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STATE OF MICHIGAN BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION ***** In the matter, on Commission’s own motion, to approve procedures and forms for use with the interconnection and net metering programs. ) ) ) ) Case No. U-15919 JOINT APPLICATION Consumers Energy Company (“Consumers”), The Detroit Edison Company (“Detroit Edison”), the Michigan Electric and Gas Association (“MEGA”) on behalf of its electric utility members, and the Michigan Electric Cooperative Association (“MECA”) on behalf of its regulated distribution utility members (collectively “Applicants”) submit this joint application for approval of proposed interconnection procedures and forms, under Rule 15(1) of the Commission’s new rules governing electric utility interconnection standards, 2009 MR 10, R 460.615(1). Applicants state the following: 1. Consumers is, among other things, engaged as a public utility in the business of generating, purchasing, distributing and selling electric energy to approximately 1.8 million retail customers in Michigan. The retail electric business of Consumers is subject to regulation by the Commission under applicable regulatory statutes, including Section 173 of 2008 PA 295; MCL 460.1173 (“Section 173 of Act 295”). 2. Detroit Edison is a Michigan corporation which, as a wholly owned subsidiary of DTE Energy, supplies retail electric service to customers in Southeast Michigan. Detroit Edison’s retail electric service to Michigan customers is subject to regulation by the Commission under applicable regulatory statutes, including Section 173 of Act 295. 1 3. MEGA is a trade association of investor-owned electric and gas utilities providing service in Michigan. Its electric utility members participating in this application through MEGA include Alpena Power Company; Edison Sault Electric Company; Indiana Michigan Power Company; Northern States Power Company, a Wisconsin corporation and wholly-owned subsidiary of Xcel Energy, Inc., d/b/a Xcel Energy; Upper Peninsula Power Company; We Energies and Wisconsin Public Service Corporation. These member electric utilities provide retail electric service to Michigan customers subject to regulation by the Commission under applicable regulatory statutes, including Section 173 of Act 295. 4. MECA is a statewide association representing the collective interest of Michigan’s cooperative electric utilities, which are customer-owned. MECA member cooperatives provide retail service to Michigan customers, subject to regulation by the Commission except to the extent that a particular cooperative’s services are member regulated. The following cooperatives are participating in this application through MECA: Alger Delta Cooperative Electric Association; Cherryland Electric Cooperative; Cloverland Electric Cooperative; Great Lakes Energy; HomeWorks Tri-County Electric Cooperative; Midwest Energy Cooperative; Ontonagon County REA; Presque Isle Electric & Gas Co-op and Thumb Electric Cooperative. 5. Pursuant to Act 295, Section 173 and other statutes providing rulemaking authority, the Commission promulgated new rules governing electric interconnection and net metering standards, effective May 27, 2009. 2009 MR 10, R 460.601a – 460.656, corresponding to Rules 1a through 56. These rules replaced previous rules governing electric interconnection standards as well as utility net metering programs and 2 interconnection procedures adopted under the earlier rules or, in the case of net metering, Commission regulatory approval. 6. Rule 15(1); R 460.615(1) of the new interconnection rules provides: Each electric utility shall file applications for approval of proposed interconnection procedures and forms within 90 days of the effective date of these rules or by August 3, 2009, whichever date is sooner. Two or more electric utilities may file a joint application proposing interconnection procedures for use by the joint applicants. All procedures and forms shall be written in plain English. Rule 15 also contains specific directives for the content of procedures and forms for projects in Categories 1 through 5 of the electric generating project size categories described in the rules. The following forms and procedures are identified: • Application for interconnection • Uniform interconnection agreement • Description of steps for processing applications (Categories 2-5) • Specific technical, engineering and operational requirements • Schedule of fees conforming to R 460.618(1) • Timeline for notifications under R 460.620 • Protective scheme for projects interconnecting to a spot network circuit >5% maximum load • Minimum load limits for inverter-based projects interconnecting to area networks • Non-inverter or noncompliant project protective devices • An informal waiver process 7. On March 18, 2009, the Commission issued an order in this docket, jointly captioned with Case No. U-15803, directing that electric utilities file proposed 3 interconnection applications, net metering applications and interconnection agreements by no later than May 4, 2009, for Category 1 projects only (0-20kW renewable). This occurred while the new administrative rules were pending approval. Applicants submitted standard application and agreement forms for Category 1 projects in response to this order, which were approved by the Commission with slight modification on May 26, 2009. The Commission, however, stated that the approved Category 1 documents would be subject to a 30-day comment period concurrent with a similar period for the documents submitted with the present application, as required by Rule 15(7); R 460.615 (7). 8. Applicants have continued to work together on developing the standard application and agreement forms for the projects in Categories 2-5 and procedures for all categories and reached agreement on the documents submitted with this application. 9. Applicants represent that the documents listed in Appendix A and contained in Appendix B were developed to serve as uniform statewide forms and procedures consistent with the requirements of Rule 15; R 460.615. 10. Applicants have submitted, for Categories 2 and 3, a single combined net metering and interconnection form or, alternatively, separate forms for each activity. The regulatory approval is requested for all of these forms, with use to be based on particular project circumstances. 11. Applicants propose to utilize the forms and procedures of Appendix B, once approved by the Commission, with slight modification to reflect formats and processes applicable to individual utilities, including company identification. WHEREFORE, Applicants respectfully request that the Commission grant the following relief: 4 A. Determine that the documents contained in Appendix B are in compliance with Rule 15; R 460.615. B. Provide for the 30-day comment period prior to approval, as required by Rule 15(7); R 460.615(7). C. Approve the use of the documents contained in Appendix B including all procedures and standards contained therein, and the alternative combined/separate application forms for Categories 2 and 3, by each of Applicants as uniform procedures. D. Authorize modifications by any individual utility to reflect company identification and unique requirements not inconsistent with applicable law and rules. E. Grant such other relief as is necessary, lawful and reasonable. Dated: August 3, 2009 Respectfully submitted, James A. Ault (P-30201) Michigan Electric & Gas Association 110 W. Michigan Avenue, Suite 1000B Lansing, MI 48933 (517) 484-7730 For the Applicants: Consumers Energy Company One Energy Plaza Jackson, MI 49201 Contact: Raymond E. McQuillen (517) 788-0677 Michigan Electric Cooperative Association 2859 W. Jolly Road Okemos, MI 48864 Contact: Michael W. Peters (517) 351-6322 The Detroit Edison Company 2000 Second Avenue Detroit, MI 48826 Contact: Jon Christinidis (P-47352) 5 APPENDIX A U-15919 (August 3, 2009 Joint Application) List of Documents Submitted for Approval 1 • Michigan Electric Utility Generator Interconnection Requirements – Category 1 – Projects with Aggregate Generator Output 20 kW or Less • Michigan Electric Utility Generator Interconnection Requirements – Category 2 – Projects with Aggregate Generator Output Greater than 20 kW, but Less Than or Equal to 150 kW • Michigan Electric Utility Generator Interconnection Requirements – Category 3 – Projects with Aggregate Generator Output 150 kW, but Less Than or Equal to 550 kW • Michigan Electric Utility Generator Interconnection Requirements – Category 4 – Projects with Aggregate Generator Output 550 kW or More, but Less Than or Equal to 2 MW • Michigan Electric Utility Generator Interconnection Requirements – Category 5 – Projects with Aggregate Generator Output Greater than 2 MW • Interconnection and Parallel Operating Agreement for Category 2 Projects • Interconnection and Operating Agreement for Category 3-5 Projects • Combined Application Form – Category 21 • Net Metering Application Form – Category 2 • Interconnection Application Form – Category 2 • Combined Application Form – Category 3 • Net Metering Application Form – Category 3 A single file for each of Category 2 and 3 applications contains the forms for combined/separate functions. • Interconnection Application Form – Category 3 • Generator Interconnection Application – Category 4 • Generator Interconnection Application – Category 5 APPENDIX B U-15919 (August 3, 2009 Joint Application) [Documents Submitted for Approval] MICHIGAN ELECTRIC UTILITY Generator Interconnection Requirements Category 1 Projects with Aggregate Generator Output 20 kW or Less August 3, 2009 Page 1 Introduction Category 1 This Generator Interconnection Procedure document outlines the process & requirements used to install or modify generation projects with aggregate generator output capacity ratings less than or equal to 20kW and designed to operate in parallel with the Utility electric system. Technical requirements (data, equipment, relaying, telemetry, metering) are defined according to type of generation, location of the interconnection, and mode of operation (Flow-back or Non-Flowback). The process is designed to provide an expeditious interconnection to the Utility electric system that is both safe and reliable. This document has been filed with the Michigan Public Service Commission (MPSC) and complies with rules established for the interconnection of parallel generation to the Utility electric system in the MPSC Order in Case No. U-15787. The term “Project” will be used throughout this document to refer to electric generating equipment and associated facilities that are not owned or operated by an electric utility. The term “Project Developer” means a person that owns, operates, or proposes to construct, own, or operate, a Project. This document does not address other Project concerns such as environmental permitting, local ordinances, or fuel supply. Nor does it address agreements that may be required with the Utility and/or the transmission provider, or state or federal licensing, to market the Project’s energy. An interconnection request does not constitute a request for transmission service. It may be possible for the Utility to adjust requirements stated herein on a case-by-case basis. The review necessary to support such adjustments, however, may be extensive and may exceed the costs and timeframes established by the MPSC and addressed in these requirements. Therefore, if requested by the Project Developer, adjustments to these requirements will only be considered if the Project Developer agrees in advance to compensate the Utility for the added costs of the necessary additional reviews and to also allow the Utility additional time for the additional reviews. The Utility may apply for a technical waiver from one or more provisions of these rules and the MPSC may grant a waiver upon a showing of good cause. Page 2 Table of Contents ITERCOECTIO PROCESS ............................................................................................................... 5 Customer Project Planning Phase ...................................................................................................5 Application & Queue Assignment ..................................................................................................5 Application Review ......................................................................................................................5 Engineering Review ......................................................................................................................5 Distribution Study .........................................................................................................................6 Customer Install & POA ................................................................................................................6 Meter install, Testing, & Inspection ................................................................................................6 Operation in Parallel .....................................................................................................................7 OPERATIOAL PROVISIOS ................................................................................................................... 7 Disconnection ...............................................................................................................................7 Maintenance and Testing ...............................................................................................................7 MAJOR COMPOET DESIG REQUIREMETS ................................................................................ 8 Data .............................................................................................................................................8 Isolating Transformer(s) ................................................................................................................8 Isolation Device ............................................................................................................................9 Interconnection Lines ....................................................................................................................9 RELAYIG DESIG REQUIREMETS .................................................................................................. 10 Momentary Paralleling ............................................................................................................... 10 Automatic Reclosing .................................................................................................................. 10 Single-Phase Sectionalizing ........................................................................................................ 11 Specific Requirements by Generator Type ................................................................................... 12 Synchronous Projects ................................................................................................................. 12 Induction Projects ...................................................................................................................... 12 Inverter Projects......................................................................................................................... 12 Relay Setting Criteria ................................................................................................................. 12 MAITEACE AD TESTIG .............................................................................................................. 12 Installation Approval .................................................................................................................. 13 MISCELLAEOUS OPERATIOAL REQUIREMETS ....................................................................... 13 Operating in Parallel .................................................................................................................. 13 Reactive Power Control .............................................................................................................. 14 Site Limitations ......................................................................................................................... 15 REVEUE METERIG REQUIREMETS ............................................................................................. 15 Non Flow-back Projects ............................................................................................................. 15 Flow-back Projects .................................................................................................................... 15 COMMUICATIO CIRCUITS ................................................................................................................ 16 APPEDIX A ............................................................................................................................................... 17 Interconnection Process Flow Diagram ........................................................................................ 17 APPEDIX B ............................................................................................................................................... 18 Interconnection Table – Applicant Costs ...................................................................................... 18 Combined Net Metering / Interconnection Table - Applicant Costs ................................................ 18 Interconnection Timeline – Working Days ................................................................................... 18 Page 3 APPEDIX C ............................................................................................................................................... 19 Procedure Definitions.19 Appendix D. ............................................................................................................. 23 SAMPLE SITE PLA .......................................................................................................................... 23 Appendix E.. ................................................................................................................... 24 SAMPLE OE-LIE DIAGRAM FOR IVERTER PROJECTS................................................... 24 Appendix F.. ............................................................................................................ 25 SAMPLE OE LIE DIAGRAM FOR SYCHROOUS PROJECTS ......................................... 25 APPEDIX G .............................................................................................................................................. 26 SAMPLE OE LIE DIAGRAM FOR IDUCTIO PROJECTS ................................................ 26 Appendix H .............................................................................................................. 27 SAMPLE OE LIE DIAGRAM FOR O-FLOW BACK PROJECTS ...................................... 27 Appendix I.. ................................................................................................................. 28 SAMPLE OE LIE DIAGRAM FOR FLOW-BACK PROJECTS.................................................. 28 Page 4 Interconnection Procedures Interconnection Process Customer Project Planning Phase An applicant may contact the utility before or during the application process regarding the project. The utility can be reached by phone, e-mail, or by the external website to access information, forms, rates, and agreements. A utility will provide up to 2 hours of technical consultation at no additional cost to the applicant. Consultation may be limited to providing information concerning the utility system operating characteristics and location of system components. Application & Queue Assignment The Project Developer must first submit a combined Interconnection and Net Metering application to the Utility. A separate application is required for each Project or Project site. The blank Interconnection Application can be found on the Utility’s customer generation’s website. A complete submittal of required interconnection data and Interconnection filing fee per the table in Appendix B. The Utility will notify the Project Developer within 10 business days of receipt of an Interconnection Application. If any portion of the Interconnection Application, data submittal (a site plan and the one-line diagrams), or filing fee is incomplete and/or missing, the Utility will return the application, data, and filing fee to the Project developer with explanations. Project Developer will need to resubmit the application with all the missing items. Once the Utility has accepted the combined Interconnection and Net Metering Application, a queue number will be assigned to the Project. The utility will then advise the applicant that the application is complete and provide the customer with the queue assignment. Application Review The Utility shall review the complete application for interconnection to determine if an engineering review is required. The Utility will notify the Project Developer within 10 business days of receipt of complete application and if an engineering review is required. If an engineering review is required, the Utility will apply for an MPSC waiver to complete an Engineering Review and notify the applicant of the waiver request. The applicant is exempt from the cost of the engineering review. Upon MPSC granting the waiver request the utility will proceed with an engineering review. The applicant shall provide any changes or updates to the application before the engineering review begins. If an engineering review is not required or the MPSC denies the waiver request, the project will advance to the Meter install, Testing, & Inspection phase of the process. The Utility may request additional data be submitted as necessary during the review phase to clarify the operation of the Project. Engineering Review Upon MPSC granting the waiver request, the Utility shall study the project to determine the suitability of the interconnection equipment including safety and reliability complications arising from equipment saturation, multiple technologies, and proximity to synchronous motor loads. Page 5 The electric utility shall provide in writing the results of the engineering study within the time indicated in the MPSC waiver request. If the engineering review indicates that a distribution study is necessary, the electric utility shall request an MPSC waiver to perform the distribution study. The customer is exempt from the cost of a distribution study except with respect to any distribution study costs that may be included in and applicable to the customer through the Company’s general tariff rates for the relevant customer class. If an engineering review determines that a distribution study is not required, the project will advance to the Meter install, Testing, & Inspection Distribution Study Upon MPSC granting the waiver request, the Utility shall study the project to determine if a distribution system upgrade is needed to accommodate the proposed project and determine the cost of an upgrade if required. The applicant is exempt from the cost of the study and upgrades if required, except with respect to any distribution study costs that may be included in and applicable to the customer through the Company’s general tariff rates for the relevant customer class. The electric utility shall provide in writing the results of the distribution study including estimated completion timeframe for the upgrades, if required, to the applicant, within the timeframe allowed by the waiver request. If an distribution study determines that a distribution upgrades are not required, the project will advance to the Meter install, Testing, & Inspection phase of the process. Customer Install & POA The applicant shall notify the electric utility when an installation and any required local code inspection and approval is complete. The Parallel Operating Agreement for different rates can be found from the Utility’s customer generation website. The Parallel Operating Agreement will cover matters customarily addressed in such agreements in accordance with Good Utility Practice, including, without limitation, construction of facilities, system operation, interconnection rate, defaults and remedies, and liability. The applicant shall complete, sign and return the POA ( Parallel Operating Agreement ) to the Utility. Any delay in the applicant’s execution of the Interconnection and Operating Agreement will not count toward the interconnection deadlines. Meter install, Testing, & Inspection Upon receipt of the local code inspection approval and executed POA, the Utility will schedule the meter install, testing, and inspection. The utility shall have an opportunity to schedule a visit to witness and perform commissioning tests required by IEEE 1547.1 and inspect the project. The electric utility may provide a waiver of its right to visit the site to inspect the project and witness or perform the commissioning tests. The utility shall notify the applicant of its intent to visit the site, inspect the project, witness or perform the commissioning tests, or of its intent to waive inspection within 10 working days after notification that the installation and local code inspections have passed. Within 5 working days from receipt of the completed commissioning test report ( if applicable ), the utility will notify the applicant of its approval or disapproval of the interconnection. If the electric utility does not approve the interconnection, the utility shall notify the applicant of the necessary corrective actions required for approval. The applicant, Page 6 after taking corrective action, may request the electric utility to reconsider the interconnection request. Operation in Parallel Upon utility approval of the interconnection, the electric utility shall install required metering, provide to the applicant a written statement of final approval, and a fully executed POA authorizing parallel operation. Operational Provisions Disconnection An electric utility may refuse to connect or may disconnect a project from the distribution system if any of the following conditions apply: a. Lack of fully executed interconnection agreement (POA) b. Termination of interconnection by mutual agreement c. Noncompliance with technical or contractual requirements in the interconnection agreement after notice is provided to the applicant of the technical or contractual deficiency. d. Distribution system emergency e. Routine maintenance, repairs, and modifications, but only for a reasonable length of time necessary to perform the required work and upon reasonable notice. Maintenance and Testing The Utility reserves the right to test the relaying and control equipment that involves protection of the Utility’s electric system whenever the Utility determines a reasonable need for such testing exists. The applicant is solely responsible for conducting and documenting proper periodic maintenance on the generating equipment and its associated control, protective equipment, interrupting devices, and main Isolation Device, per manufacturer recommendations. Routine and maintenance checks of the relaying and control equipment must be conducted in accordance with provided written test procedures which are required by IEEE Std. 1547, and test reports of such testing shall be maintained by the applicant and made available for Utility inspection upon request. [NOTE – IEEE 1547 requires that testing be conducted in accordance with written test procedures, and the nationally recognized testing laboratory providing certification will require that such test procedures be available before certification of the equipment.] Page 7 Technical Requirements Technical Requirements The following discussion details the technical requirements for interconnection of Category 1 Projects 20 kW or less. For Projects within this capacity rating range, the Utility has made a significant effort to simplify the technical requirements. This effort has resulted in adoption of IEEE Standard 1547, Standard for Interconnecting Distributed Resources with Electric Power Systems, being incorporated herein by reference. All protective functions are compliant with IEEE Standard 1547. Certain requirements, as specified by this document, must be met to provide compatibility between the Project and the Utility’s electric system, and to assure that the safety and reliability of the electric system is not degraded by the interconnection. The Utility reserves the right to evaluate and apply newly developed protection and/or operation schemes at its discretion. In addition, the Utility reserves the right to evaluate Projects on an ongoing basis as system conditions change, such as circuit loading, additional generation placed online, etc. Upgraded revenue metering may be required for the Project. Major Component Design Requirements The data requested in Appendix E, F, or G for all major equipment and relaying proposed by the Project Developer, must be submitted as part of the initial application for review and approval by the Utility. The Utility may request additional data be submitted as necessary during the Distribution Study phase to clarify the operation of the Project. Once installed, the interconnection equipment must be reviewed and approved by the Utility prior to being connected to the Utility’s electric system and before Parallel Operation is allowed. Data The data that the Utility requires to evaluate the proposed interconnection is documented on a one-line diagram by generator type in Appendices E, F, or G. A site plan, one-line diagrams, and interconnection protection system details of the Project are required as part of the application data. The generator manufacturer supplied data package should also be supplied. Isolating Transformer(s) Page 8 If a Project Developer installs an isolating transformer, the transformer must comply with the current ANSI Standard C57.12. The type of generation and electrical location of the interconnection will determine the isolating transformer connections. Allowable connections are detailed in the “Specific Requirements by Generator Type” section. Note: Some Utilities do not allow an isolation transformer to be connected to a grounded Utility system with an ungrounded secondary (Utility side) winding configuration, regardless of the Project type. Therefore, the Project Developer is encouraged to consult with the Utility prior to submitting an application. Isolation Device After review, this device may not be required by the Utility. If required and/or installed, this device would be placed at the Point of Common Coupling (PCC). It can be a circuit breaker, circuit switcher, pole top switch, load-break disconnect, etc., depending on the electrical system configuration. The following are required of the isolation device: • Must be approved for use on the Utility system. • Must comply with current relevant ANSI and/or IEEE Standards. • Must have load break capability, unless used in series with a three-phase interrupting device. • Must be rated for the application. • If used as part of a protective relaying scheme, it must have adequate interrupting capability. The Utility will provide maximum short circuit currents and X/R ratios available at the PCC upon request. • Must be operable and accessible by the Utility at all times (24 hours a day, 7 days a week) • The Utility will determine if the isolation device will be used as a protective tagging point. If the determination is so made, the device must have a visible open break, provisions for padlocking in the open position and it must be gang operated. If the device has automatic operation, the controls must be located remote from the device. Interconnection Lines Any new line construction to connect the Project to the Utility’s electric system will be undertaken by the Utility at the Utility's expense. The physically closest available system voltage, as well as equipment and operational constraints influence the chosen point of interconnection. The Utility has the ultimate authority to determine the acceptability of a particular PCC. Page 9 Any new line construction to connect the Project to the Utility’s electric system will be undertaken by the Utility at the Project Developer's expense. The new line(s) will terminate on a structure provided by the Project Developer. Relaying Design Requirements Regardless of the technology of the interconnection, for simplicity for all Projects in this capacity rating range, the interconnection relaying system must be certified by a nationally recognized testing laboratory to meet IEEE Std. 1547. The data submitted for review must include information from the manufacturer indicating such certification, and the manufacturer must placard the equipment such that a field inspection can verify the certification. A copy of this standard may be obtained (for a fee) from the Institute of Electrical and Electronics Engineers (www.ieee.org). If the protective system uses AC power as the control voltage, it must be designed to disconnect the generation from the Utility electric system if the AC control power is lost. Utility will work with Project Developer for system design for this requirement. Momentary Paralleling For situations where the Project will only be operated in parallel with the Utility’s electric system for a short duration (100 milliseconds or less), as in a make-before-break automatic transfer scheme, no additional relaying is required. Such momentary paralleling requires a modern integrated Automatic Transfer Switch (ATS) system, which is incapable of paralleling the Project with the Utility’s electric system. The ATS must be tested, verified, and documented by the Project Developer for proper operation at least every 2 years. The Utility may be present during this testing. Automatic Reclosing The Utility employs automatic multiple-shot reclosing on most of the Utility’s circuit breakers and circuit reclosers to increase the reliability of service to its customers. Automatic singlephase overhead reclosers are regularly installed on distribution circuits to isolate faulted segments of these circuits. The Project Developer is advised to consider the effects of Automatic Reclosing (both single phase and three phase) to assure that the Project’s internal equipment will not be damaged. In addition to the risk of damage to the Project, an out-of-phase reclosing operation may also present a hazard to Utility equipment since this equipment may not be rated or built to withstand this type of reclosing. The Utility will determine relaying and control equipment that needs to be installed to protect its own equipment from out-of-phase reclosing. Installation of this protection will be undertaken by the Utility at the Utility's expense. The Utility shall not be liable to the customer with respect to damage(s) to the Project arising as a result of Automatic Reclosing. Page 10 Single-Phase Sectionalizing The Utility also installs single-phase fuses and/or reclosers on its distribution circuits to increase the reliability of service to its customers. Three-phase generator installations may require replacement of fuses and/or single-phase reclosers with three-phase circuit breakers or circuit reclosers at the Utility’s expense. Page 11 Specific Requirements by Generator Type Synchronous Projects An isolation transformer may be required for three-phase Synchronous Generator Facilities. Except as noted below, the isolation transformer must be incapable of producing ground fault current to the Utility system; any connection except delta primary (Project side), grounded-wye secondary (Utility side) is acceptable. A grounded-wye - grounded-wye transformer connection is acceptable only if the Project’s single line-to-ground fault current contribution is less than the Project’s three-phase fault current contribution at the PCC. Protection must be provided for internal faults in the isolating transformer; fuses are acceptable. For a sample One-Line Diagram of this type of facility, see Appendix F. Induction Projects For three-phase installations, any isolation transformer connection is acceptable except grounded-wye (Utility side), delta (Project side). Protection must be provided for internal faults in the isolating transformer; fuses are acceptable. The Utility does not require the Project Developer to provide any protection for Utility system ground faults. For a sample One-Line Diagram of this type of facility, see Appendix G. Inverter Projects No isolation transformer is required between the generator and the secondary distribution connection. If an isolation transformer is used for three-phase installations, any isolation transformer connection is acceptable except grounded-wye (Utility side), delta (Project side). Protection must be provided for internal faults in the isolating transformer; fuses are acceptable. The Utility does not require the Project Developer to provide any protection for Utility system ground faults. For a sample One-Line Diagram of this type of facility, see Appendix E. Relay Setting Criteria The relay settings for Projects 20 kW or less must conform to the values specified in IEEE Std. 1547. Maintenance and Testing The Utility reserves the right to test the relaying and control equipment that involves protection of the Utility’s electric system whenever the Utility determines a reasonable need for such testing exists. The Project Developer is solely responsible for conducting and documenting proper periodic maintenance on the generating equipment and its associated control, protective equipment, interrupting devices, and main Isolation Device, per manufacturer recommendations. Page 12 Routine and maintenance checks of the relaying and control equipment must be conducted in accordance with provided written test procedures which are required by IEEE Std. 1547, and test reports of such testing shall be maintained by the Project Developer and made available for Utility inspection upon request. [NOTE – IEEE 1547 requires that testing be conducted in accordance with written test procedures, and the nationally recognized testing laboratory providing certification will require that such test procedures be available before certification of the equipment.] Installation Approval The Project Developer must provide the Utility with 5 business days advance written notice of when the Project will be ready for inspection, testing, and approval. Prior to final approval for Parallel Operation, the Utility reserves the right to inspect the Project and require action to assure conformance to the requirements stated herein. Miscellaneous Operational Requirements Miscellaneous requirements include synchronizing equipment for Parallel Operation, reactive requirements, and system stability limitations. Operating in Parallel The Project Developer will be solely responsible for the required synchronizing equipment and for properly synchronizing the Project with the Utility’s electric system. Voltage fluctuation at the PCC during synchronization is limited per IEEE Std. 1547. These requirements are directly concerned with the actual operation of the Project with the Utility: • The Project may not commence parallel operation until approval has been given by the Utility. The completed installation is subject to inspection by the Utility prior to approval. Preceding this inspection, all contractual agreements must be executed by the Project Developer. • The Project must be designed to prevent the Project from energizing into a de-energized Utility line. The Project’s circuit breaker or contactor must be blocked from closing in on a de-energized circuit. • The Project shall discontinue parallel operation with a particular service and perform necessary switching when requested by the Utility for any of the following reasons: 1. When public safety is being jeopardized. Page 13 2. During voltage or loading problems, system emergencies, or when abnormal sectionalizing or circuit configuration occurs on the Utility system. 3. During scheduled shutdowns of Utility equipment that are necessary to facilitate maintenance or repairs. Such scheduled shutdowns shall be coordinated with the Project. 4. In the event there is demonstrated electrical interference (i.e. Voltage Flicker, Harmonic Distortion, etc.) to the Utility’s customers, suspected to be caused by the Project, and such interference exceeds then current system standards, the Utility reserves the right, at the Utility’s initial expense, to install special test equipment as may be required to perform a disturbance analysis and monitor the operation and control of the Project to evaluate the quality of power produced by the Project. In the event that no standards exist, then the applicable tariffs and rules governing electric service shall apply. If the Project is proven to be the source of the interference, and that interference exceeds the Utility’s standards or generally accepted industry standards, then it shall be the responsibility of the Project Developer to eliminate the interference problem and to reimburse the Utility for the costs of the disturbance monitoring installation, removal, and analysis excluding the cost of the meters or other special test equipment. 5. When either the Project or its associated synchronizing and protective equipment is demonstrated by the Utility to be improperly maintained, so as to present a hazard to the Utility system or its customers. 6. Whenever the Project is operating isolated with other Utility customers, for whatever reason. 7. Whenever the Utility notifies the Project Developer in writing of a claimed non-safety related violation of the Interconnection Agreement and the Project Developer fails to remedy the claimed violation within ten working days of notification, unless within that time either the Project Developer files a complaint with the MPSC seeking resolution of the dispute or the Project Developer and Utility agree in writing to a different procedure. If the Project has shown an unsatisfactory response to requests to separate the generation from the Utility system, the Utility reserves the right to disconnect the Project from parallel operation with the Utility electric system until all operational issues are satisfactorily resolved. Reactive Power Control Synchronous generators that will operate in the Flow-back Mode must be dynamically capable of providing 0.90 power factor lagging (delivering reactive power to the Utility) and 0.95 power factor leading (absorbing reactive power from the Utility) at the Point of Receipt. The Point of Receipt is the location where the Utility accepts delivery of the output of the Project. The Point of Receipt can be the physical location of the billing meters or a location where the billing meters are not located, but adjusted for line and transformation losses. Page 14 Induction and Inverter- Projects that will operate in the Flow-back Mode must provide for their own reactive needs (steady state unity power factor at the Point of Receipt). To obtain unity power factor, the Induction or Inverter Project can: 1. Install a switchable Volt-Ampere reactive (VAR) supply source to maintain unity power factor at the Point of Receipt; or 2. Provide the Utility with funds to install a VAR supply source equivalent to that required for the Project to attain unity power factor at the Point of Receipt at full output. There are no interconnection reactive power capability requirements for Synchronous, Induction, and Inverter Projects that will operate in the Non-Flow-back Mode. The Utility’s existing rate schedules, incorporated herein by reference, contain power factor adjustments based on the power factor of the metered load at these facilities. Site Limitations The Project Developer is responsible for evaluating the consequences of unstable generator operation or voltage transients on the Project equipment and determining, designing, and applying any relaying which may be necessary to protect that equipment. This type of protection is typically applied on individual generators to protect the generator facilities. The Utility will determine if operation of the Project will create objectionable voltage flicker and/or disturbances to other Utility customers and develop any required mitigation measures at the Project Developer’s expense. Revenue Metering Requirements The Utility will own, operate, and maintain all required billing metering equipment at the Project Developer's expense. -on Flow-back Projects A Utility meter will be installed that only records energy deliveries to the Project. Flow-back Projects Special billing metering will be required. The Project Developer may be required to provide, at no cost to the Utility, a dedicated dial-up voice-grade circuit (POTS line) to allow remote access to the billing meter by the Utility. This circuit shall be terminated within ten feet of the meter involved. The Project Developer shall provide the Utility access to the premises at all times to install, turn on, disconnect, inspect, test, read, repair, or remove the metering equipment. The Project Developer may, at its option, have representative witness this work. Page 15 The metering installations shall be constructed in accordance with the practices, which normally apply to the construction of metering installations for residential, commercial, or industrial customers. For Projects with multiple generators, metering of each generator may be required. When practical, multiple generators may be metered at a common point provided the metered quantity represents only the gross generator output. The Utility shall supply to the Project Developer all required metering equipment and the standard detailed specifications and requirements relating to the location, construction, and access of the metering installation and will provide consultation pertaining to the meter installation as required. The Utility will endeavor to coordinate the delivery of these materials with the Project Developer’s installation schedule during normal scheduled business hours. The Project Developer may be required to provide a mounting surface for the metering equipment. The mounting surface and location must meet the Utility’s specifications and requirements. The responsibility for installation of the equipment is shared between the Utility and the Project Developer. The Project Developer may be required to install some of the metering equipment on its side of the PCC, including instrument transformers, cabinets, conduits, and mounting surfaces. The Utility shall install the meters and communication links. The Utility will endeavor to coordinate the installation of these items with the Project Developer's schedule during normal scheduled business hours. Communication Circuits The Project Developer is responsible for ordering and acquiring the telephone circuits required for the Project interconnection. The Project Developer will assume all installation, operating, and maintenance costs associated with the telephone circuits, including the monthly charges for the telephone lines and any rental equipment required by the local telephone provider. However, at the Utility’s discretion, the Utility may select an alternative communication method, such as wireless communications. Regardless of the method, the Project Developer will be responsible for all costs associated with the material,installation and maintenance, whereas the Utility will be responsible to define the specific communication requirements. The Utility will cooperate and provide Utility information necessary for proper installation of the telephone (or alternate) circuits upon written request. Page 16 Appendix A Interconnection Process Flow Diagram Page 17 Appendix B Interconnection Table – Applicant Costs Distribution Testing & Application Engineering Distribution Review Review Study Upgrades Inspection $0 Category 1 $75 $0 $0 ( or, As Approved $0 by Waiver) Combined -et Metering / Interconnection Table - Applicant Costs Application Engineering Distribution Distribution Testing & Net Meter Review Study Upgrades Inspection Program Fee Review Category 1 $25 $75 $0 $0 $0 $0 Interconnection Timeline – Working Days Application Application Engineering Complete Review Study Completion Category 1 10 10 0 ( or, As allowed By Waiver ) Page 18 Distribution Study Completion Distribution Upgrades Testing & Inspection 0, (As allowed By Waiver) 0, ( or, As allowed By waiver ) 10 Appendix C Procedure Definitions Alternative electric supplier ( AES ): as defined in section 10g of 2000 PA 141, MCL 460.10g Alternative electric supplier net metering program plan: document supplied by an AES that provides detailed information to an applicant about the AES’s net metering program. Applicant: Legally responsible person applying to an electric utility to interconnect a project with the electric utility’s distribution system or a person applying for a net metering program. An applicant shall be a customer of an electric utility and may be a customer or an AES. Application Review: Review by the electric utility of the completed application for interconnection to determine if an engineering review is required. Area -etwork: A location on the distribution system served by multiple transformers interconnected in an electrical network circuit. Category 1: An inverter based project of 20kW or less that uses equipment certified by a nationally recognized testing laboratory to IEEE 1547.1 testing standards and in compliance with UL 1741 scope 1.1A. Category 2: A project of greater than 20 kW and not more than 150 kW. Category 3: A project of greater than 150 kW and not more than 550 kW. Category 4: A project of greater than 550 kW and not more than 2 MW. Category 5: A project of greater than 2 MW. Certified equipment: A generating, control, or protective system that has been certified as meeting acceptable safety and reliability standards by a nationally recognized testing laboratory in conformance with UL 1741. Commission: The Michigan Public Service Commission Commissioning test: The procedure, performed in compliance with IEEE 1547.1, for documenting and verifying the performance of a project to confirm that the project operates in conformity with its design specifications. Customer: A person who receives electric service from an electric utility’s distribution system or a person who participates in a net metering program through an AES or electric utility. Customer-generator: A person that uses a project on-site that is interconnected to an electric utility distribution system. Page 19 Distribution system: The structures, equipment, and facilities operated by an electric utility to deliver electricity to end users, not including transmission facilities that are subject to the jurisdiction of the federal energy regulatory commission. Distribution system study: A study to determine if a distribution system upgrade is needed to accommodate the proposed project and to determine the cost of an upgrade if required. Electric provider: Any person or entity whose rates are regulated by the commission for selling electricity to retail customers in the state. Electric utility: Term as defined in section 2 of 1995 PA 30, MCL 460.562. Eligible electric generator: A methane digester or renewable energy system with a generation capacity limited to the customer’s electrical need and that does not exceed the following: • • 150 kW of aggregate generation at a single site for a renewable energy system 550 kW of aggregate generation at a single site for a methane digester Engineering Review: A study to determine the suitability of the interconnection equipment including any safety and reliability complications arising from equipment saturation, multiple technologies, and proximity to synchronous motor loads. Full retail rate: The power supply and distribution components of the cost of electric service. Full retail rate does not include system access charge, service charge, or other charge that is assessed on a per meter basis. IEEE: Institute of Electrical and Electronics Engineers IEEE 1547: IEEE “Standard for Interconnecting Distributed Resources with Electric Power Systems” IEEE 1547.1: IEEE “Standard Conformance Test Procedures for Equipment Interconnecting Distributed Resources with Electric Power Systems” Interconnection: The process undertaken by an electric utility to construct the electrical facilities necessary to connect a project with a distribution system so that parallel operation can occur. Interconnection procedures: The requirements that govern project interconnection adopted by each electric utility and approved by the commission. kW: kilowatt kWh: kilowatt-hours Material modification: A modification that changes the maximum electrical output of a project or changes the interconnection equipment including the following: Page 20 • • Changing from certified to non certified equipment Replacing a component with a component of different functionality or UL listing. Methane digester: 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. Modified net metering: A 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 utility distribution system during a billing period or time-of-use pricing period. MW: megawatt -ationally recognized testing laboratory: Any testing laboratory recognized by the accreditation program of the U.S. department of labor occupational safety and health administration. Parallel operation: The operation, for longer than 100 milliseconds, of a project while connected to the energized distribution system. Project: Electrical generating equipment and associated facilities that are not owned or operated by an electric utility. Renewable energy credit ( REC ): A credit granted pursuant to the commission’s renewable energy credit certification and tracking program in section 41 of 2008 PA 295, MCL 460.1041. Renewable energy resource: Term as defined in section 11(i) of 2008 PA 295, MCL 460.1011(i) Renewable energy system: Term as defined in section 11(k) of 2008 PA 295, MCL 460.1011(k). Spot network: A location on the distribution system that uses 2 or more inter-tied transformers to supply an electrical network circuit. True net metering: A utility billing method that applies the full retail rate to the net of the bidirectional flow of kW hors across the customer interconnection with the utility distribution system, during a billing period or time-of-use pricing period. UL: Underwriters Laboratory UL 1741: The “Standard for Inverters, Converters, Controllers and Interconnection System Equipment for Use With Distributed Energy Resources.” UL 1741 scope 1.1A: Paragraph 1.1A contained in chapter 1, section 1 of UL 1741. Page 21 Uniform interconnection application form: The standard application forms, approved by the commission under R 460.615 and used for category 1, category 2, category 3, category 4, and category 5 projects. Uniform interconnection agreement: The standard interconnection agreements approved by the commission under R 460.615 and used for category 1, category 2, category 3, category 4, and category 5 projects. Uniform net metering application: The net metering application form approved by the commission under R 460.642 and used by all electric utilities and AES. Working days: Days excluding Saturdays, Sundays, and other days when the offices of the electric utility are not open to the public. Page 22 Appendix D Sample Site Plan Page 23 Appendix E Sample One-Line Diagram for Inverter Projects Page 24 Appendix F Sample One Line Diagram for Synchronous projects Page 25 Appendix G Sample One Line Diagram for Induction projects Page 26 Appendix H Sample One Line Diagram for Non-Flow Back projects ONE-LINE DIAGRAM & CONTROL SCHEMATIC TYPICAL ISOLATION PROECTION FOR NON FLOW-BACK INSTALLATIONS Distribution Circuit Page 27 Appendix I Sample One Line Diagram for Flow-Back projects Page 28 Page 29 MICHIGAN ELECTRIC UTILITY Generator Interconnection Requirements Category 2 Projects with Aggregate Generator Output Greater Than 20 kW, but Less Than or Equal to 150 kW August 3, 2009 Page 1 Introduction Category 2 – Greater than 20kW but less than or equal to 150kW This Generator Interconnection Procedure document outlines the process & requirements used to install or modify generation projects with aggregate generator output capacity ratings greater than 20kW but less than or equal to 150kW and designed to operate in parallel with the Utility electric system. Technical requirements (data, equipment, relaying, telemetry, metering) are defined according to type of generation, location of the interconnection, and mode of operation (Flow-back or Non-Flow-back). The process is designed to provide an expeditious interconnection to the Utility electric system that is both safe and reliable. This document has been filed with the Michigan Public Service Commission (MPSC) and complies with rules established for the interconnection of parallel generation to the Utility electric system in the MPSC Order in Case No. U-15787. The term “Project” will be used throughout this document to refer to electric generating equipment and associated facilities that are not owned or operated by an electric utility. The term “Project Developer” means a person that owns, operates, or proposes to construct, own, or operate, a Project. This document does not address other Project concerns such as environmental permitting, local ordinances, or fuel supply. Nor does it address agreements that may be required with the Utility and/or the transmission provider, or state or federal licensing, to market the Project’s energy. An interconnection request does not constitute a request for transmission service. It may be possible for the Utility to adjust requirements stated herein on a case-by-case basis. The review necessary to support such adjustments, however, may be extensive and may exceed the costs and timeframes established by the MPSC and addressed in these requirements. Therefore, if requested by the Project Developer, adjustments to these requirements will only be considered if the Project Developer agrees in advance to compensate the Utility for the added costs of the necessary additional reviews and to also allow the Utility additional time for the additional reviews. The Utility may apply for a technical waiver from one or more provisions of these rules and the MPSC may grant a waiver upon a showing of good cause. Page 2 Table of Contents ITERCOECTIO PROCESS ....................................................................................................5 Customer Project Planning Phase ................................................................................................... 5 Application & Queue Assignment .................................................................................................. 5 Application Review ......................................................................................................................... 5 Engineering Review ........................................................................................................................ 6 Distribution Study ........................................................................................................................... 6 Customer Install & POA ................................................................................................................. 6 Meter install, Testing, & Inspection ................................................................................................ 7 Operation in Parallel........................................................................................................................ 7 OPERATIOAL PROVISIOS .......................................................................................................7 Disconnection .................................................................................................................................. 7 Maintenance and Testing ................................................................................................................ 8 Operating in Parallel........................................................................................................................ 8 Momentary Paralleling .................................................................................................................. 10 MAJOR COMPOET DESIG REQUIREMETS ....................................................................11 Data ............................................................................................................................................... 11 Isolating Transformer(s) ................................................................................................................ 11 Isolation Device............................................................................................................................. 12 Interconnection Lines .................................................................................................................... 13 Relaying Design Requirements ..................................................................................................... 13 Automatic Reclosing ..................................................................................................................... 13 Single-Phase Sectionalizing .......................................................................................................... 14 Specific Requirements by Generator Type ................................................................................... 15 Synchronous Projects .................................................................................................................... 15 Induction Projects .......................................................................................................................... 15 Inverter Projects ............................................................................................................................ 15 Dynamometer Projects .................................................................................................................. 15 Relay Setting Criteria .................................................................................................................... 16 Maintenance and Testing .............................................................................................................. 16 Installation Approval ..................................................................................................................... 16 Page 3 MISCELLAEOUS OPERATIOAL REQUIREMETS .............................................................17 Reactive Power Control ................................................................................................................ 17 Site Limitations ............................................................................................................................. 18 Non Flow-back Projects ................................................................................................................ 18 Flow-back Projects ........................................................................................................................ 18 COMMUICATIO CIRCUITS ....................................................................................................19 APPEDIX A..................................................................................................................................20 Interconnection Process Flow Diagram ........................................................................................ 20 APPENDIX B ..................................................................................................................................21 Interconnection Table – Applicant Costs ...................................................................................... 21 Combined Net Metering / Interconnection Table - Applicant Costs ............................................ 21 Interconnection Timeline – Working Days ................................................................................... 21 APPENDIX C ..................................................................................................................................22 Procedure Definitions .................................................................................................................... 22 APPENDIX D – SITE PLAN ...........................................................................................................26 APPENDIX E – SAMPLE ON-LINE SYNCHRONOUS .................................................................27 APPENDIX F – SAMPLE ONE-LINE INDUCTION .......................................................................29 APPENDIX G – SAMPLE ONE-LINE INVERTER .........................................................................31 APPENDIX H: ................................................................................................................................33 Sample One Line Diagram for Non-Flow Back projects .............................................................. 33 APPENDIX I ...................................................................................................................................34 Sample One Line Diagram for Flow-Back projects ...................................................................... 34 Page 4 Interconnection Procedures Interconnection Process Customer Project Planning Phase An applicant may contact the utility before or during the application process regarding the project. The utility can be reached by phone, e-mail, or by the external website to access information, forms, rates, and agreements. A utility will provide up to 2 hours of technical consultation at no additional cost to the applicant. Consultation may be limited to providing information concerning the utility system operating characteristics and location of system components. Application & Queue Assignment The Project Developer must first submit a combined Interconnection and Net Metering application to the Utility. A separate application is required for each Project or Project site. The blank Interconnection Application can be found on the Utility’s customer generation’s website . A complete submittal of the application and the application fee (See Appendix B) will enable the process. The Utility will notify the Project Developer within 10 business days of receipt of an Interconnection Application. If any portion of the Interconnection Application, data submittal (a site plan and the one-line diagrams), or filing fee is incomplete and/or missing, the Utility will return the application, data, and filing fee to the Project developer with explanations. Project Developer will need to resubmit the application with all the missing items. Once the Utility has accepted the combined Interconnection and Net Metering Application, a queue number will be assigned to the Project. The utility will then advise the applicant that the application is complete and provide the customer with the queue assignment. Application Review The Utility shall review the complete application for interconnection to determine if an engineering review is required. The Utility will notify the Project Developer within 10 business days of receipt of complete application and if an engineering review is required. If an engineering review is required, the Utility will apply for an MPSC waiver to complete an Engineering Review and notify the applicant of the waiver request. The applicant is exempt from the cost of the engineering review. Upon MPSC granting the waiver request the utility will proceed with an engineering review. The applicant shall provide any changes or updates to the application before the engineering review begins. If an engineering review is not required or the MPSC denies the waiver request, the project will advance to the Customer Install & POA. The Page 5 Utility may request additional data be submitted as necessary during the review phase to clarify the operation of the Project. Engineering Review Upon MPSC granting the waiver request, the Utility shall study the project to determine the suitability of the interconnection equipment including safety and reliability complications arising from equipment saturation, multiple technologies, and proximity to synchronous motor loads. The electric utility shall provide in writing the results of the engineering study within the time indicated in the MPSC waiver request. If the engineering review indicates that a distribution study is necessary, the electric utility shall request an MPSC waiver to perform the distribution study. The customer is exempt from the cost of a distribution study. If an engineering review determines that a distribution study is not required, the project will advance to the Customer Install & POA. Distribution Study Upon MPSC granting the waiver request, the Utility shall study the project to determine if a distribution system upgrade is needed to accommodate the proposed project and determine the cost of an upgrade if required. The Customer is responsible for cost for distribution upgrades study and the distribution upgrades if required. The electric utility shall provide in writing the results of the distribution study including estimated completion timeframe for the upgrades, if required, to the applicant, within the timeframe allowed by the waiver request. If a distribution study determines that a distribution upgrades are not required, the project will advance to the Customer Install & POA. Customer Install & POA The applicant shall notify the electric utility when an installation and any required local code inspection and approval is complete. The Parallel Operating Agreement for different rates can be found from the Utility’s customer generation website. The Parallel Operating Agreement will cover matters customarily addressed in such agreements in accordance with Good Utility Practice, including, without limitation, construction of facilities, system operation, interconnection rate, defaults and remedies, and liability. The applicant shall complete, sign and return the POA (Parallel Operating Agreement to the Utility). Any delay in the applicant’s execution of the Interconnection and Operating Agreement will not count toward the interconnection deadlines. Page 6 Meter install, Testing, & Inspection Upon receipt of the local code inspection approval and executed POA, the Utility will schedule the meter install, testing, and inspection. The utility shall have an opportunity to schedule a visit to witness and perform commissioning tests required by IEEE 1547.1 and inspect the project. The electric utility may provide a waiver of its right to visit the site to inspect the project and witness or perform the commissioning tests. The utility shall notify the applicant of its intent to visit the site, inspect the project, witness or perform the commissioning tests, or of its intent to waive inspection within 10 working days after notification that the installation and local code inspections have passed. Within 5 working days from receipt of the completed commissioning test report ( if applicable ), the utility will notify the applicant of its approval or disapproval of the interconnection. If the electric utility does not approve the interconnection, the utility shall notify the applicant of the necessary corrective actions required for approval. The applicant, after taking corrective action, may request the electric utility to reconsider the interconnection request. Operation in Parallel Upon utility approval of the interconnection, the electric utility shall install required metering, provide to the applicant a written statement of final approval, and a fully executed POA authorizing parallel operation. Operational Provisions Disconnection An electric utility may refuse to connect or may disconnect a project from the distribution system if any of the following conditions apply: a. Lack of fully executed interconnection agreement (POA) b. Termination of interconnection by mutual agreement c. Noncompliance with technical or contractual requirements in the interconnection agreement after notice is provided to the applicant of the technical or contractual deficiency. d. Distribution system emergency Page 7 e. Routine maintenance, repairs, and modifications, but only for a reasonable length of time necessary to perform the required work and upon reasonable notice. Maintenance and Testing The Utility reserves the right to test the relaying and control equipment that involves protection of the Utility’s electric system whenever the Utility determines a reasonable need for such testing exists. The applicant is solely responsible for conducting and documenting proper periodic maintenance on the generating equipment and its associated control, protective equipment, interrupting devices, and main Isolation Device, per manufacturer recommendations. Routine and maintenance checks of the relaying and control equipment must be conducted in accordance with provided written test procedures which are required by IEEE Std. 1547, and test reports of such testing shall be maintained by the applicant and made available for Utility inspection upon request. [NOTE – IEEE 1547 requires that testing be conducted in accordance with written test procedures, and the nationally recognized testing laboratory providing certification will require that such test procedures be available before certification of the equipment.] Operating in Parallel The Project Developer will be solely responsible for the required synchronizing equipment and for properly synchronizing the Project with the Utility electric system. Voltage fluctuation at the PCC during synchronizing is limited perIEEE Std. 1547. These requirements are directly concerned with the actual operation of the Project with the Utility: • The Project may not commence parallel operation until approval has been given by the Utility. The completed installation is subject to inspection by the Utility prior to approval. Preceding this inspection, all contractual agreements must be executed by the Project Developer. • The Project must be designed to prevent the Project from energizing into a de-energized Utility line. The Project’s circuit breaker or contactor must be blocked from closing in on a de-energized circuit. • The Project shall discontinue parallel operation with a particular service and perform necessary switching when requested by the Utility for any of the following reasons: Page 8 1. When public safety is being jeopardized. 2. During voltage or loading problems, system emergencies, or when abnormal sectionalizing or circuit configuration occurs on the Utility system. 3. During scheduled shutdowns of Utility equipment that are necessary to facilitate maintenance or repairs. Such scheduled shutdowns shall be coordinated with the Project. 4. In the event there is demonstrated electrical interference (i.e. Voltage Flicker, Harmonic Distortion, etc.) to the Utility’s customers, suspected to be caused by the Project, and such interference exceeds then current system standards, the Utility reserves the right, at the Utility’s initial expense, to install special test equipment as may be required to perform a disturbance analysis and monitor the operation and control of the Project to evaluate the quality of power produced by the Project. In the event that no standards exist, then the applicable tariffs and rules governing electric service shall apply. If the Project is proven to be the source of the interference, and that interference exceeds the Utility’s standards or the generally accepted industry standards, then it shall be the responsibility of the Project Developer to eliminate the interference problem and to reimburse the Utility for the costs of the disturbance monitoring installation, removal, and analysis, excluding the cost of the meters or other special test equipment. 5. When either the Project or its associated synchronizing and protective equipment is demonstrated by the Utility to be improperly maintained, so as to present a hazard to the Utility system or its customers. 6. Whenever the Project is operating isolated with other Utility customers, for whatever reason. 7. Whenever the Utility notifies the Project Developer in writing of a claimed non-safety related violation of the Interconnection Agreement and the Project Developer fails to remedy the claimed violation within ten working days of notification, unless within that time either the Project Developer files a complaint with the MPSC seeking resolution of the dispute or the Project Developer and Utility agree in writing to a different procedure. If the Project has shown an unsatisfactory response to requests to separate the generation from the Utility system, the Utility reserves the right to disconnect the Project from parallel operation with the Utility electric system until all operational issues are satisfactorily resolved. Page 9 Momentary Paralleling For situations where the Project will only be operated in parallel with the Utility’s electric system for a short duration (100 milliseconds or less), as in a make-before-break automatic transfer scheme, no additional relaying is required. Such momentary paralleling requires a modern integrated Automatic Transfer Switch (ATS) system, which is incapable of paralleling the Project with the Utility’s electric system. The ATS must be tested, verified, and documented by the Project Developer for proper operation at least every 2 years. The Utility may be present during this testing. Page 10 Technical Requirements The following discussion details the technical requirements for interconnection of Category 2 Projects greater than 20 kW , but less than or equal to 150 kW. For Projects within this capacity rating range, the Utility has made a significant effort to simplify the technical requirements. This effort has resulted in adoption of IEEE Std. 1547, Standard for Interconnecting Distributed Resources with Electric Power Systems, being incorporated herein by reference. Certain requirements, as specified by this document, must be met to provide compatibility between the Project and the Utility’s electric system, and to assure that the safety and reliability of the electric system is not degraded by the interconnection. The Utility reserves the right to evaluate and apply newly developed protection and/or operation schemes at its discretion. In addition, the Utility reserves the right to evaluate Projects on an ongoing basis as system conditions change, such as circuit loading, additional generation placed online, etc. Upgraded revenue metering may be required for the Project. Major Component Design Requirements The data requested in Appendix E, F, or G for all major equipment and relaying proposed by the Project Developer, must be submitted as part of the initial application for review and approval by the Utility. The Utility may request additional data be submitted as necessary during the Distribution Study phase to clarify the operation of the Project. Once installed, the interconnection equipment must be reviewed and approved by the Utility prior to being connected to the Utility’s electric system and before Parallel Operation is allowed. Data The data that the Utility requires to evaluate the proposed interconnection is documented on a one-line diagram and “fill in the blank” table by generator type in Appendices E, F, or G. A site plan, one-line diagrams, and interconnection protection system details of the Project are required as part of the application data. The generator manufacturer data package should also be supplied. Isolating Transformer(s) If a Project Developer installs an isolating transformer, the transformer must comply with the current ANSI Standard C57.12. The transformer should have high and/or low voltage windings sufficient to assure satisfactory generator operation over the range of voltage variation expected on the Utility electric system. Page 11 The type of generation and electrical location of the interconnection will determine the isolating transformer connections. Allowable connections are detailed in the “Specific Requirements by Generator Type” section. Note: Some Utilities do not allow an isolation transformer to be connected to a grounded Utility system with an ungrounded secondary (Utility side) winding configuration, regardless of the Project type. Therefore, the Project Developer is encouraged to consult with the Utility prior to submitting an application. Isolation Device An isolation device is required and should be placed at the Point of Common Coupling (PCC). It can be a circuit breaker, circuit switcher, pole top switch, load-break disconnect, etc., depending on the electrical system configuration. The following are required of the isolation device: • Must be approved for use on the Utility system. • Must comply with current relevant ANSI and/or IEEE Standards. • Must have load break capability, unless used in series with a three-phase interrupting device. • Must be rated for the application. • If used as part of a protective relaying scheme, it must have adequate interrupting capability. The Utility will provide maximum short circuit currents and X/R ratios available at the PCC, upon request. • Must be operable and accessible by the Utility at all times (24 hours a day, 7 days a week). • The Utility will determine if the isolation device will be used as a protective tagging point. If the determination is so made, the device must have visible open break provisions for padlocking in the open position and it must be gang operated. If the device has automatic operation, the controls must be located remote from the device. Page 12 Interconnection Lines Any new line construction to connect the Project to the Utility’s electric system will be undertaken by the Utility at the Project Developer's expense. Relaying Design Requirements Regardless of the technology of the interconnection, for simplicity for all projects in this capacity rating range, the interconnection relaying system must be certified by a nationally recognized testing laboratory to meet IEEE Std. 1547. The data submitted for review must include information from the manufacturer indicating such certification, and the manufacturer must placard the equipment such that a field inspection can verify the certification. A copy of this standard may be obtained (for a fee) from the Institute of Electrical and Electronics Engineers (www.ieee.org). If the protective system uses AC power as the control voltage, it must be designed to disconnect the generation from the Utility electric system if the AC control power is lost. Utility will work with Project Developer for system design for this requirement. Automatic Reclosing The Utility employs automatic multiple-shot reclosing on most of the Utility’s circuit breakers and circuit reclosers to increase the reliability of service to its customers. Automatic singlephase overhead reclosers are regularly installed on distribution circuits to isolate faulted segments of these circuits. The Project Developer is advised to consider the effects of Automatic Reclosing (both singlephase and three- phase) to assure that the Project’s internal equipment will not be damaged. In addition to the risk of damage to the Project, an out-of-phase reclosing operation may also present a hazard to Utility equipment since this equipment may not be rated or built to withstand this type of reclosing. The Utility will determine relaying and control equipment that needs to be installed to protect its own equipment from out-of-phase reclosing. Installation of this protection will be undertaken by the Utility at the Project Developer’s expense. In some cases, recloser settings can be modified to prevent out-of-phase reclosing. This could delay reclosing until the parallel generation is separated and the line is “de-energized”. Hydraulic single-phase overhead recloser settings cannot be modified; therefore, these devices will have to be either replaced with three-phase overhead reclosers whose settings can be changed, or relocated beyond the Project location - depending upon the sectionalizing and protection requirements of the distribution circuit. If the Project can be connected to more than one circuit, these revisions may be required on the alternate circuit(s) as well. The Utility shall not be liable to the customer with respect to damage(s) to the Project arising as a result of Automatic Reclosing. Page 13 Single-Phase Sectionalizing The Utility also installs single-phase fuses and/or reclosers on its distribution circuits to increase the reliability of service to its customers. Three-phase generator installations may require replacement of fuses and/or single-phase reclosers with three-phase circuit breakers or circuit reclosers at the Project Developer’s expense. Page 14 Specific Requirements by Generator Type Synchronous Projects An isolation transformer will be required for three-phase Synchronous Projects. Except as noted below, the isolation transformer must be incapable of producing ground fault current to the Utility system; any connection except delta primary (Project side), grounded-wye secondary (Utility side) is acceptable. A grounded-wye - grounded-wye transformer connection is acceptable only if the Project’s single line-to-ground fault current contribution is less than the Project’s three-phase fault current contribution at the PCC. Protection must be provided for internal faults in the isolating transformer; fuses are acceptable. For a sample One-Line Diagram of this type of facility, see Appendix E. Induction Projects For three-phase installations, any isolation transformer connection is acceptable except grounded-wye (Utility side), delta (Project side). Protection must be provided for internal faults in the isolating transformer; fuses are acceptable. In cases where it can be shown that self excitation of the induction generator cannot occur when isolated from the Utility, the Utility may waive the requirement that the generator provide protection for Utility system ground faults. For a sample One-Line Diagram of this type of facility, see Appendix F. Inverter Projects No isolation transformer is required between the generator and the secondary distribution connection. If an isolation transformer is used for three-phase installations, any isolation transformer connection is acceptable except grounded-wye (Utility side), delta (Project side). Protection must be provided for internal faults in the isolating transformer; fuses are acceptable. If the inverter has passed a certified anti-island test, the Utility may waive the requirement that the Project Developer provide protection for the Utility system ground faults. For a sample One-Line Diagram of this type of facility, see Appendix G. Dynamometer Projects No isolation transformer is required between the generator and the secondary distribution connection. If an isolation transformer is used for three-phase installations, any isolation transformer connection is acceptable except grounded-wye (Utility side), delta (Project side). Protection must be provided for internal faults in the isolating transformer; fuses are acceptable. Page 15 If an inverter is used and has passed a certified anti-island test, the Utility may waive the requirement that the Project Developer provide protection for the Utility system ground faults. Relay Setting Criteria The relay settings for Projects greater than 20 kW but less than or equal to 150 kW must conform to the values specified in IEEE Std. 1547. Maintenance and Testing The Utility reserves the right to test the relaying and control equipment that involves protection of the Utility electric system whenever the Utility determines a reasonable need for such testing exists. The Project Developer is solely responsible for conducting proper periodic maintenance on the generating equipment and its associated control, protective equipment, interrupting devices, and main Isolation Device, per manufacturer recommendations. Routine Maintenance checks of the relaying and control equipment must be conducted in accordance with provided written test procedures which are required by IEEE Std. 1547, and test reports of such testing shall be maintained by the Project Developer and made available for Utility inspection upon request. [NOTE – IEEE 1547 requires that testing be conducted in accordance with written test procedures, and the nationally recognized testing laboratory providing certification will require that such test procedures be available before certification of the equipment.] Installation Approval The Project Developer must provide the Utility with 5 business days advance written notice of when the Project will be ready for inspection, testing, and approval. Prior to final approval for Parallel Operation, the Utility reserves the right to inspect the Project and receive action to assure conformance to the requirements stated herein. Page 16 Miscellaneous Operational Requirements Miscellaneous requirements include synchronizing equipment for Parallel Operation, reactive requirements, and system stability limitations. If the Project has shown an unsatisfactory response to requests to separate the generation from the Utility system, the Utility reserves the right to disconnect the Project from parallel operation with the Utility electric system until all operational issues are satisfactorily resolved. Reactive Power Control Synchronous generators that will operate in the Flow-back Mode must be dynamically capable of providing 0.90 power factor lagging (delivering reactive power to the Utility) and 0.95 power factor leading (absorbing reactive power from the Utility) at the Point of Receipt. The Point of Receipt is the location where the Utility accepts delivery of the output of the Project. The Point of Receipt can be the physical location of the billing meters or a location where the billing meters are not located, but adjusted for line and transformation losses. Induction and Inverter Projects that will operate in the Flow-back Mode must provide for their own reactive needs (steady state unity power factor at the Point of Receipt). To obtain unity power factor, the Induction or Inverter Project can: 1. Install a switchable Volt-Ampere reactive VAR supply source to maintain unity power factor at the Point of Receipt; or 2. Provide the Utility with funds to install a VAR supply source equivalent to that required for the Project to attain unity power factor at the Point of Receipt at full output. There are no interconnection reactive power capability requirements for Synchronous, Induction, and Inverter Projects that will operate in the Non-Flow-back Mode. The Utility’s existing rate schedules, incorporated herein by reference, contain power factor adjustments based on the power factor of the metered load at these facilities. Page 17 Site Limitations The Project Developer is responsible for evaluating the consequences of unstable generator operation or voltage transients on the Project equipment, and determining, designing, and applying any relaying which may be necessary to protect that equipment. This type of protection is typically applied on individual generators to protect the Projects. The Utility will determine if operation of the Project will create objectionable voltage flicker and/or disturbances to other Utility customers and develop any required mitigation measures at the Project Developer’s expense. Revenue Metering Requirements The Utility will own, operate, and maintain all required billing metering equipment at the Project Developer's expense. on Flow-back Projects A Utility meter will be installed that only records energy deliveries to the Project. Flow-back Projects Special billing metering will be required. The Project Developer may be required to provide, at no cost to the Utility, a dedicated dial-up voice-grade circuit (POTS line) to allow remote access to the billing meter by the Utility. This circuit shall be terminated within ten feet of the meter involved. The Project Developer shall provide the Utility access to the premises at all times to install, turn on, disconnect, inspect, test, read, repair, or remove the metering equipment. The Project Developer may, at its option, have a representative witness this work. The metering installations shall be constructed in accordance with the practices, which normally apply to the construction of metering installations for residential, commercial, or industrial custoPage 18 mers. For Projects with multiple generators, metering of each generator may be required. When practical, multiple generators may be metered at a common point provided the metered quantity represents only the gross generator output. The Utility shall supply to the Project Developer all required metering equipment and the standard detailed specifications and requirements relating to the location, construction, and access of the metering installation and will provide consultation pertaining to the meter installation as required. The Utility will endeavor to coordinate the delivery of these materials with the Project Developer’s installation schedule during normal scheduled business hours. The Project Developer may be required to provide a mounting surface for the metering equipment. The mounting surface and location must meet the Utility’s specifications and requirements. The responsibility for installation of the equipment is shared between the Utility and the Project Developer. The Project Developer may be required to install some of the metering equipment on its side of the PCC, including instrument transformers, cabinets, conduits, and mounting surfaces. The Utility shall install the meters and communication links. The Utility will endeavor to coordinate the installation of these items with the Project Developer's schedule during normal scheduled business hours. Communication Circuits The Project Developer is responsible for ordering and acquiring the telephone circuit required for the Project Interconnection. The Project Developer will assume all installation, operating, and maintenance costs associated with the telephone circuits, including the monthly charges for the telephone lines and any rental equipment required by the local telephone provider. However, at the Utility’s discretion, the Utility may select an alternative communication method, such as wireless communications. Regardless of the method, the Project Developer will be responsible for all costs associated with the material, installation and maintenance, whereas the Utility will be responsible to define the specific communication requirements. The Utility will cooperate and provide Utility information necessary for proper installation of the telephone (or alternate) circuits upon written request. Page 19 Appendix A Interconnection Process Flow Diagram Page 20 Appendix B Interconnection Table – Applicant Costs Category 2 Application Review $100 Engineering Review $0 Distribution Study Propose fixed fee Distribution Upgrades Actual or Max Approved by Commission Testing & Inspection Proposed Fixed fee Combined Net Metering / Interconnection Table - Applicant Costs Category 2 Net Meter Program Fee $25 Application Review $75 Engineering Review $0 Distribution Study Propose fixed fee Distribution Upgrades Actual or Max Approved by Commission Testing & Inspection $0 Interconnection Timeline – Working Days Category 2 Application Complete Application Review 10 days 10 days Engineering Study Completion 10 days Page 21 Distribution Study Completion 10 days Distribution Upgrades Testing & Inspection Mutually Agreed 10 days to notify of scheduled visit Appendix C Procedure Definitions Alternative electric supplier ( AES ): as defined in section 10g of 2000 PA 141, MCL 460.10g Alternative electric supplier net metering program plan: document supplied by an AES that provides detailed information to an applicant about the AES’s net metering program. Applicant: Legally responsible person applying to an electric utility to interconnect a project with the electric utility’s distribution system or a person applying for a net metering program. An applicant shall be a customer of an electric utility and may be a customer or an AES. Application Review: Review by the electric utility of the completed application for interconnection to determine if an engineering review is required. Area Network: A location on the distribution system served by multiple transformers interconnected in an electrical network circuit. Category 1: An inverter based project of 20kW or less that uses equipment certified by a nationally recognized testing laboratory to IEEE 1547.1 testing standards and in compliance with UL 1741 scope 1.1A. Category 2: A project of greater than 20 kW and not more than 150 kW. Category 3: A project of greater than 150 kW and not more than 550 kW. Category 4: A project of greater than 550 kW and not more than 2 MW. Category 5: A project of greater than 2 MW. Certified equipment: A generating, control, or protective system that has been certified as meeting acceptable safety and reliability standards by a nationally recognized testing laboratory in conformance with UL 1741. Commission: The Michigan Public Service Commission Commissioning test: The procedure, performed in compliance with IEEE 1547.1, for documenting and verifying the performance of a project to confirm that the project operates in conformity with its design specifications. Page 22 Customer: A person who receives electric service from an electric utility’s distribution system or a person who participates in a net metering program through an AES or electric utility. Customer-generator: A person that uses a project on-site that is interconnected to an electric utility distribution system. Distribution system: The structures, equipment, and facilities operated by an electric utility to deliver electricity to end users, not including transmission facilities that are subject to the jurisdiction of the federal energy regulatory commission. Distribution system study: A study to determine if a distribution system upgrade is needed to accommodate the proposed project and to determine the cost of an upgrade if required. Electric provider: Any person or entity whose rates are regulated by the commission for selling electricity to retail customers in the state. Electric utility: Term as defined in section 2 of 1995 PA 30, MCL 460.562. Eligible electric generator: A methane digester or renewable energy system with a generation capacity limited to the customer’s electrical need and that does not exceed the following: • • 150 kW of aggregate generation at a single site for a renewable energy system 550 kW of aggregate generation at a single site for a methane digester Engineering Review: A study to determine the suitability of the interconnection equipment including any safety and reliability complications arising from equipment saturation, multiple technologies, and proximity to synchronous motor loads. Full retail rate: The power supply and distribution components of the cost of electric service. Full retail rate does not include system access charge, service charge, or other charge that is assessed on a per meter basis. IEEE: Institute of Electrical and Electronics Engineers IEEE 1547: IEEE “Standard for Interconnecting Distributed Resources with Electric Power Systems” IEEE 1547.1: IEEE “Standard Conformance Test Procedures for Equipment Interconnecting Distributed Resources with Electric Power Systems” Page 23 Interconnection: The process undertaken by an electric utility to construct the electrical facilities necessary to connect a project with a distribution system so that parallel operation can occur. Interconnection procedures: The requirements that govern project interconnection adopted by each electric utility and approved by the commission. kW: kilowatt kWh: kilowatt-hours Material modification: A modification that changes the maximum electrical output of a project or changes the interconnection equipment including the following: • • Changing from certified to non certified equipment Replacing a component with a component of different functionality or UL listing. Methane digester: 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. Modified net metering: A 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 utility distribution system during a billing period or time-of-use pricing period. MW: megawatt Nationally recognized testing laboratory: Any testing laboratory recognized by the accreditation program of the U.S. department of labor occupational safety and health administration. Parallel operation: The operation, for longer than 100 milliseconds, of a project while connected to the energized distribution system. Project: Electrical generating equipment and associated facilities that are not owned or operated by an electric utility. Renewable energy credit ( REC ): A credit granted pursuant to the commission’s renewable energy credit certification and tracking program in section 41 of 2008 PA 295, MCL 460.1041. Renewable energy resource: Term as defined in section 11(i) of 2008 PA 295, MCL 460.1011(i) Page 24 Renewable energy system: Term as defined in section 11(k) of 2008 PA 295, MCL 460.1011(k). Spot network: A location on the distribution system that uses 2 or more inter-tied transformers to supply an electrical network circuit. True net metering: A utility billing method that applies the full retail rate to the net of the bidirectional flow of kW hors across the customer interconnection with the utility distribution system, during a billing period or time-of-use pricing period. UL: Underwriters Laboratory UL 1741: The “Standard for Inverters, Converters, Controllers and Interconnection System Equipment for Use With Distributed Energy Resources.” UL 1741 scope 1.1A: Paragraph 1.1A contained in chapter 1, section 1 of UL 1741. Uniform interconnection application form: The standard application forms, approved by the commission under R 460.615 and used for category 1, category 2, category 3, category 4, and category 5 projects. Uniform interconnection agreement: The standard interconnection agreements approved by the commission under R 460.615 and used for category 1, category 2, category 3, category 4, and category 5 projects. Uniform net metering application: The net metering application form approved by the commission under R 460.642 and used by all electric utilities and AES. Working days: Days excluding Saturdays, Sundays, and other days when the offices of the electric utility are not open to the public. Page 25 Appendix D – Site Plan Page 26 Appendix E – Sample On-Line Synchronous (not required for flow-back) Page 27 Instructions: Attach data sheets as required. Indicate in the table below the page number of the attached data (manufacturer’s data where appropriate) on which the requested information is provided. Provide one table for each unique generator. Synchronous Electric Generator(s) at the Project Item No Data Value Generator No _____ Data Attached Description Page No 1 Generator Type (synchronous or induction) 2 Generator Nameplate Voltage 3 Generator Nameplate Watts or Volt-Amperes 4 Generator Nameplate Power Factor (pf) 5 Direct axis reactance (saturated) 6 Direct axis transient reactance (saturated) 7 Direct axis sub-transient reactance (saturated) 8 Short Circuit Current contribution from generator at the Point of Common Coupling (single-phase and three-phase 9 National Recognized Testing Laboratory Certification 10 Written Commissioning Test Procedure Page 28 Appendix F – Sample One-Line Induction (not required for flow-back) Page 29 Instructions: Attach data sheets as required. Indicate in the table below the page number of the attached data (manufacturer’s data where appropriate) on which the requested information is provided. Provide one table for each unique generator. Induction Electric Generator(s) at the Project: Generator No _____ Item Data Attached No Description Page No 1 Generator Type (Inverter) 2 Generator Nameplate Voltage 3 Generator Nameplate Watts or Volt-Amperes 4 Generator Nameplate Power Factor (pf) 5 Short Circuit Current contribution from generator at the Point of Common Coupling (single-phase and three-phase) 6 National Recognized Testing Laboratory Certification 7 Written Commissioning Test Procedure Page 30 Appendix G – Sample One-Line Inverter ONE-LINE REPRESENTATION TYPICAL ISOLATION AND FAULT PROTECTION FOR INVERTER GENERATOR INSTALLATIONS (not required for flow-back) Page 31 Instructions: Attach data sheets as required. Indicate in the table below the page number of the attached data (manufacturer’s data where appropriate) on which the requested information is provided. Provide one table for each unique generator. Inverter Electric Generator(s) at the Project: Generator No _____ Item Data Attached No Description Page No 1 Generator Type (Inverter) 2 Generator Nameplate Voltage 3 Generator Nameplate Watts or Volt-Amperes 4 Generator Nameplate Power Factor (pf) 5 Short Circuit Current contribution from generator at the Point of Common Coupling (single-phase and three-phase) 6 National Recognized Testing Laboratory Certification 7 Written Commissioning Test Procedure Page 32 Appendix H: Sample One Line Diagram for Non-Flow Back projects ONE-LINE DIAGRAM & CONTROL SCHEMATIC TYPICAL ISOLATION PROECTION FOR NON FLOW-BACK INSTALLATIONS Distribution Circuit Page 33 Appendix I Sample One Line Diagram for Flow-Back projects Distribution Circuit Page 34 Page 35 MICHIGAN ELECTRIC UTILITY Generator Interconnection Requirements Category 3 Projects with Aggregate Generator Output Greater Than 150 kW, but Less Than or Equal to 550 kW August 3, 2009 Page 1 Introduction Category 3 – Greater than 150kW less than or equal 550 kW This Generator Interconnection Procedure document outlines the process & requirements used to install or modify generation projects with aggregate generator output capacity ratings greater than 150kW less than or equal to 550kW and designed to operate in parallel with the Utility electric system. Technical requirements (data, equipment, relaying, telemetry, metering) are defined according to type of generation, location of the interconnection, and mode of operation (Flow-back or Non-Flow-back). The process is designed to provide an expeditious interconnection to the Utility electric system that is both safe and reliable. This document has been filed with the Michigan Public Service Commission (MPSC) and complies with rules established for the interconnection of parallel generation to the Utility electric system in the MPSC Order in Case No. U-15787. The term “Project” will be used throughout this document to refer to electric generating equipment and associated facilities that are not owned or operated by an electric utility. The term “Project Developer” means a person that owns, operates, or proposes to construct, own, or operate, a Project. This document does not address other Project concerns such as environmental permitting, local ordinances, or fuel supply. Nor does it address agreements that may be required with the Utility and/or the transmission provider, or state or federal licensing, to market the Project’s energy. An interconnection request does not constitute a request for transmission service. It may be possible for the Utility to adjust requirements stated herein on a case-by-case basis. The review necessary to support such adjustments, however, may be extensive and may exceed the costs and timeframes established by the MPSC and addressed in these requirements. Therefore, if requested by the Project Developer, adjustments to these requirements will only be considered if the Project Developer agrees in advance to compensate the Utility for the added costs of the necessary additional reviews and to also allow the Utility additional time for the additional reviews. The Utility may apply for a technical waiver from one or more provisions of these rules and the MPSC may grant a waiver upon a showing of good cause. Page 2 Table of Contents ITERCOECTIO PROCESS ....................................................................................................5 Customer Project Planning Phase ...................................................................................................5 Application & Queue Assignment ..................................................................................................5 Application Review ......................................................................................................................5 Engineering Review ......................................................................................................................5 Distribution Study .........................................................................................................................6 Customer Install & POA ................................................................................................................6 Meter install, Testing, & Inspection ................................................................................................6 Operation in Parallel .....................................................................................................................7 OPERATIOAL PROVISIOS .......................................................................................................7 Disconnection ...............................................................................................................................7 Maintenance and Testing ...............................................................................................................7 Technical Requirements ................................................................................................................ 8 MAJOR COMPONENT DESIGN REQUIREMENTS .......................................................................8 Data ............................................................................................................................................8 Isolating Transformer(s) .............................................................................................................8 Isolation Device ..........................................................................................................................9 Interconnection Lines .................................................................................................................9 Termination Structure .................................................................................................................9 RELAYING DESIGN REQUIREMENTS ........................................................................................10 Protective Relaying General Considerations .......................................................................... 10 Momentary Paralleling............................................................................................................. 10 Instrument Transformer Requirements ................................................................................... 10 Direct Transfer Trip (DTT) ....................................................................................................... 11 Reverse Power Relaying for Non Flow-back .......................................................................... 11 Automatic Reclosing................................................................................................................ 11 Single-Phase Sectionalizing .................................................................................................... 12 Synchronous Projects ................................................................................................................. 13 General .................................................................................................................................... 13 Isolation Transformer and Utility Ground Fault Detection ....................................................... 13 Induction Projects 14 General .................................................................................................................................... 14 Isolation Transformer and Utility Ground Fault Detection ....................................................... 14 Inverter Projects 16 General .................................................................................................................................... 16 DYNAMOMETER PROJECTS ......................................................................................................17 GENERAL ......................................................................................................................................17 RELAY SETTING CRITERIA .........................................................................................................18 Maintenance and Testing ........................................................................................................ 19 INSTALLATION AND DESIGN APPROVAL ................................................................................19 Page 3 TELEMETRY AND DISTURBANCE MONITORING REQUIREMENTS .......................................20 Operating in Parallel ................................................................................................................ 22 Reactive Power Control........................................................................................................... 23 Standby Power ........................................................................................................................ 23 System Stability and Site Limitations ...................................................................................... 23 REVENUE METERING REQUIREMENTS ....................................................................................24 Non Flow-back Projects .......................................................................................................... 24 Flow-back Projects .................................................................................................................. 24 APPENDIX A..................................................................................................................................26 Interconnection Process Flow Diagram .................................................................................. 26 APPENDIX B ..................................................................................................................................27 Interconnection Table – Applicant Costs................................................................................. 27 Combined Net Metering / Interconnection Table - Applicant Costs ........................................ 27 Interconnection Timeline – Working Days .............................................................................. 27 APPENDIX C - PROCEDURE DEFINITIONS ...............................................................................28 APPENDIX D – SITE PLAN ...........................................................................................................33 APPENDIX E – SAMPLE SYNCHRONOUS ONE-LINE ...............................................................34 APPENDIX F – SAMPLE INDUCTION ONE-LINE .......................................................................36 APPENDIX G – SAMPLE ONE-LINE INVERTER .........................................................................38 APPENDIX H ..................................................................................................................................40 Sample One Line Diagram for Non-Flow Back projects ......................................................... 41 APPENDIX I ...................................................................................................................................41 Sample One Line Diagram for Flow-Back projects ................................................................. 42 Page 4 Interconnection Procedures Interconnection Process Customer Project Planning Phase An applicant may contact the utility before or during the application process regarding the project. The utility can be reached by phone, e-mail, or by the external website to access information, forms, rates, and agreements. A utility will provide up to 2 hours of technical consultation at no additional cost to the applicant. Consultation may be limited to providing information concerning the utility system operating characteristics and location of system components. Application & Queue Assignment The Project Developer must first submit a combined Interconnection and Net Metering application to the Utility. A separate application is required for each Project or Project site. The blank Interconnection Application can be found on the Utility’s customer generation’s website. A complete submittal of the application and the application fee (See Appendix B) will enable the process. The Utility will notify the Project Developer within 10 business days of receipt of an Interconnection Application. If any portion of the Interconnection Application, data submittal (a site plan and the one-line diagrams), or filing fee is incomplete and/or missing, the Utility will return the application, data, and filing fee to the Project developer with explanations. Project Developer will need to resubmit the application with all the missing items. Once the Utility has accepted the combined Interconnection and Net Metering Application, a queue number will be assigned to the Project. The utility will then advise the applicant that the application is complete and provide the customer with the queue assignment. Application Review The Utility shall review the complete application for interconnection to determine if an engineering review is required. The Utility will notify the Project Developer within 10 business days of receipt of complete application and if an engineering review is required. If an engineering review is required, the Utility will notify the applicant of the need for the Engineering Review. The applicant is exempt from the cost of the engineering review. The applicant shall provide any changes or updates to the application before the engineering review begins. If an engineering review is not required, the project will advance to the Customer Install & POA. The Utility may request additional data be submitted as necessary during the review phase to clarify the operation of the Project. Engineering Review Page 5 The Utility shall study the project to determine the suitability of the interconnection equipment including safety and reliability complications arising from equipment saturation, multiple technologies, and proximity to synchronous motor loads. The electric utility shall provide in writing the results of the engineering study within the time indicated in the Interconnection Timeline Table Appendix B. If the engineering review indicates that a distribution study is necessary, the electric utility shall notify the applicant the need to perform the distribution study. The fee for t the cost of a distribution study is indicated in Tables of Appendix B.. If an engineering review determines that a distribution study is not required, the project will advance to the Customer Install & POA. Distribution Study The Utility shall study the project to determine if a distribution system upgrade is needed to accommodate the proposed project and determine the cost of an upgrade if required. The applicant is responsible for the cost of the study and upgrades if required. The electric utility shall provide in writing the results of the distribution study including estimated completion timeframe for the upgrades, if required, to the applicant, within the timeframe allowed by the Interconnection Timeline Table Appendix B. If an distribution study determines that a distribution upgrades are not required, the project will advance to the Customer Install & POA. Customer Install & POA The applicant shall notify the electric utility when an installation and any required local code inspection and approval is complete. The Parallel Operating Agreement for different rates can be found from the Utility’s customer generation website. The Parallel Operating Agreement will cover matters customarily addressed in such agreements in accordance with Good Utility Practice, including, without limitation, construction of facilities, system operation, interconnection rate, defaults and remedies, and liability. The applicant shall complete, sign and return the POA (Parallel Operating Agreement to the Utility). Any delay in the applicant’s execution of the Interconnection and Operating Agreement will not count toward the interconnection deadlines. Meter Install, Testing, & Inspection Upon receipt of the local code inspection approval and executed POA, the Utility will schedule the meter install, testing, and inspection. The utility shall have an opportunity to schedule a visit to witness and perform commissioning tests required by IEEE 1547.1 and inspect the project. The electric utility may provide a waiver of its right to visit the site to inspect the project and witness or perform the commissioning tests. The utility shall notify the applicant of its intent to visit the site, inspect the project, witness or perform the commissioning tests, or of its intent to waive inspection within 10 working days after notification that the installation and local code inspections have passed. Within 5 working days from receipt of the completed commissioning test report ( if applicable ), the utility will notify the applicant of its approval or disapproval of the interconnection. If the electric utility does not approve the interconnection, the utility shall notify the applicant of the necessary corrective actions required for approval. The applicant, after taking corrective action, may request the electric utility to reconsider the interconnection request. Page 6 Operation in Parallel Upon utility approval of the interconnection, the electric utility shall install required metering, provide to the applicant a written statement of final approval, and a fully executed POA authorizing parallel operation. Operational Provisions Disconnection An electric utility may refuse to connect or may disconnect a project from the distribution system if any of the following conditions apply: a. Lack of fully executed interconnection agreement (POA) b. Termination of interconnection by mutual agreement c. Noncompliance with technical or contractual requirements in the interconnection agreement after notice is provided to the applicant of the technical or contractual deficiency. d. Distribution system emergency e. Routine maintenance, repairs, and modifications, but only for a reasonable length of time necessary to perform the required work and upon reasonable notice. Maintenance and Testing The Utility reserves the right to test the relaying and control equipment that involves protection of the Utility’s electric system whenever the Utility determines a reasonable need for such testing exists. The applicant is solely responsible for conducting and documenting proper periodic maintenance on the generating equipment and its associated control, protective equipment, interrupting devices, and main Isolation Device, per manufacturer recommendations. Routine and maintenance checks of the relaying and control equipment must be conducted in accordance with provided written test procedures which are required by IEEE Std. 1547, and test reports of such testing shall be maintained by the applicant and made available for Utility inspection upon request. [NOTE – IEEE 1547 requires that testing be conducted in accordance with written test procedures, and the nationally recognized testing laboratory providing certification will require that such test procedures be available before certification of the equipment.] Page 7 Technical Requirements Technical Requirements The following discussion details the technical requirements for interconnection of Category 3 Projects with aggregate generator output greater than 150 kW, but less than or equal to 550 kW. Many of these requirements will vary based on the capacity rating of the Project, the type of generation being used, and the mode of operation (Flow-back or Non Flow-back). A few of the requirements will vary based on location of the interconnection (isolated load and available fault current). Certain major component, relaying, telemetry, and operational requirements must be met to provide compatibility between the Project equipment and the Utility electric system, and to assure that the safety and reliability of the electric system is not degraded by the interconnection. The Utility reserves the right to evaluate and apply newly developed protection and/or operation schemes at its discretion. All protective functions are evaluated for compliance to IEEE std. 1547. In addition, the Utility reserves the right to evaluate Projects on an ongoing basis as system conditions change, such as circuit loading, additional generation placed online, etc. Upgraded revenue metering may be required for the Project. Major Component Design Requirements The data requested in Appendix B or C, for all major equipment and relaying proposed by the Project Developer, must be submitted as part of the initial application for review and approval by the Utility. The Utility may request additional data be submitted as necessary during the Distribution Study phase to clarify the operation of the Project. Once installed, the interconnection equipment must be reviewed and approved by the Utility prior to being connected to the Utility electric system and before Parallel Operation is allowed. Data The data that the Utility requires to evaluate the proposed interconnection is documented on a one-line diagram and “fill in the blank” table by generator type in Appendices E, F, or G. A site plan, one-line diagrams, and interconnection protection system details of the Project are required as part of the application data. The generator manufacturer data package should also be supplied. Isolating Transformer(s) If the Project Developer installs an isolating transformer, the transformer must comply with the current ANSI Standard C57.12. The transformer must have voltage taps on the high and/or low voltage windings sufficient to assure satisfactory generator operation over the range of voltage variation expected on the Utility electric system. The Project Developer also needs to assure sufficient voltage regulation at its facility to maintain an acceptable voltage level for its equipment during such periods when its Project is off-line. This may involve the provision of voltage regulation or a separate transformer between the Utility and the Project station power bus. The type of generation and electrical location of the interconnection will determine the isolating transformer connections. Allowable connections are detailed under the specific Project type. Note: Some Utilities do not allow an isolation transformer to be connected to a grounded Utility system with an Page 8 ungrounded secondary (Utility side) winding configuration, regardless of the Project type. Therefore, the Project Developer is encouraged to consult with the Utility prior to submitting an application. The proper selection and specification of transformer impedance is important relative to enabling the proposed Project to meet the Utility’s reactive power requirements (see “Reactive Power Control”). Isolation Device An isolation device is required and should be placed at the Point of Common Coupling (PCC). It can be a circuit breaker, circuit switcher, pole top switch, load-break disconnect, etc., depending on the electrical system configuration. The following are required of the isolation device: • Must be approved for use on the Utility system. • Must comply with current relevant ANSI and/or IEEE Standards. • Must have load break capability, unless used in series with a three-phase interrupting device. • Must be rated for the application. • If used as part of a protective relaying scheme, it must have adequate interrupting capability. The Utility will provide maximum short circuit currents and X/R ratios available at the PCC upon request. • Must be operable and accessible by the Utility at all times (24 hours a day, 7 days a week). • The Utility will determine if the isolation device will be used as a protective tagging point. If the determination is so made, the device must have a visible open break, provisions for padlocking in the open position and it must be gang operated. If the device has automatic operation, the controls must be located remote from the device. Interconnection Lines The physically closest available system voltage, as well as equipment and operational constraints influence the chosen point of interconnection. The Utility has the ultimate authority to determine the acceptability of a particular PCC. Any new line construction to connect the Project to the Utility’s electric system will be undertaken by the Utility at the Project Developer's expense. The new line(s) will terminate on a structure provided by the Project Developer. Termination Structure The Project Developer is responsible for ensuring that structural material strengths are adequate for all requirements, incorporating appropriate safety factors. Upon written request, the Utility will provide line tension information for maximum line dead-end tensions under heavy icing conditions. The structure must be designed for this maximum line tension along with an adequate margin of safety. Electrical clearances shall comply with requirements of the National Electrical Safety Code and Michigan Public Service Commission Standard 16-79. The installation of disconnect switches, bus support insulators, and other equipment shall comply with accepted industry practices. Page 9 Surge arresters shall be selected to coordinate with the BIL rating of major equipment components and shall comply with recommendations set forth in the current ANSI Standard C62.2. Relaying Design Requirements The interconnection relaying design requirements are intended to assure protection of the Utility electric system. Any additional relaying which may be necessary to protect equipment at the Project is solely the responsibility of the Project Developer to determine, design, and apply. The relaying requirements will vary with the capacity rating of the Project, the type of generation being used, and the mode of operation (Flow-back or Non Flow-back). All relaying proposed by the Project Developer to satisfy these requirements must be submitted for review and approved by the Utility. Protective Relaying General Considerations All relays must be equipped with targets or other visible indicators to indicate that the relay has operated. If the protective system uses AC power as the control voltage, it must be designed to disconnect the generation from the Utility electric system if the AC control power is lost. Utility will work with Project Developer for system design for this requirement. The relay system must be designed such that the generator is prevented from energizing the Utility electric system if that system is de-energized. See “Approved Relay Types” in the Generator Interconnection Supplement. Momentary Paralleling For situations where the Project will only be operated in parallel with the Utility electric system for a short duration (100 milliseconds or less), as in a make-before-break automatic transfer scheme, no additional relaying is required. Such momentary paralleling requires a modern integrated Automatic Transfer Switch (ATS) system, which is incapable of paralleling the Project with the Utility electric system. The ATS must be tested and verified for proper operation at least every 2 years. The Utility may be present during this testing. Instrument Transformer Requirements All relaying must be connected into instrument transformers. All current connections shall be connected into current transformers (CTs). All CTs shall be rated to provide no more than 5 amperes secondary current for all normal load conditions, and must be designed for relaying use, with an “accuracy class” of at least C50. Current transformers with an accuracy class designation such as T50 are NOT acceptable. For three-phase systems, all three phases must be equipped with CTs. All potential connections must be connected into voltage transformers (VTs). For single-phase connections, the VTs shall be provided such that the secondary voltage does not exceed 120 volts for normal operations. For three-phase connections, the VTs shall be provided such that the line-to-line voltage does not exceed 120 volts for normal operation, and both the primary and secondary of the VTs shall be connected for grounded-wye connections. Page 10 Direct Transfer Trip (DTT) Direct Transfer Trip is generally not required for Induction or Inverter Projects. Direct Transfer Trip generally is not required for Synchronous Projects that will operate in the Non Flow-back Mode since a simpler and more economic reverse power relay scheme can usually meet the requirements. For Synchronous Flow-back Projects, the need for DTT is determined based on the location of the PCC. The Utility requires DTT when the total generation within a protective zone is greater than 33% of the minimum Utility load that could be isolated along with the generation. This prevents sustained isolated operation of the generation for conditions where generator protective relaying may not otherwise operate (see “Isolated Operation” in the Generator Interconnection Supplement). Direct transfer trip adds to the cost and complexity of an interconnection. A DTT transmitter is required for each Utility protective device whose operation could result in sustained isolated operation of the generator. An associated DTT receiver at the Project is required for each DTT transmitter. A Data Circuit is required between each transmitter and receiver. Telemetry is required to monitor the status of the DTT communication. At the Project Developer’s expense, the Utility will provide the receiver(s) that the Project Developer must install, and the Utility will install the transmitter(s) at the appropriate Utility protective devices. Reverse Power Relaying for Non Flow-back If Flow-back Mode is not utilized, reverse power protection must be provided. The reverse power relaying will detect power flow from the Project into the Utility system, and operation of the reverse power relaying will separate the Project from the Utility system. Automatic Reclosing The Utility employs automatic multiple-shot reclosing on most of the Utility’s circuit breakers and circuit reclosers to increase the reliability of service to its customers. Automatic single-phase overhead reclosers are regularly installed on distribution circuits to isolate faulted segments of these circuits. The Project Developer is advised to consider the effects of Automatic Reclosing (both single-phase and three-phase) to assure that the Project’s internal equipment will not be damaged. In addition to the risk of damage to the Project, an out-of-phase reclosing operation may also present a hazard to the Utility’s electric system equipment since this equipment may not be rated or built to withstand this type of reclosing. To prevent out-of-phase reclosing, circuit breakers can be modified with voltage check relays. These relays block reclosing until the parallel generation is separated and the line is "de-energized." Hydraulic single-phase overhead reclosers cannot be modified with voltage check relays; therefore, these devices will have to be either replaced with three-phase overhead reclosers, which can be voltage controlled, or relocated beyond the Project location - depending upon the sectionalizing and protection requirements of the distribution circuit. If the Project can be connected to more than one circuit, these revisions may be required on the alternate circuit(s) as well. The Utility will determine relaying and control equipment that needs to be installed to protect its own equipment from out-of-phase reclosing. Installation of this protection will be undertaken by the Utility at the Project Developer's expense. The Utility shall not be liable to the customer with respect to damage(s) to the Project arising as a result of Automatic Reclosing. Page 11 Single-Phase Sectionalizing The Utility also installs single-phase fuses and/or reclosers on its distribution circuits to increase the reliability of service to its customers. Three-phase generator installations may require replacement of fuses and/or single-phase reclosers with three-phase circuit breakers or circuit reclosers at the Project Developer’s expense. Page 12 Synchronous Projects General If the interconnection system is certified by a nationally recognized testing laboratory to satisfy all requirements of IEEE Std. 1547, no additional equipment is required, except as noted below. To satisfy IEEE Std. 1547 requirements for disconnection for faults, each generator must be equipped with voltage-controlled overcurrent relays. These relays shall measure and respond to currents and voltages in all three phases. Also, out-of-step relaying may be required as suggested in IEEE Std. 1547 for loss-of-synchronism conditions if the apparent voltage flicker from a loss-of-synchronism condition exceeds 5%. If the interconnection system is not certified to satisfy requirements of IEEE Std. 1547, under/overvoltage, under/overfrequency, and voltage-controlled overcurrent relays will be required, and must conform to the requirements detailed in “Relay Setting Criteria” below. The under/overvoltage relays must monitor all three phases. All protection must use utility grade relays. For a sample One-Line Diagram of this type of facility, see Appendix E. Isolation Transformer and Utility Ground Fault Detection If the Project is connected to an ungrounded distribution system, the secondary winding (Utility side) of the isolation transformer must be connected delta. If the Project is connected to a grounded distribution system, the developer has a choice of the following transformer connections: 1. A grounded-wye - grounded-wye transformer connection is acceptable only if the Project’s single lineto-ground fault current contribution is less than the Project’s three-phase fault current contribution at the PCC, 2. The isolation transformer may be connected for a delta secondary (Utility side) connection with any primary (Project side) connection, or 3. Ungrounded-wye secondary connection with a delta primary connection. If the Project is connected to a grounded distribution system via one of the isolation transformer connections specified above, ground fault detection for Utility faults may be required at the discretion of the Utility, and will consist of a (59N) ground overvoltage relay or (51N) overcurrent relay. The specific application of this relay will depend on the connection of the isolation transformer: 1. If a grounded-wye - grounded-wye transformer connection is used, a time overcurrent relay must be connected into a CT located on the Utility side isolation transformer neutral connection. 2. If a delta secondary/grounded-wye primary connection is used, a (59N) ground overvoltage relay will be connected into the secondary of a set of three-phase VTs, which will be connected grounded-wye primary, with the secondary connected delta with one corner of the delta left open. The (59N) relay will be connected across this open-corner. 3. If an ungrounded-wye secondary/delta primary connection is used, a (59N) ground overvoltage relay will be connected into the secondary of a single VT, which will be connected from the ungroundedwye neutral of the isolation transformer to ground. Page 13 Induction Projects General If the interconnection system is certified by a nationally recognized testing laboratory to satisfy all requirements of IEEE Std. 1547, no additional equipment is required. If the interconnection system is not certified to satisfy requirements of IEEE Std. 1547, under/overvoltage, and under/overfrequency, will be required, and must conform to the requirements detailed in “Relay Setting Criteria” below. The under/overvoltage relays must monitor all three phases. All protection must use Utility grade relays. For a sample One-Line Diagram of this type of facility, see Appendix F. Isolation Transformer and Utility Ground Fault Detection If the Project is connected to an ungrounded distribution system, the secondary winding (Utility side) of the isolation transformer must be connected delta. If the facility is connected to a grounded distribution system, the Project Developer has a choice of the following transformer connections: 1. The isolation transformer may be connected for a delta secondary (Utility side) connection with any primary (Project side) connection, or 2. The isolation transformer may be connected for an ungrounded-wye secondary connection with a delta primary connection, or 3. The isolation transformer may be connected for a grounded-wye - grounded-wye connection. If the Project is connected to a grounded distribution system via one of the isolation transformer connections specified above, ground fault detection for Utility faults may be required at the discretion of the Utility. The specific application of this relay will depend on the connection of the isolation transformer: 1. If a delta secondary/grounded-wye primary connection is used, a (59N) ground overvoltage relay will be connected into the secondary of a set of three-phase VTs, which will be connected grounded-wye primary, with the secondary connected delta with one corner of the delta left open. The (59N) relay will be connected across this open-corner. 2. If an ungrounded-wye secondary/delta primary connection is used, a (59N) ground overvoltage relay will be connected into the secondary of a single VT that will be connected from the ungrounded-wye neutral of the isolation transformer to ground. 3. If a grounded-wye - grounded-wye connection is used, a time overcurrent relay must be connected into a CT located on the Utility side isolation transformer neutral connection. Protection must be provided for internal faults in the isolating transformer; fuses are acceptable. In cases where it can be shown that self excitation of the induction generator cannot occur when isolated from the Utility, the Utility may waive the requirement that the Project Developer provide protection for Utility system ground faults. In all cases, ground fault detection for Utility faults may be required at the discretion of the Utility. Page 14 Page 15 Inverter Projects General If the interconnection system is certified by a nationally recognized testing laboratory to satisfy all requirements of IEEE Std. 1547, no additional equipment is required. If the interconnection system is not certified to satisfy requirements of IEEE Std. 1547, under/overvoltage, and under/overfrequency, will be required, and must conform to the requirements detailed in “Relay Setting Criteria” below. The under/overvoltage relays must monitor all three phases. All protection must use Utility grade relays. The isolation transformer (without generation on-line) must be incapable of producing ground fault current to the Utility system; any connection except delta primary (Project side), grounded-wye secondary (Utility side) is acceptable. Protection must be provided for internal faults in the isolating transformer; fuses are acceptable. If the inverter has passed a certified anti-island test, the Utility may waive the requirement that the Project Developer provide protection for Utility system ground faults. In all cases, ground fault detection for Utility faults may be required at the discretion of the Utility. If required, type and methodology will be the same as Synchronous Projects listed above. For a sample One-Line Diagram of this type of facility, see Appendix G. Page 16 Dynamometer Projects No isolation transformer is required between the generator and the secondary distribution connection. If an isolation transformer is used for three-phase installations, any isolation transformer connection is acceptable except grounded-wye (Utility side), delta (Project side). Protection must be provided for internal faults in the isolating transformer; fuses are acceptable. If an inverter is used and has passed a certified anti-island test, the Utility may waive the requirement that the Project Developer provide protection for the Utility system ground faults. General If the interconnection system is certified by a nationally recognized testing laboratory to satisfy all requirements of IEEE Std. 1547, no additional equipment is required. If the interconnection system is not certified to satisfy requirements of IEEE Std. 1547, under/overvoltage, and under/overfrequency, will be required, and must conform to the requirements detailed in “Relay Setting Criteria” below. The under/overvoltage relays must monitor all three phases. . All protection must use Utility grade relays. Additional anti-islanding schemes in conformance with IEEE Std 1547 4.4.1 may be utilized at the utilities discretion. The isolation transformer (without generation on-line) must be incapable of producing ground fault current to the Utility system; any connection except delta primary (Project side), grounded-wye secondary (Utility side) is acceptable. Protection must be provided for internal faults in the isolating transformer; fuses are acceptable. If an inverter is used and has passed a certified anti-island test, the Utility may waive the requirement that the Project Developer provide protection for Utility system ground faults. In all cases, ground fault detection for Utility faults may be required at the discretion of the Utility. If required, type and methodology will be the same as Synchronous Projects listed above. Page 17 Relay Setting Criteria The relay settings as detailed in this section will apply in the vast majority of applications. The Utility will issue relay settings for each individual project that will address the settings for these protective functions. All voltages will be adjusted for the specific VT ratio, and all currents will be adjusted for the specific CT ratio. Undervoltage Relays If an interconnection system which is certified to meet IEEE Std. 1547 is used, the undervoltage setpoints as defined in IEEE Std. 1547 will be used. Otherwise, the undervoltage relays will normally be set to trip at 88% of the nominal primary voltage at the relay location, and must reset from a trip condition if the voltage increases to 90% of the nominal primary voltage at the relay location. In order to accommodate variations in this criteria, the trip point of the relays shall be adjustable over a range of 70% of the nominal voltage to 90% of the nominal voltage. The trip time shall not exceed 1.0 seconds at 90% of the relay setting. Overvoltage Relays If an interconnection system which is certified to meet IEEE Std. 1547 is used, the overvoltage setpoints as defined in IEEE Std. 1547 will be used. Two steps of overvoltage relaying are required. For the first overvoltage set point, the overvoltage relays will normally be set to trip at 107% of the nominal primary voltage at the relay location, and must reset from a trip condition if the voltage decreases to 105% of the nominal primary voltage at the relay location. In order to accommodate variations in this criteria, the trip point of the relays shall be adjustable over a range of 105% of the nominal voltage to 120% of the nominal voltage. The trip time shall not exceed 1.0 seconds at 110% of the relay setting. Underfrequency Relays If an interconnection system which is certified to meet IEEE Std. 1547 is used, the underfrequency setpoints as defined in IEEE Std. 1547 will be used. Otherwise, the Underfrequency relay will normally be set for a trip point of 58.5 Hz, and must trip within 0.2 seconds. Relays with an inverse time characteristic (where the trip time changes with respect to the applied frequency) are not acceptable. These relays must respond reliably for applied source voltages as low as 70% of the nominal voltage. Overfrequency Relays If an interconnection system which is certified to meet IEEE Std. 1547 is used, the overfrequency setpoints as defined in IEEE Std. 1547 will be used. Otherwise, the overfrequency relay will normally be set for a trip point of 60.5 Hz, and must trip within 0.2 seconds. Relays with an inverse time characteristic are not acceptable. These relays must respond reliably for applied source voltages as low as 70% of the nominal voltage. 51V Relays – Voltage Controlled Overcurrent Relays For synchronous generator applications, the (51V) relays must be set to detect any phase faults that may occur between the generator and the nearest three-phase fault clearing device on the Utility system. Since these faults may take up to 1-second to detect and isolate, the appropriate saturated direct-axis reactance of the generator will be used depending on its time constants. The settings of this device will consider the relay manufacturer’s recommended practice for the type of generator and prime mover (mechanical energy source), and will be determined by the Utility for the specific system application. 59N Relay – Ground Fault Detection This relay will be applied to detect ground faults on the Utility system when the Project is connected to a grounded Utility system via an ungrounded transformer winding. This relay will be set for a 10% shift in the apparent power system neutral. For an ungrounded-wye transformer winding with a single 120 V secondary VT, the setting will usually be 12 Volts. For a delta transformer winding with broken delta 120 V secondary VTs, the setting will usually be 20 Volts. The time delay will normally be 1 second. Page 18 51N Relay – Ground Fault Detection This relay will be applied to detect ground faults on the Utility system when the Project is connected to a grounded Utility system via a grounded-wye transformer winding, and will be connected into a CT in the transformer neutral connection. This relay will be set to detect faults on the directly connected Utility system, and the timing will be set to comply with Utility practice for overcurrent relay coordination. The CT ratio and specific relay setting will be determined via a fault study performed by the Utility. 32 Relay – Reverse Power The reverse power relay must be selected such that it can detect a power flow into the Utility system of a small fraction of the overall generator capacity. The relay will normally be set near its minimum (most sensitive) setting, and will trip after a 1 second time delay. The delay will avoid unnecessary tripping for momentary conditions. Maintenance and Testing The Utility reserves the right to test the relaying and control equipment that involves protection of the Utility electric system whenever the Utility determines a reasonable need for such testing exists. The Project Developer is solely responsible for conducting proper periodic maintenance on the generating equipment and its associated control, protective equipment, interrupting devices, and main Isolation Device, per manufacturer recommendations. The Project Developer is responsible for the periodic scheduled maintenance on those relays, interrupting devices, control schemes, and batteries that involve the protection of the Utility electric system. If the interconnection system is certified to meet IEEE Std. 1547, the Standard requires that testing be conducted in accordance with written test procedures, and the nationally recognized testing laboratory providing certification, will require that such test procedures be available before certification of the equipment. Otherwise, a periodic maintenance program is to be established to test these relays at least every 2 years. Test reports of such testing shall be maintained by the Project Developer and made available for Utility inspection upon request for a period of four years. Each routine maintenance check of the relaying equipment shall include both an exact calibration check and an actual trip of the circuit breaker or contactor from the device being tested. For each test, a report shall be submitted to the Utility indicating the results of the tests made and the "as found" and "as left" relay calibration values. Visually setting, without verification, a calibration dial or tap is not considered an adequate relay calibration check. Installation and Design Approval The Project Developer must provide the Utility with 10 business days advance written notice of when the Project will be ready for inspection, testing, and approval. The Utility may review the design drawings for approval, after the Engineering Review has been completed. The design drawings must be submitted by the Project Developer in accordance with “Engineering Design Drawing Requirements” (see Generator Interconnection Supplement). If reviewed, the Utility shall either approve the Project Developer's design drawings as submitted or return them to the Project Developer with a clear statement as to why they were not approved. Where appropriate, the Utility will indicate required changes on the engineering drawings. In the event that revisions are necessary to the Project Developer's submitted design drawings, and the Project Developer submits revised design drawings to the Utility, the Utility shall either approve, in writing, the Project Developer's revised design drawings as resubmitted, or return them to the Project Developer with a clear statement as to why they were not approved. Where appropriate, the Utility will indicate required changes on the engineering drawings. Page 19 The Utility will retain one copy of the approved design drawings. In the event that the Utility exercises its option to Acceptance Test the proposed interconnection relays that protect the Utility electric system, then the Utility shall communicate the results of that testing to the Project Developer for both the relays and the necessary documentation on the relays. Prior to final approval for Parallel Operation, the Utility’s specified relay calibration settings shall be applied and a commissioning test must be performed on the generator relaying and control equipment that involves the protection of the Utility electric system. The commissioning test must be witnessed by the Utility and can be performed by the Utility at the Project Developer's request. Upon satisfactory completion of this test and final inspection, the Utility will provide written permission for Parallel Operation. If the results are unsatisfactory, the Utility will provide written communication of these results and required action to the Project Developer. In the event the Project Developer proposes a revision to the Utility’s approved relaying and control equipment used to protect the Utility electric system and submits a description and engineering design drawings of the proposed changes, the Utility shall either approve the Project Developer's amended design drawings or return them to the Project Developer with a clear statement as to why they were not approved. Where appropriate, the Utility will indicate required changes on the engineering drawings. Telemetry and Disturbance Monitoring Requirements If DTT is required, telemetry to monitor the DTT is also required. Disturbance monitoring is also recommended as being beneficial to the Project Developer and the Utility, but is not required in all cases. Telemetry enables the Utility to operate the electric system safely and reliably under both normal and emergency conditions. The Utility measures its internal load plus losses (generation) on a real time basis via an extensive telemetry system. This system sums all energy flowing into the Utility electric system from Projects interconnected to the system and from interconnections with other utilities. During system disturbances when portions of the electrical systems are out of service, it is essential to know if a generator is on line or off line to determine the proper action to correct the problem. Time saved during restoration activities translates to fewer outages and outages of shorter duration for the Utility’s customers. The Utility evaluates the performance of the overall protective system for all faults on the electric system. It is critical that sufficient monitoring of the protective system is in place to determine its response. It is preferable to deploy disturbance monitoring into all Projects, but it can be expensive to deploy. Therefore, disturbance monitoring is required only for installations at the Utility’s discretion.. The Project Developer shall provide a suitable indoor location, approved by the Utility, for the Utility’s owned, operated, and maintained Remote Terminal Unit (RTU). The location must be equipped with a 48 V or 125 V DC power supply. The Project Developer must provide the necessary phone (or alternate) and data circuits, and install a telephone (or alternate) backboard for connections to the Utility RTU and metering equipment. All phone circuits must be properly protected as detailed in IEEE Std. 487. See “Typical Meter and RTU Installation Where Telemetry is Required” in the Generator Interconnection Supplement. When telemetry is required, the following values will be telemetered: 1. Real and reactive power flow at the PCC. 2. Voltage at the PCC. 3. The status (normal/fail) of protective relay Communication Channels. A status indication of "FAIL" indicates the Communication Channel used for relaying (i.e. transfer trip) is unable to perform its protective function. This includes the following individual contacts from each individual Direct Transfer Trip receiver which is required by the Utility: i. Loss-of-guard (LOG) alarm Page 20 ii. iii. Receive-trip relay (RTX) Lockout relay 4. The status (open/closed) of the main isolating breaker and each generating unit breaker (if the Project is composed of multiple units, a single logical (OR) status of the individual generator breaker states, indicating all generator breakers are open or any one or more generator breakers are closed, is permissible). A closed status would be indicated if any individual generator is on line. For disturbance monitoring, the RTU will be equipped with “sequence of events” recording. The Project Developer shall, at a minimum, provide, wired to a terminal block near the RTU panel, sufficient connections to separately monitor the status of the three items listed above in item 3. Monitoring of the items listed below is optional, but is highly recommended since this will allow the utility to more quickly analyze abnormal events which might involve the Project and this additional monitoring should be able to be accomplished at minimum incremental cost: 1. An output contact of an instantaneous relay to act as a ground fault detector for faults on the Utility electric system. This relay shall be connected into the same sensing source as the ground fault protective relay required by the Utility. 2. Each and every trip of an interconnection isolation device, which is initiated by any of the generator interconnection relaying schemes required by the Utility. 3. Each and every trip of an interconnection isolation device, which is initiated by any of the protective systems for the generator. 4. Each and every trip or opening of an interconnecting isolation device, which is initiated by any other manual or electrical means. 5. A contact indicating the position of the Project’s primary-side main breaker. 6. A contact indicating operation of the over/undervoltage relays. 7. A contact indicating operation of the under/overfrequency relay or the Utility’s ground fault relay. 8. A contact indicating operation of the Project provided transformer bank relaying. 9. A contact indicating operation of any of the (51V) relaying. 10. A contact indicating the position of the high-side fault-clearing device. 11. A contact indicating the position of the reverse power relay, if said relay is required by the Utility. If any of the functions indicated in items 2-4, 6, 7, 9, or 11 are combined into a multi-functional device, either (1) each of those functions should be monitored independently on the RTU, or (2) provisions acceptable to the Utility should be provided to interrogate the multi-functional device such that the operation of the individual functions may be evaluated separately. Telemetry, when required, will be provided by the Utility at the Project Developer's expense. In addition to other telemetry costs, a one-time charge will be assessed to the Project Developer for equipment and software installed at the Utility’s System Control Center to process the data signals. Page 21 Miscellaneous Operational Requirements Miscellaneous requirements include synchronizing equipment for Parallel Operation, reactive requirements, standby power considerations, and system stability limitations. Operating in Parallel The Project Developer will be solely responsible for the required synchronizing equipment and for properly synchronizing the Project with the Utility electric system. Voltage fluctuation at the PCC during synchronizing shall be limited per IEEE std. 1547.. The Project Developer will notify the Utility prior to synchronizing to and prior to scheduled disconnection from the electric system. These requirements are directly concerned with the actual operation of the Project with the Utility: • The Project may not commence parallel operation until approval has been given by the Utility. The completed installation is subject to inspection by the Utility prior to approval. Preceding this inspection, all contractual agreements must be executed by the Project Developer. • The Project must be designed to prevent the Project from energizing into a de-energized Utility line. The Project’s circuit breaker or contactor must be blocked from closing in on a de-energized circuit. • The Project shall discontinue parallel operation with a particular service and perform necessary switching when requested by the Utility for any of the following reasons: 1. When public safety is being jeopardized. 2. During voltage or loading problems, system emergencies, or when abnormal sectionalizing or circuit configuration occurs on the Utility system. 3. During scheduled shutdowns of Utility equipment that are necessary to facilitate maintenance or repairs. Such scheduled shutdowns shall be coordinated with the Project. 4. In the event there is demonstrated electrical interference (i.e. Voltage Flicker, Harmonic Distortion, etc.) to the Utility’s customers, suspected to be caused by the Project, and such interference exceeds then current system standards, the Utility reserves the right, at the Utility’s initial expense, to install special test equipment as may be required to perform a disturbance analysis and monitor the operation and control of the Project to evaluate the quality of power produced by the Project. In the event that no standards exist, then the applicable tariffs and rules governing electric service shall apply. If the Project is proven to be the source of the interference, and that interference exceeds the Utility’s standards or the generally accepted industry standards, then it shall be the responsibility of the Project Developer to eliminate the interference problem and to reimburse the Utility for the costs of the disturbance monitoring installation, removal, and analysis, excluding the cost of the meters or other special test equipment. 5. When either the Project or its associated synchronizing and protective equipment is demonstrated by the Utility to be improperly maintained, so as to present a hazard to the Utility system or its customers. 6. Whenever the Project is operating isolated with other Utility customers, for whatever reason. 7. Whenever a loss of communication channel alarm is received from a location where a communication channel has been installed for the protection of the Utility system. 8. Whenever the Utility notifies the Project Developer in writing of a claimed non-safety related violation of the Interconnection Agreement and the Project Developer fails to remedy the claimed violation Page 22 within ten working days of notification, unless within that time either the Project Developer files a complaint with the MPSC seeking resolution of the dispute or the Project Developer and Utility agree in writing to a different procedure. If the Project has shown an unsatisfactory response to requests to separate the generation from the Utility system, the Utility reserves the right to disconnect the Project from parallel operation with the Utility electric system until all operational issues are satisfactorily resolved. Reactive Power Control Synchronous generators that will operate in the Flow-back Mode must be dynamically capable of providing 0.90 power factor lagging (delivering reactive power to the Utility) and 0.95 power factor leading (absorbing reactive power from the Utility) at the Point of Receipt. The Point of Receipt is the location where the Utility accepts delivery of the output of the Project. The Point of Receipt can be the physical location of the billing meters or a location where the billing meters are not located, but adjusted for line and transformation losses. Induction and Inverter Projects that will operate in the Flow-back Mode must provide for their own reactive needs (steady state unity power factor at the Point of Receipt). To obtain unity power factor, the Induction or Inverter Project can: 1. Install a switchable VAR supply source to maintain unity power factor at the Point of Receipt; or 2. Provide the Utility with funds to install a VAR supply source equivalent to that required for the Project to attain unity power factor at the Point of Receipt at full output. There are no interconnection reactive power capability requirements for Synchronous, Induction, and Inverter Projects that will operate in the Non Flow-back Mode. The Utility’s existing rate schedules, incorporated herein by reference, contain power factor adjustments based on the power factor of the metered load at these facilities. Standby Power Standby power will be provided under the terms of an approved rate set forth in the Utility’s Standard Rules and Regulations. The Project Developer should be aware that to qualify for Standby Rates, a separate meter must be installed at the generator. If outside of the Utility’s franchise area, it will be the Project Developer’s responsibility to arrange contractually and technically for the supply of its facility’s standby, maintenance, and any supplemental power needs. System Stability and Site Limitations The Stiffness Ratio is the combined three-phase short circuit capability of the Project and the Utility divided by the short circuit capability of the Project measured at the PCC. A stability study may be required for Projects with a Stiffness Ratio of less than 40. Five times the generator rated kVA will be used as a proxy for short circuit current contribution for induction generators. For synchronous Projects, with a Stiffness Ratio of less than 40, the Utility requires special generator trip schemes or loss of synchronism (out-of-step) relay protection. If the apparent voltage flicker from a loss-of-synchronism condition exceeds 5%, an out-of-step relay will be required. This type of protection is typically applied at the PCC and trips the entire Project off-line, if instability is detected, to protect the Utility electric system and its customers. If the Project Developer chooses not to provide for mitigation of unacceptable voltage flicker (above five percent), the Utility may disallow the interconnection of the Project or require a new dedicated interconnection at the Project Developer’s expense. The Project Developer is responsible for evaluating the consequences of unstable generator operation or voltage transients on Project equipment and determining, designing, and applying any relaying which may be necessary to protect that equipment. This type of protection is typically applied on individual generators to protect the Project facilities. Page 23 The Utility will determine if operation of the Project will create objectionable voltage flicker and/or disturbances to other Utility customers and develop any required mitigation measures at the Project Developer’s expense. Revenue Metering Requirements The Utility will own, operate, and maintain all required billing metering equipment at the Project Developer's expense. Non Flow-back Projects A Utility meter will be installed that only records power flow energy deliveries to the Project. Flow-back Projects Special billing metering may be required. The Project Developer may be required to provide, at no cost to the Utility, a dedicated communication circuit, to allow remote access to the billing meter by the Utility. This circuit shall be terminated within ten feet of the meter involved. Ground fault protection for this circuit may be required, and coordination with the telephone company and all associated costs will be by Project Developer. The Project Developer shall provide the Utility access to the premises at all times to install, turn on, disconnect, inspect, test, read, repair, or remove the metering equipment. The Project Developer may, at its option, have a representative witness this work. The metering installations shall be constructed in accordance with the practices, which normally apply to the construction of metering installations for residential, commercial, or industrial customers. At a minimum three meters will be required; two at the PCC, one import and one export and one at the generator. For Projects with multiple generators, metering of each generator may be required. When practical, multiple generators may be metered at a common point provided the metered quantity represents only the gross generator output. The Utility shall supply to the Project Developer all required metering equipment and the standard detailed specifications and requirements relating to the location, construction, and access of the metering installation and will provide consultation pertaining to the meter installation as required. The Utility will endeavor to coordinate the delivery of these materials with the Project Developer’s installation schedule during normal scheduled business hours. The Project Developer may be required to provide a mounting surface for the metering equipment, including enclosures and conduit. The mounting surface and location must meet the Utility’s specifications and requirements. The responsibility for installation of the equipment is shared between the Utility and the Project Developer. The Project Developer may be required to install some of the metering equipment on its side of the PCC, including instrument transformers, cabinets, conduits, and mounting surfaces. The Utility, shall install the meters and communication links. The Utility will endeavor to coordinate the installation of these items with the Project Developer's schedule during normal scheduled business hours. Page 24 Communication Circuits The Project Developer is responsible for ordering and acquiring the telephone circuit required for the Project Interconnection. The Project Developer will assume all installation, operating, and maintenance costs associated with the telephone circuits, including the monthly charges for the telephone lines and any rental equipment required by the local telephone provider. However, at the Utility’s discretion, the Utility may select an alternative communication method, such as wireless communications. Regardless of the method, the Project Developer will be responsible for all costs associated with the material, installation and maintenance, whereas the Utility will be responsible to define the specific communication requirements. The Utility will cooperate and provide Utility information necessary for proper installation of the telephone (or alternate) circuits upon written request. A dedicated communication circuit is required for access to the billing meter by the Utility. When DTT is required, a modular RJ-11 jack must also be installed within six feet of the billing metering equipment, to allow the Utility to use this circuit for voice communication with personnel performing master station checkout of the RTU. This dialup voice-grade circuit shall be a local telephone company provided business measured line without dial-in or dialout call restrictions. If DTT is required, a separate dedicated 4-wire, Class A, Data Circuit must be installed and protected as specified by the local telephone Utility for each DTT receiver and for the RTU. The circuit must be installed in rigid metallic conduit from the RTU and each DTT receiver to the point of connection to the telephone Utility equipment. Wall space must be provided for adjacent mounting next to the telephone board, of the billing metering panel and a telemetry enclosure. The billing metering panel is typically 60 inches high by 48 inches wide and the telemetry enclosure is typically 24 inches high by 24 inches wide. A clear space of 4.5 feet in front of this equipment is required to permit maintenance and testing. A review of each installation shall be made to determine the location and space requirements most agreeable to the Utility and the Project Developer. Page 25 Appendix A Interconnection Process Flow Diagram Page 26 Appendix B Category 3 Interconnection Table – Applicant Costs Distribution Application Engineering Distribution Review Review Study Upgrades $150 $0 Propose fixed Actual or Max Fee Approved by Commission Testing & Inspection Actual or Max Approved by Commission * Costs incurred by affected systems are born directly by the applicant and are not included in the table. ** Projects greater than 6MW will have an initial fixed fee with actual cost true up at the completion of the study. Combined Net Metering / Interconnection Table - Applicant Costs Distribution Application Engineering Distribution Net Meter Review Study Upgrades Program Fee Review Category 3 $25 $75 $0 Propose fixed Actual or Max fee Approved by Methane Digester Only Commission Application Complete Category 3 10 days Interconnection Timeline – Working Days Application Engineering Distribution Distribution Review Study Study Upgrades Completion Completion 10 days 15 days 15 days Mutually Agreed Page 27 Testing & Inspection $0 Testing & Inspection 10 days to notify of scheduled visit Appendix C - Procedure Definitions Alternative electric supplier ( AES ): as defined in section 10g of 2000 PA 141, MCL 460.10g Alternative electric supplier net metering program plan: document supplied by an AES that provides detailed information to an applicant about the AES’s net metering program. Applicant: Legally responsible person applying to an electric utility to interconnect a project with the electric utility’s distribution system or a person applying for a net metering program. An applicant shall be a customer of an electric utility and may be a customer or an AES. Application Review: Review by the electric utility of the completed application for interconnection to determine if an engineering review is required. Area Network: A location on the distribution system served by multiple transformers interconnected in an electrical network circuit. Category 1: An inverter based project of 20kW or less that uses equipment certified by a nationally recognized testing laboratory to IEEE 1547.1 testing standards and in compliance with UL 1741 scope 1.1A. Category 2: A project of greater than 20 kW and not more than 150 kW. Category 3: A project of greater than 150 kW and not more than 550 kW. Category 4: A project of greater than 550 kW and not more than 2 MW. Category 5: A project of greater than 2 MW. Certified equipment: A generating, control, or protective system that has been certified as meeting acceptable safety and reliability standards by a nationally recognized testing laboratory in conformance with UL 1741. Commission: The Michigan Public Service Commission Commissioning test: The procedure, performed in compliance with IEEE 1547.1, for documenting and verifying the performance of a project to confirm that the project operates in conformity with its design specifications. Customer: A person who receives electric service from an electric utility’s distribution system or a person who participates in a net metering program through an AES or electric utility. Customer-generator: A person that uses a project on-site that is interconnected to an electric utility distribution system. Page 28 Distribution system: The structures, equipment, and facilities operated by an electric utility to deliver electricity to end users, not including transmission facilities that are subject to the jurisdiction of the federal energy regulatory commission. Distribution system study: A study to determine if a distribution system upgrade is needed to accommodate the proposed project and to determine the cost of an upgrade if required. Electric provider: Any person or entity whose rates are regulated by the commission for selling electricity to retail customers in the state. Electric utility: Term as defined in section 2 of 1995 PA 30, MCL 460.562. Eligible electric generator: A methane digester or renewable energy system with a generation capacity limited to the customer’s electrical need and that does not exceed the following: • 150 kW of aggregate generation at a single site for a renewable energy system • 550 kW of aggregate generation at a single site for a methane digester Engineering Review: A study to determine the suitability of the interconnection equipment including any safety and reliability complications arising from equipment saturation, multiple technologies, and proximity to synchronous motor loads. Full retail rate: The power supply and distribution components of the cost of electric service. Full retail rate does not include system access charge, service charge, or other charge that is assessed on a per meter basis. IEEE: Institute of Electrical and Electronics Engineers IEEE 1547: IEEE “Standard for Interconnecting Distributed Resources with Electric Power Systems” IEEE 1547.1: IEEE “Standard Conformance Test Procedures for Equipment Interconnecting Distributed Resources with Electric Power Systems” Interconnection: The process undertaken by an electric utility to construct the electrical facilities necessary to connect a project with a distribution system so that parallel operation can occur. Interconnection procedures: The requirements that govern project interconnection adopted by each electric utility and approved by the commission. kW: kilowatt kWh: kilowatt-hours Material modification: A modification that changes the maximum electrical output of a project or changes the interconnection equipment including the following: Page 29 • • Changing from certified to non certified equipment Replacing a component with a component of different functionality or UL listing. Methane digester: 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. Modified net metering: A 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 utility distribution system during a billing period or time-of-use pricing period. MW: megawatt Nationally recognized testing laboratory: Any testing laboratory recognized by the accreditation program of the U.S. department of labor occupational safety and health administration. Parallel operation: The operation, for longer than 100 milliseconds, of a project while connected to the energized distribution system. Project: Electrical generating equipment and associated facilities that are not owned or operated by an electric utility. Renewable energy credit ( REC ): A credit granted pursuant to the commission’s renewable energy credit certification and tracking program in section 41 of 2008 PA 295, MCL 460.1041. Renewable energy resource: Term as defined in section 11(i) of 2008 PA 295, MCL 460.1011(i) Renewable energy system: Term as defined in section 11(k) of 2008 PA 295, MCL 460.1011(k). Spot network: A location on the distribution system that uses 2 or more inter-tied transformers to supply an electrical network circuit. True net metering: A utility billing method that applies the full retail rate to the net of the bidirectional flow of kW hors across the customer interconnection with the utility distribution system, during a billing period or time-of-use pricing period. UL: Underwriters Laboratory UL 1741: The “Standard for Inverters, Converters, Controllers and Interconnection System Equipment for Use With Distributed Energy Resources.” UL 1741 scope 1.1A: Paragraph 1.1A contained in chapter 1, section 1 of UL 1741. Page 30 Uniform interconnection application form: The standard application forms, approved by the commission under R 460.615 and used for category 1, category 2, category 3, category 4, and category 5 projects. Uniform interconnection agreement: The standard interconnection agreements approved by the commission under R 460.615 and used for category 1, category 2, category 3, category 4, and category 5 projects. Uniform net metering application: The net metering application form approved by the commission under R 460.642 and used by all electric utilities and AES. Working days: Days excluding Saturdays, Sundays, and other days when the offices of the electric utility are not open to the public. Page 31 Page 32 Appendix D – Site Plan Page 32 Appendix E – Sample Synchronous One-Line (not required for flow-back) Page 34 Instructions: Attach data sheets as required. Indicate in the table below the page number of the attached data (manufacturer’s data where appropriate) on which the requested information is provided. Provide one table for each unique generator. Synchronous Electric Generator(s) at the Project Item No 1 2 3 4 5 6 7 8 9 10 Data Valu e Generator o _____ Data Description Generator Type (synchronous or induction) Generator Nameplate Voltage Generator Nameplate Watts or Volt-Amperes Generator Nameplate Power Factor (pf) Direct axis reactance (saturated) Direct axis transient reactance (saturated) Direct axis sub-transient reactance (saturated) Short Circuit Current contribution from generator at the Point of Common Coupling (single-phase and three-phase National Recognized Testing Laboratory Certification Written Commissioning Test Procedure ‘ Page 35 Attached Page No Appendix F – Sample Induction One-Line (not required for flow-back) Page 36 Instructions: Attach data sheets as required. Indicate in the table below the page number of the attached data (manufacturer’s data where appropriate) on which the requested information is provided. Provide one table for each unique generator. Item No 1 2 3 4 5 6 7 Induction Electric Generator(s) at the Project: Generator No _____ Data Attached Description Page No Generator Type (Inverter) Generator Nameplate Voltage Generator Nameplate Watts or Volt-Amperes Generator Nameplate Power Factor (pf) Short Circuit Current contribution from generator at the Point of Common Coupling (single-phase and three-phase) National Recognized Testing Laboratory Certification Written Commissioning Test Procedure Page 37 Appendix G – Sample One-Line Inverter ONE-LINE REPRESENTATION TYPICAL ISOLATION AND FAULT PROTECTION FOR INVERTER GENERATOR INSTALLATIONS 32 (not required for flow-back) 59 A) Page 38 Instructions: Attach data sheets as required. Indicate in the table below the page number of the attached data (manufacturer’s data where appropriate) on which the requested information is provided. Provide one table for each unique generator. Item No 1 2 3 4 5 6 7 Inverter Electric Generator(s) at the Project: Generator No _____ Data Attached Description Page No Generator Type (Inverter) Generator Nameplate Voltage Generator Nameplate Watts or Volt-Amperes Generator Nameplate Power Factor (pf) Short Circuit Current contribution from generator at the Point of Common Coupling (single-phase and three-phase) National Recognized Testing Laboratory Certification Written Commissioning Test Procedure Page 39 Appendix H Page 40 Sample One Line Diagram for Non-Flow Back projects ONE-LINE DIAGRAM & CONTROL SCHEMATIC TYPICAL ISOLATION PROECTION FOR NON FLOW-BACK INSTALLATIONS Distribution Circuit Appendix I Page 41 Sample One Line Diagram for Flow-Back projects Page 42 MICHIGAN ELECTRIC UTILITY Generator Interconnection Requirements Category 4 Projects with Aggregate Generator Output Greater Than 550 kW or More, but Less Than or Equal to 2 MW August 3, 2009 Page 1 Introduction Category 4 – Greater than 550kW less than or equal to 2MW This Generator Interconnection Procedure document outlines the process & requirements used to install or modify generation projects with aggregate generator output capacity ratings greater than 550kW less than or equal to 2MW designed to operate in parallel with the Utility electric system. Technical requirements (data, equipment, relaying, telemetry, metering) are defined according to type of generation, location of the interconnection, and mode of operation (Flowback or Non-Flow-back). The process is designed to provide an expeditious interconnection to the Utility electric system that is both safe and reliable. This document has been filed with the Michigan Public Service Commission (MPSC) and complies with rules established for the interconnection of parallel generation to the Utility electric system in the MPSC Order in Case No. U-15787. The term “Project” will be used throughout this document to refer to electric generating equipment and associated facilities that are not owned or operated by an electric utility. The term “Project Developer” means a person that owns, operates, or proposes to construct, own, or operate, a Project. This document does not address other Project concerns such as environmental permitting, local ordinances, or fuel supply. Nor does it address agreements that may be required with the Utility and/or the transmission provider, or state or federal licensing, to market the Project’s energy. An interconnection request does not constitute a request for transmission service. It may be possible for the Utility to adjust requirements stated herein on a case-by-case basis. The review necessary to support such adjustments, however, may be extensive and may exceed the costs and timeframes established by the MPSC and addressed in these requirements. Therefore, if requested by the Project Developer, adjustments to these requirements will only be considered if the Project Developer agrees in advance to compensate the Utility for the added costs of the necessary additional reviews and to also allow the Utility additional time for the additional reviews. The Utility may apply for a technical waiver from one or more provisions of these rules and the MPSC may grant a waiver upon a showing of good cause. Page 2 Table of Contents Interconnection Process .....................................................................................................................5 Customer Project Planning Phase ............................................................................................................................. 5 Application & Queue Assignment ............................................................................................................................ 5 Application Review................................................................................................................................................... 5 Engineering Review .................................................................................................................................................. 6 Distribution Study ..................................................................................................................................................... 6 Customer Install & POA ........................................................................................................................................... 6 Meter install, Testing, & Inspection .......................................................................................................................... 7 Cat 4 -Installation and Design Approval ................................................................................................................... 7 Operation in Parallel ................................................................................................................................................. 8 Operational Provisions ......................................................................................................................8 Disconnection ........................................................................................................................................................... 8 Maintenance and Testing .......................................................................................................................................... 8 TECHNICAL REQUIREMENTS .....................................................................................................10 Major Component Design Requirements ...................................................................................10 Data ......................................................................................................................................................................... 10 Isolation Device ...................................................................................................................................................... 11 Interconnection Lines .............................................................................................................................................. 11 Termination Structure ............................................................................................................................................. 11 Relaying Design Requirements ..................................................................................................12 Protective Relaying General Considerations ........................................................................................................... 12 Momentary Paralleling ............................................................................................................................................ 12 Instrument Transformer Requirements ................................................................................................................... 12 Direct Transfer Trip (DTT) ..................................................................................................................................... 13 Reverse Power Relaying for Non-Flow-back ......................................................................................................... 13 Automatic Reclosing ............................................................................................................................................... 13 Single-Phase Sectionalizing .................................................................................................................................... 13 Inverter Projects ...................................................................................................................................................... 17 Dynamometer Projects ................................................................................................................18 General ..........................................................................................................................................18 Relay Setting Criteria .............................................................................................................................................. 18 Maintenance and Testing ........................................................................................................................................ 19 Telemetry and Disturbance Monitoring Requirements ............................................................20 Miscellaneous Operational Requirements .................................................................................21 Operating in Parallel ............................................................................................................................................... 21 Reactive Power Control .......................................................................................................................................... 23 Standby Power ........................................................................................................................................................ 23 System Stability and Site Limitations ..................................................................................................................... 23 Page 3 Revenue Metering Requirements ...............................................................................................24 Communication Circuits ..............................................................................................................24 Appendix A....................................................................................................................................26 Interconnection Process Flow Diagram .................................................................................................................. 26 Appendix B ....................................................................................................................................27 Interconnection Table – Applicant Costs ................................................................................................................ 27 Interconnection Timeline – Working Days ............................................................................................................. 27 Appendix C - Procedure Definitions ..........................................................................................28 Appendix D – Site Plan ................................................................................................................32 Appendix E – Sample One-Line Synchronous ..........................................................................33 Appendix F – Sample One-Line Induction .................................................................................35 Appendix G – Sample One-Line Inverter....................................................................................37 Appendix H ....................................................................................................................................39 Sample One Line Diagram for Non-Flow Back projects ........................................................................................ 39 Appendix I .....................................................................................................................................40 Sample One Line Diagram for Flow-Back projects ................................................................................................ 40 Page 4 Interconnection Procedures Interconnection Process Customer Project Planning Phase An applicant may contact the utility before or during the application process regarding the project. The utility can be reached by phone, e-mail, or by the external website to access information, forms, rates, and agreements. A utility will provide up to 2 hours of technical consultation at no additional cost to the applicant. Consultation may be limited to providing information concerning the utility system operating characteristics and location of system components. Application & Queue Assignment The Project Developer must first submit a ,”Combined Category 4” application to the Utility. A separate application is required for each Project or Project site. The blank Interconnection Application can be found on the Utility’s customer generation’s website . A complete submittal of required interconnection data and Interconnection filing fee per the table in Appendix B. The Utility will notify the Project Developer within 10 business days of receipt of an Interconnection Application. If any portion of the Interconnection Application, data submittal (a site plan and the one-line diagrams), or filing fee is incomplete and/or missing, the Utility will return the application, data, and filing fee to the Project developer with explanations. Project Developer will need to resubmit the application with all the missing items. Once the Utility has accepted the application, a queue number will be assigned to the Project. The utility will then advise the applicant that the application is complete and provide the customer with the queue assignment. Application Review The Utility shall review the complete application for interconnection to determine if an engineering review is required. The Utility will notify the Project Developer within 10 business days of receipt of complete application and if an engineering review is required. If an engineering review is required, the Utility will supply the applicant with the “request for engineering study - acceptance letter” and identify the required engineering study fee. The Page 5 applicant shall provide any changes or updates to the application before the engineering review begins. If an engineering review is not required, the project will advance to the Customer Install & POA phase of the process. The Utility may request additional data be submitted as necessary during the review phase to clarify the operation of the Project. Engineering Review Upon the Utility receiving an executed “request for engineering study – acceptance letter” and engineering study fee, the Utility shall study the project to determine the suitability of the interconnection equipment including safety and reliability complications arising from equipment saturation, multiple technologies, and proximity to synchronous motor loads. Category 4 & 5 projects may involve affected system studies which are performed by the affected system owner. Category 4 & 5 projects affected system study fees and timeline are the responsibility of the applicant. The electric utility shall provide in writing the results of the engineering study including identifying major components affected and provide a non-binding estimate ( as practically possible) for interconnection, within the time indicated in the Interconnection Timeline Table. If the engineering review indicates that a distribution study is necessary, the Utility will supply the applicant with the “request for distribution study - acceptance letter” and identify the required distribution study fee. If an engineering review determines that a distribution study is not required, the project will advance to the Customer Install & POA phase of the process. Distribution Study Upon the Utility receiving an executed “request for distribution study – acceptance letter” and distribution study fee, the Utility shall study the project to determine if a distribution system upgrade is needed to accommodate the proposed project and determine the cost of an upgrade if required. The electric utility shall provide in writing the results of the distribution study including estimated completion timeframe and cost estimate +/- 10% for the upgrades, if required, to the applicant, within the timeframe allowed by the Interconnection Timeline Table. If a distribution study determines that a distribution upgrades are not required, the project will advance to the Customer Install & POA phase of the process. Customer Install & POA The applicant shall notify the electric utility when an installation and any required local code inspection and approval is complete. The Parallel Operating Agreement for different rates can be found from the Utility Customer Generation website. The Parallel Operating Agreement will cover matters customarily addressed in such agreements in accordance with Good Utility Practice, including, without limitation, construction of facilities, system operation, interconnection rate, defaults and remedies, and liability. The applicant shall complete, sign and return the POA ( Parallel Operating Agreement ) to the Utility. Any delay in the applicant’s execution of the Interconnection and Operating Agreement will not count toward the interconnection deadlines. Page 6 Meter install, Testing, & Inspection Upon receipt of the local code inspection approval and executed POA, the Utility will schedule the meter install, testing, and inspection. The utility shall have an opportunity to schedule a visit to witness and perform commissioning tests required by IEEE 1547.1 and inspect the project. The electric utility may provide a waiver of its right to visit the site to inspect the project and witness or perform the commissioning tests. The utility shall notify the applicant of its intent to visit the site, inspect the project, witness or perform the commissioning tests, or of its intent to waive inspection within 10 working days after notification that the installation and local code inspections have passed. Within 5 working days from receipt of the completed commissioning test report ( if applicable ), the utility will notify the applicant of its approval or disapproval of the interconnection. If the electric utility does not approve the interconnection, the utility shall notify the applicant of the necessary corrective actions required for approval. The applicant, after taking corrective action, may request the electric utility to reconsider the interconnection request. Cat 4 -Installation and Design Approval The Project Developer must provide the Utility with 10 business days advance written notice of when the Project will be ready for inspection, testing and approval. The Utility may review the design drawings, for approval, after the Interconnection Review & Study has been completed. The design drawings must be submitted by the Project Developer in accordance with “Engineering Design Drawing Requirements” (see Generator Interconnection Supplement). If reviewed, the Utility shall either approve the Project Developer's design drawings as submitted or return them to the Project Developer with a clear statement as to why they were not approved. Where appropriate, the Utility will indicate required changes on the engineering drawings. In the event that revisions are necessary to the Project Developer's submitted design drawings and the Project Developer submits revised design drawings to the Utility, then the Utility shall either approve, in writing, the Project Developer's revised design drawings as resubmitted, or return them to the Project Developer with a clear statement as to why they were not approved. Where appropriate, the Utility will indicate required changes on the engineering drawings. The Utility will retain one copy of the approved design drawings. In the event that the Utility exercises its option to Acceptance Test the proposed interconnection relays that protect the Utility electric system, then the Utility shall communicate the results of that testing to the Project Developer for both the relays and the necessary documentation on the relays. Prior to final approval for Parallel Operation, the Utility’s specified relay calibration settings shall be applied and a commissioning test must be performed on the Project relaying and control equipment that involves the protection of the Utility electric system. The commissioning test must be witnessed by the Utility and can be performed by the Utility at the Project Developer's request. Upon satisfactory completion of this test and final inspection, the Utility will provide Page 7 written permission for Parallel Operation. If the results are unsatisfactory, the Utility will provide written communication of these results and required action to the Project Developer. In the event the Project Developer proposes a revision to the Utility’s approved relaying and control equipment used to protect the Utility electric system and submits a description and engineering design drawings of the proposed changes, the Utility shall either approve the Project Developer's amended design drawings or return them to the Project Developer with a clear statement as to why they were not approved. Where appropriate, the Utility will indicate required changes on the engineering drawings. Operation in Parallel Upon utility approval of the interconnection, the electric utility shall install required metering, provide to the applicant a written statement of final approval, and a fully executed POA authorizing parallel operation. Operational Provisions Disconnection An electric utility may refuse to connect or may disconnect a project from the distribution system if any of the following conditions apply: a. Lack of fully executed interconnection agreement (POA) b. Termination of interconnection by mutual agreement c. Noncompliance with technical or contractual requirements in the interconnection agreement after notice is provided to the applicant of the technical or contractual deficiency. d. Distribution system emergency e. Routine maintenance, repairs, and modifications, but only for a reasonable length of time necessary to perform the required work and upon reasonable notice. Maintenance and Testing The Utility reserves the right to test the relaying and control equipment that involves protection of the Utility electric system whenever the Utility determines a reasonable need for such testing exists. The Project Developer is solely responsible for conducting proper periodic maintenance on the generating equipment and its associated control, protective equipment, interrupting devices, and main Isolation Device, per manufacturer recommendations. The Project Developer is responsible for the periodic scheduled maintenance on those relays, interrupting devices, control schemes, and batteries that involve the protection of the Utility electric system. A periodic maintenance program is to be established to test these relays at least every 2 years. This maintenance testing must be witnessed by the Utility. Each routine maintenance check of the relaying equipment shall include both an exact calibration check and an actual trip of the circuit breaker or contactor from the device being tested. For each test, a report shall be submitted to the Utility indicating the results of the tests made and the "as Page 8 found" and "as left" relay calibration values. Visually setting, without verification, a calibration dial or tap is not considered an adequate relay calibration check. Routine and maintenance checks of the relaying and control equipment must be conducted in accordance with provided written test procedures which are required by IEEE Std. 1547, and test reports of such testing shall be maintained by the applicant and made available for Utility inspection upon request. [NOTE – IEEE 1547 requires that testing be conducted in accordance with written test procedures, and the nationally recognized testing laboratory providing certification will require that such test procedures be available before certification of the equipment.] The Project Developer is responsible for maintaining written reports for the above tests for a period of four years. These written reports shall be made available to the Utility upon request. Page 9 Technical Requirements The following discussion details the technical requirements for interconnection of Category 4 Projects with aggregate generator output greater than 550 kW but less than or equal to 2 MW. Many of these requirements will vary based on the capacity rating of the Project, type of generation being used, and mode of operation (Flow-back or Non-Flow-back). A few of the requirements will vary based on location of the interconnection (isolated load and available fault current). Certain major component, relaying, telemetry, and operational requirements must be met to provide compatibility between the Project equipment and the Utility electric system, and to assure that the safety and reliability of the electric system is not degraded by the interconnection. The Utility reserves the right to evaluate and apply newly developed protection and/or operation schemes at its discretion. All protective schemes and functions are evaluated for compliance to IEEE std. 1547. In addition, the Utility reserves the right to evaluate Projects on an ongoing basis as system conditions change, such as circuit loading, additional generation placed online, etc. Upgraded revenue metering may be required. Major Component Design Requirements The data requested in Appendix B or C, for all major equipment and relaying proposed by the Project Developer, must be submitted as part of the initial application for review and approval by the Utility. The Utility may request additional data be submitted as necessary during the Distribution Study phase to clarify the operation of the Project. Once installed, the interconnection equipment must be reviewed and approved by the Utility prior to being connected to the Utility electric system and before Parallel Operation is allowed. Data The data that the Utility requires to evaluate the proposed interconnection is documented on a one-line diagram and “fill in the blank” table by generator type in Appendices E, F, or G. A site plan, one-line diagrams, and interconnection protection system details of the Project are required as part of the application data. The generator manufacturer data package should also be supplied. Isolating Transformer(s) If an isolating transformer is required, the transformer must comply with the current ANSI Standard C57.12. The transformer must have voltage taps on the high and/or low voltage windings sufficient to assure satisfactory generator operation over the range of voltage variation expected on the Utility electric system. Page 10 The Project Developer also needs to assure sufficient voltage regulation at its Project to maintain an acceptable voltage level for its equipment during such periods when its Project is off-line. This may involve the provision of voltage regulation or a separate transformer between the Utility and the Project station power bus. The type of generation and electrical location of the interconnection will determine the isolating transformer connections. Allowable connections are detailed under the specific generator type. Note: Some Utilities do not allow an isolation transformer to be connected to a grounded Utility system with an ungrounded secondary (Utility side) winding configuration, regardless of the Project type. Therefore, the Project Developer is encouraged to consult with the Utility prior to submitting an application. The proper selection and specification of transformer impedance is important relative to enabling the proposed Project to meet the Utility’s reactive power requirements (see “Reactive Power Control”). Isolation Device An isolation device is required and should be placed at the Point of Common Coupling (PCC). It can be a circuit breaker, circuit switcher, pole top switch, load-break disconnect, etc., depending on the electrical system configuration. The following are required of the isolation device: • Must be approved for use on the Utility system. • Must comply with current relevant ANSI and/or IEEE Standards. • Must have load break capability, unless used in series with a three-phase interrupting device. • Must be rated for the application. • If used as part of a protective relaying scheme, it must have adequate interrupting capability. The Utility will provide maximum short circuit currents and X/R ratios available at the PCC upon request. • Must be operable and accessible by the Utility at all times (24 hours a day, 7 days a week). • The Utility will determine if the isolation device will be used as a protective tagging point. If the determination is so made, the device must have visible open break provisions for padlocking in the open position, and it must be gang operated. If the device has automatic operation, the controls must be located remote from the device. Interconnection Lines The physically closest available system voltage, as well as equipment and operational constraints influence the chosen point of interconnection. The Utility has the ultimate authority to determine the acceptability of a particular PCC. Any new line construction to connect the Project to the Utility’s electric system will be undertaken by the Utility at the Project Developer's expense. The new lines will terminate on a termination structure provided by the Project Developer. Termination Structure The Project Developer is responsible for ensuring that structural material strengths are adequate for all requirements, incorporating appropriate safety factors. Upon written request, the Utility will provide line tension information for maximum line dead-end tensions under heavy icing conditions. The structure must be designed for this maximum line tension along with an adequate margin of safety. Substation electrical clearances shall comply with requirements of the National Electrical Safety Code and Michigan Public Service Commission Standard 16-79. Page 11 The installation of disconnect switches, bus support insulators, and other equipment shall comply with accepted industry practices. Surge arresters shall be selected to coordinate with the BIL rating of major equipment components and shall comply with recommendations set forth in the current ANSI Standard C62.2. Relaying Design Requirements The interconnection relaying design requirements are intended to assure protection of the Utility electric system. Any additional relaying which may be necessary to protect equipment at the Project is solely the responsibility of the Project Developer to determine, design, and apply. The relaying requirements will vary with the capacity rating of the Project, the type of generation being used, and the mode of operation (Flow-back or Non Flow-back). All relaying proposed by the Project Developer to satisfy these requirements must be submitted for review and approved by the Utility. Protective Relaying General Considerations Utility grade relays are required. See “Approved Relay Types” in the Generator Interconnection Supplement. All relays must be equipped with targets or other visible indicators to indicate that the relay has operated. If the protective system uses AC power as the control voltage, it must be designed to disconnect the generation from the Utility electric system if the AC control power is lost. Utility will work with Project Developer for system design for this requirement. The relay system must be designed such that the generator is prevented from energizing the Utility electric system if that system is de-energized. Momentary Paralleling For situations where the Project will only be operated in parallel with the Utility electric system for a short duration (100 milliseconds or less), as in a make-before-break automatic transfer scheme, no additional relaying is required. Such momentary paralleling requires a modern integrated Automatic Transfer Switch (ATS) system, which is incapable of paralleling the Project with the Utility electric system. The ATS must be tested and verified for proper operation at least every 2 years. The Utility may be present during this testing. Instrument Transformer Requirements All relaying must be connected into instrument transformers. All current connections shall be connected into current transformers (CTs). All CTs shall be rated to provide no more than 5 amperes secondary current for all normal load conditions, and must be designed for relaying use, with an “accuracy class” of at least C50. Current transformers with an accuracy class designation such as T50 are NOT acceptable. For three-phase systems, all three phases must be equipped with CTs. All potential connections must be connected into voltage transformers (VTs). For single-phase connections, the VTs shall be provided such that the secondary voltage does not exceed 120 volts for normal operations. For three-phase connections, the VTs shall be provided such that the line-to-line voltage does not exceed 120 volts for normal operation, and both the primary and secondary of the VTs shall be connected for grounded-wye connections. Page 12 Direct Transfer Trip (DTT) Direct Transfer Trip is generally not required for Induction or Inverter Projects. Direct Transfer Trip is generally not required for Synchronous Projects that will operate in the Non Flow-back Mode since a more economic reverse power relay scheme can usually meet the requirements. For Synchronous Flowback Projects the need for DTT is determined based on the location of the PCC. The Utility requires DTT when the total generation within a protective zone is greater than 33% of the minimum Utility load that could be isolated along with the generation. This prevents sustained isolated operation of the generation for conditions where generator protective relaying may not otherwise operate (see “Isolated Operation” in the Generator Interconnection Supplement). Direct transfer trip adds to the cost and complexity of an interconnection. A DTT transmitter is required for each Utility protective device whose operation could result in sustained isolated operation of the generator. An associated DTT receiver at the Project is required for each DTT transmitter. A Data Circuit is required between each transmitter and receiver. Telemetry is required to monitor the status of the DTT communication, even if telemetry would not otherwise have been required. At the Project Developer’s expense, the Utility will provide the receiver(s) that the Project Developer must install, and the Utility will install the transmitter(s) at the appropriate Utility protective devices. Reverse Power Relaying for Non-Flow-back If Flow-back Mode is not utilized, reverse power protection must be provided. The reverse power relaying will detect power flow from the Project into the Utility system, and operation of the reverse power relaying will separate the Project from the Utility system. Automatic Reclosing The Utility employs automatic multiple-shot reclosing on most of the Utility’s circuit breakers and circuit reclosers to increase the reliability of service to its customers. Automatic single-phase overhead reclosers are regularly installed on distribution circuits to isolate faulted segments of these circuits. The Project Developer is advised to consider the effects of Automatic Reclosing (both single-phase and three-phase) to assure that the Project’s internal equipment will not be damaged. In addition to the risk of damage to the Project, an out-of-phase reclosing operation may also present a hazard to the Utility’s electric system equipment since this equipment may not be rated or built to withstand this type of reclosing. To prevent out-of-phase reclosing, circuit breakers can be modified with voltage check relays. These relays block reclosing until the parallel generation is separated and the line is "de-energized." Hydraulic single-phase overhead reclosers cannot be modified with voltage check relays; therefore, these devices will have to be either replaced with three-phase overhead reclosers, which can be voltage controlled, or relocated beyond the Project location - depending upon the sectionalizing and protection requirements of the distribution circuit. If the Project can be connected to more than one circuit, these revisions may be required on the alternate circuit(s) as well. The Utility will determine relaying and control equipment that needs to be installed to protect its own equipment from out-of-phase reclosing. Installation of this protection will be undertaken by the Utility at the Project Developer's expense. The Utility shall not be liable to the customer with respect to damage(s) to the Project arising as a result of Automatic Reclosing. Single-Phase Sectionalizing The Utility also installs single-phase fuses and/or reclosers on its distribution circuits to increase the reliability of service to its customers. Three-phase generator installations may require replacement of fuses and/or single-phase reclosers with three-phase circuit breakers or circuit reclosers at the Project Developer’s expense. Page 13 Page 14 Synchronous Projects Under/overfrequency relaying and under/overvoltage relaying are required. Each Project must also be equipped with voltage-controlled overcurrent relays to detect faults on the Utility system. The under/overvoltage relaying must be either a three-phase relay or three single-phase relays, and threephase voltage controlled overcurrent relaying must be provided. In order to minimize damage to both Project equipment and to Utility system equipment for loss-of-synchronism (also called out-of-step), and to minimize disruptions to other Utility customers in the area, out-of-step relaying may also be required. The Utility has evaluated and approved a relay for this purpose, which would usually be installed at the same location as the metering, and would isolate the Project from the Utility system. If the Project is connected to an ungrounded distribution system, the secondary winding (Utility side) of the isolation transformer must be connected delta. If the Project is connected to a grounded distribution system, the Project Developer has a choice of the following transformer connections: 1. A grounded-wye - grounded-wye transformer connection is acceptable only if the Project’s single lineto-ground fault current contribution is less than the Project’s three-phase fault current contribution at the PCC. 2. The isolation transformer may be connected for a delta secondary (Utility side) connection with any primary (Project side) connection, or 3. Ungrounded-wye secondary connection with a delta primary connection. If the Project is connected to a grounded distribution system via one of the isolation transformer connections specified above, ground fault detection for Utility faults may be required at the discretion of the Utility, and will consist of a (59N) ground overvoltage relay or (51N) overcurrent relay. The specific application of this relay will depend on the connection of the isolation transformer: 1. If a delta secondary/grounded-wye primary connection is used, the (59N) relay will be connected into the secondary of a set of three-phase VTs, which will be connected grounded-wye primary, with the secondary connected delta with one corner of the delta left open. The (59N) relay will be connected across this open-corner. 2. If an ungrounded-wye secondary/delta primary connection is used, the (59N) relay will be connected into the secondary of a single VT that will be connected from the ungrounded-wye neutral of the isolation transformer to ground. 3. If a grounded-wye - grounded-wye transformer connection is used, a time overcurrent relay must be connected into a CT located on the Utility side isolation transformer neutral connection. In some instances, additional isolation transformer connection options may be available and will be determined by the Utility for the specific system location. The potential connection alternatives will include all alternatives listed above for application on a grounded distribution system, but will add a possible connection of grounded-wye (Utility side), delta (Project side). In the case of this additional isolation transformer connection, Utility system ground fault detection will take the form of a time overcurrent relay connected into a current transformer located in the Utility-side transformer neutral. This time overcurrent relay must have a very-inverse time characteristic. For a sample One-Line Diagram of this type of facility including the various methods of (59N) application, see Appendix E. Page 15 Induction Projects Three-phase under/overvoltage relays and three-phase under/overfrequency relays must be provided. Utility-grade relays are required. If the Project is connected to an ungrounded distribution system, the secondary winding (Utility side) of the isolation transformer must be connected delta. If the Project is connected to a grounded distribution system, the Project Developer has a choice of the following transformer connections: 1. The isolation transformer may be connected for a delta secondary (Utility side) connection with any primary (Project side) connection, or 2. The isolation transformer may be connected for an ungrounded-wye secondary connection with a delta primary connection, or 3. The isolation transformer may be connected for a grounded-wye - grounded-wye connection. If the Project is connected to a grounded distribution system via one of the isolation transformer connections specified above, ground fault detection for Utility faults must be provided. The specific application of this relay will depend on the connection of the isolation transformer: 1. If a delta secondary/grounded-wye primary connection is used, a (59N) ground overvoltage relay will be connected into the secondary of a set of three-phase VTs, which will be connected grounded-wye primary, with the secondary connected delta with one corner of the delta left open. The (59N) relay will be connected across this open-corner. 2. If an ungrounded-wye secondary/delta primary connection is used, a (59N) ground overvoltage relay will be connected into the secondary of a single VT that will be connected from the ungrounded-wye neutral of the isolation transformer to ground. 3. If a grounded-wye - grounded-wye connection is used, a time overcurrent relay must be connected into a CT located on the Utility side isolation transformer neutral connection. Protection must be provided for internal faults in the isolating transformer. In cases where it can be shown that self excitation of the induction generator cannot occur when isolated from the Utility, the Utility may waive the requirement that the Project Developer provide protection for Utility system ground faults. In all cases, ground fault detection for Utility faults may be required at the discretion of the Utility. For a sample One-Line Diagram of this type of facility, see Appendix F. Page 16 Inverter Projects Under/overfrequency relaying and under/overvoltage relaying are required. The under/overvoltage relaying must be either a three-phase relay or three single-phase relays. The isolation transformer (without generation on-line) must be incapable of producing ground fault current to the Utility system; any connection except delta primary (Project side), grounded-wye secondary (Utility side) is acceptable. The isolation transformer must be protected for internal faults; fuses are acceptable. If the inverter has passed a certified anti-island test, the Utility may waive the requirement that the Project Developer provide protection for the Utility system ground faults. In all cases, ground fault detection for Utility faults may be required at the discretion of the Utility. If required, type and methodology will be the same as Synchronous Projects listed above. For a sample One-Line Diagram of this type of facility, see Appendix G. Page 17 Dynamometer Projects No isolation transformer is required between the generator and the secondary distribution connection. If an isolation transformer is used for three-phase installations, any isolation transformer connection is acceptable except grounded-wye (Utility side), delta (Project side). Protection must be provided for internal faults in the isolating transformer; fuses are acceptable. If an inverter is used and has passed a certified anti-island test, the Utility may waive the requirement that the Project Developer provide protection for the Utility system ground faults. General Under/overfrequency relaying and under/overvoltage relaying are required. The under/overvoltage relaying must be either a three-phase relay or three single-phase relays. The isolation transformer (without generation on-line) must be incapable of producing ground fault current to the Utility system; any connection except delta primary (Project side), grounded-wye secondary (Utility side) is acceptable. Protection must be provided for internal faults in the isolating transformer; fuses are acceptable. If an inverter is utilized and has passed a certified anti-island test, the Utility may waive the requirement that the Project Developer provide protection for Utility system ground faults. In all cases, ground fault detection for Utility faults may be required at the discretion of the Utility. If required, type and methodology will be the same as Synchronous Projects listed above. Relay Setting Criteria The relay settings as detailed in this section will apply in the vast majority of applications. The Utility will issue relay settings for each individual project that will address the settings for these protective functions. All voltages will be adjusted for the specific VT ratio, and all currents will be adjusted for the specific CT ratio. Undervoltage Relays The undervoltage relays will normally be set to trip at 88% of the nominal primary voltage at the relay location, and must reset from a trip condition if the voltage increases to 90% of the nominal primary voltage at the relay location. In order to accommodate variations in this criteria, the trip point of the relays shall be adjustable over a range of 70% of the nominal voltage to 90% of the nominal voltage. The trip time shall not exceed 1.0 seconds at 90% of the relay setting. Overvoltage Relays Two steps of overvoltage relaying are required. For the first overvoltage set point, the overvoltage relays will normally be set to trip at 107% of the nominal primary voltage at the relay location, and must reset from a trip condition if the voltage decreases to 105% of the nominal primary voltage at the relay location. In order to accommodate variations in this criteria, the trip point of the relays shall be adjustable over a range of 105% of the nominal voltage to 120% of the nominal voltage. The trip time shall not exceed 1.0 seconds at 110% of the relay setting. For the second overvoltage set point, the overvoltage relays will normally be set to trip at 120% of the nominal primary voltage at the relay location, and must reset from a trip condition if the voltage decreases to 118% of the nominal primary voltage at the relay location. In order to accommodate variations in this criteria, the trip point of the relays shall be adjustable over a range of 115% of the nominal voltage to 140% of the nominal voltage. The trip time shall be instantaneous (relay operating time not to exceed 0.02 seconds at 110% of the trip setting). Underfrequency Relays The Underfrequency relay will normally be set for a trip point of 58.5 Hz, and must trip within 0.2 seconds. Relays with an inverse time characteristic (where the trip time changes with respect to the applied Page 18 frequency) are not acceptable. These relays must respond reliably for applied source voltages as low as 70% of the nominal voltage. Overfrequency Relays The overfrequency relay will normally be set for a trip point of 60.5 Hz, and must trip within 0.2 seconds. Relays with an inverse time characteristic are not acceptable. These relays must respond reliably for applied source voltages as low as 70% of the nominal voltage. 51V Relays – Voltage Controlled Overcurrent Relays For synchronous generator applications, the (51V) relays must be set to detect any phase faults that may occur between the generator and the nearest three-phase fault clearing device on the Utility system. Since these faults may take up to 1-second to detect and isolate, the appropriate saturated direct-axis reactance of the generator will be used depending on its time constants. The settings of this device will consider the relay manufacturer’s recommended practice for the type of generator and prime mover (mechanical energy source), and will be determined by the Utility for the specific system application. 59N Relay – Ground Fault Detection This relay will be applied to detect ground faults on the Utility system when the Project is connected to a grounded Utility system via an ungrounded transformer winding. This relay will be set for a 10% shift in the apparent power system neutral. For an ungrounded-wye transformer winding with a single 120 V secondary VT, the setting will usually be 12 Volts. For a delta transformer winding with broken delta 120 V secondary VTs, the setting will usually be 20 Volts. The time delay will normally be 1 second. 51N Relay – Ground Fault Detection This relay will be applied to detect ground faults on the Utility system when the Project is connected to a grounded Utility system via a grounded-wye transformer winding, and will be connected into a CT in the transformer neutral connection. This relay will be set to detect faults on the directly connected Utility system, and the timing will be set to comply with Utility practice for overcurrent relay coordination. The CT ratio and specific relay setting will be determined via a fault study performed by the Utility. 32 Relay – Reverse Power The reverse power relay must be selected such that it can detect a power flow into the Utility system of a small fraction of the overall generator capacity. The relay will normally be set near its minimum (most sensitive) setting, and will trip after a 1 second time delay. The delay will avoid unnecessary tripping for momentary conditions. Maintenance and Testing The Utility reserves the right to test the relaying and control equipment that involves protection of the Utility electric system whenever the Utility determines a reasonable need for such testing exists. The Project Developer is solely responsible for conducting proper periodic maintenance on the generating equipment and its associated control, protective equipment, interrupting devices, and main Isolation Device, per manufacturer recommendations. The Project Developer is responsible for the periodic scheduled maintenance on those relays, interrupting devices, control schemes, and batteries that involve the protection of the Utility electric system. A periodic maintenance program is to be established to test these relays at least every 2 years. This maintenance testing must be witnessed by the Utility. Each routine maintenance check of the relaying equipment shall include both an exact calibration check and an actual trip of the circuit breaker or contactor from the device being tested. For each test, a report shall be submitted to the Utility indicating the results of the tests made and the "as found" and "as left" relay calibration values. Visually setting, without verification, a calibration dial or tap is not considered an adequate relay calibration check. Page 19 The Project Developer is responsible for maintaining written reports for the above tests for a period of four years. These written reports shall be made available to the Utility upon request. Telemetry and Disturbance Monitoring Requirements Telemetry and disturbance monitoring is required in all cases for Projects that will operate in the Flowback Mode and have the capability to supply aggregate generation of 550 kW or more to the Utility. For generation facilities that will operate in the Non Flow-back Mode, the requirement for telemetry will be determined on a case-by-case basis as part of the Interconnection Study. Telemetry enables the Utility to operate the electric system safely and reliably under both normal and emergency conditions. The Utility measures its internal load plus losses (generation) on a real time basis via an extensive telemetry system. This system sums all energy flowing into the Utility electric system from Projects interconnected to the system and from interconnections with other utilities. During system disturbances when portions of the electrical systems are out of service, it is essential to know if a generator is on line or off line to determine the proper action to correct the problem. Time saved during restoration activities translates to fewer outages and outages of shorter duration for the Utility’s customers. The Utility evaluates the performance of the overall protective system for all faults on the electric system. It is critical that sufficient monitoring of the protective system is in place to determine its response. It is preferable to deploy disturbance monitoring into all Projects, but it can be expensive to deploy. Therefore, disturbance monitoring is required only for installations that already require telemetry. The Project Developer shall provide a suitable indoor location, approved by the Utility, for the Utility’s owned, operated, and maintained Remote Terminal Unit (RTU). The location must be equipped with a 48 V or 125 V DC power supply. The Project Developer must provide the necessary phone (or alternate) and data circuits, and install a telephone (or alternate) backboard for connections to the Utility RTU and metering equipment. All phone circuits must be properly protected as detailed in IEEE Std. 487. See “Typical Meter and RTU Installation Where Telemetry is Required” in the Generator Interconnection Supplement. When telemetry is required, the following values will be telemetered: 1. Real and reactive power flow at the PCC. 2. Voltage at the PCC. 3. The status (normal/fail) of protective relay Communication Channels. A status indication of "FAIL" indicates the Communication Channel used for relaying (i.e. transfer trip) is unable to perform its protective function. 4. The status (open/closed) of the main isolating breaker and each generating unit breaker (if the Project is composed of multiple units, a single logical (OR) status of the individual generator breaker states, indicating all generator breakers are open or any one or more generator breakers are closed, is permissible). A closed status would be indicated if any individual generator is on line. For disturbance monitoring, the RTU will be equipped with “sequence of events” recording. The Project Developer shall provide, wired to a terminal block near the RTU panel, sufficient connections to separately monitor the following: Page 20 1. An output contact of an instantaneous relay to act as a ground fault detector for faults on the Utility electric system. This relay shall be connected into the same sensing source as the ground fault protective relay required by the Utility. 2. Each and every trip of an interconnection isolation device, which is initiated by any of the generator interconnection relaying schemes required by the Utility. 3. Each and every trip of an interconnection isolation device, which is initiated by any of the protective systems for the generator. 4. Each and every trip or opening of an interconnecting isolation device, which is initiated by any other manual or electrical means. 5. A contact indicating the position of the Project’s primary-side main breaker. 6. A contact indicating operation of the over/undervoltage relays. 7. A contact indicating operation of the under/overfrequency relay or the Utility’s ground fault relay. 8. A contact indicating operation of the Project provided transformer bank relaying. 9. A contact indicating operation of any of the (51V) relaying. 10. A contact indicating the position of the high-side fault-clearing device. 11. A contact indicating the position of the reverse power relay, if said relay is required by the Utility. 12. The following individual contacts from each individual Direct Transfer Trip receiver, required by the Utility: i. Loss-of-guard (LOG) alarm ii. Receive-trip relay (RTX). iii. Lockout relay. If any of the functions indicated in items 2-4, 6, 7, 9, or 11 are combined into a multi-functional device, either: 1. Each of those functions must be monitored independently on the RTU, or 2. Provisions acceptable to the Utility must be provided to interrogate the multi-functional device such that the operation of the individual functions may be evaluated separately. Telemetry, when required, will be provided by the Utility at the Project Developer's expense. In addition to other telemetry costs, a one-time charge will be assessed to the Project Developer for equipment and software installed at the Utility’s System Control Center to process the data signals. Miscellaneous Operational Requirements Miscellaneous requirements include synchronizing equipment for Parallel Operation, reactive requirements, standby power considerations, and system stability limitations. Operating in Parallel The Project Developer will be solely responsible for the required synchronizing equipment and for properly synchronizing the Project with the Utility electric system. Page 21 Voltage fluctuation at the PCC during synchronizing shall be limited per IEEE std. 1547.. The Project Developer will notify the Utility prior to synchronizing to and prior to scheduled disconnection from the electric system. These requirements are directly concerned with the actual operation of the Project with the Utility: • The Project may not commence parallel operation until approval has been given by the Utility. The completed installation is subject to inspection by the Utility prior to approval. Preceding this inspection, all contractual agreements must be executed by the Project Developer. • The Project must be designed to prevent the Project from energizing into a de-energized Utility line. The Project’s circuit breaker or contactor must be blocked from closing in on a de-energized circuit. • The Project shall discontinue parallel operation with a particular service and perform necessary switching when requested by the Utility for any of the following reasons: 1. When public safety is being jeopardized. 2. During voltage or loading problems, system emergencies, or when abnormal sectionalizing or circuit configuration occurs on the Utility system. 3. During scheduled shutdowns of Utility equipment that are necessary to facilitate maintenance or repairs. Such scheduled shutdowns shall be coordinated with the Project. 4. In the event there is demonstrated electrical interference (i.e. Voltage Flicker, Harmonic Distortion, etc.) to the Utility’s customers, suspected to be caused by the Project, and such interference exceeds then current system standards, the Utility reserves the right, at the Utility’s initial expense, to install special test equipment as may be required to perform a disturbance analysis and monitor the operation and control of the Project to evaluate the quality of power produced by the Project. In the event that no standards exist, then the applicable tariffs and rules governing electric service shall apply. If the Project is proven to be the source of the interference, and that interference exceeds the Utility’s standards or the generally accepted industry standards, then it shall be the responsibility of the Project Developer to eliminate the interference problem and to reimburse the Utility for the costs of the disturbance analysis, excluding the cost of the meters or other special test equipment. 5. When either the Project or its associated synchronizing and protective equipment is demonstrated by the Utility to be improperly maintained, so as to present a hazard to the Utility system or its customers. 6. Whenever the Project is operating isolated with other Utility customers, for whatever reason. 7. Whenever a loss of communication channel alarm is received from a location where a communication channel has been installed for the protection of the Utility system. 8. Whenever the Utility notifies the Project Developer in writing of a claimed non-safety related violation of the Interconnection Agreement and the Project Developer fails to remedy the claimed violation within ten working days of notification, unless within that time either the Project Developer files a complaint with the MPSC seeking resolution of the dispute or the Project Developer and Utility agree in writing to a different procedure. Page 22 If the Project has shown an unsatisfactory response to requests to separate the generation from the Utility system, the Utility reserves the right to disconnect the Project from parallel operation with the Utility electric system until all operational issues are satisfactorily resolved. Reactive Power Control Synchronous generators that will operate in the Flow-back Mode must be dynamically capable of providing 0.90 power factor lagging (delivering reactive power to the Utility) and 0.95 power factor leading (absorbing reactive power from the Utility) at the Point of Receipt. The Point of Receipt is the location where the Utility accepts delivery of the output of the Project. The Point of Receipt can be the physical location of the billing meters or a location where the billing meters are not located, but adjusted for line and transformation losses. Induction and Inverter Projects that will operate in the Flow-Back Mode must provide for their own reactive needs (steady state unity power factor at the Point of Receipt). To obtain unity power factor, the Induction or Inverter Project can: 1. Install a switchable VAR supply source to maintain unity power factor at the Point of Receipt; or 2. Provide the Utility with funds to install a VAR supply source equivalent to that required for the Project to attain unity power factor at the Point of Receipt at full output. There are no interconnection reactive power capability requirements for Synchronous, Induction, and Inverter-Type Projects that will operate in the Non-Flow-Back Mode. The Utility’s existing rate schedules, incorporated herein by reference, contain power factor adjustments based on the power factor of the metered load at these facilities. Standby Power Standby power will be provided under the terms of an approved rate set forth in the Utility’s Standard Rules and Regulations. The Project Developer should be aware that to qualify for Standby Rates, a separate meter must be installed at the generator. If outside of the Utility’s franchise area, it will be the Project Developer’s responsibility to arrange contractually and technically for the supply of its facility’s standby, maintenance, and any supplemental power needs. System Stability and Site Limitations The Stiffness Ratio is the combined three-phase short circuit capability of the Project and the Utility divided by the short circuit capability of the Project measured at the PCC. A stability study may be required for Projects with a Stiffness Ratio of less than 40. Five times the generator rated kVA will be used as a proxy for short circuit current contribution for induction generators. For synchronous Projects, with a Stiffness Ratio of less than 40, the Utility requires special generator trip schemes or loss of synchronism (out-of-step) relay protection. If the apparent voltage flicker from a loss-of-synchronism condition exceeds 5%, an out-of-step relay will be required. This type of protection is typically applied at the PCC and trips the entire Project off-line, if instability is detected, to protect the Utility electric system and its customers. If the Project Developer chooses not to provide for mitigation of unacceptable voltage flicker (above five percent), the Utility may disallow the interconnection of the Project or require a new dedicated interconnection at the Project Developer’s expense. A stability study may be required for induction Projects and wind turbine facilities to determine the impacts of sudden variation in real or reactive power output of the generators. The above Stiffness Ratio criteria will be applied to determine if a stability study is required, with a proxy for the generator short circuit current calculated from five times the generator rated MVA. The Project Developer is responsible for evaluating the consequences of unstable generator operation or voltage transients on the Project equipment and determining, designing, and applying any relaying which Page 23 may be necessary to protect that equipment. This type of protection is typically applied on individual generators to protect the Project facilities. The Utility will determine if operation of the Project will create objectionable voltage flicker and/or disturbances to other Utility customers and develop any required mitigation measures at the Project Developer’s expense. Revenue Metering Requirements The Utility will own, operate, and maintain the billing metering equipment at the Project Developer’s expense. The billing metering will meter both real and reactive interconnection flows between the Project and the Utility electric system. Where applicable, separate metering of station power may be required to accurately meter the Project load when the generator is off-line. Special billing metering will be required for Projects operating in the Flow-back Mode. If telemetering is required, the billing metering will be included as part of the telemetering installation. The Project Developer will be required to provide, at no cost to the Utility, communication circuit line, to allow remote access to the billing meter by the Utility. This circuit shall be terminated within ten feet of the meter involved. Ground fault protection for this circuit may be required, and coordination with the telephone company and all associated costs will be by Project Developer. The Project Developer shall provide a suitable indoor location, approved by the Utility, for the Utility’s owned, operated, and maintained billing metering. The Project Developer shall provide authorized employees and agents of the Utility access to the premises at all times to install, turn on, disconnect, inspect, test, read, repair, or remove the metering equipment. The Project Developer may, at its option, have a representative witness this work. The metering installations for Flow-back operation shall be constructed in accordance with the practices, which normally apply to the construction of metering installations for commercial, industrial, or other customers with demand recording equipment. At a minimum three meters will be required; two at the PCC, one import and one export and one at the generator. The Utility shall supply to the Project Developer all required metering equipment and the standard detailed specifications and requirements relating to the location, construction, and access of the metering installation and will provide consultation pertaining to the meter installation as required. The Utility will endeavor to coordinate the delivery of these materials with the Project Developer’s installation schedule during normal scheduled business hours. The Project Developer shall provide a mounting surface for the meters, recorders, connection cabinets, a housing for the instrument transformers, a conduit for the conductors between the instrument transformer secondary windings and the meter connection cabinets, and a conduit for the communication links, if required. All of this equipment must meet the Utility’s specifications and requirements. The responsibility for the installation of the equipment is shared between the Utility and the Project Developer, with the Project Developer generally installing all of the equipment on its side of the Point of Interconnection, including instrument transformers, cabinets, conduits, and mounting surfaces. The Utility, or its agents, shall install the meters, recorders, and communication links. The Utility will endeavor to coordinate the installation of these items with the Project Developer’s schedule. Communication Circuits The Project Developer is responsible for ordering and acquiring the telephone circuit required for the Project Interconnection. The Project Developer will assume all installation, operating, and maintenance costs associated with the telephone circuits, including the monthly charges for the telephone lines and any rental equipment required by the local telephone provider. However, at the Utility’s discretion, the Page 24 Utility may select an alternative communication method, such as wireless communications. Regardless of the method, the Project Developer will be responsible for all costs associated with the material, installation and maintenance, whereas the Utility will be responsible to define the specific communication requirements. The Utility will cooperate and provide Utility information necessary for proper installation of the telephone (or alternate) circuits upon written request. A dedicated communication circuit is required for access to the billing meter by the Utility. When DTT is required, a modular RJ-11 jack must also be installed within six feet of the billing metering equipment, to allow the Utility to use this circuit for voice communication with personnel performing master station checkout of the RTU. This dial-up voice-grade circuit shall be a local telephone company provided business measured line without dial-in or dial-out call restrictions. If DTT is required, a separate dedicated 4-wire, Class A, Data Circuit must be installed and protected as specified by the local telephone Utility for each DTT receiver and for the RTU. The circuit must be installed in rigid metallic conduit from the RTU and each DTT receiver to the point of connection to the telephone Utility equipment. Wall space must be provided for adjacent mounting next to the telephone board, of the billing metering panel and a telemetry enclosure. The billing metering panel is typically 60 inches high by 48 inches wide and the telemetry enclosure is typically 24 inches high by 24 inches wide. A clear space of 4.5 feet in front of this equipment is required to permit maintenance and testing. A review of each installation shall be made to determine the location and space requirements most agreeable to the Utility and the Project Developer. Page 25 Appendix A Interconnection Process Flow Diagram Page 26 Appendix B Category 4 Interconnection Table – Applicant Costs Distribution Distribution Application Engineering Review Review Study Upgrades $250 Propose fixed Propose fixed Actual or Max Fee Fee Approved by Commission* Testing & Inspection Actual or Max Approved by Commission* * Costs incurred by affected systems are born directly by the applicant and are not included in the table. Application Complete Category 4 10 days Interconnection Timeline – Working Days Application Engineering Distribution Distribution Review Study Upgrades Study Completion Completion 10 days 25 days*** 45 days Mutually **,*** Agreed*** Testing & Inspection 10 to notify of scheduled visit ** Unless a different time period is mutually agreed upon *** Timeline impacts due to affected system studies & Upgrades are not included in the quoted timeframe Page 27 Appendix C - Procedure Definitions Alternative electric supplier ( AES ): as defined in section 10g of 2000 PA 141, MCL 460.10g Alternative electric supplier net metering program plan: document supplied by an AES that provides detailed information to an applicant about the AES’s net metering program. Applicant: Legally responsible person applying to an electric utility to interconnect a project with the electric utility’s distribution system or a person applying for a net metering program. An applicant shall be a customer of an electric utility and may be a customer or an AES. Application Review: Review by the electric utility of the completed application for interconnection to determine if an engineering review is required. Area Network: A location on the distribution system served by multiple transformers interconnected in an electrical network circuit. Category 1: An inverter based project of 20kW or less that uses equipment certified by a nationally recognized testing laboratory to IEEE 1547.1 testing standards and in compliance with UL 1741 scope 1.1A. Category 2: A project of greater than 20 kW and not more than 150 kW. Category 3: A project of greater than 150 kW and not more than 550 kW. Category 4: A project of greater than 550 kW and not more than 2 MW. Category 5: A project of greater than 2 MW. Certified equipment: A generating, control, or protective system that has been certified as meeting acceptable safety and reliability standards by a nationally recognized testing laboratory in conformance with UL 1741. Commission: The Michigan Public Service Commission Commissioning test: The procedure, performed in compliance with IEEE 1547.1, for documenting and verifying the performance of a project to confirm that the project operates in conformity with its design specifications. Page 28 Customer: A person who receives electric service from an electric utility’s distribution system or a person who participates in a net metering program through an AES or electric utility. Customer-generator: A person that uses a project on-site that is interconnected to an electric utility distribution system. Distribution system: The structures, equipment, and facilities operated by an electric utility to deliver electricity to end users, not including transmission facilities that are subject to the jurisdiction of the federal energy regulatory commission. Distribution system study: A study to determine if a distribution system upgrade is needed to accommodate the proposed project and to determine the cost of an upgrade if required. Electric provider: Any person or entity whose rates are regulated by the commission for selling electricity to retail customers in the state. Electric utility: Term as defined in section 2 of 1995 PA 30, MCL 460.562. Eligible electric generator: A methane digester or renewable energy system with a generation capacity limited to the customer’s electrical need and that does not exceed the following: • 150 kW of aggregate generation at a single site for a renewable energy system • 550 kW of aggregate generation at a single site for a methane digester Engineering Review: A study to determine the suitability of the interconnection equipment including any safety and reliability complications arising from equipment saturation, multiple technologies, and proximity to synchronous motor loads. Full retail rate: The power supply and distribution components of the cost of electric service. Full retail rate does not include system access charge, service charge, or other charge that is assessed on a per meter basis. IEEE: Institute of Electrical and Electronics Engineers IEEE 1547: IEEE “Standard for Interconnecting Distributed Resources with Electric Power Systems” IEEE 1547.1: IEEE “Standard Conformance Test Procedures for Equipment Interconnecting Distributed Resources with Electric Power Systems” Page 29 Interconnection: The process undertaken by an electric utility to construct the electrical facilities necessary to connect a project with a distribution system so that parallel operation can occur. Interconnection procedures: The requirements that govern project interconnection adopted by each electric utility and approved by the commission. kW: kilowatt kWh: kilowatt-hours Material modification: A modification that changes the maximum electrical output of a project or changes the interconnection equipment including the following: • • Changing from certified to non certified equipment Replacing a component with a component of different functionality or UL listing. Methane digester: 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. Modified net metering: A 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 utility distribution system during a billing period or time-of-use pricing period. MW: megawatt Nationally recognized testing laboratory: Any testing laboratory recognized by the accreditation program of the U.S. department of labor occupational safety and health administration. Parallel operation: The operation, for longer than 100 milliseconds, of a project while connected to the energized distribution system. Project: Electrical generating equipment and associated facilities that are not owned or operated by an electric utility. Renewable energy credit ( REC ): A credit granted pursuant to the commission’s renewable energy credit certification and tracking program in section 41 of 2008 PA 295, MCL 460.1041. Renewable energy resource: Term as defined in section 11(i) of 2008 PA 295, MCL 460.1011(i) Page 30 Renewable energy system: Term as defined in section 11(k) of 2008 PA 295, MCL 460.1011(k). Spot network: A location on the distribution system that uses 2 or more inter-tied transformers to supply an electrical network circuit. True net metering: A utility billing method that applies the full retail rate to the net of the bidirectional flow of kW hors across the customer interconnection with the utility distribution system, during a billing period or time-of-use pricing period. UL: Underwriters Laboratory UL 1741: The “Standard for Inverters, Converters, Controllers and Interconnection System Equipment for Use With Distributed Energy Resources.” UL 1741 scope 1.1A: Paragraph 1.1A contained in chapter 1, section 1 of UL 1741. Uniform interconnection application form: The standard application forms, approved by the commission under R 460.615 and used for category 1, category 2, category 3, category 4, and category 5 projects. Uniform interconnection agreement: The standard interconnection agreements approved by the commission under R 460.615 and used for category 1, category 2, category 3, category 4, and category 5 projects. Uniform net metering application: The net metering application form approved by the commission under R 460.642 and used by all electric utilities and AES. Working days: Days excluding Saturdays, Sundays, and other days when the offices of the electric utility are not open to the public. Page 31 Appendix D – Site Plan Page 32 Appendix E – Sample One-Line Synchronous (not required for flow-back) Page 33 Instructions: Attach data sheets as required. Indicate in the table below the page number of the attached data (manufacturer’s data where appropriate) on which the requested information is provided. Provide one table for each unique generator. Synchronous Electric Generator(s) at the Project Item No 1 2 3 4 5 6 7 8 9 10 Data Value Generator No _____ Data Description Generator Type (synchronous or induction) Generator Nameplate Voltage Generator Nameplate Watts or Volt-Amperes Generator Nameplate Power Factor (pf) Direct axis reactance (saturated) Direct axis transient reactance (saturated) Direct axis sub-transient reactance (saturated) Short Circuit Current contribution from generator at the Point of Common Coupling (single-phase and three-phase National Recognized Testing Laboratory Certification Written Commissioning Test Procedure Page 34 Attached Page No Appendix F – Sample One-Line Induction (not required for flow-back) Page 35 Instructions: Attach data sheets as required. Indicate in the table below the page number of the attached data (manufacturer’s data where appropriate) on which the requested information is provided. Provide one table for each unique generator. Item No 1 2 3 4 5 6 7 Induction Electric Generator(s) at the Project: Generator No _____ Data Attached Description Page No Generator Type (Inverter) Generator Nameplate Voltage Generator Nameplate Watts or Volt-Amperes Generator Nameplate Power Factor (pf) Short Circuit Current contribution from generator at the Point of Common Coupling (single-phase and three-phase) National Recognized Testing Laboratory Certification Written Commissioning Test Procedure Page 36 Appendix G – Sample One-Line Inverter ONE-LINE REPRESENTATION TYPICAL ISOLATION AND FAULT PROTECTION FOR INVERTER GENERATOR INSTALLATIONS 32 (not required for flow-back) 59 A) Page 37 Instructions: Attach data sheets as required. Indicate in the table below the page number of the attached data (manufacturer’s data where appropriate) on which the requested information is provided. Provide one table for each unique generator. Item No 1 2 3 4 5 6 7 Inverter Electric Generator(s) at the Project: Generator No _____ Data Attached Description Page No Generator Type (Inverter) Generator Nameplate Voltage Generator Nameplate Watts or Volt-Amperes Generator Nameplate Power Factor (pf) Short Circuit Current contribution from generator at the Point of Common Coupling (single-phase and three-phase) National Recognized Testing Laboratory Certification Written Commissioning Test Procedure Page 38 Appendix H Sample One Line Diagram for Non-Flow Back projects ONE-LINE DIAGRAM & CONTROL SCHEMATIC TYPICAL ISOLATION PROECTION FOR NON FLOW-BACK INSTALLATIONS Distribution Circuit Page 39 Appendix I Sample One Line Diagram for Flow-Back projects Distribution Circuit Page 40 Page 41 MICHIGA ELECTRIC UTILITY Generator Interconnection Requirements Category 5 Projects with Aggregate Generator Output Greater Than 2 MW August 3, 2009 Introduction Category 5 – Greater than 2MW This Generator Interconnection Procedure document outlines the process & requirements used to install or modify generation projects with aggregate generator output capacity ratings greater than 2MW designed to operate in parallel with the Utility electric system. Technical requirements (data, equipment, relaying, telemetry, metering) are defined according to type of generation, location of the interconnection, and mode of operation (Flow-back or Non-Flowback). The process is designed to provide an expeditious interconnection to the Utility electric system that is both safe and reliable. This document has been filed with the Michigan Public Service Commission (MPSC) and complies with rules established for the interconnection of parallel generation to the Utility electric system in the MPSC Order in Case No. U-15787 The term “Project” will be used throughout this document to refer to electric generating equipment and associated facilities that are not owned or operated by an electric utility. The term “Project Developer” means a person that owns, operates, or proposes to construct, own, or operate, a Project. This document does not address other Project concerns such as environmental permitting, local ordinances, or fuel supply. Nor does it address agreements that may be required with the Utility and/or the transmission provider, or state or federal licensing, to market the Project’s energy. An interconnection request does not constitute a request for transmission service. It may be possible for the Utility to adjust requirements stated herein on a case-by-case basis. The review necessary to support such adjustments, however, may be extensive and may exceed the costs and timeframes established by the MPSC and addressed in these requirements. Therefore, if requested by the Project Developer, adjustments to these requirements will only be considered if the Project Developer agrees in advance to compensate the Utility for the added costs of the necessary additional reviews and to also allow the Utility additional time for the additional reviews. The Utility may apply for a technical waiver from one or more provisions of these rules and the MPSC may grant a waiver upon a showing of good cause. Table of Contents Interconnection Process .....................................................................................................................5 Customer Project Planning Phase ............................................................................................................................. 5 Application & Queue Assignment ............................................................................................................................ 5 Application Review................................................................................................................................................... 5 Engineering Review .................................................................................................................................................. 5 Distribution Study ..................................................................................................................................................... 6 Customer Install & POA ........................................................................................................................................... 6 Meter install, Testing, & Inspection .......................................................................................................................... 6 Cat 5 -Installation and Design Approval ................................................................................................................... 7 Operation in Parallel ................................................................................................................................................. 8 Operational Provisions ......................................................................................................................8 Disconnection ........................................................................................................................................................... 8 Maintenance and Testing .......................................................................................................................................... 8 TECHNICAL REQUIREMENTS ...................................................................................................... 9 Major Component Design Requirements ...........................................................................................9 Data ........................................................................................................................................................................... 9 Isolating Transformer(s) ........................................................................................................................................... 9 Isolation Device ...................................................................................................................................................... 10 Interconnection Lines .............................................................................................................................................. 11 Termination Structure ............................................................................................................................................. 11 Relaying Design Requirements ..................................................................................................11 Protective Relaying General Considerations ........................................................................................................... 11 Momentary Paralleling ............................................................................................................................................ 12 Instrument Transformer Requirements ................................................................................................................... 12 Direct Transfer Trip (DTT) ..................................................................................................................................... 12 Reverse Power Relaying for Non Flow-back .......................................................................................................... 13 Automatic Reclosing ............................................................................................................................................... 13 Single-Phase Sectionalizing .................................................................................................................................... 14 Synchronous Projects .................................................................................................................15 Induction Projects ........................................................................................................................17 For a sample One-Line Diagram of this type of facility, see Appendix F............................................................... 17 Inverter Projects ...................................................................................................................................................... 18 Dynamometer Projects ................................................................................................................19 General ..........................................................................................................................................19 Relay Setting Criteria .............................................................................................................................................. 20 Maintenance and Testing ........................................................................................................................................ 22 Installation and Design Approval............................................................................................................................ 22 Telemetry and Disturbance Monitoring Requirements ........................................................................................... 23 Miscellaneous Operational Requirements ........................................................................................25 Operating in Parallel ............................................................................................................................................... 25 Reactive Power Control .......................................................................................................................................... 27 Standby Power ........................................................................................................................................................ 28 System Stability and Site Limitations ..................................................................................................................... 28 Revenue Metering Requirements .....................................................................................................28 Communication Circuits .................................................................................................................29 Appendix A .....................................................................................................................................31 Interconnection Process Flow Diagram .................................................................................................................. 31 Appendix B .....................................................................................................................................32 Interconnection Table – Applicant Costs ................................................................................................................ 32 Interconnection Timeline – Working Days ............................................................................................................. 32 Appendix C ....................................................................................................................................33 Procedure Definitions ............................................................................................................................................. 33 Appendix D – Site Plan ................................................................................................................37 Appendix E – Sample One-line Synchronous ...........................................................................38 Appendix F – Sample One-Line Induction .................................................................................40 Appendix G – Sample One-Line Inverter....................................................................................42 Appendix H ....................................................................................................................................44 Sample One Line Diagram for Non-Flow Back projects ........................................................................................ 44 Appendix I .....................................................................................................................................45 Sample One Line Diagram for Flow-Back projects ................................................................................................ 45 Interconnection Procedures Interconnection Process Customer Project Planning Phase An applicant may contact the utility before or during the application process regarding the project. The utility can be reached by phone, e-mail, or by the external website to access information, forms, rates, and agreements. A utility will provide up to 2 hours of technical consultation at no additional cost to the applicant. Consultation may be limited to providing information concerning the utility system operating characteristics and location of system components. Application & Queue Assignment The Project Developer must first submit a “Combined Category 5” application to the Utility. A separate application is required for each Project or Project site. The blank Interconnection Application can be found on the Utility’s customer generation’s website . A complete submittal of required interconnection data and Interconnection filing fee per the table in Appendix B. The Utility will notify the Project Developer within 10 business days of receipt of an Interconnection Application. If any portion of the Interconnection Application, data submittal (a site plan and the one-line diagrams), or filing fee is incomplete and/or missing, the Utility will return the application, data, and filing fee to the Project developer with explanations. Project Developer will need to resubmit the application with all the missing items. Once the Utility has accepted the application, a queue number will be assigned to the Project. The utility will then advise the applicant that the application is complete and provide the customer with the queue assignment. Application Review The Utility shall review the complete application for interconnection to determine if an engineering review is required. The Utility will notify the Project Developer within 10 business days of receipt of complete application and if an engineering review is required. If an engineering review is required, the Utility will supply the applicant with the “request for engineering study - acceptance letter” and identify the required engineering study fee. The applicant shall provide any changes or updates to the application before the engineering review begins. If an engineering review is not required, the project will advance to the Customer Install & POA phase of the process. The Utility may request additional data be submitted as necessary during the review phase to clarify the operation of the Project. Engineering Review Upon the Utility receiving an executed “request for engineering study – acceptance letter” and engineering study fee, the Utility shall study the project to determine the suitability of the interconnection equipment including safety and reliability complications arising from equipment saturation, multiple technologies, and proximity to synchronous motor loads. Category 4 & 5 projects may involve affected system studies which are performed by the affected system owner. Category 4 & 5 projects affected system study fees and timeline are the responsibility of the applicant. The electric utility shall provide in writing the results of the engineering study including identifying major components affected a non-binding estimate ( as practically possible) for interconnection, within the time indicated in the Interconnection Timeline Table. If the engineering review indicates that a distribution study is necessary, the Utility will supply the applicant with the “request for distribution study - acceptance letter” and identify the required distribution study fee. If an engineering review determines that a distribution study is not required, the project will advance to the Customer Install & POA. Distribution Study Upon the Utility receiving an executed “request for distribution study – acceptance letter” and distribution study fee, the Utility shall study the project to determine if a distribution system upgrade is needed to accommodate the proposed project and determine the cost of an upgrade if required. The electric utility shall provide in writing the results of the distribution study including estimated completion timeframe and cost estimate +/- 10% for the upgrades, if required, to the applicant, within the timeframe allowed by the Interconnection Timeline Table. If a distribution study determines that a distribution upgrades are not required, the project will advance to the Customer Install & POA phase of the process. Customer Install & POA The applicant shall notify the electric utility when an installation and any required local code inspection and approval is complete. The Parallel Operating Agreement for different rates can be found from the Utility’s Customer Generation website. The Parallel Operating Agreement will cover matters customarily addressed in such agreements in accordance with Good Utility Practice, including, without limitation, construction of facilities, system operation, interconnection rate, defaults and remedies, and liability. The applicant shall complete, sign and return the POA ( Parallel Operating Agreement ) to the Utility. Any delay in the applicant’s execution of the Interconnection and Operating Agreement will not count toward the interconnection deadlines. Meter install, Testing, & Inspection Upon receipt of the local code inspection approval and executed POA, the Utility will schedule the meter install, testing, and inspection. The utility shall have an opportunity to schedule a visit to witness and perform commissioning tests required by IEEE 1547.1 and inspect the project. The electric utility may provide a waiver of its right to visit the site to inspect the project and witness or perform the commissioning tests. The utility shall notify the applicant of its intent to visit the site, inspect the project, witness or perform the commissioning tests, or of its intent to waive inspection within 10 working days after notification that the installation and local code inspections have passed. Within 5 working days from receipt of the completed commissioning test report ( if applicable ), the utility will notify the applicant of its approval or disapproval of the interconnection. If the electric utility does not approve the interconnection, the utility shall notify the applicant of the necessary corrective actions required for approval. The applicant, after taking corrective action, may request the electric utility to reconsider the interconnection request. Cat 5 -Installation and Design Approval The Project Developer must provide the Utility with 10 business days advance written notice of when the Project will be ready for inspection, testing and approval. The Utility may review the design drawings, for approval, after the Interconnection Review / Study has been completed. The design drawings must be submitted by the Project Developer in accordance with “Engineering Design Drawing Requirements” (see Generator Interconnection Supplement). If reviewed, the Utility shall either approve the Project Developer's design drawings as submitted or return them to the Project Developer with a clear statement as to why they were not approved. Where appropriate, the Utility will indicate required changes on the engineering drawings. In the event that revisions are necessary to the Project Developer's submitted design drawings and the Project Developer submits revised design drawings to the Utility, then the Utility shall either approve, in writing, the Project Developer's revised design drawings as resubmitted, or return them to the Project Developer with a clear statement as to why they were not approved. Where appropriate, the Utility will indicate required changes on the engineering drawings. The Utility will retain one copy of the approved design drawings. In the event that the Utility exercises its option to Acceptance Test the proposed interconnection relays that protect the Utility electric system, then the Utility shall communicate the results of that testing to the Project Developer for both the relays and the necessary documentation on the relays. Prior to final approval for Parallel Operation, the Utility’s specified relay calibration settings shall be applied and a commissioning test must be performed on the Project relaying and control equipment that involves the protection of the Utility electric system. The commissioning test must be witnessed by the Utility and can be performed by the Utility at the Project Developer's request. Upon satisfactory completion of this test and final inspection, the Utility will provide written permission for Parallel Operation. If the results are unsatisfactory, the Utility will provide written communication of these results and required action to the Project Developer. In the event the Project Developer proposes a revision to the Utility’s approved relaying and control equipment used to protect the Utility electric system and submits a description and engineering design drawings of the proposed changes, the Utility shall either approve the Project Developer's amended design drawings or return them to the Project Developer with a clear statement as to why they were not approved. Where appropriate, the Utility will indicate required changes on the engineering drawings. Operation in Parallel Upon utility approval of the interconnection, the electric utility shall install required metering, provide to the applicant a written statement of final approval, and a fully executed POA authorizing parallel operation. Operational Provisions Disconnection An electric utility may refuse to connect or may disconnect a project from the distribution system if any of the following conditions apply: a. Lack of fully executed interconnection agreement (POA) b. Termination of interconnection by mutual agreement c. Noncompliance with technical or contractual requirements in the interconnection agreement after notice is provided to the applicant of the technical or contractual deficiency. d. Distribution system emergency e. Routine maintenance, repairs, and modifications, but only for a reasonable length of time necessary to perform the required work and upon reasonable notice. Maintenance and Testing Routine and maintenance checks of the relaying and control equipment must be conducted in accordance with provided written test procedures which are required by IEEE Std. 1547, and test reports of such testing shall be maintained by the applicant and made available for Utility inspection upon request. [NOTE – IEEE 1547 requires that testing be conducted in accordance with written test procedures, and the nationally recognized testing laboratory providing certification will require that such test procedures be available before certification of the equipment.] The Project Developer is responsible for maintaining written reports for the above tests for a period of four years. These written reports shall be made available to the Utility upon request. Technical Requirements The following discussion details the technical requirements for interconnection of Category 5 Projects greater than 2 MW of generation. Many of these requirements will vary based on the capacity rating of the Project, type of generation being used, and mode of operation (Flow-back or Non-Flow-back). A few of the requirements will vary based on location of the interconnection (isolated load and available fault current). Certain major component, relaying, telemetry, and operational requirements must be met to provide compatibility between the Project equipment and the Utility electric system, and to assure that the safety and reliability of the electric system is not degraded by the interconnection. The Utility reserves the right to evaluate and apply newly developed protection and/or operation schemes at its discretion. All protective schemes and functions are evaluated for compliance to IEEE std. 1547. In addition, the Utility reserves the right to evaluate Projects on an ongoing basis as system conditions change, such as circuit loading, additional generation placed online, etc. Upgraded revenue metering may be required for the Project. Major Component Design Requirements The data requested in Appendix E,F, or G, data for all major equipment and relaying proposed by the Project Developer, must be submitted as part of the initial application for review and approval by the Utility. The Utility may request additional data be submitted as necessary during the interconnection process to clarify the operation of the Project facilities. Once installed, the interconnection equipment must be reviewed and approved by the Utility prior to being connected to the Utility electric system and before parallel operation is allowed. Data The data that the Utility requires to evaluate the proposed interconnection is documented on a one-line diagram and “fill in the blank” table by generator type in Appendices E, F, or G. A site plan, one-line diagrams, and interconnection protection system details of the Project are required as part of the application data. The generator manufacturer data package should also be supplied. Isolating Transformer(s) If an isolating transformer is required, the transformer must comply with the current ANSI Standard C57.12. The transformer must have voltage taps on the high and/or low voltage windings sufficient to assure satisfactory generator operation over the range of voltage variation expected on the Utility electric system. The Project Developer also needs to assure sufficient voltage regulation at its facility to maintain an acceptable voltage level for its equipment during such periods when its Project is off-line. This may involve the provision of voltage regulation or a separate transformer between the Utility and the Project station power bus. The type of generation and electrical location of the interconnection will determine the isolating transformer connections. Allowable connections are detailed under the specific Project type. Note: Some Utilities do not allow an isolation transformer to be connected to a grounded Utility system with an ungrounded secondary (Utility side) winding configuration, regardless of the Project type. Therefore, the Project Developer is encouraged to consult with the Utility prior to submitting an application. The proper selection and specification of transformer impedance is important relative to enabling the proposed Project to meet the Utility’s reactive power requirements (see “Reactive Power Control”). Isolation Device An isolation device is required and should be placed at the Point of Common Coupling (PCC). It can be a circuit breaker, circuit switcher, pole top switch, load-break disconnect, etc., depending on the electrical system configuration. The following are required of the isolation device: • Must be approved for use on the Utility system. • Must comply with current relevant ANSI and/or IEEE Standards. • Must have load break capability, unless used in series with a three-phase interrupting device. • Must be rated for the application. • If used as part of a protective relaying scheme, it must have adequate interrupting capability. The Utility will provide maximum short circuit currents and X/R ratios available at the PCC upon request. • Must be operable and accessible by the Utility at all times (24 hours a day, 7 days a week). • The Utility will determine if the isolation device will be used as a protective tagging point. If the determination is so made, the device must have visible open break provisions for padlocking in the open position, and it must be gang operated. If the device has automatic operation, the controls must be located remote from the device. Interconnection Lines The physically closest available system voltage, as well as equipment and operational constraints influence the chosen point of interconnection. The Utility has the ultimate authority to determine the acceptability of a particular PCC. Any new line construction to connect the Project to the Utility’s electric system will be undertaken by the Utility at the Project Developer’s expense. Interconnection line(s) will terminate on a termination structure provided by the Project Developer. Termination Structure The Project Developer is responsible for ensuring that structural material strengths are adequate for all requirements, incorporating appropriate safety factors. Upon written request, the Utility will provide line tension information for maximum dead-end tensions under heavy icing conditions. The structure must be designed for this maximum line tension along with an adequate margin of safety. Electrical clearances shall comply with requirements of the National Electrical Safety Code and Michigan Public Service Commission Standard 16-79. The installation of disconnect switches, bus support insulators, and other equipment shall comply with accepted industry practices. Surge arresters shall be selected to coordinate with the BIL rating of major equipment components and shall comply with recommendations set forth in the current ANSI Standard C62.2. Relaying Design Requirements The interconnection relaying design requirements are intended to assure protection of the Utility electric system. Any additional relaying which may be necessary to protect equipment at the Project is solely the responsibility of the Project Developer to determine, design, and apply. The relaying requirements will vary with the capacity rating of the Project, the type of generation being used, and the mode of operation (Flow-back or Non Flow-back). All relaying proposed by the Project Developer to satisfy these requirements must be submitted for review and approved by the Utility. Protective Relaying General Considerations Utility grade relays are required. See “Approved Relay Types” in the Generator Interconnection Supplement. All relays must be equipped with targets or other visible indicators to indicate that the relay has operated. If the protective system uses AC power as the control voltage, it must be designed to disconnect the generation from the Utility electric system if the AC control power is lost. Utility will work with Project Developer for system design for this requirement. The relay system must be designed such that the Project Developer is prevented from energizing the Utility electric system if that system is de-energized. Momentary Paralleling For situations where the Project will only be operated in parallel with the Utility electric system for a short duration (100 milliseconds or less), as in a make-before-break automatic transfer scheme, no additional relaying is required. Such momentary paralleling requires a modern integrated Automatic Transfer Switch (ATS) system, which is incapable of paralleling the Project with the Utility electric system. The ATS must be tested and verified for proper operation at least every 2 years. The Utility may be present during this testing. Instrument Transformer Requirements All relaying must be connected into instrument transformers. All current connections shall be connected into current transformers (CTs). All CTs shall be rated to provide no more than 5 amperes secondary current for all normal load conditions, and must be designed for relaying use, with an “accuracy class” of at least C50. Current transformers with an accuracy class designation such as T50 are NOT acceptable. For threephase systems, all three phases must be equipped with CTs. All potential connections must be connected into voltage transformers (VTs). For single-phase connections, the VTs shall be provided such that the secondary voltage does not exceed 120 volts for normal operations. For three-phase connections, the VTs shall be provided such that the lineto-line voltage does not exceed 120 volts for normal operation, and both the primary and secondary of the VTs shall be connected for grounded-wye connections. Direct Transfer Trip (DTT) Direct Transfer Trip is generally not required for Synchronous Projects that will operate in the Non Flow-back Mode since a more economic reverse power relay scheme can usually meet the requirements. For Flow-back Projects, the need for DTT is determined based on the location of the PCC. The Utility requires DTT when the total generation within a protective zone is greater than 33% of the minimum Utility load that could be isolated along with the generation. This prevents sustained isolated operation of the generation for conditions where Project protective relaying may not otherwise operate (see “Isolated Operation” in the Generator Interconnection Supplement). Direct transfer trip adds to the cost and complexity of an interconnection. A DTT transmitter is required for each Utility protective device whose operation could result in sustained isolated operation of the Project. An associated DTT receiver at the Project is required for each DTT transmitter. A Data Circuit is required between each transmitter and receiver. Telemetry is required to monitor status of the DTT communication, even if telemetry would not otherwise have been required. At the Project Developer’s expense, the Utility will provide the receiver(s) that the Project Developer must install, and the Utility will install the transmitter(s) at the appropriate Utility protective devices. Reverse Power Relaying for on Flow-back If Flow-back Mode is not utilized, reverse power protection must be provided. The reverse power relaying will detect power flow from the Project into the Utility system, and operation of the reverse power relaying will separate the Project from the Utility system. Automatic Reclosing The Utility employs automatic multiple-shot reclosing on most of the Utility’s circuit breakers and circuit reclosers to increase the reliability of service to its customers. Automatic singlephase overhead reclosers are regularly installed on distribution circuits to isolate faulted segments of these circuits. The Project Developer is advised to consider the effects of Automatic Reclosing (both singlephase and three-phase) to assure that the Project’s internal equipment will not be damaged. In addition to the risk of damage to the Project, an out-of-phase reclosing operation may also present a hazard to the Utility’s electric system equipment since this equipment may not be rated or built to withstand this type of reclosing. To prevent out-of-phase reclosing, circuit breakers can be modified with voltage check relays. These relays block reclosing until the parallel generation is separated and the line is "deenergized." Hydraulic single-phase overhead reclosers cannot be modified with voltage check relays; therefore, these devices will have to be either replaced with three-phase overhead reclosers, which can be voltage controlled, or relocated beyond the Project location - depending upon the sectionalizing and protection requirements of the distribution circuit. If the Project can be connected to more than one circuit, these revisions may be required on the alternate circuit(s) as well. The Utility will determine relaying and control equipment that needs to be installed to protect its own equipment from out-of-phase reclosing. Installation of this protection will be undertaken by the Utility at the Project Developer's expense. The Utility shall not be liable to the customer with respect to damage(s) to the Project arising as a result of Automatic Reclosing Single-Phase Sectionalizing The Utility also installs single-phase fuses and/or reclosers on its distribution circuits to increase the reliability of service to its customers. Three-phase generator installations may require replacement of fuses and/or single-phase reclosers with three-phase circuit breakers or circuit reclosers at the Project Developer’s expense. Synchronous Projects Under/overfrequency relaying and under/overvoltage relaying are required. Each Project must also be equipped with voltage-controlled overcurrent relays to detect faults on the Utility system. The under/overvoltage relaying must be either a three-phase relay or three single-phase relays, and three-phase voltage controlled overcurrent relaying must be provided. In order to minimize damage to both Project equipment and to Utility system equipment for loss-of-synchronism (also called out-of-step), and to minimize disruptions to other Utility customers in the area, out-of-step relaying may also be required. The Utility has evaluated and approved a relay for this purpose, which would usually be installed at the same location as the metering, and would isolate the Project from the Utility system. If the Project is connected to an ungrounded distribution system, the secondary winding (Utility side) of the isolation transformer must be connected delta. If the Project is connected to a grounded distribution system, the Project Developer has a choice of the following transformer connections: 1. A grounded-wye - grounded-wye transformer connection is acceptable only if the Project’s single line-to-ground fault current contribution is less than the Project’s three-phase fault current contribution at the PCC. 2. The isolation transformer may be connected for a delta secondary (Utility side) connection with any primary (Project side) connection, or 3. Ungrounded-wye secondary connection with a delta primary connection. If the Project is connected to a grounded distribution system via one of the isolation transformer connections specified above, ground fault detection for Utility faults may be required at the discretion of the Utility, and will consist of a (59N) ground overvoltage relay or (51N) overcurrent relay. The specific application of this relay will depend on the connection of the isolation transformer: 1. If a delta secondary/grounded-wye primary connection is used, the (59N) relay will be connected into the secondary of a set of three-phase VTs, which will be connected groundedwye primary, with the secondary connected delta with one corner of the delta left open. The (59N) relay will be connected across this open-corner. 2. If an ungrounded-wye secondary/delta primary connection is used, the (59N) relay will be connected into the secondary of a single VT that will be connected from the ungrounded-wye neutral of the isolation transformer to ground. 3. If a grounded-wye - grounded-wye transformer connection is used, a time overcurrent relay must be connected into a CT located on the Utility side isolation transformer neutral connection. In some instances, additional isolation transformer connection options may be available and will be determined by the Utility for the specific system location. The potential connection alternatives will include all alternatives listed above for application on a grounded distribution system, but will add a possible connection of grounded-wye (Utility side), delta (Project side). In the case of this additional isolation transformer connection, Utility system ground fault detection will take the form of a time overcurrent relay connected into a current transformer located in the Utility-side transformer neutral. This time overcurrent relay must have a very-inverse time characteristic. For a sample One-Line Diagram of this type of facility including the various methods of (59N) application, see Appendix E. Induction Projects Three-phase under/overvoltage relays and three-phase under/overfrequency relays must be provided. Utility-grade relays are required. If the Project is connected to an ungrounded distribution system, the secondary winding (Utility side) of the isolation transformer must be connected delta. If the Project is connected to a grounded distribution system, the developer has a choice of the following transformer connections: 1. The isolation transformer may be connected for a delta secondary (Utility side) connection with any primary (Project side) connection, or 2. The isolation transformer may be connected for an ungrounded-wye secondary (Utility side) connection with a delta primary (Project side) connection. 3. The isolation transformer may be connected for a grounded-wye - grounded-wye connection. If the Project is connected to a grounded distribution system via one of the isolation transformer connections specified above, ground fault detection for Utility faults must be provided. The specific application of this relay will depend on the connection of the isolation transformer: 1. If a delta secondary/grounded-wye primary connection is used, a (59N) ground overvoltage relay will be connected into the secondary of a set of three-phase VTs, which will be connected grounded-wye primary, with the secondary connected delta with one corner of the delta left open. The (59N) relay will be connected across this open-corner. 2. If an ungrounded-wye secondary/delta primary connection is used, a (59N) ground overvoltage relay will be connected into the secondary of a single VT that will be connected from the ungrounded-wye neutral of the isolation transformer to ground. 3. If a grounded-wye - grounded-wye connection is used, a time overcurrent relay must be connected into a CT located on the Utility side isolation transformer neutral connection. Protection must be provided for internal faults in the isolating transformer. In cases where it can be shown that self excitation of the induction generator cannot occur when isolated from the Utility, the Utility may waive the requirement that the Project Developer provide protection for Utility system ground faults. In all cases, ground fault detection for Utility faults may be required at the discretion of the Utility. For a sample One-Line Diagram of this type of facility, see Appendix F. Inverter Projects Under/overfrequency relaying and under/overvoltage relaying are required. The under/overvoltage relaying must be either a three-phase relay or three single-phase relays. The isolation transformer (without generation on-line) must be incapable of producing ground fault current to the Utility system; any connection except delta primary (Project side), groundedwye secondary (Utility side) is acceptable. The isolation transformer must be protected for internal faults; fuses are acceptable. If the inverter has passed a certified anti-island test, the Utility may waive the requirement that the generator Project Developer provide protection for the Utility system ground faults. In all cases, ground fault detection for Utility faults may be required at the discretion of the Utility. If required, type and methodology will be the same as Synchronous Projects listed above. For a sample One-Line Diagram of this type of facility, see Appendix G. Dynamometer Projects Under/overfrequency relaying and under/overvoltage relaying are required. The under/overvoltage relaying must be either a three-phase relay or three single-phase relays. All protection must use Utility grade relays. The isolation transformer (without generation on-line) must be incapable of producing ground fault current to the Utility system; any connection except delta primary (Project side), groundedwye secondary (Utility side) is acceptable. The isolation transformer must be protected for internal faults; fuses are acceptable. If an inverter is utilized and has passed a certified anti-island test, the Utility may waive the requirement that the generator Project Developer provide protection for the Utility system ground faults. In all cases, ground fault detection for Utility faults may be required at the discretion of the Utility. If required, type and methodology will be the same as Synchronous Projects listed above. General Under/overfrequency relaying and under/overvoltage relaying are required. The under/overvoltage relaying must be either a three-phase relay or three single-phase relays. The isolation transformer (without generation on-line) must be incapable of producing ground fault current to the Utility system; any connection except delta primary (Project side), groundedwye secondary (Utility side) is acceptable. Protection must be provided for internal faults in the isolating transformer; fuses are acceptable. If an inverter is utilized and has passed a certified anti-island test, the Utility may waive the requirement that the Project Developer provide protection for Utility system ground faults. In all cases, ground fault detection for Utility faults may be required at the discretion of the Utility. If required, type and methodology will be the same as Synchronous Projects listed above. Relay Setting Criteria The relay settings as detailed in this section will apply in the vast majority of applications. The Utility will issue relay settings for each individual Project Developer that will address the settings for these protective functions. All voltages will be adjusted for the specific VT ratio, and all currents will be adjusted for the specific CT ratio. Undervoltage Relays The undervoltage relays will normally be set to trip at 88% of the nominal primary voltage at the relay location, and must reset from a trip condition if the voltage increases to 90% of the nominal primary voltage at the relay location. In order to accommodate variations in this criteria, the trip point of the relays shall be adjustable over a range of 70% of the nominal voltage to 90% of the nominal voltage. The trip time shall not exceed 1.0 seconds at 90% of the relay setting. Overvoltage Relays Two steps of overvoltage relaying are required. For the first overvoltage set point, the overvoltage relays will normally be set to trip at 107% of the nominal primary voltage at the relay location, and must reset from a trip condition if the voltage decreases to 105% of the nominal primary voltage at the relay location. In order to accommodate variations in this criteria, the trip point of the relays shall be adjustable over a range of 105% of the nominal voltage to 120% of the nominal voltage. The trip time shall not exceed 1.0 seconds at 110% of the relay setting. For the second overvoltage set point, the overvoltage relays will normally be set to trip at 120% of the nominal primary voltage at the relay location, and must reset from a trip condition if the voltage decreases to 118% of the nominal primary voltage at the relay location. In order to accommodate variations in this criteria, the trip point of the relays shall be adjustable over a range of 115% of the nominal voltage to 140% of the nominal voltage. The trip time shall be instantaneous (relay operating time not to exceed 0.02 seconds at 110% of the trip setting). Underfrequency Relays The Underfrequency relay will normally be set for a trip point of 58.5 Hz, and must trip within 0.2 seconds. Relays with an inverse time characteristic (where the trip time changes with respect to the applied frequency) are not acceptable. These relays must respond reliably for applied source voltages as low as 70% of the nominal voltage. Overfrequency Relays The overfrequency relay will normally be set for a trip point of 60.5 Hz, and must trip within 0.2 seconds. Relays with an inverse time characteristic are not acceptable. These relays must respond reliably for applied source voltages as low as 70% of the nominal voltage. 51V Relays – Voltage Controlled Overcurrent Relays For synchronous Project applications, the (51V) relays must be set to detect any phase faults that may occur between the Project and the nearest three-phase fault clearing device on the Utility system. Since these faults may take up to 1-second to detect and isolate, the appropriate saturated direct-axis reactance of the Project will be used depending on its time constants. The settings of this device will consider the relay manufacturer’s recommended practice for the type of Project and prime mover (mechanical energy source), and will be determined by the Utility for the specific system application. 59 Relay – Ground Fault Detection This relay will be applied to detect ground faults on the Utility system when the Project is connected to a grounded Utility system via an ungrounded transformer winding. This relay will be set for a 10% shift in the apparent power system neutral. For an ungrounded-wye transformer winding with a single 120 V secondary VT, the setting will usually be 12 Volts. For a delta transformer winding with broken delta 120 V secondary VTs, the setting will usually be 20 Volts. The time delay will normally be 1 second. 51 Relay – Ground Fault Detection This relay will be applied to detect ground faults on the Utility system when the Project is connected to a grounded Utility system via a grounded-wye transformer winding, and will be connected into a CT in the transformer neutral connection. This relay will be set to detect faults on the directly connected Utility system, and the timing will be set to comply with Utility practice for overcurrent relay coordination. The CT ratio and specific relay setting will be determined via a fault study performed by the Utility. 32 Relay – Reverse Power The reverse power relay must be selected such that it can detect a power flow into the Utility system of a small fraction of the overall Project capacity. The relay will normally be set near its minimum (most sensitive) setting, and will trip after a 1 second time delay. The delay will avoid unnecessary tripping for momentary conditions. Maintenance and Testing The Utility reserves the right to test the relaying and control equipment that involves protection of the Utility electric system whenever the Utility determines a reasonable need for such testing exists. The Project Developer is solely responsible for conducting proper periodic maintenance on the generating equipment and its associated control, protective equipment, interrupting devices, and main Isolation Device, per manufacturer recommendations. The Project Developer is responsible for the periodic scheduled maintenance on those relays, interrupting devices, control schemes, and batteries that involve the protection of the Utility electric system. A periodic maintenance program is to be established to test these relays at least every 2 years. This maintenance testing must be witnessed by the Utility. Each routine maintenance check of the relaying equipment shall include both an exact calibration check and an actual trip of the circuit breaker or contactor from the device being tested. For each test, a report shall be submitted to the Utility indicating the results of the tests made and the "as found" and "as left" relay calibration values. Visually setting, without verification, a calibration dial or tap is not considered an adequate relay calibration check. The Project Developer is responsible for maintaining written reports for the above tests for a period of four years. These written reports shall be made available to the Utility upon request. Installation and Design Approval The Project Developer must provide the Utility with 10 business days advance written notice of when the Project will be ready for inspection, testing and approval. The Utility may review the design drawings, for approval, after the Interconnection Study has been completed. The design drawings must be submitted by the Project Developer in accordance with “Engineering Design Drawing Requirements” (see Generator Interconnection Supplement). If reviewed, the Utility shall either approve the Project Developer's design drawings as submitted or return them to the Project Developer with a clear statement as to why they were not approved. Where appropriate, the Utility will indicate required changes on the engineering drawings. In the event that revisions are necessary to the Project Developer's submitted design drawings and the Project Developer submits revised design drawings to the Utility, then the Utility shall either approve, in writing, the Project Developer's revised design drawings as resubmitted, or return them to the Project Developer with a clear statement as to why they were not approved. Where appropriate, the Utility will indicate required changes on the engineering drawings. The Utility will retain one copy of the approved design drawings. In the event that the Utility exercises its option to Acceptance Test the proposed interconnection relays that protect the Utility electric system, then the Utility shall communicate the results of that testing to the Project Developer for both the relays and the necessary documentation on the relays. Prior to final approval for Parallel Operation, the Utility’s specified relay calibration settings shall be applied and a commissioning test must be performed on the Project relaying and control equipment that involves the protection of the Utility electric system. The commissioning test must be witnessed by the Utility and can be performed by the Utility at the Project Developer's request. Upon satisfactory completion of this test and final inspection, the Utility will provide written permission for Parallel Operation. If the results are unsatisfactory, the Utility will provide written communication of these results and required action to the Project Developer. In the event the Project Developer proposes a revision to the Utility’s approved relaying and control equipment used to protect the Utility electric system and submits a description and engineering design drawings of the proposed changes, the Utility shall either approve the Project Developer's amended design drawings or return them to the Project Developer with a clear statement as to why they were not approved. Where appropriate, the Utility will indicate required changes on the engineering drawings. Telemetry and Disturbance Monitoring Requirements Telemetry and disturbance monitoring is required in all cases for Projects that will operate in the Flow-back Mode and have the capability to supply aggregate generation greater than 2 MW to the Utility. For Projects that will operate in the Non-Flow-back Mode, the requirement for telemetry will be determined on a case-by-case basis as part of the Interconnection Study. Telemetry enables the Utility to operate the electric system safely and reliably under both normal and emergency conditions. The Utility measures its internal load plus losses (generation) on a real time basis via an extensive telemetry system. This system sums all energy flowing into the Utility electric system from Projects interconnected to the system and from interconnections with other utilities. During system disturbances when portions of the electrical systems are out of service, it is essential to know if a Project is on line or off line to determine the proper action to correct the problem. Time saved during restoration activities translates to fewer outages and outages of shorter duration for the Utility’s customers. The Utility evaluates the performance of the overall protective system for all faults on the electric system. It is critical that sufficient monitoring of the protective system is in place to determine its response. It is preferable to deploy disturbance monitoring into all Projects, but it can be expensive to deploy. Therefore, disturbance monitoring is required only for installations that already require telemetry. The Project Developer shall provide a suitable indoor location, approved by the Utility, for the Utility’s owned, operated, and maintained Remote Terminal Unit (RTU). The location must be equipped with a 48 V or 125 V DC power supply. The Project Developer must provide the necessary phone (or alternate) and data circuits, and install a telephone (or alternate) backboard for connections to the Utility RTU and metering equipment. All phone circuits must be properly protected as detailed in IEEE Std. 487. See “Typical Meter and RTU Installation Where Telemetry is Required” in the Generator Interconnection Supplement. When telemetry is required, the following values will be telemetered: 1. Real and reactive power flow at the PCC. 2. Voltage at the PCC. 3. The status (normal/fail) of protective relay Communication Channels. A status indication of "FAIL" indicates the Communication Channel used for relaying (i.e. transfer trip) is unable to perform its protective function. 4. The status (open/closed) of the main isolating breaker and each generating unit breaker (if the Project is composed of multiple units, a single logical (OR) status of the individual Project breaker states, indicating all Project breakers are open or any one or more Project breakers are closed, is permissible). A closed status would be indicated if any individual generator is on line. The RTU will be equipped with “sequence of events” recording. The Project Developer shall provide, wired to a terminal block near the RTU panel, the following general equipment Auxiliary Contacts and relay contacts: 1. An output contact of an instantaneous relay to act as a ground fault detector for faults on the Utility electric system. This relay shall be connected into the same sensing source as the ground fault protective relay required by the Utility. 2. Each and every trip of an interconnection isolation device, which is initiated by any of the generator interconnection relaying schemes required by the Utility. 3. Each and every trip of an interconnection isolation device, which is initiated by any of the protective systems for the generator. 4. Each and every trip or opening of an interconnecting isolation device, which is initiated by any other manual or electrical means. 5. A contact indicating the position of the Project’s primary-side main breaker. 6. A contact indicating operation of the over/undervoltage relays. 7. A contact indicating operation of the under/overfrequency relay or the Utility’s ground fault relay. 8. A contact indicating operation of the Project provided transformer bank relaying. 9. A contact indicating operation of any of the (51V) relaying. 10. A contact indicating the position of the high-side fault-clearing device. 11. A contact indicating the position of the reverse power relay, if said, relay is required by the Utility. 12. The following individual contact from each individual Direct Transfer Trip receiver, required by the Utility: i. Loss-of-guard (LOG) alarm ii. Receive-trip relay (RTX). iii. Lockout relay. If any of the functions indicated in items 2-4, 6, 7, 9, or 11 are combined into a multi-functional device, either: 1. Each of those functions must be monitored independently on the RTU, or 2. Provisions acceptable to the Utility must be provided to interrogate the multi-functional device such that the operation of the individual functions may be evaluated separately. Telemetry, when required, will be provided by the Utility at the Project Developer's expense. In addition to other telemetry costs, a one-time charge will be assessed to the Project Developer for equipment and software installed at the Utility’s System Control Center to process the data signals. Miscellaneous Operational Requirements Miscellaneous requirements include synchronizing equipment for Parallel Operation, reactive requirements, standby power considerations, and system stability limitations. Operating in Parallel The Project Developer will be solely responsible for the required synchronizing equipment and for properly synchronizing the generation with the Utility electric system. Voltage fluctuation at the PCC during synchronizing shall be limited per IEEE std. 1547.. The Project Developer will notify the Utility prior to synchronizing to and prior to scheduled disconnection from the electric system. These requirements are directly concerned with the actual operation of the Project with the Utility: • The Project may not commence parallel operation until approval has been given by the Utility. The completed installation is subject to inspection by the Utility prior to approval. Preceding this inspection, all contractual agreements must be executed by the Project Developer. • The Project must be designed to prevent the Project from energizing into a de-energized Utility line. The Project’s circuit breaker or contactor must be blocked from closing in on a de-energized circuit. • The Project shall discontinue parallel operation with a particular service and perform necessary switching when requested by the Utility for any of the following reasons: 1. When public safety is being jeopardized. 2. During voltage or loading problems, system emergencies, or when abnormal sectionalizing or circuit configuration occurs on the Utility system. 3. During scheduled shutdowns of Utility equipment that are necessary to facilitate maintenance or repairs. Such scheduled shutdowns shall be coordinated with the Project. 4. In the event there is demonstrated electrical interference (i.e. Voltage Flicker, Harmonic Distortion, etc.) to the Utility’s customers, suspected to be caused by the Project, and such interference exceeds then current system standards, the Utility reserves the right, at the Utility’s initial expense, to install special test equipment as may be required to perform a disturbance analysis and monitor the operation and control of the Project to evaluate the quality of power produced by the Project. In the event that no standards exist, then the applicable tariffs and rules governing electric service shall apply. If the Project is proven to be the source of the interference, and that interference exceeds the Utility’s standards or the generally accepted industry standards, then it shall be the responsibility of the Project Developer to eliminate the interference problem and to reimburse the Utility for the costs of the disturbance monitoring installation, removal, and analysis, excluding the cost of the meters or other special test equipment. 5. When either the Project or its associated synchronizing and protective equipment is demonstrated by the Utility to be improperly maintained, so as to present a hazard to the Utility system or its customers. 6. Whenever the Project is operating isolated with other Utility customers, for whatever reason. 7. Whenever a loss of communication channel alarm is received from a location where a communication channel has been installed for the protection of the Utility system. 8. Whenever the Utility notifies the Project Developer in writing of a claimed non-safety related violation of the Interconnection Agreement and the Project Developer fails to remedy the claimed violation within ten working days of notification, unless within that time either the Project Developer files a complaint with the MPSC seeking resolution of the dispute or the Project Developer and Utility agree in writing to a different procedure. If the Project has shown an unsatisfactory response to requests to separate the generation from the Utility system, the Utility reserves the right to disconnect the Project from parallel operation with the Utility electric system until all operational issues are satisfactorily resolved. Reactive Power Control Synchronous Projects that will operate in the Flow-back Mode must be dynamically capable of providing 0.90 power factor lagging (delivering reactive power to the Utility) and 0.95 power factor leading (absorbing reactive power from the Utility) at the Point of Receipt. The Point of Receipt is the location where the Utility accepts delivery of the output of the Project. The Point of Receipt can be the physical location of the billing meters or a location where the billing meters are not located, but adjusted for line and transformation losses. Induction and Inverter Projects that will operate in the Flow-back Mode must provide for their own reactive needs (steady state unity power factor at the Point of Receipt). To obtain unity power factor, the Induction or Inverter Project can: 1. Install a switchable VAR supply source to maintain unity power factor at the Point of Receipt; or 2. Provide the Utility with funds to install a VAR supply source equivalent to that required for the Project to attain unity power factor at the Point of Receipt at full output. There are no interconnection reactive power capability requirements for Synchronous, Induction, and Inverter-Type Projects that will operate in the Non-Flow-back Mode. The Utility’s existing rate schedules, incorporated herein by reference, contain power factor adjustments based on the power factor of the metered load at these facilities. Standby Power Standby power will be provided under the terms of an approved rate set forth in the Utility’s Standard Rules and Regulations. The Project Developer should be aware that to qualify for Standby Rates, a separate meter must be installed at the Project. If outside of the Utility’s franchise area, it will be the Project Developer’s responsibility to arrange contractually and technically for the supply of its facility’s standby, maintenance, and any supplemental power needs. System Stability and Site Limitations The Stiffness Ratio is the combined three-phase short circuit capability of the Project and the Utility divided by the short circuit capability of the Project measured at the PCC. A stability study may be required for Projects with a Stiffness Ratio of less than 40. Five times the generator rated kVA will be used as a proxy for short circuit current contribution for induction generators. For synchronous Projects, with a Stiffness Ratio of less than 40, the Utility requires special generator trip schemes or loss of synchronism (out-of-step) relay protection. If the apparent voltage flicker from a loss-of-synchronism condition exceeds 5%, an out-of-step relay will be required. This type of protection is typically applied at the PCC and trips the entire Project off-line, if instability is detected, to protect the Utility electric system and its customers. If the project Developer chooses not to provide for mitigation of unacceptable voltage flicker (above five percent), the Utility may disallow the interconnection of the Project or require a new dedicated interconnection at the Project Developer’s expense. The Project Developer is responsible for evaluating the consequences of unstable generator operation or voltage transients on Project equipment at the Project, and determining, designing, and applying any relaying which may be necessary to protect that equipment. This type of protection is typically applied on individual generators to protect the Project. The Utility will determine if operation of the Project will create objectionable voltage flicker and/or disturbances to other Utility customers and develop any required mitigation measures at the Project Developer’s expense. Revenue Metering Requirements The Utility will own, operate, and maintain the billing metering equipment at the Project Developer's expense. The billing metering will meter both real and reactive interconnection flows between the Project and the Utility electric system. Where applicable, separate metering of station power may be required to accurately meter the generation facility load when the Project is off-line. Special billing metering will be required for Projects operating in the Flow-back Mode. If telemetering is required, the billing metering will be included as part of the telemetering installation. Ground fault protection for this circuit may be required, and coordination with the telephone company and all associated costs will be by Project Developer. The Project Developer shall provide a suitable indoor location, approved by the Utility, for the Utility’s owned, operated, and maintained billing metering. The Project Developer shall provide authorized employees and agents of the Utility access to the premises at all times to install, turn on, disconnect, inspect, test, read, repair, or remove the metering equipment. The Project Developer may, at its option, have a representative witness this work. The metering installations for Flow-back operation shall be constructed in accordance with the practices, which normally apply to the construction of metering installations for commercial, industrial, or other customers with demand recording equipment. At a minimum three meters will be required; two at the PCC, one import and one export and one at the generator. The Utility shall supply to the Project Developer all required metering equipment and the standard detailed specifications and requirements relating to the location, construction, and access of the metering installation and will provide consultation pertaining to the meter installation as required. The Utility will endeavor to coordinate the delivery of these materials with the Project Developer’s installation schedule during normal scheduled business hours. The Project Developer shall provide a mounting surface for the meters, recorders, connection cabinets, a housing for the instrument transformers, a conduit for the conductors between the instrument transformer secondary windings and the meter connection cabinets, and a conduit for the communication links, if required. All of this equipment must meet the Utility’s specifications and requirements. The responsibility for the installation of the equipment is shared between the Utility and the Project Developer, with the Project Developer generally installing all of the equipment on its side of the PCC, including instrument transformers, cabinets, conduits, and mounting surfaces. The Utility, or its agents, shall install the meters, recorders, and communication links. The Utility will endeavor to coordinate the installation of these items with the Project Developer's schedule. Communication Circuits The Project Developer is responsible for ordering and acquiring the telephone circuit required for the Project Interconnection. The Project Developer will assume all installation, operating, and maintenance costs associated with the telephone circuits, including the monthly charges for the telephone lines and any rental equipment required by the local telephone provider. However, at the Utility’s discretion, the Utility may select an alternative communication method, such as wireless communications. Regardless of the method, the Project Developer will be responsible for all costs associated with the material, installation and maintenance, whereas the Utility will be responsible to define the specific communication requirements. The Utility will cooperate and provide Utility information necessary for proper installation of the telephone (or alternate) communication circuits upon written request. A dedicated communication circuit is required for access to the billing meter by the Utility. When DTT is required, a modular RJ-11 jack must also be installed within six feet of the billing metering equipment, to allow the Utility to use this circuit for voice communication with personnel performing master station checkout of the RTU. This dial-up voice-grade circuit shall be a local telephone company provided business measured line without dial-in or dial-out call restrictions. If DTT is required, a separate dedicated 4-wire, Class A, Data Circuit must be installed and protected as specified by the local telephone Utility for each DTT receiver and for the RTU. The circuit must be installed in rigid metallic conduit from the RTU and each DTT receiver to the point of connection to the telephone Utility equipment. Wall space must be provided for adjacent mounting next to the telephone board, of the billing metering panel and a telemetry enclosure. The billing metering panel is typically 60 inches high by 48 inches wide and the telemetry enclosure is typically 24 inches high by 24 inches wide. A clear space of 4.5 feet in front of this equipment is required to permit maintenance and testing. A review of each installation shall be made to determine the location and space requirements most agreeable to the Utility and the Project Developer. Appendix A Interconnection Process Flow Diagram Appendix B Interconnection Table – Applicant Costs Distribution Distribution Application Engineering Review Review Study Upgrades Category 5 $500 Propose fixed Propose fixed Actual or Max Fee** Fee** Approved by Commission* Testing & Inspection Actual or Max Approved by Commission* * Costs incurred by affected systems are born directly by the applicant and are not included in the table. ** Projects greater than 6MW will have an initial fixed fee with actual cost true up at the completion of the study. Category 5 Interconnection Timeline – Working Days Distribution Distribution Testing & Applicati Application Engineering Review Study Study Upgrades Inspection on Completion Completion Complete 10 10 45*** 60**,*** Mutually 10 Agreed*** ** Unless a different time period is mutually agreed upon *** Timeline impacts due to affected system studies & Upgrades are not included in the quoted timeframe Appendix C Procedure Definitions Alternative electric supplier ( AES ): as defined in section 10g of 2000 PA 141, MCL 460.10g Alternative electric supplier net metering program plan: document supplied by an AES that provides detailed information to an applicant about the AES’s net metering program. Applicant: Legally responsible person applying to an electric utility to interconnect a project with the electric utility’s distribution system or a person applying for a net metering program. An applicant shall be a customer of an electric utility and may be a customer or an AES. Application Review: Review by the electric utility of the completed application for interconnection to determine if an engineering review is required. Area etwork: A location on the distribution system served by multiple transformers interconnected in an electrical network circuit. Category 1: An inverter based project of 20kW or less that uses equipment certified by a nationally recognized testing laboratory to IEEE 1547.1 testing standards and in compliance with UL 1741 scope 1.1A. Category 2: A project of greater than 20 kW and not more than 150 kW. Category 3: A project of greater than 150 kW and not more than 550 kW. Category 4: A project of greater than 550 kW and not more than 2 MW. Category 5: A project of greater than 2 MW. Certified equipment: A generating, control, or protective system that has been certified as meeting acceptable safety and reliability standards by a nationally recognized testing laboratory in conformance with UL 1741. Commission: The Michigan Public Service Commission Commissioning test: The procedure, performed in compliance with IEEE 1547.1, for documenting and verifying the performance of a project to confirm that the project operates in conformity with its design specifications. Customer: A person who receives electric service from an electric utility’s distribution system or a person who participates in a net metering program through an AES or electric utility. Customer-generator: A person that uses a project on-site that is interconnected to an electric utility distribution system. Distribution system: The structures, equipment, and facilities operated by an electric utility to deliver electricity to end users, not including transmission facilities that are subject to the jurisdiction of the federal energy regulatory commission. Distribution system study: A study to determine if a distribution system upgrade is needed to accommodate the proposed project and to determine the cost of an upgrade if required. Electric provider: Any person or entity whose rates are regulated by the commission for selling electricity to retail customers in the state. Electric utility: Term as defined in section 2 of 1995 PA 30, MCL 460.562. Eligible electric generator: A methane digester or renewable energy system with a generation capacity limited to the customer’s electrical need and that does not exceed the following: • 150 kW of aggregate generation at a single site for a renewable energy system • 550 kW of aggregate generation at a single site for a methane digester Engineering Review: A study to determine the suitability of the interconnection equipment including any safety and reliability complications arising from equipment saturation, multiple technologies, and proximity to synchronous motor loads. Full retail rate: The power supply and distribution components of the cost of electric service. Full retail rate does not include system access charge, service charge, or other charge that is assessed on a per meter basis. IEEE: Institute of Electrical and Electronics Engineers IEEE 1547: IEEE “Standard for Interconnecting Distributed Resources with Electric Power Systems” IEEE 1547.1: IEEE “Standard Conformance Test Procedures for Equipment Interconnecting Distributed Resources with Electric Power Systems” Interconnection: The process undertaken by an electric utility to construct the electrical facilities necessary to connect a project with a distribution system so that parallel operation can occur. Interconnection procedures: The requirements that govern project interconnection adopted by each electric utility and approved by the commission. kW: kilowatt kWh: kilowatt-hours Material modification: A modification that changes the maximum electrical output of a project or changes the interconnection equipment including the following: • • Changing from certified to non certified equipment Replacing a component with a component of different functionality or UL listing. Methane digester: 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. Modified net metering: A 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 utility distribution system during a billing period or time-of-use pricing period. MW: megawatt ationally recognized testing laboratory: Any testing laboratory recognized by the accreditation program of the U.S. department of labor occupational safety and health administration. Parallel operation: The operation, for longer than 100 milliseconds, of a project while connected to the energized distribution system. Project: Electrical generating equipment and associated facilities that are not owned or operated by an electric utility. Renewable energy credit ( REC ): A credit granted pursuant to the commission’s renewable energy credit certification and tracking program in section 41 of 2008 PA 295, MCL 460.1041. Renewable energy resource: Term as defined in section 11(i) of 2008 PA 295, MCL 460.1011(i) Renewable energy system: Term as defined in section 11(k) of 2008 PA 295, MCL 460.1011(k). Spot network: A location on the distribution system that uses 2 or more inter-tied transformers to supply an electrical network circuit. True net metering: A utility billing method that applies the full retail rate to the net of the bidirectional flow of kW hors across the customer interconnection with the utility distribution system, during a billing period or time-of-use pricing period. UL: Underwriters Laboratory UL 1741: The “Standard for Inverters, Converters, Controllers and Interconnection System Equipment for Use With Distributed Energy Resources.” UL 1741 scope 1.1A: Paragraph 1.1A contained in chapter 1, section 1 of UL 1741. Uniform interconnection application form: The standard application forms, approved by the commission under R 460.615 and used for category 1, category 2, category 3, category 4, and category 5 projects. Uniform interconnection agreement: The standard interconnection agreements approved by the commission under R 460.615 and used for category 1, category 2, category 3, category 4, and category 5 projects. Uniform net metering application: The net metering application form approved by the commission under R 460.642 and used by all electric utilities and AES. Working days: Days excluding Saturdays, Sundays, and other days when the offices of the electric utility are not open to the public. Appendix D – Site Plan Appendix E – Sample One-line Synchronous (not required for flow-back) Instructions: Attach data sheets as required. Indicate in the table below the page number of the attached data (manufacturer’s data where appropriate) on which the requested information is provided. Provide one table for each unique generator. Synchronous Electric Generator(s) at the Project Item o 1 2 3 4 5 6 7 8 9 10 Data Valu e Generator No _____ Data Description Generator Type (synchronous or induction) Generator Nameplate Voltage Generator Nameplate Watts or Volt-Amperes Generator Nameplate Power Factor (pf) Direct axis reactance (saturated) Direct axis transient reactance (saturated) Direct axis sub-transient reactance (saturated) Short Circuit Current contribution from generator at the Point of Common Coupling (single-phase and three-phase National Recognized Testing Laboratory Certification Written Commissioning Test Procedure Attached Page o Appendix F – Sample One-Line Induction (not required for flow-back) Instructions: Attach data sheets as required. Indicate in the table below the page number of the attached data (manufacturer’s data where appropriate) on which the requested information is provided. Provide one table for each unique generator. Induction Electric Generator(s) at the Project: Generator o _____ Item Data Attached o Description Page o 1 Generator Type (Inverter) 2 Generator Nameplate Voltage 3 Generator Nameplate Watts or Volt-Amperes 4 Generator Nameplate Power Factor (pf) 5 Short Circuit Current contribution from generator at the Point of Common Coupling (single-phase and three-phase) 6 National Recognized Testing Laboratory Certification 7 Written Commissioning Test Procedure Appendix G – Sample One-Line Inverter ONE-LINE REPRESENTATION TYPICAL ISOLATION AND FAULT PROTECTION FOR INVERTER GENERATOR INSTALLATIONS 32 59 A) (not required for flow-back) Instructions: Attach data sheets as required. Indicate in the table below the page number of the attached data (manufacturer’s data where appropriate) on which the requested information is provided. Provide one table for each unique generator. Inverter Electric Generator(s) at the Project: Generator o _____ Item Data Attached o Description Page o 1 Generator Type (Inverter) 2 Generator Nameplate Voltage 3 Generator Nameplate Watts or Volt-Amperes 4 Generator Nameplate Power Factor (pf) 5 Short Circuit Current contribution from generator at the Point of Common Coupling (single-phase and three-phase) 6 National Recognized Testing Laboratory Certification 7 Written Commissioning Test Procedure Appendix H Sample One Line Diagram for Non-Flow Back projects ONE-LINE DIAGRAM & CONTROL SCHEMATIC TYPICAL ISOLATION PROECTION FOR NON FLOW-BACK INSTALLATIONS Distribution Circuit Appendix I Sample One Line Diagram for Flow-Back projects Distribution Circuit ITERCOECTIO AD PARALLEL OPERATIG AGREEMET FOR CATEGORY 2 PROJECTS (GREATER THA 20kW TO 150kW) This Interconnection and Parallel Operating Agreement (“Agreement”) is entered into on (insert date of last signature from page 6) by __________________(the “Utility”), (the “Applicant”), and (if applicable under Paragraph 5) (the “Property Owner”). Utility and Applicant are sometimes also referred to in this Agreement collectively as “Parties” or individually as “Party.” Applicant shall be the “Project Developer” as used in and for purposes of the applicable Michigan Electric Utility Generator Interconnection Requirements (“Interconnection Requirements”) approved by the Michigan Public Service Commission (“Commission”). I. RECITALS A. Applicant is an electric service Customer of Utility in good standing and has submitted a Generator Interconnection Application (“Application”) to Utility. B. Applicant desires to interconnect an electric generating facility with maximum capacity of 150kW kilowatts (“kW”) or less (the “Applicant Facility”) with Utility’s electric distribution system and operate Applicant’s Facility in parallel with Utility’s distribution system, under the Utility’s Interconnection Requirements for Category 2 (greater than 20kW to 150kW) projects, as defined in the Electric Interconnection and Net Metering Standards approved by the Commission (the “Standards”), as applicable. C. For purposes of this Agreement, “interconnect” means establishing a connection between a non-utility generating resource (in this case, the “Applicant Facility”) and Utility’s distribution system. “Operate in parallel” means generating electricity from a non-utility resource (in this case, the Applicant Facility) that is connected to Utility’s system. In all cases, terms shall have the meaning as defined in the Standards. D. Interconnection of the Applicant Facility with Utility’s distribution system is subject to this Agreement, the Application, the Interconnection Requirements, the Standards and utility tariffs approved by the MPSC, as applicable. E. This Agreement does not address any purchase or sale of electricity between Utility and Applicant nor does it create any agency, partnership, joint venture or other business arrangement between or among Utility, Applicant and/or Property Owner. Page 1 of 10 II. AGREEMET NOW THEREFORE, in consideration of the above recitals, the mutual covenants contained herein and for good and valuable consideration, the Parties agree as follows: 1. Description of Applicant Facility 1.1 The Applicant Facility must be built with the following ratings, which shall not be changed without thirty (30) days advance written notice to Utility according to the notice requirements herein and as depicted in Exhibit 1 – Interconnection Diagram: Photovoltaic/Solar (“PV”) Array Rating: kW Certified Test Record Number (UL1741 Scope 1.1A): Wind Turbine (WT) Rating: kW kW Hydroelectric Turbine (HT) Rating: Fuel Cell (FC) Rating: kW and kW Other (specify type and rating): Single Phase Three Phase Service Type: Voltage Level: kW 1.2 Applicant Facility Location: Street Address, City, State, Zip If Applicant is not the owner of the property identified above, the Property Owner must sign this Agreement for the purposes indicated in Paragraph 5. 1.3 Applicant’s Utility service account number: Property Owner’s Utility service account number (if applicable): 1.4 The Applicant Facility is planned to be ready for parallel operation on or about: Date 2. Interconnection Facilities If it is necessary for Utility to install certain interconnection facilities (“Interconnection Facilities”) and make certain system modifications in order to establish an interconnection between the Applicant Facility and Utility’s distribution system, the Interconnection facilities and modifications shall be described to the Applicant. Page 2 of 10 3. Design Requirements, Testing and Maintenance of Applicant Facility 3.1 Applicant shall be responsible for the design and installation of the Applicant Facility and obtaining and maintaining any required governmental authorizations and/or permits, which may include, but shall not be limited to, easements to clear trees, and necessary rights-of-way for installation and maintenance of the Utility Interconnection Facilities. Applicant shall reimburse Utility for its costs and expenses to acquire such easements / permits. 3.2 Applicant shall, at its sole expense, install and properly maintain protective relay equipment and devices to protect its equipment and service, and the equipment and system of Utility, from damage, injury or interruptions, and will assume any loss, liability or damage to the Applicant Facility caused by lack of or failure of such protection. Such protective equipment specifications and design shall be consistent with the applicable Interconnection Requirements. Prior to the Applicant Facility operating in parallel with Utility distribution system, Applicant shall provide satisfactory evidence to Utility that it has met the Interconnection Requirements, including but not limited to the receipt of approval from the local building/electrical code inspector. The Utility’s approval, or failure to approve, under this section shall in no way act as a waiver or otherwise relieve the Applicant of its obligations under this section 3.3 At its own expense, Applicant shall perform operational testing at least five (5) days prior to the installation of any Interconnection Facilities by Utility. Utility may, but is not required to, send qualified personnel to the Applicant Facility to inspect the facility and observe the testing. Upon completion of such testing and inspection and prior to interconnection Applicant shall provide Utility with a written report explaining all test results, including a copy of the generator commissioning test report. Applicant shall test protective relay equipment every two (2) years (unless an extension is agreed to by Utility) to verify the calibration indicated on the latest relay setting document issued by Utility. The results of such tests shall be provided to Utility in writing for review and approval. Utility may, at any time and at its sole expense, inspect and test the Applicant Facility to verify that the required protective equipment is in service, properly maintained, and calibrated to provide the intended protection. This inspection may also include a review of Applicant's pertinent records. Inspection, testing and/or approval by Utility or the omission of any inspection, testing and/or approval by Utility pursuant to this Agreement shall not relieve the Applicant of any obligations or responsibility assumed under this Agreement. 3.4 Applicant shall operate and maintain the Applicant Facility in a safe and prudent manner and in conformance with all applicable laws and regulations. Applicant shall obtain or maintain any governmental authorizations and permits required for construction and operation of the Applicant Facility. Page 3 of 10 4. Disconnection Utility shall be entitled to disconnect the Applicant Facility from Utility’s distribution system, or otherwise refuse to connect the Applicant Facility, if: (a) Applicant has not complied with any one of the technical requirements contained in the applicable Interconnection Requirements, (b) the electrical characteristics of the Applicant Facility are not compatible with the electrical characteristics of Utility’s distribution system, (c) an emergency condition exists on Utility’s distribution system, (d) Applicant's protective relay equipment fails, (e) Utility determines that the Applicant Facility is disrupting service to any Utility Customer, (f) disconnection is required to allow for construction, installation, maintenance, repair, replacement, removal, investigation, inspection or testing of any part of Utility’s facilities, (g) if a required installation (e.g., telephone line) fails or becomes incapacitated and is not repaired in a timely manner, as determined by Utility, or (h) Applicant commits a material breach of this Agreement, (i) by mutual consent, or (j) Applicant fails to execute this Interconnection Agreement or upon cancellation or termination of this Interconnection Agreement. 5. Access to Property 5.1 At its own expense, Applicant shall make the Applicant Facility site available to Utility. The site shall be free from hazards and shall be adequate for the operation and construction of the Interconnection Facilities. Utility, its agents and employees, shall have full right and authority of ingress and egress at all reasonable times on and across the property at which the Applicant Facility is located, for the purpose of installing, operating, maintaining, inspecting, replacing, repairing, and removing the Interconnection Facilities. The right of ingress and egress shall not unreasonably interfere with Applicant's or (if different) Property Owner’s use of the property. 5.2 Utility may enter the property on which the Applicant Facility is located to inspect, at reasonable hours, Applicant’s protective devices and read or test meters. Utility will use reasonable efforts to provide Applicant or Property Owner, if applicable, at least 24 hours’ notice prior to entering said property, in order to afford Applicant or Property Owner the opportunity to remove any locks or other encumbrances to entry; provided, however, that Utility may enter the property without notice (removing, at Applicant’s expense, any lock or other encumbrance to entry) and disconnect the Interconnection Facilities if Utility believes that disconnection is necessary to address a hazardous condition and/or to protect persons, Utility’s facilities, or the property of others from damage or interference caused by Applicant Facility. 5.3 By executing this Agreement, Applicant and Property Owner consents to and agrees to provide access to its property, including all rights of ingress and Page 4 of 10 egress, on which the Applicant Facility is located to Utility as described in this section, but does not assume or guarantee other performance obligations of the Applicant under this Agreement. 6. Indemnity and Liability 6.1 To the extent permitted by law, Applicant covenants and agrees that it shall hold the Utility, and all of its agents, employees, officers and affiliates harmless for any claim, loss, damage, cost, charge, expense, lien, settlement or judgment, including interest thereon, whether to any person or property or both, arising directly or indirectly out of, or in connection with this Agreement or the Applicant Facility or equipment, to which the Utility or any of its agents, employees, officers or affiliates may be subject or put by reason of any act, action, neglect or omission on the part of the Utility or the Applicant or any of its contractors or subcontractors or any of their respective officers, agents, employees, and affiliates (excluding claims based on the Utility’s reckless or intentional misconduct). If this Agreement is one subject to the provisions of Michigan Act No. 165, PA 1966, as amended, then Applicant will not be liable under this section for damages arising out of injury or damage to persons or property directly caused or resulting from the sole negligence of the Utility, or any of its officers, agents or employees. 6.2 The indemnification obligations and limits on liability in this Section 6 shall continue in full force and effect notwithstanding the expiration or termination of this Agreement, with respect to any event or condition giving rise to an indemnification obligation that occurred prior to such expiration or termination. 7. Subcontractors Either Party may contract a subcontractor to perform its obligations under this Agreement and shall incorporate the obligations of this Agreement into its respective subcontracts, agreements and purchase orders. Each Party shall remain liable to the other Party for the performance of such subcontractor under this Agreement and shall fully defend, indemnify and hold the other Party harmless from all acts or omissions of its subcontractors. 8. Force Majeure Neither Party shall be liable for failure to perform any of its obligations hereunder, to the extent due to fire, flood, storm, other natural disaster, national emergency or war (referred to collectively as “Force Majeure”), and not due to labor problems, inability to obtain financing, negligence or other similar condition of such party, provided that either party has given the other prompt notice of such occurrence. The Party affected Page 5 of 10 shall exercise due diligence to remove such Force Majeure with reasonable dispatch, but shall not be required to accede or agree to any provision not satisfactory to it in order to settle and terminate a strike or other labor disturbance. 9. Default A default of this Agreement (“Default”) shall occur upon the failure of a Party to perform any material term or condition of this Agreement. Upon a Default by one Party, the non-defaulting Party shall give written notice of such Default to the defaulting Party. The Party in Default shall have thirty (30) days from the date of the written notice to cure the Default. If a Default is not cured within the thirty (30) day period provided for herein, the non-defaulting Party shall then have the right to cancel this Agreement by written notice and recover any damages, and/or pursue any other remedies available under this Agreement, by law, or in equity. Cancellation is not the non-defaulting Party’s exclusive remedy and is in addition to any other rights and remedies it may have under this Agreement or by law. Failure of non-defaulting Party to exercise any of its rights under this Section shall not excuse defaulting Party from compliance with the provisions of this Agreement nor prejudice rights of Company to recover damages for such default. 10. Retirement Upon termination or cancellation of this Agreement or at such time after any of the Interconnection Facilities described herein are no longer required, the Parties shall mutually agree upon the retirement of the Interconnection Facilities may include without limitation (i) dismantling, demolition, and removal of equipment, facilities, and structures, (ii) security, (iii) maintenance and (iv) disposing of debris. The cost of such removal shall be borne by the Party owning such Interconnection Facilities. 11. Governing Law This Agreement shall be interpreted, governed, and construed under the laws of Michigan. 12. Amendment, Modification or Waiver Any amendments or modifications to this Agreement shall be in writing and agreed to by both Parties. The failure of any Party at any time to require performance of any provision hereof shall in no manner affect its right at a later time to enforce the same. No waiver by any Party of the breach of any term or covenant contained in this Agreement, whether by conduct or otherwise, shall be deemed to be construed as a further or continuing waiver of any such breach or a waiver of the breach of any other term or covenant unless such waiver is in writing. Page 6 of 10 13. otices Any notice required under this Agreement shall be in writing and mailed or personally delivered to the Party at the address below. Written notice is effective within 3 days of depositing the notice in the United States mail, first class postage prepaid. Personal notice is effective upon delivery. Written notice of any address changes shall be provided. All written notices shall refer to the Applicant’s Utility account number, as provided in Section 1 of this Agreement. All written notices shall be directed as follows: Notice to Utility: Notice to Applicant: Notice to Property Owner (if different than Applicant): 14. Term of Agreement and Termination This Agreement shall become effective upon execution by all Parties and, if applicable, the Property Owner, and it shall continue in full force and effect until terminated upon thirty (30) days’ prior notice by either Party, upon Default of either Party as set forth in Section 9, upon mutual agreement of the Parties, or upon a change in ownership of either the Applicant Facility or the property at which the Applicant Facility is located absent a valid assignment under Section 17. 15. Entire Agreement This Agreement supersedes all prior discussions and agreements between the Parties with respect to the subject matter hereof and constitutes the entire agreement between the Parties hereto. 16. o Third Party Beneficiary The terms and provisions of this Agreement are intended solely for the benefit of each Party, and it is not the intention of the Parties to confer third-party beneficiary rights upon any other person or entity. 17. Assignment and Binding Effect Page 7 of 10 This Agreement shall not be assigned by a Party without the prior written consent of the other Party. Any attempt to do so will be void. Subject to the preceding, this Agreement is binding upon, inures to the benefit of, and is enforceable by the Parties and their respective successors and assigns. Applicant agrees to notify Utility in writing upon the sale or transfer of the Applicant Facility. This Agreement shall terminate upon such notice unless Utility consents to an assignment in writing. 18. Severability If any provision of this Agreement is determined to be partially or wholly invalid, illegal, or unenforceable, then such provision shall be deemed to be modified or restricted to the extent necessary to make such provision valid, binding, and enforceable; or, if such provision cannot be modified or restricted in a manner so as to make such provision valid, binding or enforceable, then such provision shall be deemed to be excised from this Agreement and the validity, binding effect, and enforceability of the remaining provisions of this Agreement shall not be affected or impaired in any manner. 19. Signatures The Parties to this Agreement hereby agree to have two originals of this Agreement executed by their duly authorized representatives. This Agreement is effective as of the later (or latest) of the dates set forth below. Page 8 of 10 20. Counterparts and Electronic Documents This Agreement may be executed and delivered in counterparts, including by a facsimile or an electronic transmission thereof, each of which shall be deemed an original. Any document generated by the parties with respect to this Agreement, including this Agreement, may be imaged and stored electronically and introduced as evidence in any proceeding as if original business records. Neither party will object to the admissibility of such images as evidence in any proceeding on account of having been stored electronically. UTILITY (Applicant) By: By: (Signature) (Signature) (Print or Type Name) (Print or Type Name) Title: Title: Date: Date: (Property Owner, if applicable) By: (Signature) (Print or Type Name) Title: Date: Page 9 of 10 EXHIBIT 1 INTERCONNECTION DIAGRAM (Insert one of the eighteen One-Line Diagrams (PDF file) for the various size and type of generator that will be installed.) Page 10 of 10 GENERATOR INTERCONNECTION & OPERATING AGREEMENT FOR CATEGORY 3-5 PROJECTS WITH AGGREGATE GENERATOR OUTPUT OF GREATER THAN 150 kW GENERATOR INTERCONNECTION & OPERATING AGREEMENT BETWEEN UTILITY NAME AND (APPLICANT NAME) Dated _________________, 200_ GENERATOR INTERCONNECTION & OPERATING AGREEMENT BETWEEN (UTILITY NAME) AND (APPLICANT NAME) Table of Contents SECTION 1 - INTERCONNECTION FACILITIES ......................................................................................... 2 1.1 General ............................................................................................................................................. 2 1.2 Applicant's Interconnection Facilities .................................................................................................... 2 1.3 Utility' Interconnection Facilities ............................................................................................................ 3 1.4 Easements and Permits ........................................................................................................................ 3 1.5 Relocation by Applicant ......................................................................................................................... 3 SECTION 2 - DESIGN AND CONSTRUCTION OF THE INTERCONNECTION FACILITIES ..................... 5 2.1 Authority for Construction ...................................................................................................................... 5 2.2 Coordination of Construction Program .................................................................................................. 5 2.3 Interconnection of the Project .............................................................................................................. 5 2.4 Parallel Operation of the Project With Utility' Distribution System ........................................................ 6 2.5 Subcontractors ...................................................................................................................................... 7 SECTION 3 - OPERATION AND MAINTENANCE ....................................................................................... 7 3.1 Operation and Maintenance By Utility ................................................................................................... 7 3.2 Operation and Maintenance By Applicant ............................................................................................. 9 SECTION 4 - ACCESS................................................................................................................................ 10 SECTION 5 - INTERCONNECTION POINT; POINT OF DELIVERY; METERING;TELEMETERING..=..10 5.1 Interconnection Point........................................................................................................................... 10 5.2 Point of Delivery .................................................................................................................................. 10 5.3 Metering 10 5.4 Telemetering ....................................................................................................................................... 11 SECTION 6 - SERVICE CONDITIONS ....................................................................................................... 11 6.1 Site Preparation ................................................................................................................................... 11 6.2 Parallel Operation ................................................................................................................................ 11 6.3 Voltage Control .................................................................................................................................... 11 6.4 System Security .................................................................................................................................. 12 6.5 Continuity of Service ........................................................................................................................... 12 6.7 Project Backup Power ......................................................................................................................... 12 6.7 Utility' Obligation to Connect ............................................................................................................... 12 SECTION 7 - INDEMNITY; INSURANCE ................................................................................................... 13 7.1 Indemnity 13 7.2 Insurance 13 SECTION 8 - LIMITATION ON LIABILITY .................................................................................................. 14 SECTION 9 - FORCE MAJEURE ............................................................................................................... 14 SECTION 10 - BREACH AND DEFAULT ................................................................................................... 15 SECTION 11 - SUCCESSORS AND ASSIGNS ......................................................................................... 16 E-i SECTION 12 - GOVERNING LAW ............................................................................................................. 16 SECTION 13 - EFFECTIVE DATE, TERM AND TERMINATION ............................................................... 16 SECTION 14 - RETIREMENT ..................................................................................................................... 16 SECTION 15 - ENTIRE AGREEMENT AND AMENDMENTS .................................................................... 17 SECTION 16 - NO PARTNERSHIP ............................................................................................................ 17 SECTION 17 - SEVERABILITY ................................................................................................................... 17 SECTION 18 - NOTICE TO PARTIES ........................................................................................................ 17 SECTION 19 - NO THIRD PARTY BENEFICIARIES ................................................................................. 18 SECTION 20 - SECTION HEADINGS ........................................................................................................ 18 EXHIBIT 1 - SCOPE OF FACILITIES..=============================19 EXHIBIT 2 - WIRING DIAGRAM===============================..20 E-ii GENERATOR INTERCONNECTION & OPERATING AGREEMENT BETWEEN -_________________ COMPANY AND (APPLICANT NAME) GENERATOR INTERCONNECTON & OPERATING AGREEMENT (hereinafter, this Agreement), is made and entered into as of the _________________ day of _______________, 200__, (hereinafter, the Effective Date), between [insert utility], a Michigan corporation, with offices located at (Address, City, State Zip),, herein termed "Utility”, and (APPLICANT NAME), with offices located at (Address, City, State Zip), herein termed "Applicant." Utility and Applicant are hereinafter sometimes referred to individually as "Party" and collectively as "Parties" where appropriate. WITNESSETH: WHEREAS, Utility owns electric facilities and is engaged in the generation, purchase, distribution and sale of electric energy in the State of Michigan; and WHEREAS, Applicant intends to construct and own a _________ plant, known as the ________________ Generating Plant, herein termed "Project", with a generator design capacity nameplate rating not to exceed _______ MW and located at (Address, City, State Zip); and WHEREAS, This Agreement does not address the sale of electricity to or from Utility; and WHEREAS, The Parties desire to enter into this Agreement for the purposes, among others, of (a) describing (i) the facilities and associated appurtenances to interconnect the Project to Utility’ distribution system, including defining the Point of Delivery and Interconnection Point, (ii) the facilities required for providing and regulating reactive power supply (kilovars) at the Project, and (iii) any modifications and additions necessary on Utility’ distribution system as a result of the operation of the Project; (b) establishing the ownership interests of Utility and Applicant in such facilities; (c) establishing the respective obligations and rights of the Parties with respect to the procurement, construction, installation, operation and maintenance of such facilities. NOW, THEREFORE, in consideration of the mutual covenants and agreements herein set forth, the Parties hereto agree as follows: E-1 SECTION 1 INTERCONNECTION FACILITIES 1.1 General The Parties shall provide, as specified in this Section 1, certain facilities and associated appurtenances required to interconnect the Project to Utility’s distribution system, consistent with the Michigan Electric Utility Generator Interconnection Requirements. Such facilities and associated appurtenances include, but shall not be limited to, interconnection, transformation, switching, control, metering, telemetering, protective relaying equipment (such protective relaying equipment required by Utility or Applicant to protect Utility’s distribution system, its customers, and the Project from electrical faults occurring at the Project or on Utility’s distribution system or on the systems of others to which Utility’ distribution system is directly or indirectly connected) and any necessary additions or reinforcements by Utility to Utility’s distribution system required as a result of the interconnection of the Project to Utility’s distribution system. The facilities and associated appurtenances described in Exhibit 1 – Scope of Facilities, Subsections 1.2, "Applicant's Interconnection Facilities," and 1.3, "Utility’s Interconnection Facilities," are hereinafter sometimes referred to as the "Interconnection Facilities." Applicant shall be responsible for the cost of the Interconnection Facilities, unless otherwise specified in this Agreement. The Project, configured as discussed in this Agreement and depicted in Exhibit 2 – Wiring Diagram, will be comprised of _____ generators with a total generation output of _______ MW, which can be connected to Utility’s distribution system as described herein. In the future, if the Applicant desires to install additional generating units at this present location, the Applicant must submit a written application to Utility. Utility will evaluate its distribution system to determine, in its sole discretion, if conditions at that time will allow said system to support additional capacity. In the event future changes in (a) the design or operation of the Project, (b) Federal, State or local laws, regulations, ordinances or codes, (c) Applicant's requirements (such as additional generators located at the site location identified above) or (d) Utility requirements necessitate additional facilities or modifications to the then existing Interconnection Facilities, the Parties shall undertake such additions or modifications as may be necessary. Before undertaking such future additions or modifications, the Parties shall consult, develop plans and coordinate schedules of activities so as to minimize disruption of the Interconnection Facilities and Utility’s distribution system. The cost of such future additions or modifications to the Interconnection Facilities shall be borne by the Applicant, unless agreed upon otherwise at the time. The ownership, operation and maintenance responsibilities for any such future additions or modifications shall be made consistent with the responsibilities allocated in this Agreement. 1.2 Applicant's Interconnection Facilities Applicant’s Interconnection Facilities and associated appurtenances are described in Subsection 1.2 of Exhibit 1 – Scope of Facilities. Applicant shall bear the cost of its Project unless otherwise specified in this Agreement. Applicant shall be solely responsible for all permits, zoning reviews, and other matters associated with E-2 obtaining rights from any governmental body or agency to construct its Project. Prior to Utility beginning construction of its Interconnection Facilities, Applicant shall provide a copy of all necessary documents granting Applicant the right to construct its Project. 1.3 Utility’ Interconnection Facilities Utility’ Interconnection Facilities and associated appurtenances are described in Subsection 1.3 of Exhibit 1 – Scope of Facilities. Applicant shall bear the cost of Utility’s Interconnection Facilities unless otherwise specified in this Agreement. Utility shall be responsible for all permits, zoning reviews, and other matters associated with obtaining rights from any governmental body or agency to construct its Interconnection Facilities. Applicant shall reimburse Utility for all costs associated with the installation and connection of Utility’s Interconnection Facilities. Applicant shall solely assume the risk that Utility may be unable to complete its Interconnection Facilities due to factors beyond its reasonable control. 1.4 Easements and Permits If necessary, prior to the installation of the Interconnection Facilities, Utility will acquire required permits and necessary easements for its Interconnection Facilities. These easements / permits may include, but shall not be limited to, rights of ingress and egress, rights to clear trees, and all necessary rights-of-way for installation and maintenance of Interconnection Facilities. The Applicant shall reimburse Utility for the costs and expenses Utility incurs in acquiring such easements / permits. 1.5 Relocation by Applicant If at any time the Applicant requires Utility’s Interconnection Facilities located on its premises to be relocated on such premises, Utility shall, at Applicant's expense and upon its request, relocate the same or give permission for Applicant to relocate the same. Applicant shall provide Utility with all necessary easement rights as required for the Interconnection Facilities located on Applicant’s premises. SECTION 2 DESIGN AND CONSTRUCTION OF THE INTERCONNECTION FACILITIES 2.1 Authority for Construction Except as provided in the following paragraph, Applicant will have sole authority to manage, design, supervise, construct, procure materials for, control and will take all steps which it deems necessary or appropriate for the installation of the Interconnection Facilities required pursuant to Subsection 1.2, "Applicant's Interconnection Facilities." The design, specifications, installation and construction of the Interconnection Facilities required pursuant to Subsection 1.2 shall be in accordance with standards no less stringent than those used by Utility for its own distribution voltage level installations and shall be inspected and commented on by E-3 Utility prior to being placed into initial operation. However, Utility has no liability, obligation or responsibility with respect to such design, plans, specifications, installation or construction regardless of its inspection and comment thereon. Inspection of and comments by Utility shall not relieve Applicant of any of its obligations under this Agreement. Utility shall exercise sole authority to manage, design, supervise, construct, procure materials for, control and take all steps which it deems necessary or appropriate for the installation and connection of the Interconnection Facilities required pursuant to Subsection 1.3, "Utility's Interconnection Facilities." 2.2 Interconnection of the Project Interconnection of the Project to Utility's distribution system shall be made after the following conditions have been satisfied: 2.2.1 Both Parties have declared their Interconnection Facilities ready for service; 2.2.2 Applicant has met the design, specifications, installation and construction requirements of the second paragraph of Subsection 2.1, Authority for Construction; 2.2.3 Applicant has provided adequate protective equipment to protect the equipment and service of Utility from damage or interruption from electrical faults occurring at the Project; 2.2.4 Utility has tested and accepted the billing meters and associated telemetry for the collection of the metered data required pursuant to Exhibit 1 – Scope of Facilities, Subsection 1.3; 2.2.5 Applicant and Utility have agreed to a procedure to describe the process (i) for switching and tagging the interconnection facilities for workers’ protection during periods when such equipment must be removed from service and (ii) for returning the equipment to service. Both Parties agree to follow the procedure for disconnecting and re-connecting the interconnection as outlined in Appendix F of the appropriate Michigan Electric Utility Generator Interconnection Requirements document; 2.2.6 If the Applicant requires backup power from Utility, the Applicant shall be responsible for contracting with Utility for the delivery of said backup power. The Applicant shall provide Utility satisfactory evidence that it has purchased the resources to supply backup power pursuant to Subsection 6.6, Project Backup Power; and 2.2.7 Applicant has reimbursed Utility for all costs associated with the installation of Utility’s Interconnection Facilities as identified in Subsection 1.3 and 1.4 2.3 Parallel Operation of the Project With Utility Distribution System Parallel operation of the Project with Utility' distribution system shall only begin after the following conditions have been satisfied and confirmed in writing by Utility to Applicant: E-4 2.3.1 Applicant has met all of the requirements of Subsection 2.2; 2.3.2 Applicant has obtained written approval by Utility of all protective relay equipment required pursuant to Exhibit 1 – Scope of Facilities, Subsection 1.2 and the direct transfer trip equipment required pursuant to Subsections 1.2 and 1.3 for the protection of Utility's distribution system. Approval will be granted after the required protective relay equipment is inspected and calibrated in accordance with the relay setting data issued by Utility. Inspection and calibration must be either performed or witnessed by Utility personnel at Applicant's expense. Applicant must record the actual settings and inspection data on the relay-setting document furnished by Utility and return such document to Utility for approval; 2.3.3 Applicant has developed operating and maintenance procedures, which Utility has accepted in writing, for those protective devices which directly connect to Utility’ distribution system or interface with Utility protective devices; 2.3.4 Utility has tested and accepted the telemetry / SCADA interface and concurs they meet the technical requirements as identified in the Telemetry and Disturbance Monitoring Requirements Section and the Communication Circuits Section of the Michigan Electric Utility Generator Interconnection Requirements. Testing must be performed by Utility’s personnel at Applicant’s expense and acceptance will be communicated to Applicant in writing; and 2.3.5 Applicant has developed operating procedures to manually trip generation for system security pursuant to Subsection 6.4, System Security. 2.4 Subcontractors Either Party may hire a subcontractor to perform its obligations under this Agreement and shall incorporate the obligations of this Agreement into its respective subcontracts, agreements and purchase orders. Each Party shall remain liable to the other Party for the performance of such subcontractor under this Agreement and shall fully defend, indemnify and hold the other Party harmless from all acts or omissions of its subcontractors. SECTION 3 OPERATION AND MAINTENANCE 3.1 Operation and Maintenance By Utility Utility shall have sole authority and responsibility to operate and maintain Utility Interconnection Facilities required pursuant to Subsection 1.3, and in accordance with the applicable good utility practice standards of Utility. Utility may manually operate, when necessary, Utility's Interconnection Facilities and E-5 the isolation device provided by Applicant pursuant to Exhibit 1 – Scope of Facilities, Subsection 1.2, and may perform preventive or emergency maintenance, or make system modifications, when necessary, on Utility Interconnection Facilities. Normal maintenance shall be scheduled on Utility's Interconnection Facilities taking into consideration Applicant's schedule of maintenance for the Project. Such authority and responsibility shall include removing the Interconnection Facilities from service, when necessary, as determined by Utility. Utility shall not be required to deliver energy to the Project or provide a temporary connection to the Project when maintenance or system modifications require disconnecting Utility’s Interconnection Facilities from Utility's distribution system. 3.1.1 Applicant shall reimburse Utility for all direct and indirect costs and expenses (including but not limited to, overtime pay, property taxes, insurance, equipment testing and inspections) incurred by Utility in owning, operating and maintaining Utility’ Interconnection Facilities from the point in time in which Utility’s Interconnection Facilities are ready for service. Such costs and expenses shall be determined by Utility in accordance with the standard practices and policies followed by Utility and in effect at the time such operation and maintenance is performed. As used in this Agreement, the term "maintenance" includes inspection, repair and replacement. Payment by Applicant of such costs and expenses shall be made in accordance with Subsection 3.1.4. In the event that Utility uses any part of Utility’s Interconnection Facilities defined in Subsection 1.3 for the benefit of Utility's customers, then the allocation of the ongoing costs and expenses which are due to the ownership, operation and maintenance of Utility’ Interconnection Facilities provided pursuant to Subsection 1.3, shall be redetermined with consideration for possible changes in: (a) Point of Delivery, (b) metering location, (c) operation and maintenance costs to Applicant to new Point of Delivery, if any, and (d) compensation to Utility for appropriate operating and maintenance costs from the new Point of Delivery, if any. Utility shall not be restricted in the use of Utility’s Interconnection Facilities while such redetermination is being made. 3.1.2 If Utility performs the following tasks on the Applicant’s behalf, the Applicant shall reimburse Utility for costs associated with (a) testing of metering and associated telemetry required pursuant to Subsection 2.2.4, (b) the relay setting information, inspection and calibration required pursuant to Subsection 2.3.2 and (c) the testing of the dispatching interface required pursuant to Subsection 2.3.4, which shall be separately billed. 3.1.3 Applicant shall be solely responsible for ordering, acquiring and all continuing operating expenses associated with the telephone circuits pursuant Exhibit 1 – Scope of Facilities, Subsection 1.2. as well as the proper safety equipment required for the proper installation of said telephone circuits. Additional operation and maintenance expenses associated E-6 with telemetry facilities are the responsibility of the Applicant pursuant to Subsection 5.4. 3.1.4 Payments by Applicant of the costs and expenses described in Subsections 3.1.1 and 3.1.2 are as follows: 3.1.4.1 As soon as practicable after the end of each month in which operation and maintenance costs and expenses were incurred by Utility pursuant to Subsection 3.1.1 and 3.1.2, Utility shall furnish Applicant a statement describing the work performed or expense incurred and showing the amount of the payment to be made therefore by Applicant. 3.1.4.2 Each statement shall be paid by Applicant so that Utility will receive the funds by the 20th day following the date of such statement, or the first business day thereafter if the payment date falls on a non-business day. 3.1.4.3 All payments shall be made payable to ________________ and shall be sent to Utility, Attention: __________________________, or by wire transfer to a Utility bank account or such other manner or at such place as Utility shall, from time to time, designate by written notice to Applicant. Payments made by wire transfer shall reference the appropriate invoice number for which payment is being made. 3.1.4.4 Any payment not made on or before the due date shall bear interest, from the date due until the date upon which payment is made, at an annual percentage rate of interest equal to the lesser of (a) the prime rate published by the Wall Street Journal (which represents the base rate on corporate loans posted by at least 75% of the nation's banks) on the date due, plus 2%, or (b) the highest rate permitted by law. 3.2 Operation and Maintenance By Applicant Except as provided in Subsections 2.3.2 and 3.1 and the provisions of this Subsection 3.2, Applicant shall have sole authority and responsibility to operate and maintain the Applicant’s Interconnection Facilities required pursuant to Subsection 1.2 in accordance with prudent industry practices. Relay settings, for protective devices required by Utility, may be revised and documents stating such revisions may be issued by Utility if it determines that it is necessary to do so. The settings for these devices may be revised only if Utility issues documents specifying such revisions. In such event, the protective relay equipment shall be recalibrated by Applicant in accordance with such revised relay settings within a reasonable period specified by Utility. The procedure for recalibration and approval shall be the same as stated for the initial calibration pursuant to Subsection 2.3.2. The protective relay equipment shall be tested every two (2) years (unless an extension is E-7 agreed to by Utility) to verify the calibration indicated on the latest relay setting document issued by Utility. If the protective relay equipment is not calibrated in accordance with the latest relay-setting document, it shall be recalibrated in accordance with Subsection 2.3.2, to conform with such data. Tests shall be conducted or witnessed by Utility at Applicant's expense. The results of such tests shall be provided to Utility in writing for review and approval. Utility may, at any time in addition to that specified in the preceding paragraph, at Utility's expense, inspect and test Applicant's Interconnection Facilities to verify that the required protective interconnection equipment is in service, properly maintained, and calibrated to provide the intended protection. If necessary, this inspection may also include a review of Applicant's pertinent records. Inspection, testing and/or approval by Utility or the omission of any inspection, testing and/or approval by Utility pursuant to this Agreement shall not relieve Applicant of any obligations or responsibility assumed under this Agreement. SECTION 4 ACCESS Utility, its agents and employees, shall have full right and authority of ingress and egress at all reasonable times on and across the premises of Applicant for the purpose of installing, operating, maintaining, inspecting, replacing, repairing, and removing its Interconnection Facilities located on the premises. The right of ingress and egress, however, shall not unreasonably interfere with Applicant's use of its premises. SECTION 5 INTERCONNECTION POINT; POINT OF DELIVERY; METERING; TELEMETERING 5.1 Interconnection Point The Interconnection Point shall be where the Applicant’s Interconnection Facilities connect to Utility’s distribution system. 5.2 Point of Delivery If the Project is connected to a distribution line serving other customers, the Point of Delivery shall be at the high voltage side of the Project-supplied isolation transformer connecting the Project to Utility’s distribution system. Otherwise, the Point of Delivery shall be the point at which the radial line connecting the Project to Utility’s distribution system terminates at the first substation beyond the Project’s isolation transformer. E-8 5.3 Metering Measurements of electric energy deliveries shall be made by standard types of electric meters installed and maintained by Utility pursuant to Exhibit 1 – Scope of Facilities, Subsection 1.3. The standard electric meters shall be tested by Utility at least once every six (6) years. On request and at the expense of the Applicant, a special test may be performed. Representatives of Applicant shall be afforded the opportunity to be present at all routine or special tests and upon occasions when any readings, for purposes of settlements, are taken from meters not bearing an automatic record. 5.4 Telemetering Certain telemetry facilities will be provided by Utility pursuant to Exhibit 1 – Scope of Facilities, Subsection 1.3 as a part of the Interconnection Facilities as being necessary for the proper and efficient collection of metering and control data. The cost and maintenance of such telemetry facilities and associated phone lines shall be borne by Applicant. SECTION 6 SERVICE CONDITIONS 6.1 Site Preparation At its own expense, the Applicant shall make the proposed Project site available to Utility. Said site shall be free from hazard and shall be adequate for the operation and construction of distribution facilities necessary to interconnect the proposed Project. 6.2 Parallel Operation It is understood that the Project will normally remain connected to and be operated in parallel with Utility's distribution system. The Applicant shall, at its expense, install and properly maintain protective equipment and devices and provide sufficiently trained personnel to protect its equipment and service, and the equipment and service of Utility from damage, injury or interruptions during the Project’s parallel operation with Utility' distribution system, and, without limiting the indemnity provided in Subsection 7.1 herein, Applicant shall assume any loss, liability or damage to Applicant and Utility’s distribution system and equipment caused by lack of or failure of such protection. Such protective equipment specifications and design shall be consistent with the Michigan Electric Utility Industry Generator Interconnection Requirements, and any successor and/or supplement thereto. Prior to the Project operating in parallel with Utility’s distribution system, the Applicant shall provide satisfactory evidence to Utility that it has met the Michigan Electric Utility Generator Interconnection Requirements that are on file with the Michigan Public Service Commission and complied with all applicable laws, rules, regulations, guidelines, and safety standards. E-9 6.3 Voltage Control Applicant shall cooperate with Utility to regulate the voltage level at the Point of Delivery by controlling its generators in accordance with Utility instructions. Such instructions shall include, but not be limited to, (a) maintaining voltage or (b) delivering real and reactive power to the Point of Delivery at levels specified by Utility. The instructions given by Utility shall be consistent with the normal practices adhered to by Utility with respect to its own generators located on its system. 6.4 System Security Installation, inspection, and calibration of relaying to trip generation for under- or over-frequency operation shall be coordinated with Utility, pursuant to Subsection 2.3.2, so as not to degrade the security of Utility's distribution system. Operating practices developed by Applicant which call for manual tripping of generation for under-or over-frequency operation shall likewise be coordinated and be consistent with the provisions of East Central Area Reliability Document 3, “Emergency Procedures – During a Declining System Frequency”, and any successor and/or supplemental documents, which are incorporated herein by reference. 6.5 Continuity of Service Each Party shall exercise reasonable care to maintain continuity of service in the delivery and receipt of electric energy. If service becomes interrupted for any reason, the cause of such interruption shall be removed and normal operating conditions restored as soon as practicable. 6.6 Project Backup Power If the Applicant requires backup power from Utility, the Applicant will contract with Utility for the delivery of power provided to the Project under one of Utility's established retail rates set forth in Utility’s tariffs, which are incorporated herein by reference. The provisions of such contract shall be applied during periods when the Project is not delivering energy to Utility. The Applicant will contract with Utility for the purchase of energy or provide satisfactory evidence of the purchase of energy from an alternative electric supplier for the purpose of providing power to the Project during periods when the Project is not delivering energy to Utility’s distribution system. Applicant shall have sufficient voltage regulation at the Project to maintain an acceptable voltage level for Project equipment during such periods when the Project's generation is off-line. 6.7 Utility's Obligation to Connect Utility shall not be obligated to continue the electrical interconnection to the Project if it determines, in its sole discretion, that any one or more of the following conditions exist, including but not limited to: (a) those conditions listed in the Miscellaneous Operational Requirements section of the Michigan Electric Utility Generator Interconnection Requirements, (b) electrical characteristics of the E-10 Project are not compatible with the electrical characteristics of Utility' distribution system, (c) the Applicant is deficient in following either the voltage schedule or reactive power schedule established by Utility, (d) an emergency condition exists on Utility distribution system, (e) Applicant's protective relay equipment fails, resulting in a lack of the level of protection required by prudent utility practice, (f) the Applicant’s Project is determined to be disrupting Utility customers (g) Utility requires disconnection of the Project in order to construct, install, maintain, repair, replace, remove, investigate, inspect or test any part of Utility’s Interconnection Facilities or any other Utility equipment associated with the interconnection (also if a required component (example: phone line) or required modification to allow interconnection fails or becomes incapacitated and is not repaired in a timely manner), (h) by mutual consent, (i) Applicant commits a default or material breach of this agreement or (j) Applicant’s failure to execute this agreement or upon cancellation or termination of this agreement. Utility shall electrically connect or reconnect its distribution system to the Project when, in Utility's sole opinion, the conditions named above cease to exist. Under any of the conditions listed above, Utility will follow the procedures for disconnecting and reconnecting the interconnection as outlined in Appendix F of the appropriate Michigan Electric Utility Generator Interconnection Requirements document. SECTION 7 INDEMNITY; INSURANCE 7.1 Indemnity To the extent permitted by law, Applicant covenants and agrees that it shall hold the Utility, and all of its agents, employees, officers and affiliates harmless for any claim, loss, damage, cost, charge, expense, lien, settlement or judgment, including interest thereon, whether to any person or property or both, arising directly or indirectly out of, or in connection with this Agreement, the Project, or any of Applicant’s facilities and associated appurtenances, to which the Utility or any of its agents, employees, officers or affiliates may be subject or put by reason of any act, action, neglect or omission on the part of the Utility or the Applicant or any of its contractors or subcontractors or any of their respective officers, agents, employees, and affiliates (excluding claims based on the Utility’s reckless or intentional misconduct). If this Agreement is one subject to the provisions of Michigan Act No. 165, PA 1966, as amended, then Applicant will not be liable under this section for damages arising out of injury or damage to persons or property directly caused or resulting from the sole negligence of the Utility, or any of its officers, agents or employees. The provisions of this Subsection 7.1 shall survive termination or expiration of this Agreement. E-11 7.2 Insurance Applicant shall obtain and continuously maintain throughout the term of this Agreement General Liability insurance written on a standard occurrence form, or other form acceptable to Utility, and covering bodily injury and property damage liability with a per occurrence and annual policy aggregate amount of at least: Minimum Limit $1,000,000 When requested in writing by Utility, said limit shall be increased each year that this Agreement is in force to a limit no greater than the amount arrived at by increasing the original limit by the same percentage change as the Consumer Price Index - All Urban Workers (CPI-U.S. Cities Average). Such policy shall include, but not be limited to, contractual liability for indemnification assumed by Applicant under this Agreement. Utility shall be named as an additional insured under such policy. The policy shall be primary coverage with no contribution from any insurance maintained by Utility. Utility shall not be responsible for any unpaid premiums under Applicant policy. Evidence of insurance coverage on a certificate of insurance shall be provided to Utility upon execution of this Agreement and thereafter within ten (10) days after expiration of coverage; however, if evidence of insurance is not received by the 11th day, Utility has the right, but not the duty, to purchase the insurance coverage required under this Section and to charge the annual premium to Applicant. Utility shall receive thirty (30) days advance written notice if the policy is cancelled or substantial changes are made that affect the additional insured. At Utility' request, Applicant shall provide a copy of the policy to Utility. All certificates and notices shall be mailed to:_________________________ . SECTION 8 LIMITATION ON LIABILITY NEITHER PARTY SHALL IN ANY EVENT BE LIABLE TO THE OTHER FOR ANY INCIDENTAL OR CONSEQUENTIAL DAMAGES SUCH AS, BUT NOT LIMITED TO, LOST PROFITS, REVENUE OR GOOD WILL, INTEREST, LOSS BY REASON OF SHUTDOWN OR NON-OPERATION OF EQUIPMENT OR MACHINERY, INCREASED EXPENSE OF OPERATION OF EQUIPMENT OR MACHINERY, COST OF PURCHASED OR REPLACEMENT POWER OR SERVICES OR CLAIMS BY CUSTOMERS, WHETHER SUCH LOSS IS BASED ON CONTRACT, WARRANTY, NEGLIGENCE, STRICT LIABILITY OR OTHERWISE. EVEN IF IT HAS BEEN ADVISED OF THE POSSIBILITY OF SUCH DAMAGES. E-12 SECTION 9 FORCE MAJEURE Neither Party shall be liable for failure to perform any of its obligations hereunder, to the extent due to fire, flood, storm, other natural disaster, national emergency or war (referred to collectively as “Force Majeure”), and not due to labor problems, inability to obtain financing, negligence or other similar condition of such party, provided that either party has given the other prompt notice of such occurrence. The Party affected shall exercise due diligence to remove such Force Majeure with reasonable dispatch, but shall not be required to accede or agree to any provision not satisfactory to it in order to settle and terminate a strike or other labor disturbance. SECTION 10 DEFAULT A default of this Agreement (“Default”) shall occur upon the failure of a Party to perform or observe any material term or condition of this Agreement, which includes, but is not limited to: a. Failure to pay money when due; b. Failure to comply with any material term or condition of this Agreement, including but not limited to any breach of any material representation, warranty or covenant made in this Agreement; c. A Party: (i) becomes insolvent; (b) files a voluntary petition in bankruptcy under any provision of any federal of state bankruptcy law or shall consent to the filing of any bankruptcy or reorganization petition against it under any similar law; (c) makes a general assignment for the benefit of its creditors or (d) consents to the appointment of a receiver, trustee or liquidator; d. Assignment of this Agreement in a manner inconsistent with the terms of this Agreement; e. Failure of either Party to provide information or data to the other Party as required under this Agreement, provided the Party entitled to the information or data under this Agreement requires such information or data to satisfy its obligations under this Agreement. In the event of a Default by either Party, the Parties shall continue to operate and maintain, as applicable, its Interconnection Facilities, protection and Metering Equipment, transformers, communication equipment, building facilities, software, documentation, structural components and other facilities and appurtenances that are reasonably necessary for Utility to operate and maintain Utility’ distribution system and for the Applicant to operate and maintain its Project in a safe and reliable manner. Upon a Default, the non-defaulting Party shall give written notice of such Default to the defaulting Party. The defaulting Party then has 30 days to cure the Default. If a Default is not cured within the period provided for herein or as agreed to by the Parties, the non-defaulting Party shall have the right to terminate this Agreement and, recover any damages, and/or pursue any other remedies available under this Agreement, by law, or in equity. Termination is not the non-defaulting Party’s exclusive remedy and is in addition to any other rights and remedies it may have under this Agreement or by law. Failure of nondefaulting Party to exercise any of its rights under this Section shall not excuse defaulting Party from E-13 compliance with the provisions of this Agreement nor prejudice rights of Utility to recover damages for such default. SECTION 11 SUCCESSORS AND ASSIGNS This Agreement shall inure to the benefit of and be binding upon the successors and assigns of the respective Parties hereto. This Agreement shall not be assigned, transferred or otherwise alienated without the other Party's prior written consent, which consent shall not unreasonably be withheld. Any attempted assignment, transfer or alienation without such written consent shall be void. SECTION 12 GOVERNING LAW This Agreement shall be deemed to be a Michigan contract and shall be construed in accordance with and governed by the laws of Michigan, exclusive of its conflict of laws principles. SECTION 13 EFFECTIVE DATE, TERM AND TERMINATION The Effective Date of this Agreement shall be the date of execution and shall continue in effect until this Agreement is terminated as provided herein. The Agreement may be terminated at any time by mutual agreement of both Parties, or by either Party upon giving the other at least ninety (90) days written notice if one or more of the conditions exist as outlined in Subsection 6.7, Utility’ Obligation to Connect. SECTION 14 RETIREMENT Upon termination of this Agreement pursuant to Section 13 or at such time after any of the Interconnection Facilities described herein are no longer required, the Parties shall mutually upon the retirement of said Interconnection Facilities which may include without limitation (i) dismantling, demolition, and removal of equipment, facilities, and structures, (ii) security, (iii) maintenance and (iv) disposing of debris. The cost of such removal shall be borne by the Party owning such Interconnection Facilities. E-14 SECTION 15 ENTIRE AGREEMENT AND AMENDMENTS This Agreement and the appropriate Michigan Electric Utility Generator Interconnection Requirements shall constitute the entire understanding between the Parties with respect to the subject matter hereof, supersedes any and all previous understandings between the Parties with respect to the subject matter hereof, and bind and insure to the benefit of the Parties, their successors, and permitted assigns. No amendments or changes to this Agreement shall be binding unless made in writing and duly executed by both Parties. SECTION 16 NO PARTNERSHIP This Agreement shall not be interpreted or construed to create an association, joint venture, agency relationship, or partnership between the Parties or to impose any partnership obligation or partnership liability upon either Party. Neither Party shall have any right, power or authority to enter into any agreement or undertaking for, or act on behalf of, or to act as or be an agent or representative of, or to otherwise bind, the other Party. SECTION 17 SEVERABILITIY If any provision or portion of this Agreement shall for any reason be held or adjudged to be invalid or illegal or unenforceable by any court of competent jurisdiction or other Governmental Authority, (1) such portion or provision shall be deemed separate and independent, (2) the Parties shall negotiate in good faith to restore insofar as practicable the benefits to each Party that were affected by such ruling, and (3) the remainder of this Agreement shall remain in full force and effect. SECTION 18 NOTICE TO PARTIES Unless otherwise provided in this Agreement, any notice, consent or other communication required to be made under this Agreement, shall be in writing and (i) mailed postage prepaid, by certified or registered mail, return receipt requested; (ii) mailed via a nationally recognized overnight delivery service, or (iii) delivered in person to the address as the receiving Party may designate in writing. E-15 All notices shall be effective when received. SECTION 19 NO THIRD PARTY BENEFICIARIES This Agreement is intended for the benefit of the Parties hereto and does not grant any rights to any third parties unless otherwise specifically stated herein. SECTION 20 SECTION HEADINGS The various headings set forth in this Agreement are for convenience of reference only and shall in no way affect the construction or interpretation of this Agreement. IN WITNESS WHEREOF, the Parties hereto have executed this Agreement. UTILITY By ________________________________ Title_______________________________ Date ______________________________ (APPLICANT’S NAME) By ______________________________ Title______________________________ Date ______________________________ Review and Approval E-16 EXHIBIT 1 SCOPE OF FACILITIES 1.1 General Facilities Such facilities and associated appurtenances as required to interconnect Utility existing ___________________ - ______________________ distribution line to the Applicant’s new / modified ________ MW Project by way of a new or modified interconnection, which shall include, but shall not be limited to the following: 1.2 Applicant’s Interconnection Facilities (Identify Applicant’s Interconnection Facilities here) 1.3 Utility Interconnection Facilities (Identify Utility Interconnection Facilities here) E-17 EXHIBIT 2 WIRING DIAGRAM (Insert PDF file here!) E-18 GENERATOR INTERCONNECTION APPLICATION FOR ALL PROJECTS WITH AGGREGATE GENERATOR OUTPUT OF MORE THAN 20 KW BUT LESS THAN OR EQUAL TO 150 KW Also Serves as Application for Category 2 Net Metering (Note: Category 2 Net Metering Program only available to Renewable Generator Projects) Electric Utility Contact Information Utility Name Interconnection Coordinator Utility Street Address Utility Street Address Interconnection Hotline: XXX.XXX.XXXX Interconnection Email: XXX@XXXXXX For Office Use Only Application No._______________ Date & Time Application Received Customer / Account Information Electric Utility Customer Information: ( As shown on utility bill ) Customer Name ( Last, First, Middle): Customer Mailing Address: Customer E-Mail Address: ( optional ) Electric Service Account # Electric Service Meter Number: Are you applying for the Net Metering Program? Yes No Are you interested in selling Renewable Energy Credits (REC's) Yes No Will you have an Alternative Electric Supplier? Notes: Enter name ONLY if your energy is supplied by a 3rd party, not the utility. You must apply to both the Distribution Utility and your Alternate Energy Provider (if applicable) for Net Metering Yes No Alternative Electric Supplier Name Generation System Site Information Physical Site Service Address (if not Billing Address): Annual Site Requirements Without Generation in Kilowatthours kWh/year Peak Annual Site Demand in Kilowatts (only for customers billed on demand rates) kW/year Attached Site Plan: Page # Attached Electrical One-Line Drawing (See the Appendix D for a sample Inverter Type Project) (Per MPSC Order in Case No. U-15787- The one-line diagram must be signed and sealed by a licensed professional engineer, licensed in the State of Michigan or by an electrical contractor licensed by the State of Michigan with the electrical contractor's license number noted on the diagram.) Page # Synchronous/Induction Generators: Must fill out Appendix A or B and provide a Detail One-Line Diagram See Appendix E and F for a sample the Detail One-Line Diagram for Synchronous or Induction projects Note: The following information on these system components shall appear on the preliminary Detail One-Line Diagram Page # • • • • • • • • • • • • • • Breakers - Rating, location and normal operating status (open or closed) Buses - Operating voltage Capacitors - Size of bank in Kvar Circuit Switchers - Rating, location and normal operating status (open or closed) Current Transformers - Overall ratio, connected ratio Fuses - normal operating status, rating (Amps), type Generators - Capacity rating (kVA), location, type, method of grounding Grounding Resistors - Size (ohms), current (Amps) Isolating transformers - Capacity rating (kVA), location, impedance, voltage ratings, primary and secondary connections and method of grounding Potential Transformers - Ratio, connection Reactors - Ohms/phase Relays - Types, quantity, IEEE device number, operator lines indicating the device initiated by the relays. Switches - Location and normal operating status (open or closed), type, rating Tagging Point - Location, identification GENERATOR INTERCONNECTION APPLICATION FOR ALL PROJECTS WITH AGGREGATE GENERATOR OUTPUT OF MORE THAN 20 KW BUT LESS THAN OR EQUAL TO 150 KW Also Serves as Application for Category 2 Net Metering (Note: Category 2 Net Metering Program only available to Renewable Generator Projects) Generation System - Manufacturer Information System Type ( Solar, Wind, Biomass, Methane Digester, etc ): Generator Type ( Inverter, Induction, Synchronous ): Generator Nameplate Rating: kW Expected Annual Output in Kilowatthours kWh/year A.C. Operating Voltage: Wiring Configuration ( Single Phase, Three Phase ): Certified Test Record No.(Testing to standard UL1741 scope 1.1a) Inverter Based Systems: Manufacturer Model ( Name / Number ) Inverter Power Rating (kW) Induction & Synchronous Based Systems Manufacturer Model ( Name / Number ) Installation Information Project Single Point of Contact: ( Electric Utility Customer, Developer, or other ) Name: Company ( If Applicable ): Phone Number: E-Mail Address: Requested In Service Date: Licensed Contractor ( Name of Firm or Self ): Contractor Name ( Last, First, MI ): Contractor Phone #: Contractor E-Mail: Customer and Contractor Signature and Fees Attached $100 Interconnection Application Fee or Attached $100 combined Interconnection & Net Metering Program application fees ($75 Interconnection Application Fee plus $25 fee required if selecting net metering) (Check # / Money Order # ) ( Sign and Return complete application with Application Fee to Electric Utility Contact ) To the best of my knowledge, all the information provided in this Application Form is complete and correct. ________________________________________ Customer _________________________________________________ Project Developer/Contractor (If Applicable) Note: Refer to the applicable "Michigan Electric Utility Generator Interconnection Requirements" for a detailed explanation of the Interconnection Process, Fees, Timelines, and Technical Requirements. APPENDIXES Appendix A: Technical Information for Synchronous-Type Generators Appendix B: Technical Information for Induction-Type Generators Appendix C: Sample Site Plan Appendix D: Sample One-Line diagram for Inverter Type Project Appendix E: Sample One-Line diagram for Synchronous Type Project Appendix F: Sample One-Line diagram for Induction Type Project Appendix A Synchronous Generators Generator Information a. Generator Nameplate Voltage a. b. Generator Nameplate Watts or Volt-Amperes b. c. Generator Nameplate Power Factor (pf) c. d. RPM d. Technical Information e. Minimum and Maximum Acceptable Terminal Voltage e. f. Direct axis reactance (saturated) f. g. Direct axis reactance (unsaturated) g. h. Quadrature axis reactance (unsaturated) h. i. Direct axis transient reactance (saturated) i. j. Direct axis transient reactance (unsaturated) j. k. Quadrature axis transient reactance (unsaturated) k. l. Direct axis sub-transient reactance (saturated) l. m. Direct axis sub-transient reactance (unsaturated) m. n. Leakage Reactance n. o. Direct axis transient open circuit time constant o. p. Quadrature axis transient open circuit time constant p. q. Direct axis subtransient open circuit time constant q. r. Quadrature axis subtransient open circuit time constant r. s. Open Circuit saturation curve s. t. Reactive Capability Curve showing overexcited and underexcited limits (Reactive Information if non-synchronous) t. u. Excitation System Block Diagram with values for gains and time constants (Laplace transforms) u. v. Short Circuit Current contribution from generator at the Point of Common Coupling v. w. Rotating inertia of overall combination generator, prime mover, couplers and gear drives w. x. Station Power load when generator is off-line, Watts, pf x. y. Station Power load during start-up, Watts, pf y. z. Station Power load during operation, Watts, pf z. Appendix B Induction Generators Generator Information a. Generator Nameplate Voltage a. b. Generator Nameplate Watts or Volt-Amperes b. c. Generator Nameplate Power Factor (pf) c. d.RPM d. Technical Information e. Synchronous Rotational Speed e. f. Rotation Speed at Rated Power f. g. Slip at Rated Power g. h. Minimum and Maximum Acceptable Terminal Voltage h. i. Motoring Power (kW) i. j. Neutral Grounding Resistor (If Applicable) j. k. I22t or K (Heating Time Constant) k. l. Rotor Resistance l. m. Stator Resistance m. n. Stator Reactance n. o. Rotor Reactance o. p. Magnetizing Reactance p. q. Short Circuit Reactance q. r. Exciting Current r. s. Temperature Rise s. t. Frame Size t. u. Design Letter u. v. Reactive Power Required in Vars (No Load) v. w. Reactive Power Required in Vars (Full Load) w. x. Short Circuit Current contribution from generator at the Point of Common Coupling x. y. Rotating inertia, H in Per Unit on kVA Base, of overall combination generator, prime mover, couplers and gear drives y. z. Station Power load when generator is off-line, Watts, pf z. aa. Station Power load during start-up, Watts, pf aa. bb. Station Power load during operation, Watts, pf bb. Appendix C Sample Site Plan Appendix D Inverter Generators One - Line Diagram Name of the Licensed Contractor /PE_____________________ Contractor License Number ___________________________ Address ____________________________________________ Signature___________________________________________ Appendix E (ot Required for Flow-Back) One - Line Diagram Name of the Licensed Contractor /PE_____________________ Contractor License Number ___________________________ Address ____________________________________________ Signature___________________________________________ Appendix F (ot Required for Flow-Back) One - Line Diagram Name of the Licensed Contractor /PE_____________________ Contractor License Number ___________________________ Address ____________________________________________ Signature___________________________________________ GENERATOR INTERCONNECTION APPLICATION FOR ALL PROJECTS WITH AGGREGATE GENERATOR OUTPUT OF MORE THAN 20 KW BUT LESS THAN OR EQUAL TO 150 KW Electric Utility Contact Information Utility Name Interconnection Coordinator Utility Street Address Utility Street Address Interconnection Hotline: XXX.XXX.XXXX Interconnection Email: XXX@XXXXXX For Office Use Only Application No._______________ Date & Time Application Received Customer / Account Information Electric Utility Customer Information: ( As shown on utility bill ) Customer Name ( Last, First, Middle): Customer Mailing Address: Customer E-Mail Address: ( optional ) Electric Service Account # Electric Service Meter Number: Yes Are you interested in selling Renewable Energy Credits (REC's) No Generation System Site Information Physical Site Service Address (if not Billing Address): Annual Site Requirements Without Generation in Kilowatthours kWh/year Peak Annual Site Demand in Kilowatts (only for customers billed on demand rates) kW/year Attached Site Plan: Page # Attached Electrical One-Line Drawing (See the Appendix D for a sample Inverter Type Project) (Per MPSC Order in Case No. U-15787- The one-line diagram must be signed and sealed by a licensed professional engineer, licensed in the State of Michigan or by an electrical contractor licensed by the State of Michigan with the electrical contractor's license number noted on the diagram.) Page # Synchronous/Induction Generators: Must fill out Appendix A or B and provide a Detail One-Line Diagram See Appendix E and F for a sample the Detail One-Line Diagram for Synchronous or Induction projects Note: The following information on these system components shall appear on the preliminary Detail One-Line Diagram Page # • • • • • • • • • • • • • • Breakers - Rating, location and normal operating status (open or closed) Buses - Operating voltage Capacitors - Size of bank in Kvar Circuit Switchers - Rating, location and normal operating status (open or closed) Current Transformers - Overall ratio, connected ratio Fuses - normal operating status, rating (Amps), type Generators - Capacity rating (kVA), location, type, method of grounding Grounding Resistors - Size (ohms), current (Amps) Isolating transformers - Capacity rating (kVA), location, impedance, voltage ratings, primary and secondary connections and method of grounding Potential Transformers - Ratio, connection Reactors - Ohms/phase Relays - Types, quantity, IEEE device number, operator lines indicating the device initiated by the relays. Switches - Location and normal operating status (open or closed), type, rating Tagging Point - Location, identification GENERATOR INTERCONNECTION APPLICATION FOR ALL PROJECTS WITH AGGREGATE GENERATOR OUTPUT OF MORE THAN 20 KW BUT LESS THAN OR EQUAL TO 150 KW Also Serves as Application for Category 2 Net Metering (Note: Category 2 Net Metering Program only available to Renewable Generator Projects) Generation System - Manufacturer Information System Type ( Solar, Wind, Biomass, Methane Digester, etc ): Generator Type ( Inverter, Induction, Synchronous ): Generator Nameplate Rating: kW Expected Annual Output in Kilowatthours kWh/year A.C. Operating Voltage: Wiring Configuration ( Single Phase, Three Phase ): Certified Test Record No.(Testing to standard UL1741 scope 1.1a) Inverter Based Systems: Manufacturer Model ( Name / Number ) Inverter Power Rating (kW) Induction & Synchronous Based Systems Manufacturer Model ( Name / Number ) Installation Information Project Single Point of Contact: ( Electric Utility Customer, Developer, or other ) Name: Company ( If Applicable ): Phone Number: E-Mail Address: Requested In Service Date: Licensed Contractor ( Name of Firm or Self ): Contractor Name ( Last, First, MI ): Contractor Phone #: Contractor E-Mail: Customer and Contractor Signature and Fees Attached $100 Interconnection Application Fee (Check #/ Money Order #) ( Sign and Return complete application with Application Fee to Electric Utility Contact ) To the best of my knowledge, all the information provided in this Application Form is complete and correct. ________________________________________ Customer _________________________________________________ Project Developer/Contractor (If Applicable) Note: Refer to the applicable "Michigan Electric Utility Generator Interconnection Requirements" for a detailed explanation of the Interconnection Process, Fees, Timelines, and Technical Requirements. APPENDIXES Appendix A: Technical Information for Synchronous-Type Generators Appendix B: Technical Information for Induction-Type Generators Appendix C: Sample Site Plan Appendix D: Sample One-Line diagram for Inverter Type Project Appendix E: Sample One-Line diagram for Synchronous Type Project Appendix F: Sample One-Line diagram for Induction Type Project Appendix A Synchronous Generators Generator Information a. Generator Nameplate Voltage a. b. Generator Nameplate Watts or Volt-Amperes b. c. Generator Nameplate Power Factor (pf) c. d. RPM d. Technical Information e. Minimum and Maximum Acceptable Terminal Voltage e. f. Direct axis reactance (saturated) f. g. Direct axis reactance (unsaturated) g. h. Quadrature axis reactance (unsaturated) h. i. Direct axis transient reactance (saturated) i. j. Direct axis transient reactance (unsaturated) j. k. Quadrature axis transient reactance (unsaturated) k. l. Direct axis sub-transient reactance (saturated) l. m. Direct axis sub-transient reactance (unsaturated) m. n. Leakage Reactance n. o. Direct axis transient open circuit time constant o. p. Quadrature axis transient open circuit time constant p. q. Direct axis subtransient open circuit time constant q. r. Quadrature axis subtransient open circuit time constant r. s. Open Circuit saturation curve s. t. Reactive Capability Curve showing overexcited and underexcited limits (Reactive Information if non-synchronous) t. u. Excitation System Block Diagram with values for gains and time constants (Laplace transforms) u. v. Short Circuit Current contribution from generator at the Point of Common Coupling v. w. Rotating inertia of overall combination generator, prime mover, couplers and gear drives w. x. Station Power load when generator is off-line, Watts, pf x. y. Station Power load during start-up, Watts, pf y. z. Station Power load during operation, Watts, pf z. Appendix B Induction Generators Generator Information a. Generator Nameplate Voltage a. b. Generator Nameplate Watts or Volt-Amperes b. c. Generator Nameplate Power Factor (pf) c. d.RPM d. Technical Information e. Synchronous Rotational Speed e. f. Rotation Speed at Rated Power f. g. Slip at Rated Power g. h. Minimum and Maximum Acceptable Terminal Voltage h. i. Motoring Power (kW) i. j. Neutral Grounding Resistor (If Applicable) j. k. I22t or K (Heating Time Constant) k. l. Rotor Resistance l. m. Stator Resistance m. n. Stator Reactance n. o. Rotor Reactance o. p. Magnetizing Reactance p. q. Short Circuit Reactance q. r. Exciting Current r. s. Temperature Rise s. t. Frame Size t. u. Design Letter u. v. Reactive Power Required in Vars (No Load) v. w. Reactive Power Required in Vars (Full Load) w. x. Short Circuit Current contribution from generator at the Point of Common Coupling x. y. Rotating inertia, H in Per Unit on kVA Base, of overall combination generator, prime mover, couplers and gear drives y. z. Station Power load when generator is off-line, Watts, pf z. aa. Station Power load during start-up, Watts, pf aa. bb. Station Power load during operation, Watts, pf bb. Appendix C Sample Site Plan Appendix D Inverter Generators One - Line Diagram Name of the Licensed Contractor /PE_____________________ Contractor License Number ___________________________ Address ____________________________________________ Signature___________________________________________ Appendix E (ot Required for Flow-Back) One - Line Diagram Name of the Licensed Contractor /PE_____________________ Contractor License Number ___________________________ Address ____________________________________________ Signature___________________________________________ Appendix F (ot Required for Flow-Back) One - Line Diagram Name of the Licensed Contractor /PE_____________________ Contractor License Number ___________________________ Address ____________________________________________ Signature___________________________________________ NET METERING APPLICATION FOR ALL PROJECTS WITH AGGREGATE GENERATOR OUTPUT OF MORE THAN 20 KW BUT LESS THAN OR EQUAL TO 150 KW (Note: Category 2 Net Metering Program only available to Renewable Generator Projects) Electric Utility Contact Information Utility Name Interconnection Coordinator Utility Street Address Utility Street Address Interconnection Hotline: XXX.XXX.XXXX Interconnection Email: XXX@XXXXXX Customer / Account Information For Office Use Only Application No._______________ Date & Time Application Received Electric Utility Customer Information: ( As shown on utility bill ) Customer Name ( Last, First, Middle): Customer Mailing Address: Customer E-Mail Address: ( optional ) Electric Service Account # Electric Service Meter Number: Are you interested in selling Renewable Energy Credits (REC's) Yes No Have you completed a Generator Interconnection Application? Yes No Yes No Interconnection Application Number, if known Will you have an Alternative Electric Supplier? Notes: Enter name ONLY if your energy is supplied by a 3rd party, not the utility. You must apply to both the Distribution Utility and your Alternate Energy Provider (if applicable) for Net Metering Alternative Electric Supplier Name Generation System Site Information Physical Site Service Address (if not Billing Address): Annual Site Requirements Without Generation in Kilowatthours kWh/year Peak Annual Site Demand in Kilowatts (only for customers billed on demand rates) kW/year Generation System - Manufacturer Information System Type ( Solar, Wind, Biomass, Methane Digester, etc ): Generator Type ( Inverter, Induction, Synchronous ): Generator Nameplate Rating: kW Expected Annual Output in Kilowatthours kWh/year A.C. Operating Voltage: Wiring Configuration ( Single Phase, Three Phase ): Certified Test Record No.(Testing to standard UL1741 scope 1.1a) Inverter Based Systems: Manufacturer Model ( Name / Number ) Inverter Power Rating (kW) Induction & Synchronous Based Systems Manufacturer Model ( Name / Number ) Installation Information Project Single Point of Contact: ( Electric Utility Customer, Developer, or other ) Name: Company ( If Applicable ): Phone Number: E-Mail Address: Requested In Service Date: Licensed Contractor ( Name of Firm or Self ): Contractor Name ( Last, First, MI ): Contractor Phone #: Contractor E-Mail: Customer and Contractor Signature and Fees ( Sign and Return complete application with Application Fee to Electric Utility Contact ) To the best of my knowledge, all the information provided in this Application Form is complete and correct. ________________________________________ Customer _________________________________________________ Project Developer/Contractor (If Applicable) Note: Refer to the applicable "Michigan Electric Utility Generator Interconnection Requirements" for a detailed explanation of the Interconnection Process, Fees, Timelines, and Technical Requirements. GENERATOR INTERCONNECTION APPLICATION FOR ALL PROJECTS WITH AGGREGATE GENERATOR OUTPUT OF MORE THAN 150 KW BUT LESS THAN OR EQUAL TO 550 KW Also Serves as Application for Category 3 Net Metering (Note: Category 3 Net Metering Program only available to Methane Digester Projects) Electric Utility Contact Information Utility Name Interconnection Coordinator Utility Street Address Utility Street Address Interconnection Hotline: XXX.XXX.XXXX Interconnection Email: XXX@XXXXXX For Office Use Only Application No._______________ Date & Time Application Received Customer / Account Information Electric Utility Customer Information: ( As shown on utility bill ) Customer Name ( Last, First, Middle): Customer Mailing Address: Customer E-Mail Address: ( optional ) Electric Service Account # Electric Service Meter Number: Are you applying for the Net Metering Program? Yes No Are you interested in selling Renewable Energy Credits (REC's) Yes No Will you have an Alternative Electric Supplier? Notes: Enter name ONLY if your energy is supplied by a 3rd party, not the utility. You must apply to both the Distribution Utility and your Alternate Energy Provider (if applicable) for Net Metering Yes No Alternative Electric Supplier Name Generation System Site Information Physical Site Service Address (if not Billing Address): Annual Site Requirements Without Generation in Kilowatthours kWh/year Peak Annual Site Demand in Kilowatts (only for customers billed on demand rates) kW/year Attached Site Plan: Page # Attached Electrical One-Line Drawing (See the Appendix D for a sample Inverter Type Project) (Per MPSC Order in Case No. U-15787- The one-line diagram must be signed and sealed by a licensed professional engineer, licensed in the State of Michigan or by an electrical contractor licensed by the State of Michigan with the electrical contractor's license number noted on the diagram.) Page # Synchronous/Induction Generators: Must fill out Appendix A or B and provide a Detail One-Line Diagram See Appendix E and F for a sample the Detail One-Line Diagram for Synchronous or Induction projects Note: The following information on these system components shall appear on the preliminary Detail One-Line Diagram Page # • • • • • • • • • • • • • • Breakers - Rating, location and normal operating status (open or closed) Buses - Operating voltage Capacitors - Size of bank in Kvar Circuit Switchers - Rating, location and normal operating status (open or closed) Current Transformers - Overall ratio, connected ratio Fuses - normal operating status, rating (Amps), type Generators - Capacity rating (kVA), location, type, method of grounding Grounding Resistors - Size (ohms), current (Amps) Isolating transformers - Capacity rating (kVA), location, impedance, voltage ratings, primary and secondary connections and method of grounding Potential Transformers - Ratio, connection Reactors - Ohms/phase Relays - Types, quantity, IEEE device number, operator lines indicating the device initiated by the relays. Switches - Location and normal operating status (open or closed), type, rating Tagging Point - Location, identification GENERATOR INTERCONNECTION APPLICATION FOR ALL PROJECTS WITH AGGREGATE GENERATOR OUTPUT OF MORE THAN 150 KW BUT LESS THAN OR EQUAL TO 550 KW Also Serves as Application for Category 3 Net Metering (Note: Category 3 Net Metering Program only available to Methane Projects) Generation System - Manufacturer Information System Type ( Solar, Wind, Biomass, Methane Digester, etc ): Generator Type ( Inverter, Induction, Synchronous ): Generator Nameplate Rating: kW Expected Annual Output in Kilowatthours kWh/year A.C. Operating Voltage: Wiring Configuration ( Single Phase, Three Phase ): Certified Test Record No.(Testing to standard UL1741 scope 1.1a) Inverter Based Systems: Manufacturer Model ( Name / Number ) Inverter Power Rating (kW) Induction & Synchronous Based Systems Manufacturer Model ( Name / Number ) Installation Information Project Single Point of Contact: ( Electric Utility Customer, Developer, or other ) Name: Company ( If Applicable ): Phone Number: E-Mail Address: Requested In Service Date: Licensed Contractor ( Name of Firm or Self ): Contractor Name ( Last, First, MI ): Contractor Phone #: Contractor E-Mail: Customer and Contractor Signature and Fees Attached $150 Interconnection Application Fee or Attached $100 combined Interconnection & Net Metering Program application fees ($75 Interconnection Application Fee plus $25 fee required if selecting net metering) (Check # / Money Order # ) ( Sign and Return complete application with Application Fee to Electric Utility Contact ) To the best of my knowledge, all the information provided in this Application Form is complete and correct. ________________________________________ Customer _________________________________________________ Project Developer/Contractor (If Applicable) Note: Refer to the applicable "Michigan Electric Utility Generator Interconnection Requirements" for a detailed explanation of the Interconnection Process, Fees, Timelines, and Technical Requirements. APPENDIXES Appendix A: Technical Information for Synchronous-Type Generators Appendix B: Technical Information for Induction-Type Generators Appendix C: Sample Site Plan Appendix D: Sample One-Line diagram for Inverter Type Project Appendix E: Sample One-Line diagram for Synchronous Type Project Appendix F: Sample One-Line diagram for Induction Type Project Appendix A Synchronous Generators Generator Information a. Generator Nameplate Voltage a. b. Generator Nameplate Watts or Volt-Amperes b. c. Generator Nameplate Power Factor (pf) c. d. RPM d. Technical Information e. Minimum and Maximum Acceptable Terminal Voltage e. f. Direct axis reactance (saturated) f. g. Direct axis reactance (unsaturated) g. h. Quadrature axis reactance (unsaturated) h. i. Direct axis transient reactance (saturated) i. j. Direct axis transient reactance (unsaturated) j. k. Quadrature axis transient reactance (unsaturated) k. l. Direct axis sub-transient reactance (saturated) l. m. Direct axis sub-transient reactance (unsaturated) m. n. Leakage Reactance n. o. Direct axis transient open circuit time constant o. p. Quadrature axis transient open circuit time constant p. q. Direct axis subtransient open circuit time constant q. r. Quadrature axis subtransient open circuit time constant r. s. Open Circuit saturation curve s. t. Reactive Capability Curve showing overexcited and underexcited limits (Reactive Information if non-synchronous) t. u. Excitation System Block Diagram with values for gains and time constants (Laplace transforms) u. v. Short Circuit Current contribution from generator at the Point of Common Coupling v. w. Rotating inertia of overall combination generator, prime mover, couplers and gear drives w. x. Station Power load when generator is off-line, Watts, pf x. y. Station Power load during start-up, Watts, pf y. z. Station Power load during operation, Watts, pf z. Appendix B Induction Generators Generator Information a. Generator Nameplate Voltage a. b. Generator Nameplate Watts or Volt-Amperes b. c. Generator Nameplate Power Factor (pf) c. d.RPM d. Technical Information e. Synchronous Rotational Speed e. f. Rotation Speed at Rated Power f. g. Slip at Rated Power g. h. Minimum and Maximum Acceptable Terminal Voltage h. i. Motoring Power (kW) i. j. Neutral Grounding Resistor (If Applicable) j. k. I22t or K (Heating Time Constant) k. l. Rotor Resistance l. m. Stator Resistance m. n. Stator Reactance n. o. Rotor Reactance o. p. Magnetizing Reactance p. q. Short Circuit Reactance q. r. Exciting Current r. s. Temperature Rise s. t. Frame Size t. u. Design Letter u. v. Reactive Power Required in Vars (No Load) v. w. Reactive Power Required in Vars (Full Load) w. x. Short Circuit Current contribution from generator at the Point of Common Coupling x. y. Rotating inertia, H in Per Unit on kVA Base, of overall combination generator, prime mover, couplers and gear drives y. z. Station Power load when generator is off-line, Watts, pf z. aa. Station Power load during start-up, Watts, pf aa. bb. Station Power load during operation, Watts, pf bb. Appendix C Sample Site Plan Appendix D Inverter Generators One - Line Diagram Name of the Licensed Contractor /PE_____________________ Contractor License Number ___________________________ Address ____________________________________________ Signature___________________________________________ Appendix E (ot Required for Flow-Back) One - Line Diagram Name of the Licensed Contractor /PE_____________________ Contractor License Number ___________________________ Address ____________________________________________ Signature___________________________________________ Appendix F (ot Required for Flow-Back) One - Line Diagram Name of the Licensed Contractor /PE_____________________ Contractor License Number ___________________________ Address ____________________________________________ Signature___________________________________________ GENERATOR INTERCONNECTION APPLICATION FOR ALL PROJECTS WITH AGGREGATE GENERATOR OUTPUT OF MORE THAN 150 KW BUT LESS THAN OR EQUAL TO 550 KW Electric Utility Contact Information Utility Name Interconnection Coordinator Utility Street Address Utility Street Address Interconnection Hotline: XXX.XXX.XXXX Interconnection Email: XXX@XXXXXX For Office Use Only Application No._______________ Date & Time Application Received Customer / Account Information Electric Utility Customer Information: ( As shown on utility bill ) Customer Name ( Last, First, Middle): Customer Mailing Address: Customer E-Mail Address: ( optional ) Electric Service Account # Electric Service Meter Number: Yes Are you interested in selling Renewable Energy Credits (REC's) No Generation System Site Information Physical Site Service Address (if not Billing Address): Annual Site Requirements Without Generation in Kilowatthours kWh/year Peak Annual Site Demand in Kilowatts (only for customers billed on demand rates) kW/year Attached Site Plan: Page # Attached Electrical One-Line Drawing (See the Appendix D for a sample Inverter Type Project) (Per MPSC Order in Case No. U-15787- The one-line diagram must be signed and sealed by a licensed professional engineer, licensed in the State of Michigan or by an electrical contractor licensed by the State of Michigan with the electrical contractor's license number noted on the diagram.) Page # Synchronous/Induction Generators: Must fill out Appendix A or B and provide a Detail One-Line Diagram See Appendix E and F for a sample the Detail One-Line Diagram for Synchronous or Induction projects Note: The following information on these system components shall appear on the preliminary Detail One-Line Diagram Page # • • • • • • • • • • • • • • Breakers - Rating, location and normal operating status (open or closed) Buses - Operating voltage Capacitors - Size of bank in Kvar Circuit Switchers - Rating, location and normal operating status (open or closed) Current Transformers - Overall ratio, connected ratio Fuses - normal operating status, rating (Amps), type Generators - Capacity rating (kVA), location, type, method of grounding Grounding Resistors - Size (ohms), current (Amps) Isolating transformers - Capacity rating (kVA), location, impedance, voltage ratings, primary and secondary connections and method of grounding Potential Transformers - Ratio, connection Reactors - Ohms/phase Relays - Types, quantity, IEEE device number, operator lines indicating the device initiated by the relays. Switches - Location and normal operating status (open or closed), type, rating Tagging Point - Location, identification GENERATOR INTERCONNECTION APPLICATION FOR ALL PROJECTS WITH AGGREGATE GENERATOR OUTPUT OF MORE THAN 150 KW BUT LESS THAN OR EQUAL TO 550 KW Generation System - Manufacturer Information System Type ( Solar, Wind, Biomass, Methane Digester, etc ): Generator Type ( Inverter, Induction, Synchronous ): Generator Nameplate Rating: kW Expected Annual Output in Kilowatthours kWh/year A.C. Operating Voltage: Wiring Configuration ( Single Phase, Three Phase ): Certified Test Record No.(Testing to standard UL1741 scope 1.1a) Inverter Based Systems: Manufacturer Model ( Name / Number ) Inverter Power Rating (kW) Induction & Synchronous Based Systems Manufacturer Model ( Name / Number ) Installation Information Project Single Point of Contact: ( Electric Utility Customer, Developer, or other ) Name: Company ( If Applicable ): Phone Number: E-Mail Address: Requested In Service Date: Licensed Contractor ( Name of Firm or Self ): Contractor Name ( Last, First, MI ): Contractor Phone #: Contractor E-Mail: Customer and Contractor Signature and Fees Attached $150 Interconnection Application Fee (Check #/ Money Order #) ( Sign and Return complete application with Application Fee to Electric Utility Contact ) To the best of my knowledge, all the information provided in this Application Form is complete and correct. ________________________________________ Customer _________________________________________________ Project Developer/Contractor (If Applicable) Note: Refer to the applicable "Michigan Electric Utility Generator Interconnection Requirements" for a detailed explanation of the Interconnection Process, Fees, Timelines, and Technical Requirements. APPENDIXES Appendix A: Technical Information for Synchronous-Type Generators Appendix B: Technical Information for Induction-Type Generators Appendix C: Sample Site Plan Appendix D: Sample One-Line diagram for Inverter Type Project Appendix E: Sample One-Line diagram for Synchronous Type Project Appendix F: Sample One-Line diagram for Induction Type Project Appendix A Synchronous Generators Generator Information a. Generator Nameplate Voltage a. b. Generator Nameplate Watts or Volt-Amperes b. c. Generator Nameplate Power Factor (pf) c. d. RPM d. Technical Information e. Minimum and Maximum Acceptable Terminal Voltage e. f. Direct axis reactance (saturated) f. g. Direct axis reactance (unsaturated) g. h. Quadrature axis reactance (unsaturated) h. i. Direct axis transient reactance (saturated) i. j. Direct axis transient reactance (unsaturated) j. k. Quadrature axis transient reactance (unsaturated) k. l. Direct axis sub-transient reactance (saturated) l. m. Direct axis sub-transient reactance (unsaturated) m. n. Leakage Reactance n. o. Direct axis transient open circuit time constant o. p. Quadrature axis transient open circuit time constant p. q. Direct axis subtransient open circuit time constant q. r. Quadrature axis subtransient open circuit time constant r. s. Open Circuit saturation curve s. t. Reactive Capability Curve showing overexcited and underexcited limits (Reactive Information if non-synchronous) t. u. Excitation System Block Diagram with values for gains and time constants (Laplace transforms) u. v. Short Circuit Current contribution from generator at the Point of Common Coupling v. w. Rotating inertia of overall combination generator, prime mover, couplers and gear drives w. x. Station Power load when generator is off-line, Watts, pf x. y. Station Power load during start-up, Watts, pf y. z. Station Power load during operation, Watts, pf z. Appendix B Induction Generators Generator Information a. Generator Nameplate Voltage a. b. Generator Nameplate Watts or Volt-Amperes b. c. Generator Nameplate Power Factor (pf) c. d.RPM d. Technical Information e. Synchronous Rotational Speed e. f. Rotation Speed at Rated Power f. g. Slip at Rated Power g. h. Minimum and Maximum Acceptable Terminal Voltage h. i. Motoring Power (kW) i. j. Neutral Grounding Resistor (If Applicable) j. k. I22t or K (Heating Time Constant) k. l. Rotor Resistance l. m. Stator Resistance m. n. Stator Reactance n. o. Rotor Reactance o. p. Magnetizing Reactance p. q. Short Circuit Reactance q. r. Exciting Current r. s. Temperature Rise s. t. Frame Size t. u. Design Letter u. v. Reactive Power Required in Vars (No Load) v. w. Reactive Power Required in Vars (Full Load) w. x. Short Circuit Current contribution from generator at the Point of Common Coupling x. y. Rotating inertia, H in Per Unit on kVA Base, of overall combination generator, prime mover, couplers and gear drives y. z. Station Power load when generator is off-line, Watts, pf z. aa. Station Power load during start-up, Watts, pf aa. bb. Station Power load during operation, Watts, pf bb. Appendix C Sample Site Plan Appendix D Inverter Generators One - Line Diagram Name of the Licensed Contractor /PE_____________________ Contractor License Number ___________________________ Address ____________________________________________ Signature___________________________________________ Appendix E (ot Required for Flow-Back) One - Line Diagram Name of the Licensed Contractor /PE_____________________ Contractor License Number ___________________________ Address ____________________________________________ Signature___________________________________________ Appendix F (ot Required for Flow-Back) One - Line Diagram Name of the Licensed Contractor /PE_____________________ Contractor License Number ___________________________ Address ____________________________________________ Signature___________________________________________ NET METERING APPLICATION FOR ALL PROJECTS WITH AGGREGATE GENERATOR OUTPUT OF MORE THAN 150 KW BUT LESS THAN OR EQUAL TO 550 KW (Note: Category 3 Net Metering Program only available to Methane Digester Projects) Electric Utility Contact Information Utility Name Interconnection Coordinator Utility Street Address Utility Street Address Interconnection Hotline: XXX.XXX.XXXX Interconnection Email: XXX@XXXXXX Customer / Account Information For Office Use Only Application No._______________ Date & Time Application Received Electric Utility Customer Information: ( As shown on utility bill ) Customer Name ( Last, First, Middle): Customer Mailing Address: Customer E-Mail Address: ( optional ) Electric Service Account # Electric Service Meter Number: Are you interested in selling Renewable Energy Credits (REC's) Yes No Have you completed a Generator Interconnection Application? Yes No Yes No Interconnection Application Number, if known Will you have an Alternative Electric Supplier? Notes: Enter name ONLY if your energy is supplied by a 3rd party, not the utility. You must apply to both the Distribution Utility and your Alternate Energy Provider (if applicable) for Net Metering Alternative Electric Supplier Name Generation System Site Information Physical Site Service Address (if not Billing Address): Annual Site Requirements Without Generation in Kilowatthours kWh/year Peak Annual Site Demand in Kilowatts (only for customers billed on demand rates) kW/year Generation System - Manufacturer Information System Type ( Methane Digester ): Methane Digester Generator Type ( Inverter, Induction, Synchronous ): Generator Nameplate Rating: kW Expected Annual Output in Kilowatthours kWh/year A.C. Operating Voltage: Wiring Configuration ( Single Phase, Three Phase ): Certified Test Record No.(Testing to standard UL1741 scope 1.1a) Inverter Based Systems: Manufacturer Model ( Name / Number ) Inverter Power Rating (kW) Induction & Synchronous Based Systems Manufacturer Model ( Name / Number ) Installation Information Project Single Point of Contact: ( Electric Utility Customer, Developer, or other ) Name: Company ( If Applicable ): Phone Number: E-Mail Address: Requested In Service Date: Licensed Contractor ( Name of Firm or Self ): Contractor Name ( Last, First, MI ): Contractor Phone #: Contractor E-Mail: Customer and Contractor Signature and Fees Utility will refund $50 from Interconnection Application Fee ( Sign and Return complete application with Application Fee to Electric Utility Contact ) To the best of my knowledge, all the information provided in this Application Form is complete and correct. ________________________________________ Customer _________________________________________________ Project Developer/Contractor (If Applicable) Note: Refer to the applicable "Michigan Electric Utility Generator Interconnection Requirements" for a detailed explanation of the Interconnection Process, Fees, Timelines, and Technical Requirements. GENERATOR INTERCONNECTION APPLICATION FOR ALL PROJECTS WITH AGGREGATE GENERATOR OUTPUT OF MORE THAN 550 KW BUT LESS THAN OR EQUAL TO 2 MW Electric Utility Contact Information Utility Name Interconnection Coordinator Utility Street Address Utility Street Address Interconnection Hotline: XXX.XXX.XXXX Interconnection Email: XXX@XXXXXX Required Information for all Projects Types Electric Utility Customer Information: ( As shown on utility bill ) Customer Name ( Last, First, Middle): Customer Mailing Address: Customer Phone # Customer E-Mail Address: ( optional ) Project Developer/Single Point of Contact Name: Address: Phone Number: Fax Number: E-Mail Address: Project Site Address: Generation System Information Project Type (Base load, peaking, intermediate) Energization Date for Project Interconnection Facilities First Parallel Operation Date for Testing Project Commercial Operation Date Estimated Project Cost Operation Mode Isolating Transformer(s) between Generator(s) and Utility Transformer Model Number: Transformer Manufacturer: Rated kV and connection (delta, wye, wye-gnd) of each winding kVA of each winding BIL of each winding Fixed taps available for each winding Positive/Negative range for any LTC windings %Z impedance on transformer self cooled rating Percent Excitation current at rated kV Load Loss Watts at full load or X/R ratio For Office Use Only Application No._______________ Date & Time Application Received GENERATOR INTERCONNECTION APPLICATION FOR ALL PROJECTS WITH AGGREGATE GENERATOR OUTPUT OF MORE THAN 550 KW BUT LESS THAN OR EQUAL TO 2 MW Required Information for all Projects Types 1. Customer's Proof of General Liability Insurance for a minimum of $1,000,000 (Per MPSC Order in Case No. U-15787 - Customer must maintain a minimum of $1,000,00 General Liability Insurance.) Page # 2. Attached Site Plan: Page # 3. Attached Electrical One-Line Drawing: Page # (Per MPSC Order in Case No. U-15787, the one-line diagram must be signed and sealed by a licensed professional engineer, licensed in the State of Michigan) 4. Attached Electrical Three-Line Drawing: Page # 5. Attached Specification for Equipment Page # 6. Applicable Technical Appendix (A-C) Page # Note: The following information on these system components shall appear on the preliminary Detail One-Line Diagram • Breakers - Rating, location and normal operating status (open or closed) • Buses - Operating voltage • Capacitors - Size of bank in Kvar • • • Circuit Switchers - Rating, location and normal operating status (open or closed) Current Transformers - Overall ratio, connected ratio Fuses - normal operating status, rating (Amps), type • Generators - Capacity rating (kVA), location, type, method of grounding • • • • • Grounding Resistors - Size (ohms), current (Amps) Isolating transformers - Capacity rating (kVA), location, impedance, voltage ratings, primary and secondary connections and method of grounding Potential Transformers - Ratio, connection Reactors - Ohms/phase Relays - Types, quantity, IEEE device number, operator lines indicating the device initiated by the relays. • Switches - Location and normal operating status (open or closed), type, rating • Tagging Point - Location, identification Customer and Contractor Signature and Fees Attached $250 Interconnection Application Fee (Check #/ Money Order #) ( Sign and Return complete application with Application Fee to Electric Utility Contact ) To the best of my knowledge, all the information provided in this Application Form is complete and correct. ________________________________________ Customer _________________________________________________ Project Developer/Contractor (If Applicable) Note: Refer to the applicable "Michigan Electric Utility Generator Interconnection Requirements" for a detailed explanation of the Interconnection Process, Fees, Timelines, and Technical Requirements. APPENDIXES APPENDIX A: Technical Information for Synchonous-Type Generators APPENDIX B: Technical Information for Induction-Type Generators APPENDIX C: Technical Information for Inverter-Type Generators APPENDIX D: Sample One-Line diagram for Synchronous Type Project APPENDIX E: Sample One-Line diagram for Induction Type Project APPENDIX F: Sample One-Line diagram for Inverter Type Project Appendix A Synchronous Generators Generator Information a. Generator Nameplate Voltage a. b. Generator Nameplate Watts or Volt-Amperes b. c. Generator Nameplate Power Factor (pf) c. d. RPM d. Technical Information e. Minimum and Maximum Acceptable Terminal Voltage e. f. Direct axis reactance (saturated) f. g. Direct axis reactance (unsaturated) g. h. Quadrature axis reactance (unsaturated) h. i. Direct axis transient reactance (saturated) i. j. Direct axis transient reactance (unsaturated) j. k. Quadrature axis transient reactance (unsaturated) k. l. Direct axis sub-transient reactance (saturated) l. m. Direct axis sub-transient reactance (unsaturated) m. n. Leakage Reactance n. o. Direct axis transient open circuit time constant o. p. Quadrature axis transient open circuit time constant p. q. Direct axis subtransient open circuit time constant q. r. Quadrature axis subtransient open circuit time constant r. s. Open Circuit saturation curve s. t. Reactive Capability Curve showing overexcited and underexcited limits (Reactive Information if non-synchronous) t. u. Excitation System Block Diagram with values for gains and time constants (Laplace transforms) u. v. Short Circuit Current contribution from generator at the Point of Common Coupling v. w. Rotating inertia of overall combination generator, prime mover, couplers and gear drives w. x. Station Power load when generator is off-line, Watts, pf x. y. Station Power load during start-up, Watts, pf y. z. Station Power load during operation, Watts, pf z. Appendix B Induction Generators Generator Information a. Generator Nameplate Voltage a. b. Generator Nameplate Watts or Volt-Amperes b. c. Generator Nameplate Power Factor (pf) c. d.RPM d. Technical Information e. Synchronous Rotational Speed e. f. Rotation Speed at Rated Power f. g. Slip at Rated Power g. h. Minimum and Maximum Acceptable Terminal Voltage h. i. Motoring Power (kW) i. j. Neutral Grounding Resistor (If Applicable) j. 2 k. I2 t or K (Heating Time Constant) k. l. Rotor Resistance l. m. Stator Resistance m. n. Stator Reactance n. o. Rotor Reactance o. p. Magnetizing Reactance p. q. Short Circuit Reactance q. r. Exciting Current r. s. Temperature Rise s. t. Frame Size t. u. Design Letter u. v. Reactive Power Required in Vars (No Load) v. w. Reactive Power Required in Vars (Full Load) w. x. Short Circuit Current contribution from generator at the Point of Common Coupling x. y. Rotating inertia, H in Per Unit on kVA Base, of overall combination generator, prime mover, couplers and gear drives y. z. Station Power load when generator is off-line, Watts, pf z. aa. Station Power load during start-up, Watts, pf aa. bb. Station Power load during operation, Watts, pf bb. Appendix C Inverter Generators Generator Information a. Generator Nameplate Voltage b. Generator Nameplate Watts or Volt-Amperes c. Generator Nameplate Power Factor (pf) d. RPM e. Manufacturer f. Model ( Name / Number ) Technical Information e. Generator Nameplate Voltage f. Generator Nameplate Watts or Volt-Amperes g. Generator Nameplate Power Factor (pf) h. Minimum and Maximum Acceptable Terminal Voltage i. Reactive Capability Curve showing overexcited and underexcited limits (Reactive Information if non-synchronous) j. Short Circuit Current contribution from generator at the Point of Common Coupling k. Station Power load when generator is off-line, Watts, pf l. Station Power load during start-up, Watts, pf m. Station Power load during operation, Watts, pf Appendix D (Not Required for Flow-Back) One - Line Diagram Name of the Licensed Professional Engineer_____________________ PE License Number ________________________________________ Address __________________________________________________ Signature_________________________________________________ Appendix E (Not Required for Flow-Back) One - Line Diagram Name of the Licensed Professional Engineer_____________________ PE License Number ___________________________ Address ____________________________________________ Appendix F Distribution Circuit 32 (Not Required for Flow-Back) 59 A) One - Line Diagram Name of the Licensed Contractor /PE_____________________ PE License Number ___________________________ Address ____________________________________________ Signature___________________________________________ GENERATOR INTERCONNECTION APPLICATION FOR ALL PROJECTS WITH AGGREGATE GENERATOR OUTPUT OF MORE THAN 2 MW Electric Utility Contact Information Utility Name Interconnection Coordinator Utility Street Address Utility Street Address Interconnection Hotline: XXX.XXX.XXXX Interconnection Email: XXX@XXXXXX Required Information for all Projects Types Electric Utility Customer Information: ( As shown on utility bill ) Customer Name ( Last, First, Middle): Customer Mailing Address: Customer Phone # Customer E-Mail Address: ( optional ) Project Developer/Single Point of Contact Name: Address: Phone Number: Fax Number: E-Mail Address: Project Site Address: Generation System Information Project Type (Base load, peaking, intermediate) Energization Date for Project Interconnection Facilities First Parallel Operation Date for Testing Project Commercial Operation Date Estimated Project Cost Operation Mode Isolating Transformer(s) between Generator(s) and Utility Transformer Model Number: Transformer Manufacturer: Rated kV and connection (delta, wye, wye-gnd) of each winding kVA of each winding BIL of each winding Fixed taps available for each winding Positive/Negative range for any LTC windings %Z impedance on transformer self cooled rating Percent Excitation current at rated kV Load Loss Watts at full load or X/R ratio For Office Use Only Application No._______________ Date & Time Application Received GENERATOR INTERCONNECTION APPLICATION FOR ALL PROJECTS WITH AGGREGATE GENERATOR OUTPUT OF MORE THAN 2 MW Required Information for all Projects Types 1. Customer's Proof of General Liability Insurance for a minimum of $1,000,000 (Per MPSC Order in Case No. U-15787 - Customer must maintain a minimum of $1,000,00 General Liability Insurance.) Page # 2. Attached Site Plan: Page # 3. Attached Electrical One-Line Drawing: Page # (Per MPSC Order in Case No. U-15787, the one-line diagram must be signed and sealed by a licensed professional engineer, licensed in the State of Michigan) 4. Attached Electrical Three-Line Drawing: Page # 5. Attached Specification for Equipment Page # 6. Applicable Technical Appendix (A-C) Page # Note: The following information on these system components shall appear on the preliminary Detail One-Line Diagram • Breakers - Rating, location and normal operating status (open or closed) • Buses - Operating voltage • Capacitors - Size of bank in Kvar • • • Circuit Switchers - Rating, location and normal operating status (open or closed) Current Transformers - Overall ratio, connected ratio Fuses - normal operating status, rating (Amps), type • Generators - Capacity rating (kVA), location, type, method of grounding • • • • • Grounding Resistors - Size (ohms), current (Amps) Isolating transformers - Capacity rating (kVA), location, impedance, voltage ratings, primary and secondary connections and method of grounding Potential Transformers - Ratio, connection Reactors - Ohms/phase Relays - Types, quantity, IEEE device number, operator lines indicating the device initiated by the relays. • Switches - Location and normal operating status (open or closed), type, rating • Tagging Point - Location, identification Customer and Contractor Signature and Fees Attached $500 Interconnection Application Fee (Check #/ Money Order #) ( Sign and Return complete application with Application Fee to Electric Utility Contact ) To the best of my knowledge, all the information provided in this Application Form is complete and correct. ________________________________________ Customer _________________________________________________ Project Developer/Contractor (If Applicable) Note: Refer to the applicable "Michigan Electric Utility Generator Interconnection Requirements" for a detailed explanation of the Interconnection Process, Fees, Timelines, and Technical Requirements. APPENDIXES APPENDIX A: Technical Information for Synchonous-Type Generators APPENDIX B: Technical Information for Induction-Type Generators APPENDIX C: Technical Information for Inverter-Type Generators APPENDIX D: Sample One-Line diagram for Synchronous Type Project APPENDIX E: Sample One-Line diagram for Induction Type Project APPENDIX F: Sample One-Line diagram for Inverter Type Project Appendix A Synchronous Generators Generator Information a. Generator Nameplate Voltage a. b. Generator Nameplate Watts or Volt-Amperes b. c. Generator Nameplate Power Factor (pf) c. d. RPM d. Technical Information e. Minimum and Maximum Acceptable Terminal Voltage e. f. Direct axis reactance (saturated) f. g. Direct axis reactance (unsaturated) g. h. Quadrature axis reactance (unsaturated) h. i. Direct axis transient reactance (saturated) i. j. Direct axis transient reactance (unsaturated) j. k. Quadrature axis transient reactance (unsaturated) k. l. Direct axis sub-transient reactance (saturated) l. m. Direct axis sub-transient reactance (unsaturated) m. n. Leakage Reactance n. o. Direct axis transient open circuit time constant o. p. Quadrature axis transient open circuit time constant p. q. Direct axis subtransient open circuit time constant q. r. Quadrature axis subtransient open circuit time constant r. s. Open Circuit saturation curve s. t. Reactive Capability Curve showing overexcited and underexcited limits (Reactive Information if non-synchronous) t. u. Excitation System Block Diagram with values for gains and time constants (Laplace transforms) u. v. Short Circuit Current contribution from generator at the Point of Common Coupling v. w. Rotating inertia of overall combination generator, prime mover, couplers and gear drives w. x. Station Power load when generator is off-line, Watts, pf x. y. Station Power load during start-up, Watts, pf y. z. Station Power load during operation, Watts, pf z. Appendix B Induction Generators Generator Information a. Generator Nameplate Voltage a. b. Generator Nameplate Watts or Volt-Amperes b. c. Generator Nameplate Power Factor (pf) c. d.RPM d. Technical Information e. Synchronous Rotational Speed e. f. Rotation Speed at Rated Power f. g. Slip at Rated Power g. h. Minimum and Maximum Acceptable Terminal Voltage h. i. Motoring Power (kW) i. j. Neutral Grounding Resistor (If Applicable) j. 2 k. I2 t or K (Heating Time Constant) k. l. Rotor Resistance l. m. Stator Resistance m. n. Stator Reactance n. o. Rotor Reactance o. p. Magnetizing Reactance p. q. Short Circuit Reactance q. r. Exciting Current r. s. Temperature Rise s. t. Frame Size t. u. Design Letter u. v. Reactive Power Required in Vars (No Load) v. w. Reactive Power Required in Vars (Full Load) w. x. Short Circuit Current contribution from generator at the Point of Common Coupling x. y. Rotating inertia, H in Per Unit on kVA Base, of overall combination generator, prime mover, couplers and gear drives y. z. Station Power load when generator is off-line, Watts, pf z. aa. Station Power load during start-up, Watts, pf aa. bb. Station Power load during operation, Watts, pf bb. Appendix C Inverter Generators Generator Information a. Generator Nameplate Voltage b. Generator Nameplate Watts or Volt-Amperes c. Generator Nameplate Power Factor (pf) d. RPM e. Manufacturer f. Model ( Name / Number ) Technical Information e. Generator Nameplate Voltage f. Generator Nameplate Watts or Volt-Amperes g. Generator Nameplate Power Factor (pf) h. Minimum and Maximum Acceptable Terminal Voltage i. Reactive Capability Curve showing overexcited and underexcited limits (Reactive Information if non-synchronous) j. Short Circuit Current contribution from generator at the Point of Common Coupling k. Station Power load when generator is off-line, Watts, pf l. Station Power load during start-up, Watts, pf m. Station Power load during operation, Watts, pf Appendix D (Not Required for Flow-Back) One - Line Diagram Name of the Licensed Professional Engineer_____________________ PE License Number ___________________________ Address ____________________________________________ Signature___________________________________________ Appendix E (Not Required for Flow-Back) One - Line Diagram Name of the Licensed Professional Engineer_____________________ PE License Number ___________________________ Address ____________________________________________ Appendix F Distribution Circuit 32 (Not Required for Flow-Back) 59 A) One - Line Diagram Name of the Licensed Contractor /PE_____________________ PE License Number ___________________________ Address ____________________________________________ Signature___________________________________________