participating in a legacy net metering program approved by the  
commission before the commission establishes the initial distributed generation program  
tariff pursuant to R 460.1020 may elect to continue to receive service under the terms and  
conditions of that program for up to 10 years from the date of initial enrollment. “Initial  
enrollment,” as used in this rule, means the date a customer or site initially enrolled in a  
legacy net metering program as described in the electric utility’s tariff. A customer  
participating in a legacy net metering program who increases the nameplate rating of its  
generation system after the effective date of an electric utility’s distributed generation  
program tariff is no longer eligible to participate in the legacy net metering program.  
;