Chapter PSC 119

PSC 119.10 History History: CR 03-003: cr. Register January 2004 No. 577, eff. 2-1-04; CR 22-077: am. (2) Register April 2024 No. 820, eff. 5-1-24.

PSC 119.11 PSC 119.11 Control schematics. For equipment not certified under s. PSC 119.26, the applicant shall include with the application a complete set of control schematics showing all protective functions and controls for generator protection and distribution system protection.

PSC 119.11 History History: CR 03-003: cr. Register January 2004 No. 577, eff. 2-1-04.

PSC 119.12 PSC 119.12 Site plan. For all categories, the applicant shall include with the application a site plan that shows the location of the interconnection disconnect switch, adjoining street name, and the street address of the DG facility. For Category 2, 3, or 4 DG facilities, the site plan shall show the location of major equipment, electric service entrance, electric meter, interconnection disconnect switch, and interface equipment.

PSC 119.12 History History: CR 03−003: cr. Register January 2004 No. 577, eff. 2-1-04.

PSC 119.13 PSC 119.13 Pre-application report.

PSC 119.13(1) (1) Potential applicants may request a pre-application report in order to obtain information about system conditions at their proposed interconnection location, without submitting an application under s. PSC 119.04.

PSC 119.13(2) (2) To request a pre-application report, potential applicants shall complete and submit to its public utility the standard pre-application request form. A request for a pre- application report shall not be considered submitted until applicant submits the standard pre-application form and pays applicable pre-application review fees under s. PSC 119.08 (5).

PSC 119.13(3) (3) All submitted pre-application report requests shall be reviewed for completeness in the order in which they fulfill the requirements of sub. (2).

PSC 119.13(3m) (3m) Public utilities shall evaluate the submitted pre-application form for completeness within 5 business days of receipt. A complete request shall include location information that allows the public utility to clearly identify a proposed point of interconnection, and information on the proposed DG facility sufficient to identify DG type, nameplate and export capacity, and service configuration.

PSC 119.13(4) (4) All complete pre-application report requests shall receive pre-application reports in the order in which they fulfill the requirements of sub. (3). Within 15 business days of determining a pre-application report request complete, the public utility shall respond by providing the applicant with a completed standard pre- application report that provides information on the capacity, network and operating characteristics, and applicable operating constraints at the proposed point of interconnection.

PSC 119.13(4m) (4m) Completed pre-application reports shall reflect the best available information using existing data readily available to the public utility at the time of reporting. A public utility shall not be obligated to conduct additional analysis of the proposed project or location in order to complete a pre- application report. The report shall communicate to potential applicants that the information provided is subject to change and may not be applicable as of the date when a future application is submitted.

PSC 119.13 History History: CR 22-077: cr. Register April 2024 No. 820, eff. 5-1-24; renum. (3) (a), (4) (a) to be (3m) and (4m) under s. 13.92 (4) (b) 1., Stats., Register April 2024, No. 820.

subch. III of ch. PSC 119 Subchapter III — Design Requirements

PSC 119.20 PSC 119.20 General design requirements.

PSC 119.20(1) (1) The applicant shall install protection devices to ensure that the current supplied by the DG facility is interrupted if a fault or other potentially dangerous event occurs on the distribution system. If such an event occurs and the public utility’s distribution system is de-energized, any DG facility that is connected to this distribution system shall automatically disconnect. All DG facilities shall utilize protection devices that prevent electrically closing a DG facility that is out of synchronization with the distribution system.

PSC 119.20(2) (2) All installations shall include equipment circuit breakers, on the DG facility side of the point where the DG facility is electrically connected to the customer’s electrical system, that are capable of interrupting the maximum available fault current. Equipment circuit breakers shall meet all applicable UL, ANSI, and IEEE standards.

PSC 119.20(3) (3) The public utility may require that the applicant furnish and install an interconnection disconnect switch that opens, with a visual break, all ungrounded poles of the interconnection circuit. The interconnection disconnect switch shall be rated for the voltage and fault current requirements of the DG facility, and shall meet all applicable UL, ANSI, and IEEE standards. The switch enclosure shall be properly grounded. The interconnection disconnect switch shall be accessible at all times, located for ease of access to public utility personnel, and shall be capable of being locked in the open position. The applicant shall follow the public utility’s recommended switching, clearance, tagging, and locking procedures.

PSC 119.20 Note Note: Provisions of the Wisconsin Electrical Safety Code, Volume 2, ch. SPS 316 also apply to these installations.

PSC 119.20(4) (4) The applicant shall label the interconnection disconnect switch “Interconnection Disconnect Switch” by means of a permanently attached sign with clearly visible and permanent letters. The applicant shall provide and post its procedure for disconnecting the DG facility next to the switch.

PSC 119.20(5) (5) The applicant shall install an equipment grounding conductor, in addition to the ungrounded conductors, between the DG facility and the distribution system. The grounding conductors shall be available, permanent, and electrically continuous, shall be capable of safely carrying the maximum fault likely to be imposed on them by the systems to which they are connected, and shall have sufficiently low impedance to facilitate the operation of overcurrent protection devices under fault conditions. All DG transformations shall be multi-grounded. The DG facility may not be designed or implemented such that the earth becomes the sole fault current path.

PSC 119.20 Note Note: Grounding practices are also regulated by the Wisconsin Electrical Safety Code Volumes 1 and 2, as found in chs. SPS 316 and PSC 114.

PSC 119.20(6) (6) 

PSC 119.20(6)(a) (a) All inverter-based DG facilities shall be UL 1741 published September 28, 2021 listed.

PSC 119.20(6)(b) (b) All DG facilities shall meet the requirements of IEEE Std 1547-2018 and be tested in accordance with IEEE Std 1547.1.

PSC 119.20(6)(b)1. 1. Synchronous machine generation shall use the normal performance category of Category A and the abnormal performance category of Category I. Ride-through and trip settings shall meet the recommendations of the regional transmission operator guidelines.

PSC 119.20(6)(b)2. 2. Inverter-based DG facilities shall use the normal performance category of Category B and the abnormal performance category of Category II. Ride-through and trip settings shall meet the recommendations of the regional transmission operator guidelines. The public utility shall constructively work with the regional transmission operator to provide a recommendation whether abnormal performance category of Category III is the proper category assignment for inverter-based DG facilities.

PSC 119.20(6)(b)3. 3. Exceptions to these performance categories may be reviewed by the public utility on a case-by-case basis.

PSC 119.20(7) (7) 

PSC 119.20(7)(a) (a) All Category 1 and 2 DG facilities shall be operated at a power factor greater than 0.9.

PSC 119.20(7)(b) (b) All Category 3 and 4 DG facilities shall be operated at unity power factor or as mutually agreed between the public utility and applicant.

PSC 119.20(8) (8) The DG facility shall not create system voltage or current disturbances that exceed the standards listed in subch. VII of ch. PSC 113.

PSC 119.20(9) (9) The applicant shall protect and synchronize its DG facility with the distribution system.

PSC 119.20(10) (10) Each DG facility shall include an automatic interrupting device that is listed with a nationally recognized testing laboratory and is rated to interrupt available fault current. The interrupting device shall be tripped by any of the required protective functions.

PSC 119.20(11) (11) An applicant for interconnection of a Category 3 or Category 4 facility shall provide test switches as specified by the public utility, to allow for testing the operation of the protective functions without unwiring or disassembling the equipment.

PSC 119.20(12) (12) The public utility may require a DG facility to be isolated from other customers by installation of a separate power transformer. When a separate transformer is required, the utility may include its actual cost in the distribution system upgrade costs. The applicant is responsible for supplying and paying for any custom transformer. This requirement does not apply to an induction-type generator with a capacity of 5 kW or less, or to other generating units of 10 kW or less that utilize a line-commutated inverter.

PSC 119.20(13) (13) The owner of a DG facility designed to operate in parallel with a spot or secondary network service shall provide relaying or control equipment that is rated and listed for the application and is acceptable to the public utility.

PSC 119.20(14) (14) For a Category 3 or Category 4 DG facility, the public utility may require that the facility owner provide telemetry equipment whose monitoring functions include transfer-trip functionality, voltage, current, real power (watts), reactive power (vars), and breaker status.

PSC 119.20(15) (15) When the public utility requires two-way communication or control functionality of the DG facility, the applicant shall work with the public utility to establish the minimum standard technical and communication requirements.

PSC 119.20(16) (16) For interconnection purposes, energy storage systems shall be treated as distributed generation facilities and shall meet the following requirements and standards:

PSC 119.20(16)(a) (a) Provide operational mode programming that controls the charging, discharging, and bypass (export or non-export) of an energy storage system. Operational mode programming shall be stated in an interconnection agreement.

PSC 119.20(16)(b) (b) Be UL 9540, published February 27, 2020, listed.

PSC 119.20 Note Note: The UL standards are available at http://ulstandards.ul.com. They may also be viewed at the PSCW Library, 4822 Madison Yards Way, Madison, WI.

PSC 119.20 History History: CR 03-003: cr. Register January 2004 No. 577, eff. 2-1-04; CR 22-077: am. (6) (a), renum. (6) (b) to (6) (b) (intro.) and am., cr. (6) (b) 1. to 3., (15), (16) Register April 2024 No. 820, eff. 5-1-24; correction in (16) (b) made under s. 35.17, Stats., Register April 2024 No. 820.

PSC 119.25 PSC 119.25 Minimum protection requirements.

PSC 119.25(1) (1) Each DG facility shall include protection and unintentional islanding equipment to prevent the facility from adversely affecting the reliability or capability of the distribution system. The applicant shall contact the public utility to determine any specific protection requirements.

PSC 119.25(2) (2) The protective system functions, which may be met with microprocessor-based multifunction protection systems or discrete relays, are required. Protective relay activation shall not only alarm but shall also trip the generator breaker/contactor.

PSC 119.25(3) (3) In addition to unintentional islanding protection, a DG facility shall meet the following minimum protection requirements:

PSC 119.25(3)(a) (a) A Category 1 DG facility shall include:

PSC 119.25(3)(a)1. 1. Over/under frequency function.

PSC 119.25(3)(a)2. 2. Over/under voltage function.

PSC 119.25(3)(a)3. 3. Overcurrent function.

PSC 119.25(3)(a)4. 4. Ground fault protection.

PSC 119.25(3)(b) (b) A Category 2, 3, or 4 DG facility shall include:

PSC 119.25(3)(b)1. 1. Over/under frequency function.

PSC 119.25(3)(b)2. 2. Over/under voltage function.

PSC 119.25(3)(b)3. 3. Overcurrent function.

PSC 119.25(3)(b)4. 4. Ground fault protection.

PSC 119.25(3)(b)5. 5. Synchronism check function.

PSC 119.25(3)(b)6. 6. Other equipment, such as other protective devices, supervisory control and alarms, telemetry and associated communications channel, that the public utility determines to be necessary and is compliant with applicable codes and standards. The public utility shall advise the applicant of any communications requirements after a preliminary review of the proposed installation.

PSC 119.25(4) (4) A DG facility certified pursuant to s. PSC 119.26 shall be deemed to meet the requirements of this section.

PSC 119.25 History History: CR 03-003: cr. Register January 2004 No. 577, eff. 2-1-04; CR 22-077: am. (1), (3) (intro.), (b) 6. Register April 2024 No. 820, eff. 5-1-24.

subch. IV of ch. PSC 119 Subchapter IV — Equipment Certification

PSC 119.26 PSC 119.26 Certified paralleling equipment. DG paralleling equipment that a nationally recognized testing laboratory certifies as meeting the applicable type testing requirements of UL 1741 (September 28, 2021 revision) is acceptable for interconnection, without additional protection systems, to the distribution system. The applicant may use certified paralleling equipment for interconnection to a distribution system without further review or testing of the equipment design by the public utility, but the use of this paralleling equipment does not automatically qualify the applicant to be interconnected to the distribution system at any point in the distribution system. The public utility may still require an engineering review to determine the compatibility of the distributed generation system with the distribution system capabilities at the selected point of common coupling. DG paralleling equipment shall meet applicable codes and standards listed in PSC 119.025.

PSC 119.26 History History: CR 03-003: cr. Register January 2004 No. 577, eff. 2-1-04; CR 22-077: am. Register April 2024 No. 820, eff. 5-1-24.

PSC 119.27 PSC 119.27 Non-certified paralleling equipment.

PSC 119.27(1) (1) Any DG facility that is not certified under s. PSC 119.26 shall be equipped with protective hardware or software to prevent unintentional islanding and to maintain power quality. The applicant shall provide the final design of this protective equipment. The public utility may review and approve the design, types of protective functions, and the implementation of the installation. The applicant shall own the protective equipment installed at its facility.

PSC 119.27(2) (2) The applicant shall calibrate any protective system approved under sub. (1) to the specifications of the public utility. The applicant shall obtain prior written approval from the public utility for any revisions to specified protection system calibrations.

PSC 119.27 History History: CR 03-003: cr. Register January 2004 No. 577, eff. 2-1-04; CR 22-077: am. (1) Register April 2024 No. 820, eff. 5-1-24.

subch. V of ch. PSC 119 Subchapter V — Testing of DG Facility Installations

PSC 119.30 PSC 119.30 Unintentional islanding test. The public utility may perform an unintentional islanding test or observe the automatic shutdown before giving final written approval for interconnection of the DG facility. The unintentional islanding test requires that the DG facility shall detect the island, cease to energize the local distribution system, and trip within two seconds of the formation of an island. The test shall be conducted as close to the point of common coupling as possible and should demonstrate that the DG facility does not energize the local distribution or transmission system. The test shall be conducted with all DG facility equipment operational and generating at an output that reflects site conditions acceptable to both parties. If a voltage is sustained after the simulation of an unintentional island, approval of the installation shall not be given until corrective measures are taken with a subsequent successful test.

PSC 119.30 History History: CR 03-003: cr. Register January 2004 No. 577, eff. 2-1-04; CR 22-077: am. Register April 2024 No. 820, eff. 5-1-24.

PSC 119.31 PSC 119.31 Commissioning tests for paralleling equipment in Categories 2 to 4. The public utility shall provide the acceptable range of settings for the paralleling equipment of a Category 2, 3, or 4 DG facility. The applicant shall program protective equipment settings into this paralleling equipment. The public utility may verify the protective equipment settings prior to allowing the DG facility to interconnect to the distribution system.

PSC 119.31 History History: CR 03-003: cr. Register January 2004 No. 577, eff. 2-1-04.

PSC 119.32 PSC 119.32 Additional test. The public utility or applicant may, upon reasonable notice, re-test the DG facility installation after a failed test under s. PSC 119.30 or 119.31 or a disconnection under s. PSC 119.09. The party responsible for the re-testing shall bear the cost of the re-tests.

PSC 119.32 History History: CR 03-003: cr. Register January 2004 No. 577, eff. 2-1-04; CR 22-077: am. Register April 2024 No. 820, eff. 5-1-24.

PSC 119.40 PSC 119.40 Dispute Procedures.

PSC 119.40(1) (1) Applicants and public utilities shall attempt to resolve all disputes arising out of the interconnection process, including, but not limited to, the application and approval process under s. 119.04 and disconnection under s. 119.09, as described in this section.

PSC 119.40(2) (2) The applicant shall attempt to resolve the issue with the public utility by informing the public utility of the issue under dispute and the relief requested. The public utility shall:

PSC 119.40(2)(a) (a) Investigate the issue promptly and completely.

PSC 119.40(2)(b) (b) Advise the applicant of the results of the investigation.

PSC 119.40(2)(c) (c) Attempt to resolve the dispute.

PSC 119.40(3) (3) After the applicant has pursued available remedies with the public utility, the applicant may request that commission staff informally review the disputed issue and recommend terms of settlement.

PSC 119.40(3)(a) (a) The applicant’s request for an informal review may be made in any reasonable manner, such as by written request or telephone request direct to the commission. By telephone or written request public service commission staff may request information from the public utility to investigate the dispute.

PSC 119.40(3)(b) (b) The public utility shall designate employees for responding to disputes who are readily available and have an appropriate and sufficient authority level for investigating concerns raised by the commission and its staff. The public utility shall respond to commission staff’s request for investigation by providing a response to the commission within 10 business days. Commission staff may extend this time period if the public utility requests more time to complete its investigation. Based on the information provided by the applicant and the public utility, commission staff shall make an informal determination and communicate that determination in writing to both parties.

PSC 119.40(3)(c) (c) At least 7 days must elapse between the date commission staff communicates an informal determination and any disconnection of a distributed generation facility involved in the dispute.

PSC 119.40(4) (4) After an informal determination is made, any party to the dispute may make a written request for a formal review by the commission. All requests for formal review shall be made within 30 days of the date commission staff communicates a written informal determination. To avoid disconnection of a DG facility from the distribution system pending a formal review, an applicant must request formal commission review within 7 days after the commission’s informal determination.

PSC 119.40(5) (5) The commission shall make a determination whether to grant the request for formal review. The commission shall base its determination on the request for formal review and the information previously collected for informal review. Commission staff shall provide the commission with a memorandum based on the information it has received from the parties. A copy of the commission staff memorandum shall be provided to the parties 30 days prior to consideration by the commission. Any party to the dispute may file a response to the commission staff’s memorandum. Responses shall be filed with the commission 15 days prior to the date scheduled for consideration by the commission. The commission shall inform both parties of its decision.

PSC 119.40(6) (6) Any party to the dispute may request that the commission reconsider its formal determination under this section. Such requests shall comply with s. 227.49, Stats., and must be received by the commission within 20 days of mailing of the commission’s determination. A request for reconsideration shall include any additional information or arguments that the party believes were not considered in the original dispute. The commission may review and reaffirm its original decision, issue a new decision, or decide to hold a hearing on the matter for the gathering of additional information.