Download STATE OF MICHIGAN BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION *****

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.
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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.
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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
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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:
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Application for interconnection
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Uniform interconnection agreement
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Description of steps for processing applications (Categories 2-5)
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Specific technical, engineering and operational requirements
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Schedule of fees conforming to R 460.618(1)
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Timeline for notifications under R 460.620
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Protective scheme for projects interconnecting to a spot network circuit >5%
maximum load
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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
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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:
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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)
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APPENDIX A
U-15919 (August 3, 2009 Joint Application)
List of Documents Submitted for Approval
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Michigan Electric Utility Generator Interconnection Requirements – Category 1 –
Projects with Aggregate Generator Output 20 kW or Less
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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
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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
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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
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Interconnection and Operating Agreement for Category 3-5 Projects
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Combined Application Form – Category 21
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Net Metering Application Form – Category 2
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Interconnection Application Form – Category 2
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Combined Application Form – Category 3
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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
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Generator Interconnection Application – Category 4
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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.
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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.
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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.]
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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
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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.
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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.
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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.
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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.
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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.
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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.
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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
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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.
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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
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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
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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.
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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.
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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.
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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.
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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
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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.
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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.
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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.
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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
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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
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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
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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:
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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
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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
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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:
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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
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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
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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
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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.
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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.
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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
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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.
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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.
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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
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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.
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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.
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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
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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)
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EXHIBIT 2
WIRING DIAGRAM
(Insert PDF file here!)
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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___________________________________________