4.1 ERMUSR 02-13-2018 Elk River
Municipal Utilities UTILITIES COMMISSION MEETING
TO: FROM:
ERMU Commission Tom Sagstetter—Conservation and Key Accounts Manager
MEETING DATE: AGENDA ITEM NUMBER:
February 13, 2018 4.1
SUBJECT:
Distributed Generation and Net Metering Policy
ACTION REQUESTED:
Resolution 1 -Adopt by resolution the Distributed Generation and Net Metering Policy; and the
Rules Governing the Interconnection of Cogeneration and Small Power Production Facilities.
Resolution 2—Adopt by resolution the Cogeneration and Small Power Production Tariff.
BACKGROUND:
Every municipal electric utility should have a policy reflecting the expectations and obligations
of the municipal utility and of customers who seek to interconnect their own electric generation
facilities with the municipal utility distribution system. For ERMU these systems consist of wind
or solar PV systems that are less than 40kW.
ERMU and any customer wishing to interconnect(less than 10 MW) are subject to state statues
and rules implementing those statutes. The rules established by the Minnesota Public Utilities
Commission(MPUC) can be adapted to apply to municipal utilities and adopted by the utility's
governing body. The attached documents (Policy, Rules, and Annual Tariff) are versions of the
documents that were established by the MPUC and modified by the Minnesota Municipal
Utilities Association (MMUA) and Minnesota Municipal Power Agency(MMPA)to create
models for member municipals to use with their local governing bodies. These models create a
standard that will allow for consistency over all municipal utilities in the state.
Each municipal utility and their local governing body have the authority to adopt the utility's
policies, rules, and tariff as they pertain to the interconnection of cogeneration and small power
production facilities. Adopting the attached policy, rules, and tariff by the ERMU Utilities
Commission will provide the Commission the authority to settle disputes when they arise
between ERMU and the cogeneration and/or small power production facility. These documents
will have to be reviewed annually to adjust customer compensation rates for excess electricity
generated by the customer and put onto the utility system for use by other customers.
If the ERMU Commission would not adopt policies, rules and tariff as presented,ERMU would
continue to be under the state's rules that requires annual compensation rate filings for approval
by the Minnesota Public Utilities Commission and could potentially result in costly dispute
resolution proceedings by the state-level agency.
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DISCUSSION:
ERMU used the model documents provided by MMUA and MMPA to create the attached
ERMU policy,rules and tariff. On an annual basis, at a minimum,the Commission will have to
review and adopt Schedules 1 and 5 of the tariff. These two schedules reflect the average retail
rate for each customer class that a customer would receive for any excess generation they chose
to be reimbursed for on a monthly or annual basis and the avoided costs to customers for
distributed generation from the wholesale power providers.
The policy, rules, and tariff together represent a great deal of material. Developing standards for
interconnecting cogeneration and small power production facilities for the state of Minnesota is a
daunting task. The proposed tariff is much different than any other tariff of ERMU. This tariff
consists of very detailed rules, requirements, and processes that are not applicable to customers
that are retail consumers of electricity. This process has taken years and is still under review.
There are many interested parties that are involved in this process because it impacts over 170
utilities,their customers, and renewable energy developers.
It's important that the ERMU Utilities Commission adopt the policy, rules, and tariff because by
doing so, it should preserve the right of the ERMU Utility Commission to retain control over
these issues. If the ERMU Utility Commission does not take action on these items, customers
would have the right to dispute a utility's actions regarding cogeneration and small power
production facilities with the Minnesota Public Utilities Commission.
FINANCIAL IMPACT:
N/A
ATTACHMENTS:
• Resolution No.18-1 —Adopting the Distributed Generation and Net Metering Policy; and
Rules Governing the Interconnection of Cogeneration and Small Power Production
Facilities
• Proposed ERMU Policy—E.12—Distributed Generation and Net Metering Policy
• Proposed ERMU Policy—E.12a—Rules Governing the Interconnection of Cogeneration
and Small Power Production Facilities
• Resolution No. 18-2—Adopting the Cogeneration and Small Power Production Tariff
• Proposed ERMU Policy—E.12b—Cogeneration and Small Power Production Facilities
Tariff
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RESOLUTION NO. 18-1
BOARD OF COMMISSIONERS
ELK RIVER MUNICIPAL UTILITIES
A RESOLUTION ADOPTING ELK RIVER MUNICIPAL UTILITIES POLICY
REGARDING DISTRIBUTED GENERATION AND NET METERING; AND
RULES GOVERNING THE INTERCONNECTION OF COGENERATION AND
SMALL POWER PRODUCTION FACILITIES.
WHEREAS, the City is served by Elk River Municipal Utilities, which is committed to
providing customers with reliable and affordable power.
WHEREAS, the purpose of the distributed generation and net metering policy is to
establish the application procedures and qualification criteria for the delivery,
interconnection,metering, and purchase of electricity from distributed generation
facilities.
WHEREAS, it is the responsibility of Elk River Municipal Utilities to implement this
policy and give the maximum possible encouragement to cogeneration and small power
production consistent with protection of the ratepayers and the public.
WHEREAS,the purpose of the cogeneration and small power production rules is for
Elk River Municipal Utilities to implement certain provisions of Minnesota Statutes
Section 216B.164,the Public Utility Regulatory Policies Act of 1978, and Federal
Energy Regulatory Commission regulations related to customer distributed generation.
WHEREAS,the adoption of these rules establishes that the Elk River Municipal
Utilities Commission is the interpreting body and arbiter of the provisions of Minnesota
Statutes Section 216B.164 for Elk River Municipal Utilities.
WHEREAS, Elk River Municipal Utilities shall annually file a cogeneration and small
power production tariff with Elk River Municipal Utilities Commission under these
rules.
WHEREAS,the cogeneration and small power production tariff shall include a
calculation of average retail utility energy rates, standard contracts to be used with
qualifying facilities, interconnection process and technical requirements,procedures for
notifying qualifying facilities when Elk River Municipal Utilities Commission will not
purchase energy or capacity, and Elk River Municipal Utilities estimated average
incremental energy costs and net annual avoided capacity costs.
WHEREAS, all filings under these rules shall be maintained at the Elk River Municipal
Utilities offices and shall be made available for public inspection during normal
business hours.
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THEREFORE,BE IT RESOLVED that the Elk River Municipal Utilities
Commission adopts the Policy Regarding Distributed Generation and Net Metering; and
Rules Governing the Interconnection of Cogeneration and Small Power Production
Facilities.
This Resolution Passed and Adopted this 13th day of February, 2018.
John J. Dietz, Chair
Troy Adams, P.E., General Manager
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-.. .//
Elk RiverK -�-�
Municip al Utilities
E.12 - Distributed Generation and Net Metering Policy
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The purpose of this policy is to establish the application procedure and qualification criteria for
all customers for the delivery, interconnection, metering and purchase of electricity from
distributed generation facilities and to comply with applicable laws and rules governing
distributed generation.
Elk River Municipal Utilities (Utility) recognizes its obligation to provide an interconnection to qualifying
facilities that are eligible for distributed generation and will comply with all applicable laws and rules
governing distributed generation.
For purposes of this policy,the following terms have the meaning given them:
A. Net Metering/Net Billing-the process whereby the customer and the utility compensate each
other based on the difference in the amount of energy each sells to the other at the net
metered facility.
B. Net Metered Facility-an electric generation facility constructed for the purpose of offsetting
energy use through the use of renewable energy or high efficiency generation sources.
C. Average Retail Energy Rate-the average of the retail energy rates, exclusive of special rates
based on income,age,or energy conservation, according to the applicable rate schedule of the
utility for sales to the class of customer of which the customer/qualifying facility belong.
D. Avoided Costs-the incremental costs to the utility of electric energy or capacity or both which,
but for the purchase from the qualifying facility,the utility would generate itself or purchase
from another source.
E. Interconnection Rules-means any applicable Utility Cogeneration Rules developed in
accordance with Minnesota Statutes 2166.164 and 2166.1611 that include issues outlined in the
State of Minnesota Interconnection Process for Distributed Generation Systems, Distributed
Generation Interconnection Requirements, General Interconnection Application, Engineer Data
Submittal and Interconnection Agreement.
F. Interconnection Application-the form to be used by the customer to submit its formal request
for interconnection to the utility and which shall be substantially similar in form to that
Application attached as Exhibit A to this policy.The customer signature on the interconnection
application indicated the customer shall follow the steps outlined in the Utility Cogeneration
Rules and the State of Minnesota Interconnection Process for Distributed Generation System.
The interconnection between the qualifying facility or net metered facility and the utility must
comply with the requirements as stated in the State of Minnesota Distributed Generation
Interconnection Requirements.
G. Contract-the written agreement between the customer/qualifying facility and the utility, as
established in the Utility Cogeneration Rules.
H. Total Generator Nameplate Capacity-the total kW output of a qualifying facility's generator.
For purposes of this definition total output is determined by the nameplate capacity rating,or in
the event that the nameplate capacity is not less than 40 kW,then the existence of any variable
speed drive or other limiting device shall be factored into determining total generator
nameplate capacity.The customer must fully,accurately and completely disclose in its
interconnection application to the utility,the technical specifications for any capacity limiting
device contemplated and the customer shall furnish the utility with any factory manuals or
other similar documents requested from the utility regarding such limiting or other control
devices which factor into the calculation of total generator nameplate capacity.
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I. Measured Capacity-for purposes of determining capacity, it shall be measured based on the
highest fifteen (15) minute average demand of the unit in any one billing period.
J. In the event an inconsistency exists between terms in this policy and those established by
Statute, Rule or Court Order,then the definition so established shall supersede the definition
used in this policy and shall govern.
All customers are eligible for distributed generation, interconnection with the utility's distribution
system and application of net metering upon the following terms and conditions.
1. The customer must meet the eligibility requirements set forth in the federal Public Utility
Regulatory Policies Act of 1978 (PURPA) *18 C.F.R. 292.303, 292.304 and Minnesota's
Distributed Generation laws. Minn.Stat.§2166.164.
2. The customer shall complete,sign and return to Utility an Interconnection Application in the
form prescribed in Exhibit A hereto.The Application shall be approved by Utility prior to the
customer beginning the project.
3. The customer shall enter into a written contract with the Utility using the uniform utility
contract contained in the Utility Cogeneration Rules.
4. The qualifying facility shall pay the Utility for all reasonable costs of interconnection
including those costs outlined in Minnesota Statute 2166.164,the Minnesota
Interconnection Process, and the Minnesota Interconnection Technical Requirements as
established in PUC Docket CI-01-1023.
5. The qualifying facilities total generator nameplate capacity shall be less than 40 kW and the
facility shall operate at a measured capacity of less than 40 kW at all times.
6. The Utility may limit the capacity and operating characteristics of distributed generation
single phase generators in a manner consistent with the utility limitations for single phase
motors,when necessary to avoid a qualifying facility from causing problems with the service
of other customers.
7. The Utility may require the qualifying facility to discontinue parallel generation operations
when necessary for system safety.
8. The power output from the qualifying facility must be maintained so that frequency and
voltage are compatible with normal utility service and do not cause that service to fall
outside the prescribed limits of interconnection rules and other standard limitations.
9. The qualifying facility shall keep in force liability insurance against personal or property
damage due to the installation, interconnection, and operation of its electric generating
facilities.The amount of insurance coverage shall be the maximum amount of said insurance
for a qualifying facility or net metered facility as outlined in the State of Minnesota
Distributed Generation Interconnection Requirements.
10. Failure of the qualifying facility to operate its generators at a measured capacity below the
40 kW capacity limit established by M.S. 2166.164,Sub. 3 and as contemplated by this
policy,shall result in the following.The Utility will notify the customer/qualifying facility of
the fact that its generating equipment has failed to operate below the 40 kW maximum
capacity and will provide the customer/qualifying facility with the date,time and kW reading
that substantiate this finding.
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11. The Utility shall compensate the customer/qualifying facility for all metered electricity
produced by said qualifying facility during the thirty(30) day period during which the failure
occurred,at the Utility's Generation and Transmission Supplier's avoided cost rate.
12. The Utility shall continue to pay the customer/qualifying facility for subsequent electricity
produced and delivered pursuant to this distributed generation agreement, at the Utility's
Generation and Transmission Supplier's avoided cost rate until:
1. The problem with the generator that caused it to operate at or above the statutory
maximum capacity has been remedied;and
2. The Utility has been provided documentation adopted by a Minnesota Professional
Engineer that confirms the problem with the generator has been remedied.
13. Any customer account eligible for net metering and the net billing rate may not be eligible
for any other load management discounts unless agreed to by the Utility.
14. Payment for the purchase of distributed generation electricity herein shall be in the form of
a credit on the customer's monthly billing invoice or paid by check or electronic payment to
the customer within fifteen (15) days of the billing date,whichever is selected and indicated
in the Contract.
15. The customer must be, and continue to be,current with payment on its electric account
with Utility.
16. The customer must not enter into any arrangement that violates the Utility's exclusive right
to provide electric service in its service area under Minnesota Statutes§2166.40.
17. In the event that the distributed generator fails to meet the requirements of this policy for a
Total Generator Nameplate Capacity of less than 40 kW, and fails to satisfy the corrective
requirements set forth in Section 12 above,then Utility will have the right to (1) cancel the
Contract with the owner of the distributed generator,and (2)enter into a new contract with
the owner of the distributed generator that, among other changes, adjusts the distributed
generator's rated capacity and specifies avoided cost pricing for the distributed generator's
output.To the extent that the Utility does not have the obligation to make purchases from
qualifying facilities of 40 kW or greater due to transfer of the obligation to the Utility's
wholesale supplier that has been approved by the Federal Energy Regulatory Commission,
the new agreement will be between the Utility's wholesale supplier and the distributed
generator. In either case, Utility(and as applicable Utility's wholesale supplier)and the
owner of the distributed generator will cooperate in the transition from the form of contract
set forth in the Utility's adopted cogeneration rules to a new form of contract appropriate to
a distributed generator with a capacity of 40 kW or greater.
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Elk RiverLz
Municipal Utilitie s
E.12a — Rules Governing the Interconnection of
Cogeneration and Small Power Production
Facilities with Elk River Municipal Utilities
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•
Part A. DEFINITIONS.
Subpart 1. Applicability. For purposes of these rules, the following terms have the
meanings given them below.
Subp. 2. Average retail utility energy rate. "Average retail utility energy rate" means,
for any class of utility customer, the quotient of the total annual class revenue from sales
of electricity minus the annual revenue resulting from fixed charges, divided by the
annual class kilowatt-hour sales. The computation shall use data from the most recent 12-
month period available.
Subp. 3. Backup power. "Backup power" means electric energy or capacity supplied by
the utility to replace energy ordinarily generated by a qualifying facility's own generation
equipment during an unscheduled outage of the facility.
Subp. 4. Capacity. "Capacity" means the capability to produce, transmit, or deliver
electric energy, and is measured by the number of megawatts alternating current at the
point of common coupling between a qualifying facility and the utility's electric system
during a 15-minute interval period.
Subp. 5. Capacity costs. "Capacity costs" means the costs associated with providing the
capability to deliver energy. The utility capital costs consist of the costs of facilities from
the utility and the utility's wholesale provider used to generate, transmit, and distribute
electricity and the fixed operating and maintenance costs of these facilities.
Subp. 6. Customer. "Customer" means the person named on the utility electric bill for
the premises.
Subp. 7. Energy. "Energy" means electric energy, measured in kilowatt-hours.
Subp. 8. Energy costs. "Energy costs" means the variable costs associated with the
production of electric energy. They consist of fuel costs and variable operating and
maintenance expenses.
Subp. 9. Firm power. "Firm power" means energy delivered by the qualifying facility to
the utility with at least a 65 percent on-peak capacity factor in the month. The capacity
factor is based upon the qualifying facility's maximum metered capacity delivered to the
utility during the on-peak hours for the month.
Subp. 10. Governing body. "Governing body" means [replace this text and brackets with
the name of the city council or commission or board that governs the utility].
Subp. 11. Interconnection costs. "Interconnection costs" means the reasonable costs of
connection, switching, metering,transmission, distribution, safety provisions, and
administrative costs incurred by the utility that are directly related to installing and
maintaining the physical facilities necessary to permit interconnected operations with a
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qualifying facility. Costs are considered interconnection costs only to the extent that they
exceed the costs the utility would incur in selling electricity to the qualifying facility as a
nongenerating customer.
Subp. 12. Interruptible power. "Interruptible power" means electric energy or capacity
supplied by the utility to a qualifying facility subject to interruption under the provisions
of the utility's tariff applicable to the retail class of customers to which the qualifying
facility would belong irrespective of its ability to generate electricity.
Subp. 13. Maintenance power. "Maintenance power" means electric energy or capacity
supplied by a utility during scheduled outages of the qualifying facility.
Subp. 14. On-peak hours. "On-peak hours" means either those hours formally
designated by the utility as on-peak for ratemaking purposes or those hours for which its
typical loads are at least 85 percent of its average maximum monthly loads.
Subp. 15. Point of common coupling. "Point of common coupling" means the point
where the qualifying facility's generation system, including the point of generator output,
is connected to the utility's electric power grid.
Subp. 16.Purchase. "Purchase" means the purchase of electric energy or capacity or
both from a qualifying facility by the utility.
Subp. 17. Qualifying facility. "Qualifying facility" means a cogeneration or small power
production facility which satisfies the conditions established in Code of Federal
Regulations, title 18, part 292. The initial operation date or initial installation date of a
cogeneration or small power production facility must not prevent the facility from being
considered a qualifying facility for the purposes of this chapter if it otherwise satisfies all
stated conditions. The qualifying facility must be owned by a Customer and located in the
utility service area.
Subp. 18. Sale. "Sale" means the sale of electric energy or capacity or both by the utility
to a qualifying facility.
Subp. 19a. Standby charge. "Standby charge" means the charge imposed by the utility
upon a qualifying facility for the recovery of costs for the provision of standby services
necessary to make electricity service available to the qualifying facility.
Subp. 19b. Standby service. "Standby service" means the service to potentially provide
electric energy or capacity supplied by the utility to a qualifying facility greater than 40
kW.
Subp. 20. Supplementary power. "Supplementary power" means electric energy or
capacity supplied by the utility which is regularly used by a qualifying facility in addition
to that which the facility generates itself.
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Subp. 21. System emergency. "System emergency" means a condition on the utility's
system which is imminently likely to result in significant disruption of service to
customers or to endanger life or property.
Subp. 22. Utility. "Utility" means [replace this text with the name of the municipal
utility].
Part B. SCOPE AND PURPOSE.
The purpose of these rules are to implement certain provisions of Minnesota Statutes,
section 216B.164; the Public Utility Regulatory Policies Act of 1978, United States Code,
title 16, section 824a-3; and the Federal Energy Regulatory Commission regulations,
Code of Federal Regulations, title 18, part 292. These rules shall be applied in accordance
with their intent to give the maximum possible encouragement to cogeneration and small
power production consistent with protection of the ratepayers and the public.
Part C. FILING REQUIREMENTS
Annually the utility shall file for review and approval, a cogeneration and small
power production tariff with the governing body. The tariff must contain schedules 1 —5.
SCHEDULE 1.
Schedule 1 shall contain the calculation of the average retail utility energy rates to be
updated annually.
SCHEDULE 2.
Schedule 2 shall contain all standard contracts to be used with qualifying facilities,
containing applicable terms and conditions.
SCHEDULE 3.
Schedule 3 shall contain the utility's adopted interconnection process, safety
standards, technical requirements for distributed energy resource systems, required
operating procedures for interconnected operations, and the functions to be performed by
any control and protective apparatus.
SCHEDULE 4.
Schedule 4 shall contain procedures for notifying affected qualifying facilities of any
periods of time when the utility will not purchase electric energy or capacity because of
extraordinary operational circumstances which would make the costs of purchases during
those periods greater than the costs of internal generation.
SCHEDULE 5.
Schedule 5 shall contain the estimated average incremental energy costs by seasonal,
peak and off-peak periods for the utility's power supplier from which energy purchases
are first avoided. Schedule 5 shall also contain the net annual avoided capacity costs, if
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any, stated per kilowatt-hour and averaged over the on-peak hours and over all hours for
the utility's power supplier from which capacity purchases are first avoided. Both the
average incremental energy costs and net annual avoided capacity costs shall be increased
by a factor equal to 50 percent of the utility and the utility's power supplier's overall line
losses due to distribution, transmission and transformation of electric energy.
Part D. AVAILABILITY OF FILINGS.
All filings shall be maintained at the utility's general office and any other offices of
the utility where rate tariffs are kept. The filings shall be made available for public
inspection during normal business hours. The utility shall supply the current year's
distributed generation rates, interconnection procedures and application form on the utility
website, if practicable, or at the utility office.
Part E. REPORTING REQUIREMENTS
Annually the utility shall report to the governing body for its review and approval an
annual report including information in subparts 1-3. The utility shall still comply with
other federal and state reporting of distributed generation to federal and state agencies
expressly required by statute.
•
Subpart 1. Summary of Average Retail Utility Energy Rate. A summary of the
qualifying facilities that are currently served under average retail utility energy rate.
Subp. 2. Other Qualifying Facilities. A summary of the qualifying facilities that are not
currently served under average retail utility energy rate.
Subp. 3. Wheeling. A summary of the wheeling undertaken with respect to qualifying
facilities.
Part F. CONDITIONS OF SERVICE
Subpart 1. Requirement to Purchase. The utility shall purchase energy and capacity
from any qualifying facility which offers to sell energy and capacity to the utility and
agrees to the conditions in these rules.
Subp. 2. Written Contract. A written contract shall be executed between the qualifying
facility and the utility.
Part G. ELECTRICAL CODE COMPLIANCE.
Subpart 1. Compliance; standards. The interconnection between the qualifying facility
and the utility must comply with the requirements in the most recently published edition
of the National Electrical Safety Code issued by the Institute of Electrical and Electronics
Engineers. The interconnection is subject to subparts 2 and 3.
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Subp. 2. Interconnection. The qualifying facility is responsible for complying with all
applicable local, state, and federal codes, including building codes,the National Electrical
Code (NEC), the National Electrical Safety Code (NESC), and noise and emissions
standards. The utility shall require proof that the qualifying facility is in compliance with
the NEC before the interconnection is made. The qualifying facility must obtain
installation approval from an electrical inspector recognized by the Minnesota State
Board of Electricity.
Subp. 3. Generation system. The qualifying facility's generation system and installation
must comply with the American National Standards Institute/Institute of Electrical and
Electronics Engineers (ANSI/IEEE) standards applicable to the installation.
Part H. RESPONSIBILITY FOR APPARATUS.
The qualifying facility, without cost to the utility, must furnish, install, operate,
and maintain in good order and repair any apparatus the qualifying facility needs in order
to operate in accordance with schedule 3.
Part I. TYPES OF POWER TO BE OFFERED; STANDBY SERVICE.
Subpart 1. Service to be offered. The utility shall offer maintenance, interruptible,
supplementary, and backup power to the qualifying facility upon request.
Subp. 2. Standby service. The utility shall offer a qualifying facility standby power or
service at the utility's applicable standby rate schedule.
Part J. DISCONTINUING SALES DURING EMERGENCY.
The utility may discontinue sales to the qualifying facility during a system
emergency, if the discontinuance and recommencement of service is not discriminatory.
Part K. RATES FOR UTILITY SALES TO A QUALIFYING FACILITY.
Rates for sales to a qualifying facility are governed by the applicable tariff for the
class of electric utility customers to which the qualifying facility belongs or would belong
were it not a qualifying facility. Such rates are not guaranteed and may change from time
to time at the discretion of the utility.
Part L. STANDARD RATES FOR PURCHASES FROM QUALIFYING
FACILITIES.
Subpart 1. Qualifying facilities with 100 kilowatt capacity or less. For qualifying
facilities with capacity of 100 kilowatts or less, standard purchase rates apply. The utility
shall make available four types of standard rates, described in parts M,N, 0, and P. The
qualifying facility with a capacity of 100 kilowatts or less must choose interconnection
under one of these rates, and must specify its choice in the written contract required in
part V. Any net credit to the qualifying facility must, at its option, be credited to its
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account with the utility or returned by check or comparable electronic payment service
within 15 days of the billing date. The option chosen must be specified in the written
contract required in part V. Qualifying facilities remain responsible for any monthly
service charges and demand charges specified in the tariff under which they consume
electricity from the utility.
Subp. 2. Qualifying facilities over 100-kilowatt capacity. A qualifying facility with
more than 100-kilowatt capacity has the option to negotiate a contract with the utility or,
if it commits to provide firm power, be compensated under standard rates.
Subp. 3. Grid Access Charge. A qualifying facility shall be assessed a monthly Grid
Access Charge to recover the fixed costs not already paid by the customer through the
customer's existing billing arrangement. The additional charge shall be reasonable and
appropriate for the class of customer based on the most recent cost of service study
defining the Grid Access Charge. The cost of service study for the Grid Access Charge
shall be made available for review by the customer of the utility upon request.
Part M. AVERAGE RETAIL UTILITY ENERGY RATE.
Subpart 1. Applicability. The average retail utility energy rate is available only to
customer-owned qualifying facilities with capacity of less than 40 kilowatts which choose
not to offer electric power for sale on either a time-of-day basis, a simultaneous purchase
and sale basis or roll-over credit basis.
Subp. 2. Method of billing. The utility shall bill the qualifying facility for the excess of
energy supplied by the utility above energy supplied by the qualifying facility during each
billing period according to the utility's applicable retail rate schedule.
Subp. 3. Additional calculations for billing. When the energy generated by the
qualifying facility exceeds that supplied by the utility to the customer at the same site
during the same billing period,the utility shall compensate the qualifying facility for the
excess energy at the average retail utility energy rate.
Part N. SIMULTANEOUS PURCHASE AND SALE BILLING RATE.
Subpart 1. Applicability. The simultaneous purchase and sale rate is available only to
qualifying facilities with capacity of less than 40 kilowatts which choose not to offer
electric power for sale on average retail utility energy rate basis, time-of-day basis or roll-
over credit basis.
Subp. 2. Method of billing. The qualifying facility must be billed for all energy and
capacity it consumes during a billing period according to the utility's applicable retail rate
schedule.
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Subp. 3. Compensation to qualifying facility; energy purchase. The utility shall
purchase all energy which is made available to it by the qualifying facility. At the option
of the qualifying facility, its entire generation must be deemed to be made available to the
utility. Compensation to the qualifying facility must be the energy rate shown on schedule
5.
Subp. 4. Compensation to qualifying facility; capacity purchase. If the qualifying
facility provides firm power to the utility, the capacity component must be the utility's
net annual avoided capacity cost per kilowatt-hour averaged over all hours shown on
schedule 5, divided by the number of hours in the billing period. If the qualifying facility
does not provide firm power to the utility, no capacity component may be included in the
compensation paid to the qualifying facility.
Part O. TIME-OF-DAY PURCHASE RATES.
Subpart 1. Applicability. Time-of-day rates are required for qualifying facilities with
capacity of 40 kilowatts or more and less than or equal to 100 kilowatts, and they are
optional for qualifying facilities with capacity less than 40 kilowatts. Time-of-day rates
are also optional for qualifying facilities with capacity greater than 100 kilowatts if these
qualifying facilities provide firm power.
Subp. 2. Method of billing. The qualifying facility must be billed for all energy and
capacity it consumes during each billing period according to the utility's applicable retail
rate schedule.
Subp. 3. Compensation to qualifying facility; energy purchases. The utility shall
purchase all energy which is made available to it by the qualifying facility. Compensation
to the qualifying facility must be the energy rate shown on schedule 5.
Subp. 4. Compensation to qualifying facility; capacity purchases. If the qualifying
facility provides firm power to the utility, the capacity component must be the capacity
cost per kilowatt shown on schedule 5 divided by the number of on-peak hours in the
billing period. The capacity component applies only to deliveries during on-peak hours. If
the qualifying facility does not provide firm power to the utility, no capacity component
may be included in the compensation paid to the qualifying facility.
Part P. ROLL-OVER CREDIT PURCHASE RATES.
Subpart 1. Applicability. The roll-over credit rate is available only to qualifying facilities
with capacity of less than 40 kilowatts which choose not to offer electric power for sale on
average retail utility energy rate basis, time-of-day basis or simultaneous purchase and
sale basis.
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Subp. 2. Method of billing. The utility shall bill the qualifying facility for the excess of
energy supplied by the utility above energy supplied by the qualifying facility during each
billing period according to the utility's applicable retail rate schedule.
Subp. 3. Additional calculations for billing. When the energy generated by the
qualifying facility exceed that supplied by the utility during a billing period,the utility
shall apply the excess kilowatt hours as a credit to the next billing period kilowatt hour
usage. Excess kilowatt hours that are not offset in the next billing period shall continue to
be rolled over to the next consecutive billing period. Any excess kilowatt hours rolled
over that are remaining at the end of each calendar year shall cancel with no additional
compensation.
Part Q. CONTRACTS NEGOTIATED BY CUSTOMER.
A qualifying facility with capacity greater than 100 kilowatts must negotiate a
contract with the utility setting the applicable rates for payments to the customer of
avoided capacity and energy costs.
Subpart 1. Amount of Capacity Payments. The qualifying facility which negotiates a
contract under part Q must be entitled to the full avoided capacity costs of the utility. The
amount of capacity payments will be determined by the utility and the utility's wholesale
power provider.
Subp. 2. Full Avoided Energy Costs. The qualifying facility which negotiates a contract
under part Q must be entitled to the full avoided energy costs of the utility. The costs
must be adjusted as appropriate to reflect line losses.
Part R. WHEELING
Qualifying facilities with capacity of 30 kilowatts or greater, are interconnected to
the utility's distribution system and choose to sell the output of the qualifying facility to
any other utility, must pay any appropriate wheeling charges to the utility. Within 15 days
of receiving payment from the utility ultimately receiving the qualifying facility's output,
the utility shall pay the qualifying facility the payment less the charges it has incurred and
its own reasonable wheeling costs.
Part S. NOTIFICATION TO CUSTOMERS
Subpart 1. Contents of Written Notice. Following each annual review and approval by
the utility of the cogeneration rate tariffs the utility shall furnish in the monthly newsletter
or similar mailing, written notice to each of its customers that the utility is obligated to
interconnect with and purchase electricity from cogenerators and small power producers.
Subp. 2. Availability of Information. The utility shall make available to all interested
persons upon request, the interconnection process and requirements adopted by the utility,
pertinent rate schedules and sample contractual agreements.
8
53
Part T. DISPUTE RESOLUTION
In case of a dispute between a utility and a qualifying facility or an impasse in the
negotiations between them, either party may request the governing body to determine the
issue.
Part U. INTERCONNECTION CONTRACTS
Subpart 1. Interconnection Standards. The utility shall provide a customer applying
for interconnection with a copy of, or electronic link to, the utility's adopted
interconnection process and requirements.
Subp. 2. Existing Contracts. Any existing interconnection contract executed between
the utility and a qualifying facility with capacity of less than 40 kilowatts remains in
force until terminated by mutual agreement of the parties or as otherwise specified in the
contract. The governing body has assumed all dispute responsibilities as listed in existing
interconnection contracts. Disputes are resolved in accordance with Part T.
Subp. 3. Renewable Energy Credits; Ownership. Generators own all renewable
energy credits unless other ownership is expressly provided for by a contract between a
generator and the utility
Part V. UNIFORM CONTRACT.
The form for uniform contract that shall be used between the utility and a qualifying
facility having less than 40 kilowatts of capacity is as shown in subpart 1.
Subpart 1. Contract for Cogeneration and Small Power Production Facilities. (See
attached contract form.)
ADOPTED ON:
SIGNED:
Chair of the Elk River Municipal Utilities Commission
9
54
CONTRACT FOR COGENERATION AND
SMALL POWER PRODUCTION FACILITIES
THIS CONTRACT is entered into this day of , , by Elk
River Municipal Utilities, a municipal utility under Minnesota law (hereafter called "Utility")
and (hereafter called "QF").
RECITALS
• The QF has installed electric generating facilities, consisting of
(Description of facilities),
rated at kilowatts of electricity, on property located at
•
• The QF is a customer of the Utility located within the assigned electric service territory of
the Utility.
• The QF is prepared to generate electricity in parallel with the Utility.
• The QF's electric generating facilities meet the requirements of the rules adopted by the
Utility on Cogeneration and Small Power Production and any technical standards for
interconnection the Utility has established that are authorized by those rules.
• The Utility is obligated under federal and Minnesota law to interconnect with the QF and to
purchase electricity offered for sale by the QF.
• A contract between the QF and the Utility is required.
AGREEMENTS
The QF and the Utility agree:
1. The Utility will sell electricity to the QF under the rate schedule in force for the class
of customer to which the QF belongs.
2. The Utility will buy electricity from the QF under the current rate schedule filed with
the city council or city-appointed body governing the utility. The QF elects the rate schedule
category hereinafter indicated:
a. Average retail utility rate.
• QF capacity must be less than 40 kW.
b. Simultaneous purchase and sale billing rate.
• QF capacity must be less than 40 kW.
55
c. Roll-over credits.
• QF capacity must be less than 40 kW.
d. Time-of-day purchase rate.
• QF capacity must be 40 kW or more and less than or equal to 100 kW.
A copy of the presently filed rate schedule is attached to this contract.
3. The rates for sales and purchases of electricity may change over the time this contract
is in force, due to actions of the Utility or of the State of Minnesota, and the QF and the Utility
agree that sales and purchases will be made under the rates in effect each month during the time
this contract is in force.
4. The Utility will compute the charges and payments for purchases and sales for each
billing period. Any net credit to the QF, other than kilowatt-hour credits under clause 2(c), will
be made under one of the following options as chosen by the QF:
a. Credit to the QF's account with the Utility.
b. Paid by check or electronic payment service to the QF within 15 days of the
billing date.
5. Renewable energy credits associated with generation from the facility are owned by
QF:
6. The QF must operate its electric generating facilities within any rules, regulations,
and policies adopted by the Utility not prohibited by the Minnesota Public Utilities
Commission's rules on Cogeneration and Small Power Production. The Utility's rules,
regulations, and policies must be consistent with the Minnesota Public Utilities Commission's
rules on Cogeneration and Small Power Production, as required under Minnesota Statutes
§216B.164, subdivision 9.
7. The QF will not enter into an arrangement whereby electricity from the generating
facilities will be sold to an end user in violation of the Utility's or any other electric utility's
exclusive right to provide electric service in its service area under Minnesota Statutes, Sections
216B.37-44.
8. The QF will operate its electric generating facilities so that they conform to the
national, state, and local electric and safety codes, and will be responsible for the costs of
conformance.
9. The QF is responsible for the actual, reasonable costs of interconnection which are
estimated to be $ . The QF will pay the Utility in this way:
56
10. The QF will give the Utility reasonable access to its property and electric generating
facilities if the configuration of those facilities does not permit disconnection or testing from
the Utility's side of the interconnection. If the Utility enters the QF's property, the Utility will
remain responsible for its personnel.
11. The Utility may stop providing electricity to the QF during a system emergency. The
Utility will not discriminate against the QF when it stops providing electricity or when it
resumes providing electricity.
12. The Utility may stop purchasing electricity from the QF when necessary for the
Utility to construct, install, maintain, repair, replace, remove, investigate, or inspect any
equipment or facilities within its electric system.
The Utility will notify the QF before it stops purchasing electricity in this way:
13. The QF will keep in force liability insurance against personal or property damage
due to the installation, interconnection, and operation of its electric generating facilities. The
amount of insurance coverage will be $ (The amount must be consistent with
the Utility's distributed generation tariff under Minnesota Statutes §216B.1611, subdivision 3,
clause 2.
14. The Utility and the QF agree to attempt to resolve any dispute arising hereunder
promptly and in a good faith manner.
15. The city council or city-appointed body governing the Utility has authority to
consider and determine disputes, if any, that arise under this contract pursuant to Minnesota
Statues §216B.164, subd. 9.
16. This contract becomes effective as soon as it is signed by the QF and the Utility.
This contract will remain in force until either the QF or the Utility gives written notice to the
other that the contract is canceled. This contract will be canceled 30 days after notice is given.
17. Neither the QF or the Utility will be considered in default as to any obligation if the
QF or the Utility is prevented from fulfilling the obligation due to an event of Force Majeure.
However, the QF or Utility whose performance under this contract is hindered by an event of
Force Majeure shall make all reasonable efforts to perform its obligations.
18. This contract can only be amended or modified by mutual agreement in writing
signed by the QF and the Utility.
57
19. Each Party will be responsible for its own acts or omissions and the results thereof to
the extent authorized by law and shall not be responsible for the acts or omissions of any others
and the results thereof
20. The QF's and the Utility's liability to each other for failure to perform its obligations
under this contract shall be limited to the amount of direct damage actually occurred. In no
event, shall the QF or the Utility be liable to each other for any punitive, incidental, indirect,
special, or consequential damages of any kind whatsoever, including for loss of business
opportunity or profits, regardless of whether such damages were foreseen.
21. The Utility does not give any warranty, expressed or implied, to the adequacy,
safety, or other characteristics of the QF's interconnected system.
22. This contract contains all the agreements made between the QF and the Utility. The
QF and the Utility are not responsible for any agreements other than those stated in this contract.
THE QF AND THE UTILITY HAVE READ THIS CONTRACT AND AGREE TO BE
BOUND BY ITS TERMS. AS EVIDENCE OF THEIR AGREEMENT, THEY HAVE EACH
SIGNED THIS CONTRACT BELOW ON THE DATE WRITTEN AT THE BEGINNING OF
THIS CONTRACT.
QF UTILITY
Signature Signature
Printed Name Printed Name
Title Title
58
RESOLUTION NO. 18-2
BOARD OF COMMISSIONERS
ELK RIVER MUNICIPAL UTILITIES
A RESOLUTION ADOPTING ELK RIVER MUNICIPAL UTILITIES
COGENERATION AND SMALL POWER PRODUCTION TARIFF.
WHEREAS, Elk River Municipal Utilities rules and Minnesota Statutes Section
216B.164 require the utility to annually file a Cogeneration and Small Power Production
Tariff with the Elk River Municipal Utilities Commission
WHEREAS, Schedule 1 of this tariff shall provide the calculation of average retail
utility energy rates.
WHEREAS, Schedule 2 provides standard contracts to be used with qualifying
facilities.
WHEREAS, Schedule 3 provides the utility's safety standards, required operating
procedures for interconnected operations, and the functions to be performed by any
control and protective apparatus.
WHEREAS, Schedule 4 provides procedures for notifying qualifying facilities of
periods when Elk River Municipal Utilities will not purchase energy or capacity.
WHEREAS, Schedule 5 provides the estimated seasonal peak and off-peak system
average incremental energy costs for the utility's power supplier from which energy
purchases are first avoided, as well as the power supplier's net annual avoided capacity
costs.
WHEREAS,these filings shall be maintained at the Elk River Municipal Utilities
offices and shall be made available for public inspection during normal business hours.
THEREFORE,BE IT RESOLVED that the Elk River Municipal Utilities
Commission adopts the Cogeneration and Small Power Production Tariff for
transactions following the date of adoption stated below.
This Resolution Passed and Adopted this 13th day of February, 2018.
John J. Dietz, Chair
Troy Adams, P.E., General Manager
59
Cogeneration and Small Power Production Tariff- Introduction
E.12b-Tariff
Pursuant to its Rules Governing the Interconnection of Cogeneration and Small Power
Production Facilities, Elk River Municipal Utilities ("Utility") establishes and/or updates its
Cogeneration and Small Power Production Tariff("Tariff") for billing and sales transactions
following the date of Tariff approval as follows. The Tariff shall consist of:
SCHEDULE 1.
Calculation of average retail utility energy rates
SCHEDULE 2.
Standard contracts to be used with Qualifying Facilities.
SCHEDULE 3.
Interconnection process, safety standards, and technical requirements for distributed energy
resource systems, required operating procedures for interconnected operations, and
functions to be performed by any control and protective apparatus.
SCHEDULE 4.
Procedures for notifying affected Qualifying Facilities of any periods of time when the utility will •
not purchase electric energy or capacity because of extraordinary operational circumstances.
SCHEDULE 5.
Estimated average incremental energy costs by seasonal, peak and off-peak periods and annual
avoided capacity costs from the utility's wholesale power supplier.
60
SCHEDULE 1—AVERAGE RETAIL UTILITY ENERGY RATES
Average Retail Utility Energy Rate: Available to any Qualifying Facility of less than 40 kW
capacity that does not select either Roll Over Credits, Simultaneous Purchase and Sale Billing or
Time of Day rates.
Utility shall bill Qualifying Facilities for any excess of energy supplied by Utility above energy
supplied by the Qualifying Facility during each billing period according to Utility's applicable
rate schedule. Utility shall pay the customer for the energy generated by the Qualifying Facility
that exceeds that supplied by Utility during a billing period at the "average retail utility energy
rate." "Average retail utility energy rate" means, for any class of utility customer,the quotient
of the total annual class revenue from sales of electricity minus the annual revenue resulting
from fixed charges, divided by the annual class kilowatt-hour sales. Data from the most recent
12-month period available shall be used in the computation.
"Average retail utility energy rates" are as follows:
Customer Class Average Retail
Utility Energy Rate
Residential $0.1269/kWh
Commercial Non-Demand $0.1133/kWh
Commercial Demand $0.0613/kWh
61
SCHEDULE 2-STANDARD CONTRACT
CONTRACT FOR COGENERATION AND
SMALL POWER PRODUCTION FACILITIES
THIS CONTRACT is entered into on this day of , , by Elk
River Municipal Utilities, a municipal utility under Minnesota law (hereafter called "Utility")
and (hereafter called "QF").
RECITALS
• The QF has installed electric generating facilities, consisting of
(Description of facilities),
rated at kilowatts of electricity, on property located at
•
• The QF is a customer of the Utility located within the assigned electric service territory of
the Utility.
• The QF is prepared to generate electricity in parallel with the Utility.
• The QF's electric generating facilities meet the requirements of the rules adopted by the
Utility on Cogeneration and Small Power Production and any technical standards for
interconnection the Utility has established that are authorized by those rules.
• The Utility is obligated under federal and Minnesota law to interconnect with the QF and to
purchase electricity offered for sale by the QF.
• A contract between the QF and the Utility is required.
AGREEMENTS
The QF and the Utility agree:
1. The Utility will sell electricity to the QF under the rate schedule in force for the class
of customer to which the QF belongs.
2. The Utility will buy electricity from the QF under the current rate schedule filed with
the city council or city-appointed body governing the utility. The QF elects the rate schedule
category hereinafter indicated:
a. Average retail utility rate.
• QF capacity must be less than 40 kW.
b. Simultaneous purchase and sale billing rate.
• QF capacity must be less than 40 kW.
62
SCHEDULE 2-STANDARD CONTRACT
c. Roll-over credits.
• QF capacity must be less than 40 kW.
d. Time-of-day purchase rate.
• QF capacity must be 40 kW or more and less than or equal to 100 kW.
A copy of the presently filed rate schedule is attached to this contract.
3. The rates for sales and purchases of electricity may change over the time this contract
is in force, due to actions of the Utility or of the State of Minnesota, and the QF and the
Utility agree that sales and purchases will be made under the rates in effect each month during
the time this contract is in force.
4. The Utility will compute the charges and payments for purchases and sales for each
billing period. Any net credit to the QF, other than kilowatt-hour credits under clause 2(c),
will be made under one of the following options as chosen by the QF:
a. Credit to the QF's account with the Utility.
b. Paid by check or electronic payment service to the QF within 15 days of the
billing date.
5. Renewable energy credits associated with generation from the facility are owned by
QF:
6. The QF must operate its electric generating facilities within any rules, regulations, and
policies adopted by the Utility not prohibited by the Minnesota Public Utilities Commission's
rules on Cogeneration and Small Power Production. The Utility's rules, regulations, and
policies must be consistent with the Minnesota Public Utilities Commission's rules on
Cogeneration and Small Power Production, as required under Minnesota Statutes §216B.164,
subdivision 9.
7. The QF will not enter into an arrangement whereby electricity from the generating
facilities will be sold to an end user in violation of the Utility's or any other electric utility's
exclusive right to provide electric service in its service area under Minnesota Statutes,
Sections 216B.37-44.
8. The QF will operate its electric generating facilities so that they conform to the
national, state, and local electric and safety codes, and will be responsible for the costs of
conformance.
9. The QF is responsible for the actual, reasonable costs of interconnection which are
estimated to be $ . The QF will pay the Utility in this way:
63
SCHEDULE 2-STANDARD CONTRACT
10. The QF will give the Utility reasonable access to its property and electric generating
facilities if the configuration of those facilities does not permit disconnection or testing from
the Utility's side of the interconnection. If the Utility enters the QF's property, the Utility will
remain responsible for its personnel.
11. The Utility may stop providing electricity to the QF during a system emergency. The
Utility will not discriminate against the QF when it stops providing electricity or when it
resumes providing electricity.
12. The Utility may stop purchasing electricity from the QF when necessary for the
Utility to construct, install, maintain, repair, replace, remove, investigate, or inspect any
equipment or facilities within its electric system.
The Utility will notify the QF before it stops purchasing electricity in this way:
13. The QF will keep in force liability insurance against personal or property damage due
to the installation, interconnection, and operation of its electric generating facilities. The
amount of insurance coverage will be $ (The amount must be consistent with
the Utility's distributed generation tariff under Minnesota Statutes §216B.1611, subdivision 3,
clause 2.
14. The Utility and the QF agree to attempt to resolve any dispute arising hereunder
promptly and in a good faith manner.
15. The city council or city-appointed body governing the Utility has authority to
consider and determine disputes, if any, that arise under this contract pursuant to Minnesota
Statues §216B.164, subd. 9.
16. This contract becomes effective as soon as it is signed by the QF and the Utility.
This contract will remain in force until either the QF or the Utility gives written notice to the
other that the contract is canceled. This contract will be canceled 30 days after notice is given.
17. Neither the QF or the Utility will be considered in default as to any obligation if
the QF or the Utility is prevented from fulfilling the obligation due to an event of Force
Majeure. However, the QF or Utility whose performance under this contract is hindered by an
event of Force Majeure shall make all reasonable efforts to perform its obligations.
18. This contract can only be amended or modified by mutual agreement in writing
signed by the QF and the Utility.
19. Each Party will be responsible for its own acts or omissions and the results thereof
to the extent authorized by law and shall not be responsible for the acts or omissions of any
others and the results thereof.
64
SCHEDULE 2—STANDARD CONTRACT
20. The QF's and the Utility's liability to each other for failure to perform its
obligations under this contract shall be limited to the amount of direct damage actually
occurred. In no event, shall the QF or the Utility be liable to each other for any punitive,
incidental, indirect, special, or consequential damages of any kind whatsoever, including for
loss of business opportunity or profits, regardless of whether such damages were foreseen.
21. The Utility does not give any warranty, expressed or implied, to the adequacy,
safety, or other characteristics of the QF's interconnected system.
22. This contract contains all the agreements made between the QF and the Utility.
The QF and the Utility are not responsible for any agreements other than those stated in this
contract.
THE QF AND THE UTILITY HAVE READ THIS CONTRACT AND AGREE TO BE
BOUND BY ITS TERMS. AS EVIDENCE OF THEIR AGREEMENT, THEY HAVE EACH
SIGNED THIS CONTRACT BELOW ON THE DATE WRITTEN AT THE BEGINNING
OF THIS CONTRACT.
QF UTILITY
Signature Signature
Printed Name Printed Name
Title Title
65
SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
State of Minnesota
Interconnection Process for
Distributed Generation Systems
Introduction
This document has been prepared to explain the process established in the State of Minnesota,
to interconnect a Generation System with the Area Electrical Power System (Area EPS). This
document covers the interconnection process for all types of Generation Systems which are rated
10MW's or less of total generation Nameplate Capacity; are planned for interconnection with the
Area EPS's Distribution System; are not intended for wholesale transactions and aren't
anticipated to affect the transmission system. This document does not discuss the
interconnection Technical Requirements, which are covered in the "State of Minnesota
Distributed Generation Interconnection Requirements" document. This other interconnection
requirements document also provides definitions and explanations of the terms utilized within this
document. To interconnect a Generation System with the Area EPS, there are several steps that
must be followed. This document outlines those steps and the Parties' responsibilities. At any
point in the process, if there are questions, please contact the Generation Interconnection
Coordinator at the Area EPS. Since this document has been developed to provide an
interconnection process which covers a very diverse range of Generation Systems, the process
appears to be very involved and cumbersome. For many Generation Systems the process is
streamlined and provides an easy path for interconnection.
The promulgation of interconnection standards for Generation Systems by the Minnesota Public
Utilities Commission (MPUC) must be done in the context of a reasonable interpretation of the
boundary between state and federal jurisdiction. The Federal Energy Regulatory Commission
(FERC) has asserted authority in the area, at least as far as interconnection at the transmission
level is concerned. This, however, leaves open the question of jurisdiction over interconnection
at the distribution level. The Midwest Independent System Operator's (MISO) FERC Electric
Tariff, (first revised volume 1, August 23,2001)Attachment R(Generator Interconnection
Procedures and Agreement) states in section 2.1 that"Any existing or new generator connecting
at transmission voltages, sub-transmission voltages, or distribution voltages, planning to engage
in the sale for resale of wholesale energy, capacity, or ancillary services requiring transmission
service under the Midwest ISO OATT must apply to the Midwest ISO for interconnection service".
Further in section 2.4 it states that"A Generator not intending to engage in the sale of wholesale
energy, capacity, or ancillary services under the Midwest ISO OATT, that proposes to
interconnect a new generating facility to the distribution system of a Transmission Owner or local
distribution utility interconnected with the Transmission System shall apply to the Transmission
Owner or local distribution utility for interconnection". It goes on further to state"Where facilities
under the control of the Midwest ISO are affected by such interconnection, such interconnections
may be subject to the planning and operating protocols of the Midwest ISO...."
Through discussions with MISO personnel and as a practical matter, if the Generation System
Nameplate Capacity is not greater in size than the minimum expected load on the distribution
substation, that is feeding the proposed Generation System, and Generation System's energy is
not being sold on the wholesale market, then that installation may be considered as not
"affecting"the transmission system and the interconnection may be considered as governed by
this process. If the Generation System will be selling energy on the wholesale market or the
Generation System's total Nameplate Capacity is greater than the expected distribution
substation minimum load, then the Applicant shall contact MISO (Midwest Independent System
Operator) and follow their procedures.
Interconnection Process for Distributed Generates Systems
SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
GENERAL INFORMATION
A) Definitions
1) "Applicant" is defined as the person or entity who is requesting the interconnection of the
Generation System with the Area EPS and is responsible for ensuring that the Generation
System is designed, operated and maintained in compliance with the Technical
Requirements.
2) "Area EPS" is defined as an electric power system (EPS) that serves Local EPS's. Note.
Typically, an Area EPS has primary access to public rights-of-way, priority crossing of
property boundaries,etc.
3) "Area EPS Operator"is the entity who operates the Area EPS.
4) "Dedicated Facilities" is the equipment that is installed due to the interconnection of the
Generation System and not required to serve other Area EPS customers.
5) "Distribution System" is the Area EPS facilities which are not part of the Area EPS
Transmission System or any Generation System.
6) "Extended Parallel" means the Generation System is designed to remain connected with the
Area EPS for an extended period of time.
7) "Generation" is defined as any device producing electrical energy, i.e., rotating generators
driven by wind, steam turbines, internal combustion engines, hydraulic turbines, solar, fuel
cells,etc.;or any other electric producing device,including energy storage technologies.
8) "Generation Interconnection Coordinator" is the person or persons designated by the Area
EPS Operator to provide a single point of coordination with the Applicant for the generation
interconnection process.
9) "Generation System" is the interconnected generator(s), controls, relays, switches,
breakers, transformers, inverters and associated wiring and cables, up to the Point of
Common Coupling.
10) "Interconnection Customer" is the party or parties who will own/operate the Generation
System and are responsible for meeting the requirements of the agreements and Technical
Requirements. This could be the Generation System applicant, installer, owner, designer, or
operator.
11) "Local EPS" is an electric power system (EPS) contained entirely within a single premises or
group of premises
12) "Nameplate Capacity" is the total nameplate capacity rating of all the Generation included in
the Generation System. For this definition the"standby"and/or maximum rated kW capacity
on the nameplate shall be used.
13) "Open Transfer" is a method of transferring the local loads from the Area EPS to the
generator such that the generator and the Area EPS are never connected together.
Interconnection Process for Distributed Generate Systems
SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
14) "Point of Common Coupling" is the point where the Local EPS is connected to an Area EPS
15) "Quick Closed" is a method of generation transfer which does not parallel or parallels for
less than 100msec with the Area EPS and has utility grade timers which limit the parallel
duration to less than 100 msec with the Area EPS.
16) "Technical Requirements" "is the State of Minnesota Distributed Generation Interconnection
Requirements".
17) "Transmission System" means those facilities as defined by using the guidelines established
by the Minnesota State Public Utilities Commission; "In the Matter of Developing Statewide
Jurisdictional Boundary Guidelines for Functionally Separating Interstate Transmission from
Generation and Local Distribution Functions" Docket No. E-015/M-99-1002.
B) Dispute Resolution
The following is the dispute resolution process to be followed for problems that occur with
the implementation of this process.
1) Each Party agrees to attempt to resolve all disputes arising hereunderpromptly,
equitably and in a good faith manner.
2) In the event a dispute arises under this process,and the parties are not successful in
resolving their disputes,then either party may refer the dispute for resolution to the Elk
River Municipal Utilities Commission,which shall maintain continuing jurisdiction over this
process.
C) Area EPS Generation Interconnection Coordinator.
Each Area EPS Operator shall designate a Generation Interconnection Coordinator(s)
and this person or persons shall provide a single point of contact for an Applicant's
questions on this Generation Interconnection process. Some Area EPS Operators may
have several Generation Interconnection Coordinators assigned, due to the geographical
size of their electrical service territory or the amount of interconnection applications. This
Generation Interconnection Coordinator will typically not be able to directly answer or
resolve all of the issues involved in the review and implementation of the interconnection
process and standards, but shall be available to provide coordination assistance with the
Applicant
Interconnection Process for Distributed Generat(g8 Systems
SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
D) Engineering Studies
During the process of design of a Generation System interconnection between a
Generation System and an Area EPS, there are several studies which many need to be
undertaken. On the Local EPS (Customers side of the interconnection)the addition of a
Generation System may increase the fault current levels, even if the generation is never
interconnected with the Area EPS's system. The Interconnection Customer may need to
conduct a fault current analysis of the Local EPS in conjunction with adding the
Generation System. The addition of the Generation System may also affect the Area
EPS and special engineering studies may need to be undertaken looking at the Area
EPS with the Generation System included.Appendix D, lists some of the issues that
may need to receive further analysis for the Generation System interconnection.
While, it is not a straightforward process to identify which engineering studies are
required, we can at least develop screening criteria to identify which Generation Systems
may require further analysis. The following is the basic screening criteria to be used for
this interconnection process.
1) Generation System total Nameplate Capacity does not exceed 5%of the radial circuit
expected peak load.The peak load is the total expected load on the radial circuit when the
other generators on that same radial circuit are not in operation.
2) The aggregate generation's total Nameplate Capacity,including all existing and proposed
generation,does not exceed 25%of the radial circuit peak load and that total is also less
than the radial circuit minimum load.
3) Generation System does not exceed 15%of the Annual Peak Load for the Line Section,
which it will interconnect with.A Line Section is defined as that section of the
distribution system between two sectionalizing devices in the Area EPS.
4) Generation System does not contribute more than 10%to the distribution circuit's
maximum fault current at the point at the nearest interconnection with the Area EPS's
primary distribution voltage.
5) The proposed Generation System total Nameplate Capacity,in aggregate with other
generation on the distribution circuit,will not cause any distribution protective devices and
equipment to exceed 85 percent of the short circuit interruptingcapability.
6) If the proposed Generation System is to be interconnected on a single-phase shared
secondary, the aggregate generation Nameplate Capacity on the shared secondary,
including the proposed generation,does not exceed 20kW.
7) Generation System will not be interconnected with a "networked"system
Interconnection Process for Distributed Generat g Systems
SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
E) Scoping Meeting
During Step 2 of this process, the Applicant or the Area EPS Operator has the option to
request a scoping meeting. The purpose of the scoping meeting shall be to discuss the
Applicant's interconnection request and review the application filed. This scoping
meeting is to be held so that each Party can gain a better understanding of the issues
involved with the requested interconnection. The Area EPS and Applicant shall bring to
the meeting personnel, including system engineers, and other resources as may be
reasonably required, to accomplish the purpose of the meeting. The Applicant shall not
expect the Area EPS to complete the preliminary review of the proposed Generation
System at the scoping meeting. If a scoping meeting is requested, the Area EPS shall
schedule the scoping meeting within the 15 business day review period allowed for in
Step 2. The Area EPS shall then have an additional 5 days, after the completion of the
scoping meeting, to complete the formal response required in Step 2. The Application
fee shall cover the Area EPS's costs for this scoping meeting. There shall be no
additional charges imposed by the Area EPS for this initial scoping meeting
F) Insurance
1) At a minimum,in connection with the Interconnection Customer's performance of its
duties and obligations under this Agreement,the Interconnection Customer shall maintain,
during the term of the Agreement,general liability insurance,from a qualified insurance
agency with a B+or better rating by"Best"and with a combined single limit of not less
then:
a) Two million dollars($2,000,000)for each occurrence if the Gross Nameplate Rating
of the Generation System is greater than 250kW.
b) One million dollars($1,000,000)for each occurrence if the Gross Nameplate Rating
of the Generation System is between 40kW and 250kW.
c) Three hundred thousand($300,000)for each occurrence if the Gross Nameplate Rating
of the Generation System is less than 40kW.
d) Such general liability insurance shall include coverage against claims for damages
resulting from(i)bodily injury, including wrongful death;and (ii) property damage
arising out of the Interconnection Customer's ownershipand/or operating of the
Generation System under this agreement.
2) The general liability insurance required shall, by endorsement to the policy or policies,(a)
include the Area EPS Operator as an additional insured; (b)contain a sever ability of
interest clause or cross-liability clause; (c)provide that the Area EPS Operator shall not by
reason of its inclusion as an additional insured incur liability to the insurance carrier for the
payment of premium for such insurance;and(d) provide for thirty(30)calendar days'
written notice to the Area EPS Operator prior to cancellation,termination,alteration,or
material change of such insurance.
3) If the Generation System is connected to an account receiving residential service from
the Area EPS Operator and it total generating capacity is smaller than 40kW,then the
endorsements required in Section F.2 shall not apply.
Interconnection Process for Distributed Generatiy Systems
SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
4) The Interconnection Customer shall furnish the required insurance certificates and
endorsements to the Area EPS Operator prior to the initial operation of the Generation
System.Thereafter,the Area EPS Operator shall have the right to periodically inspect or
obtain a copy of the original policy or policies of insurance
5) Evidence of the insurance required in Section F.1.shall state that coverage provided is
primary and is not excess to or contributing with any insurance or self-insurance
maintained by the Area EPS Operator.
6) If the Interconnection Customer is self-insured with an established record of self-
insurance, the Interconnection Customer may comply with the following in lieu of
Section F.1—5:
7) Interconnection Customer shall provide to the Area EPS Operator,at least thirty(30)days
prior to the date of initial operation,evidence of an acceptable plan to self-insure to a level
of coverage equivalent to that required under section F.1
8) If Interconnection Customer ceases to self-insure to the level required hereunder,or if the
Interconnection Customer is unable to provide continuing evidence of its ability to self-
insure,the Interconnection Customer agrees to immediately obtain the coverage required
under section F.1.
9) Failure of the Interconnection Customer or Area EPS Operator to enforce the minimum
levels of insurance does not relieve the Interconnection Customer from maintaining such
levels of insurance or relieve the Interconnection Customer of any liability.
G) Pre-Certification
The most important part of the process to interconnect generation with Local and Area
EPS's is safety. One of the key components of ensuring the safety of the public and
employees is to ensure that the design and implementation of the elements connected to
the electrical power system operate as required. To meet this goal, all of the electrical
wiring in a business or residence, is required by the State of Minnesota to be listed by a
recognized testing and certification laboratory, for its intended purpose. Typically we see
this as"UL" listed. Since Generation Systems have tended to be uniquely designed for
each installation they have been designed and approved by Professional Engineers.
This process has been set up to be able to deal with these uniquely designed systems.
As the number of Generation Systems installed increase, vendors are working towards
creating equipment packages which can be tested in the factory and then will only require
limited field testing. This will allow us to move towards"plug and play" installations. For
this reason, this interconnection process recognizes the efficiency of"pre-certification" of
Generation System equipment packages that will help streamline the design and
installation process.
Interconnection Process for Distributed Generatiii Systems
SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
An equipment package shall be considered certified for interconnected operation if it has
been submitted by a manufacture, tested and listed by a nationally recognized testing
and certification laboratory(NRTL)for continuous utility interactive operation in
compliance with the applicable codes and standards. Presently generation paralleling
equipment that is listed by a nationally recognized testing laboratory as having met the
applicable type-testing requirements of UL 1741 and IEEE 929 shall be acceptable for
interconnection without additional protection system requirements.An "equipment
package"shall include all interface components including switchgear, inverters, or other
interface devices and may include an integrated generator or electric source. If the
equipment package has been tested and listed as an integrated package which includes
a generator or other electric source, it shall not require further design review, testing or
additional equipment to meet the certification requirements for interconnection. If the
equipment package includes only the interface components (switchgear, inverters, or
other interface devices), then the Interconnection Customer shall show that the generator
or other electric source being utilized with the equipment package is compatible with the
equipment package and consistent with the testing and listing specified for the package.
Provided the generator or electric source combined with the equipment package is
consistent with the testing ad listing performed by the nationally recognized testing and
certification laboratory, no further design review, testing or additional equipment shall be
required to meet the certification requirements of this interconnection procedure.A
certified equipment package does not include equipment provided by the Area EPS.
The use of Pre-Certified equipment does not automatically qualify the Interconnection
Customer to be interconnected to the Area EPS. An application will still need to be
submitted and an interconnection review may still need to be performed, to determine the
compatibility of the Generation System with the Area EPS.
H) Confidential Information
Except as otherwise agreed, each Party shall hold in confidence and shall not disclose
confidential information, to any person (except employees, officers, representatives and
agents, who agree to be bound by this section). Confidential information shall be clearly
marked as such on each page or otherwise affirmatively identified. If a court, government
agency or entity with the right, power, and authority to do so, requests or requires either
Party, by subpoena, oral disposition, interrogatories, requests for production of
documents, administrative order, or otherwise, to disclose Confidential Information, that
Party shall provide the other Party with prompt notice of such request(s) or
requirements(s) so that the other Party may seek an appropriate protective order or
waive compliance with the terms of this Agreement. In the absence of a protective order
or waiver the Party shall disclose such confidential information which, in the opinion of its
counsel, the party is legally compelled to disclose. Each Party will use reasonable efforts
to obtain reliable assurance that confidential treatment will be accorded any confidential
information so furnished.
I) Non-Warranty.
Neither by inspection, if any, or non-rejection, nor in any other way, does the Area EPS
Operator give any warranty, expressed or implied, as to the adequacy, safety, or other
characteristics of any structures, equipment, wires, appliances or devices owned,
installed or maintained by the Applicant or leased by the Applicant from third parties,
including without limitation the Generation System and any structures, equipment, wires,
appliances or devices pertinent thereto.
Interconnection Process for Distributed Generatip2 Systems
SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
J) Required Documents
The chart below lists the documents required for each type and size of Generation
System proposed for interconnection.
Find your type of Generation System interconnection, across the top, then follow the
chart straight down, to determine what documents are required as part of the
interconnection process.
Interconnection Process (This document)
State of Minnesota Distributed Generation Interconnection Requirements
Generation Interconnection Application (Appendix B)
Engineering Data Submittal (Appendix C)
Om Interconnection Agreement
(Appendix E)
it MISO/FERC
:AA � �.� PPA
Interconnection Process ="State of Minnesota Interconnection Process for Distributed
Generation Systems." (This document)
State of Minnesota Distributed Generation Interconnection Requirements ="State of Minnesota
Distributed Generation Interconnection Requirements"
Generation Interconnection Application =The application form in Appendix B of this document.
Engineering Data Submittal =The Engineering Data Form/Agreement, which is attached as
Appendix C of this document.
Interconnection Agreement="Minnesota State Interconnection Agreement for the
Interconnection of Extended Parallel Distributed Generation Systems with Electric Utilities."
MISO. = Midwest Independent System Operator, www.midwestiso.orq
FERC = Federal Energy Regulatory Commission, www.ferc.qov
PPA= Power Purchase Agreement.
Interconnection Process for Distributed Generati 3 Systems
SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
Process for Interconnection
Step 1 Application (By Applicant)
Once a decision has been made by the Applicant, that they would like to interconnect a
Generation System with the Area EPS, the Applicant shall supply the Area EPS with the following
information:
1) Completed Generation Interconnection Application (Appendix C),including;
a) One-line diagram showing;
i) Protective relaying.
ii) Point of Common Coupling.
b) Site plan of the proposed installation.
c) Name plate capacity of proposed generation system.
d) Estimate of annual energy production from proposed generation system.
e) Proposed schedule of the installation.
2) Payment of the application fee,according to the following sliding scale.
Generation Interconnection Application Fees: $200
This application fee is to contribute to the Area EPS Operator's labor costs for administration,
review of the design concept and preliminary engineering screening for the proposed Generation
System interconnection.
Step 2 Preliminary Review (By Area EPS)
Within 15 business days of receipt of all the information listed in Step 1, the Area EPS Generation
Interconnection Coordinator shall respond to the Applicant with the information listed below. (If
the information required in Step 1 is not complete, the Applicant will be notified, within 10
business days of what is missing and no further review will be completed until the missing
information is submitted. The 15-day clock will restart with the new submittal)
As part of Step 2 the proposed Generation System will be screened to see if additional
Engineering Studies are required. The base screening criteria is listed in the general information
section of this document.
Interconnection Process for Distributed Generati 4 Systems
SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
1) A single point of contact with the Area EPS Operator for this project.(Generation
Interconnection Coordinator)
2) Approval or rejection of the generation interconnection request.
a) Rejection—The Area EPS shall supply the technical reasons,with supporting
information,for rejection of the interconnection Application.
b) Approval-An approved Application is valid for 6 months from the date of the
approval.The Area EPS Generation Interconnection Coordinator may extend this
time if requested by the Applicant
3) If additional specialized engineering studies are required for the proposed interconnection,
the following information will be provided to the Applicant.Typical Engineering Studies are
outlined in Appendix D.The costs to the Applicant,for these studies shall be not exceed the
values shown in the following table for pre-certified equipment.
Generation System Size Engineering Study
Maximum Costs
<_40kW Actual Costs
>40kW Actual Costs
a) General scope of the engineering studies required.
b) Estimated cost of the engineering studies.
c) Estimated duration of the engineering studies.
d) Additional information required to allow the completion of the engineering
studies.
e) Study authorization agreement.
4) Comments on the schedule provided.
5) If the rules of MISO(Midwest Independent System Operator)require that this
interconnection request be processed through the MISO process,the Generation
Interconnection Coordinator will notify the Applicant that the generation system isnot
eligible for review through the State of Minnesota process.
Step 3 Go-No Go Decision for Engineering Studies (By Applicant)
In this step, the Applicant will decide whether or not to proceed with the required engineering
studies for the proposed generation interconnection. If no specialized engineering studies are
required by the Area EPS Operator, the Area EPS Operator and the Applicant will automatically
skip this step.
If the Applicant decides NOT to proceed with the engineering studies, the Applicant shall notify
the Area EPS Generation Interconnection Coordinator, so other generation interconnection
requests in the queue are not adversely impacted. Should the Applicant decide to proceed, the
Applicant shall provide the following to the Area EPS Generation Interconnection Coordinator:
1) Payment required by the Area EPS Operator for the specialized engineeringstudies.
2) Additional information requested by the Area EPS Operator to allow completion of the
engineering studies.
Interconnection Process for Distributed Generatiy5 Systems
SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
Step 4 Engineerina Studies (By Area EPS)
In this step, the Area EPS Operator will be completing the specialized engineering studies for the
proposed generation interconnection, as outlined in Step 2. These studies should be completed
in the time frame provided in step 2, by the Area EPS. It is expected that the Area EPS Operator
shall make all reasonable efforts to complete the Engineering Studies within the time frames
shown below. If additional time is required to complete the engineering studies the Generation
Interconnection Coordinator shall notify the Applicant and provide the reasons for the time
extension. Upon receipt of written notice to proceed, payment of applicable fee, and receipt of all
engineering study information requested by the Area EPS Operator in step 2, the Area EPS
Operator shall initiate the engineering studies.
Generation System Size Engineering Study Completion
<_40kW 20 working days
>40kW 30—90 working days
Once it is known by the Area EPS Operator that the actual costs for the engineering studies will
exceed the estimated amount by more the 25%, then the Applicant shall be notified. The Area
EPS Operator shall then provide the reason(s)for the studies needing to exceed the original
estimated amount and provide an updated estimate of the total cost for the engineering studies.
The Applicant shall be given the option of either withdrawing the application, or paying the
additional estimated amount to continue with the engineering studies.
Step 5 Study Results and Construction Estimates (By Area EPS)
Upon completion of the specialized engineering studies, or if none was necessary, the following
information will be provided to the Applicant.
1) Results of the engineering studies,if needed.
2) Monitoring&control requirements for the proposed generation.
3) Special protection requirements for the Generation System interconnection.
4) Comments on the schedule proposed by the Applicant.
5) Distributed Generation distribution constrained credits available
6) Interconnection Agreement(if applicable).
7) Cost estimate and payment schedule for required Area EPS work,including,but not limited
to;
a) Labor costs related to the final design review.
b) Labor&expense costs for attending meetings
c) Required Dedicated Facilities and other Area EPS modification(s).
d) Final acceptance testing costs.
Interconnection Process for Distributed Generatiy Systems
SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
Step 6 Final Go-No Go Decision (By Applicant)
In this step, the Applicant shall again have the opportunity to indicate whether or not they want to
proceed with the proposed generation interconnection. If the decision is NOT to proceed, the
Applicant will notify the Area EPS Generation Interconnection Coordinator, so that other
generation interconnections in the queue are not adversely impacted. Should the Applicant
decide to proceed, a more detailed design, if not already completed by the Applicant, must be
done, and the following information is to be supplied to the Area EPS Generation Interconnection
Coordinator:
1) Applicable up-front payment required by the Area EPS,per Payment Schedule,
provided in Step 5.(if applicable)
2) Signed Interconnection Agreement(if applicable).
3) Final proposed schedule,incorporating the Area EPS comments.The schedule of the project
should include such milestones as foundations poured,equipment delivery dates,all conduit
installed,cutover(energizing of the new switchgear/transfer switch),Area EPS work, relays
set and tested,preliminary vendor testing,final Area EPS acceptance testing,and any other
major milestones.
4) Detailed one-line diagram of the Generation System,including the generator,transfer
switch/switchgear,service entrance, lockable and visible disconnect,metering,protection
and metering CT's/VT's,protective relaying and generator control system.
5) Detailed information on the proposed equipment,including wiring diagrams,models and
types.
6) Proposed relay settings for all interconnection required relays.
7) Detailed site plan of the Generation System.
8) Drawing(s)showing the monitoring system(as required per table 5A and section 5 of the
"State of Minnesota Distributed Generation Interconnection Requirements". Including a
drawing which shows the interface terminal block with the Area EPS monitoring system.
9) Proposed testing schedule and initial procedure,including;
a) Time of day(after-hours testing required?).
b) Days required.
c) Testing steps proposed.
Step 7 Final Design Review (By Area EPS)
Within 15 business days of receipt of the information required in Step 6, The Area EPS
Generation Interconnection Coordinator will provide the Applicant with an estimated time table for
final review. If the information required in Step 6 is not complete, the Applicant will be notified,
within 10 business days of what information is missing. No further review may be completed until
the missing information is submitted. The 15-business day clock will restart with the new
submittal. This final design review shall not take longer than 15 additional business days to
complete, for a total of 30 business days.
Interconnection Process for Distributed Generatip7 Systems
SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
During this step, the Area EPS shall complete the review of the final Generation System design.
If the final design has significant changes from the Generation System proposed on the original
Application which invalidate the engineering studies or the preliminary engineering screening, the
Generation System Interconnection Application request may be rejected by the Area EPS
Operator and the Applicant may be requested to reapply with the revised design.
Upon completion of this step the Generation Interconnection Coordinator shall supply the
following information to the Applicant.
1) Requested modifications or corrections of the detailed drawings provided by the
Applicant.
2) Approval of and mutual agreement with the Project Schedule.(This may need to be
interactively discussed between the Parties,during this Step)
3) Final review of Distributed Generation Credit amount(s)(where applicable).
4) Initial testing procedure review comments. (Additional work on the testing process will occur
during Step 8,once the actual equipment is identified)
Step 8 Order Equipment and Construction (By Both Parties)
The following activities shall be completed during this step. For larger installations this step will
involve much interaction between the Parties. It is typical for approval drawings to be supplied by
the Applicant to the Area EPS for review and comments. It is also typical for the Area EPS to
require review and approval of the drawings that cover the interconnection equipment and
interconnection protection system. If the Area EPS also requires remote control and/or
monitoring, those drawings are also exchanged for review and comment.
By the Applicant's personnel:
1) Ordering of Generation System equipment.
2) Installing Generation System.
3) Submit approval drawings for interconnection equipment and protection systems,as
required by Area EPS Operator.
4) Provide final relay settings provided to the Area EPS Operator.
5) Submit Completed and signed Engineering Data Submittal form.
6) Submit proof of insurance,as required by the Area EPS tariff(s)or interconnection
agreements.
7) Submit required State of Minnesota electrical inspection forms("blue Copy)filedwith the
Area EPS Operator.
8) Inspecting and functional testing Generation System components.
9) Work with the Area EPS personnel and equipment vendor(s)to finalize the
installation testing procedure.
By Area EPS personnel:
1) Ordering any necessary Area EPS equipment.
2) Installing and testing any required equipment.
a) Monitoring facilities.
b) Dedicated Equipment.
3) Assisting Applicant's personnel with interconnection installation coordination issues
4) Providing review and input for testing procedures.
Step 9 Final Tests (By Area EPS /Applicant)
(Due to equipment lead times and construction, a significant amount of time may take place
between the execution of Step 8 and Step 9.) During this time the final test steps are developed
and the construction of the facilities are completed.
Interconnection Process for Distributed Generatiy8 Systems
SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
Final acceptance testing will commence when all equipment has been installed, all contractor
preliminary testing has been accomplished and all Area EPS preliminary testing of the monitoring
and dedicated equipment is completed. One to three weeks prior to the start of the acceptance
testing of the generation iriterconnection the Applicant shall provide, a report stating:
1. That the Generation System meets all interconnection requirements.
2. All contractor preliminary testing has been completed.
3. The protective systems are functionally tested and ready.
4. A proposed date that the Generation System will be is ready to be energized
and acceptance tested.
For non-type certified systems a Professional Electrical Engineer registered in the State of
Minnesota is required to provide this formal report.
For smaller systems scheduling of this testing may be more flexible, as less testing time is
required than for larger systems.
In many cases, this testing is done after hours to ensure no typical business-hour load is
disturbed. If acceptance testing occurs after hours, the Area EPS Operator's labor will be billed
at overtime wages. During this testing, the Area EPS Operator will typically run three different
tests. These tests can differ depending on which type of communication/monitoring system(s)
the Area EPS Operator decides to install at the site.
For, problems created by Area EPS or any Area EPS equipment that arise during testing, the
Area EPS will fix the problem as soon as reasonably possible. If problems arise during testing
which are caused by the Applicant or Applicant's vendor or any vendor supplied or installed
equipment, the Area EPS will leave the project until the problem is resolved. Having the testing
resume will then be subject to Area EPS personnel time and availability.
Step 10 (By Area EPS)
After all Area EPS Operator's acceptance testing has been accomplished and all requirements
are met, the Area EPS Operator shall provide written approval for normal operation of the
Generation System interconnection, within 3 business days of successful completion of the
acceptance tests.
Step 11 (By Applicant)
Within two (2) months of interconnection, the Applicant shall provide the Area EPS with updated
drawings and prints showing the Generation System as it was when approved for normal
operation by the Area EPS Operator. The drawings shall also include all changes which were
made during construction and the testing process.
Attachments:
Attached are several documents which may be required for the interconnection process. They
are as follows;
Appendix A:
Flow chart showing summary of the interconnection process.
Appendix B:
Generation Interconnection Application Form.
Interconnection Process for Distributed Generatiyg Systems
SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
Appendix C:
Engineering Data Submittal Form.
Appendix D:
Engineering Studies: Brief description of the types of possible Engineering
Studies that may be required for the review of the Generation System
interconnection.
Interconnection Process for Distributed Generates Systems
SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
APPENDIX A
DISTRIBUTED GENERATION INTERCONNECTION PROCESS
SUMMARY
Request for
Additional -NO
STEP 1 — 1 Information
Application&$$ Is`N
Filed with Application
�y
Area EPS Operator y Information
---------------„„ ''‘,,Complete?
Written Response by
STEP 2 / Are '� Yes
N.
rea Cwt of Engineering Yes�� Specialized Area EPS preliminary review of
ti Engmeerirg Studi Generation System Design
15 DAYS Studies \
-- �.. Required?LL—
STEP 3
r f
Applicant Decision
No
♦- -.__.No ----K Proceed or Not? j
`,,y-$for Studies„7"
N. I Area EPS Provides;
��� • Results of Engineering Studies(if required)
STEP 4&5 Yes • Estimated Interconnection Costs
T_ ... ..__._ • Monitoring and Control Requirements
Area EPS- • Interconnection Agreement(if applicable)
Specialized Engineering Studies € poj • Special Protection Requirements
_ • Dedicated Facilities(if required)
• Etc.
STEP 6 n M..
The following FINAL Design is provided by the Applicanti „..„,_
ill they decide to proceed.
• Applicable upfront payment
• Engineering Data Submittal
• Detailed Drawings and plans ,, .--
(one-lines,site plan,protection system) /
• Signed Interconnection Agreement Yes^'- Applicant �, No ►
• Relay Settings �._ Proceed or Not?
• Proposed Schedule �`�.,.
• Testing Plan
• Etc. -----
STEP? V
Area EPS reviews the FINAL plans, and provides final design approval.
15-30 DAYS Some issues at this step may need to be worked out interactively.
STEP 8 — I —
Parties Order Equipment
4.
1 -Hr = Area EPS approval
i
Testing for operation
Construction STEP 9 0' STEP 10
Interconnection Process for Distributed Generate Systems
SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
APPENDIX B
Interconnection Process for Distributed Generates Systems
SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
State of Minnesota
Generation Interconnection Application Page 1
WHO SHOULD FILE THIS APPLICATION: Anyone expressing interest to install generation which will interconnec
with (the Utility). This application should be completed and returned
to the Utility'sGeneration Interconnection Coordinator,in order to begin processing the request.
INFORMATION: This application is used by the Utility to perform a preliminary interconnection review.
The Applicant shall complete as much of the form as possible. The fields in BOLD are required to be completed
to the best of the Applicants ability.The Applicant will be contacted if additional information is required. The
response may take up to 15 business days after receipt of all the required information.
COST: A payment to cover the application fee shall be included with this application. The application fee amount is
outlined in the`State of Minnesota Interconnection Process for Distributed Generation Systems'.
OWNER/APPLICANT
Company!Applicant's Name:
Representative: Phone Number: FAX Number:
Title:
Mailing Address:
Email Address:
LOCATION OF GENERATION SYSTEM INTERCONNECTION
Street Address,legal description or GPS coordinates:
PROJECT DESIGN I ENGINEERING (if applicable)
Company:
Representative: Phone: FAX Number:
Mailing Address:
Email Address:
ELECTRICAL CONTRACTOR(if applicable)
Company:
Representative: Phone: FAX Number:
Mailing Address:
Email Address:
GENERATOR
Manufacturer: Mod et:
Type(Synchronous Induction.Inverter,etc): Phases: 1 or 3
Rated Output(Prime kW): (Standby kW): Frequency:
Rated Power Factor(%): Rated Voltage(Volts): Rated Current(Amperes):
Energy Source(gas,steam,hydro,wind,etc.)
TYPE OF INTERCONNECTED OPERATION
Interconnection,'Transfer method:
Open Quick Open Closed Soft Loading Inverter
Proposed use of generation:(Check all that may apply) Duration Parallel:
Peak Reduction Standby Energy Sales None Limited Continuous
Cover Load
Pre-Certified System: Yes!No (Circle one) Exporting Energy Yes i No (Circle one)
Interconnection Process for Distributed Generate Systems
SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS, AND OPERATING PROCEDURES
State of Minnesota
Generation Interconnection Application Page 2
ESTIMATED LOAD INFORMATION
The following information will be used to help properly design the interconnection. This Information is not
intended as a commitment or contract for billing purposes.
Minimum anticipated load(generation not operating): kW: kVA:
Maximum anticipated load(generation not operating): kW: kVA:
ESTIMATED START/COMPLETION DATES
Construction start date: Completion(operational)date:
DESCRIPTION OF PROPOSED INSTALLATION AND OPERATION
Attach a single line diagram showing the switchgear. transformers, and generation facilities.
Give a general description of the manner of operation of the generation (cogeneration. closed-
transition peak shaving. open-transition peak shaving. emergency power. etc.). Also. does the
Applicant intend to sell power and energy or ancillary services andlor wheel power over
's facilities. If there is an intent to sell power and energy, also define the target
market.
1__
PROJECT INFORMATION (Required by MN Statute 216B.16611 subd. 3a)
Nameplate Capacity of Facility:
Pre-Incentive Install Cost and Cost Components:
Facility Energy Source:(Circle One)
Solar Wind Biomass Other(Please Specify)
Zip Code of the Facility Location:
SIGN OFF AREA:
With this Application,we are requesting the Utility to review the proposed Generation System Interconnection.
We request that the Utility identifies the additional equipment and costs involved with the interconnection of this
system and to provide a budgetary estimate of those costs. We understand that the estimated costs supplied by
the Utility will be estimated using the information provided.We also agree that we will supply,as requested,
additional information,to allow the Utility to better review this proposed Generation System interconnection. We
have read the°State of Minnesota Distributed Generation Interconnection Requirements'and will design the
Generation System and interconnection to meet those requirements.
Applicant Name(print):
Applicant Signature: Date:
SEND THIS COMPLETED&SIGNED APPLICATION AND ATTACHMENTS TO
Interconnection Process for Distributed Generate Systems
SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
APPENDIX C
INSERT
ENGINEERING DATA
SUBMITTAL
FORM
(if applicable)
Interconnection Process for Distributed Generate Systems
SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
APPENDIX D
Engineering Studies
For the engineering studies the major concerns are; 1.Does the distributed generator cause a problem?
and 2.What would it cost to make a change to handle the problem?The first question is relatively
straightforward to determine as the Area EPS Engineer reviews the proposed installation.The second
question typically has multiple alternatives and can turn into an iterative process.This iterative process
can become quite large for more complex generation installations.For the Engineer there is no"cook
book"solution which can be applied.
For some of the large generation installations and/or the more complex interconnections the Area EPS
Operator may suggest dividing up the engineering studies into the two parts;identify the scope of the
problems and attempt to identify solutions to resolve the problems.By splitting the engineering studies
into two steps,it will allow for the Applicant to see the problems identified and to provide the Applicant
the ability to remove the request for interconnection if the problems are too large and expensive to resolve.
This would then save the additional costs to the Applicant for the more expensive engineering studies;to
identity ways to resolve the problem(s).
This appendix provides an overview of some of the main issues that are looked at during the engineering
study process.Every interconnection has its unique issues,such as relative strength of the distribution
system,ratio of the generation size to the existing area loads,etc.Thus many of the generation
interconnections will require further review of one or several of the issues listed.
• Short circuit analysis—the system is studied to make sure that the addition of the generation will
not over stress any of the Area EPS equipment and that equipment will still be able to clear during
a fault.It is expected that the Applicant will complete their own short circuit analysis on their
equipment to ensure that the addition of the generation system does not overstress the Applicant's
electrical equipment.
• Power Flow and Voltage Drop
- Reviews potential islanding of the generation
- Will Area EPS Equipment be overloaded
• Under normal operation?
• Under contingent operation?With back feeds?
• Flicker Analysis-
- Will the operation of the generation cause voltage swings?
• When it loads up?When it off loads?
- How will the generation interact with Area EPS voltage regulation?
- Will Area EPS capacitor switching affect the generation while on-line?
• Protection Coordination
- Reclosing issues—this is where the reclosing for the distribution system and transmission
system are looked at to see if the Generation System protection can be set up to ensure
that it will clear from the distribution system before the feeder is reenergized.
• Is voltage supervision of reclosing needed?
- Is transfer-trip required?
- Do we need to modify the existing protection systems?Existing settings?
- At which points do we need"out of sync"protection?
- Is the proposed interconnection protection system sufficient to sense a problem on the
Area EPS?
- Are there protection problems created by the step-up transformer?
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SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
• Grounding Reviews
- Does the proposed grounding system for the Generation System meet the requirements of
the NESC? "National Electrical Safety Code" published by the Institute of Electrical
and Electronics Engineers(IEEE)
• System Operation Impact.
- Are special operating procedures needed with the addition of the generation?
- Reclosing and out of sync operation of facilities.
- What limitations need to be placed on the operation of the generation?
- Operational Var requirements?
Interconnection Process for Distributed Generate Systems
SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
STATE OF MINNESOTA
DISTRIBUTED GENERATION INTERCONNECTION
REQUIREMENTS
TABLE OF CONTENTS
Foreword 2
1. Introduction 3
2. References 6
3. Types of Interconnections 7
4. Interconnection Issues and Technical Requirements 10
5. Generation Metering, Monitoring and Control 13
Table 5A— Metering, Monitoring and Control Requirements 14
6. Protective Devices and Systems 17
Table 6A— Relay Requirements 19
7. Agreements 20
8. Testing Requirements 21
Attachments: System Diagrams
Figure 1 —Open Transition 25
Figure 2—Closed Transition 26
Figure 3—Soft Loading Transfer
With Limited Parallel Operation 27
Figure 4—Soft Loading Transfer
With Limited Parallel Operation 28
Figure 5— Extended Parallel
With Transfer-Trip 29
Interconnection Process for Distributed General.;i Systems
SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
Foreword
Electric distribution system connected generation units span a wide range of sizes and electrical
characteristics. Electrical distribution system design varies widely from that required to serve the
rural customer to that needed to serve the large commercial customer. With so many variations
possible, it becomes complex and difficult to create one interconnection standard that fits all
generation interconnection situations.
In establishing a generation interconnection standard there are three main issues that must be
addressed; Safety, Economics and Reliability.
The first and most important issue is safety; the safety of the general public and of the employees
working on the electrical systems. This standard establishes the technical requirements that
must be met to ensure the safety of the general public and of the employees working with the
Area EPS. Typically designing the interconnection system for the safety of the general public will
also provide protection for the interconnected equipment.
The second issue is economics; the interconnection design must be affordable to build. The
interconnection standard must be developed so that only those items, that are necessary to meet
safety and reliability, are included in the requirements. This standard sets the benchmark for the
minimum required equipment. If it is not needed, it will not be required.
The third issue is reliability; the generation system must be designed and interconnected such
that the reliability and the service quality for all customers of the electrical power systems are not
compromised. This applies to all electrical systems not just the Area EPS.
Many generation interconnection standards exist or are in draft form. The IEEE, FERC and many
states have been working on generation interconnection standards. There are other standards
such as the National Electrical Code (NEC)that, establish requirements for electrical installations.
The NEC requirements are in addition to this standard. This standard is designed to document
the requirements where the NEC has left the establishment of the standard to "the authority
having jurisdiction" or to cover issues which are not covered in other national standards.
This standard covers installations, with an aggregated capacity of 10MW's or less. Many of the
requirements in this document do not apply to small, 40kW or less generation installations. As an
aid to the small, distributed generation customer, these small unit interconnection requirements
have been extracted from this full standard and are available as a separate, simplified document
titled: "Standards for Interconnecting Generation Sources, Rated Less then 40kW with Minnesota
Electric Utilities"
Interconnection Process for Distributed Generatg Systems
SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
1. Introduction
This standard has been developed to document the technical requirements for the interconnection
between a Generation System and an area electrical power system "Utility system or Area EPS". This
standard covers 3 phase Generation Systems with an aggregate capacity of 10 MW's or less and
single phase Generation Systems with an aggregate capacity of 40kW or less at the Point of
Common Coupling. This standard covers Generation Systems that are interconnected with the Area
EPS's distribution facilities. This standard does not cover Generation Systems that are directly
interconnected with the Area EPS's Transmission System, Contact the Area EPS for their
Transmission System interconnection standards.
While, this standard provides the technical requirements for interconnecting a Generation System
with a typical radial distribution system, it is important to note that there are some unique Area EPS,
which have special interconnection needs. One example of a unique Area EPS would be one
operated as a "networked" system. This standard does not cover the additional special requirements
of those systems. The Interconnection Customer must contact the Owner/operator of the Area EPS
with which the interconnection is intended, to make sure that the Generation System is not proposed
to be interconnected with a unique Area EPS. If the planned interconnection is with a unique Area
EPS, the Interconnection Customer must obtain the additional requirements for interconnecting with
the Area EPS.
The Area EPS operator has the right to limit the maximum size of any Generation System or number
of Generation Systems that, may want to interconnect, if the Generation System would reduce the
reliability to the other customers connected to the Area EPS.
This standard only covers the technical requirements and does not cover the interconnection process
from the planning of a project through approval and construction. Please read the companion
document "State of Minnesota Interconnection Process for Distributed Generation Systems" for the
description of the procedure to follow and a generic version of the forms to submit. It is important to
also get copies of the Area EPS's tariff's concerning generation interconnection which will include
rates, costs and standard interconnection agreements. The earlier the Interconnection Customer gets
the Area EPS operator involved in the planning and design of the Generation System interconnection
the smoother the process will go.
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SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
A) Definitions
The definitions defined in the "IEEE Standard for Interconnecting Distributed Resources with
Electric Power Systems" (1547 Draft Ver. 11) apply to this document as well. The following
definitions are in addition to the ones defined in IEEE 1547, or are repeated from the IEEE 1547
standard.
i) "Area EPS"an electric power system(EPS)that serves Local EPS's. Note.Typically,an Area EPS has
primary access to public rights-of-way,priority crossing of property boundaries,etc.
ii) "Generation" any device producing electrical energy, i.e., rotating generators driven by wind, steam
turbines, internal combustion engines, hydraulic turbines, solar, fuel cells, etc.; or any other electric
producing device,including energy storagetechnologies.
iii)"Generation System"the interconnected Distributed Generation(s),controls, relays,switches,breakers,
transformers,inverters and associated wiring and cables, up to the Point of Common Coupling.
iv)"Interconnection Customer" the party or parties who are responsible for meeting the requirements of
this standard.This could be the Generation System applicant,installer,designer,owner or operator.
v) "Local EPS" an electric power system (EPS) contained entirely within a single premises or group of
premises.
vi) "Point of Common Coupling" the point where the Local EPS is connected to an Area EPS.
vii) "Transmission System", are those facilities as defined by using the guidelines established by the
Minnesota State Public Utilities Commission; "In the Matter of Developing Statewide Jurisdictional
Boundary Guidelines for Functionally Separating Interstate Transmission from Generation and Local
Distribution Functions" Docket No.E-015/M-99-1002.
viii) "Type-Certified" Generation paralleling equipment that is listed by an OSHA listed national testing
laboratory as having met the applicable type testing requirement of UL 1741.At the time is document
was prepared this was the only national standard available for certification of generation transfer
switch equipment. This definition does not preclude other forms of type- certification if agreeable to
the Area EPSoperator.
B) Interconnection Requirements Goals
This standard defines the minimum technical requirements for the implementation of the electrical
interconnection between the Generation System and the Area EPS. It does not define the overall
requirements for the Generation System. The requirements in this standard are intended to achieve
the following:
i) Ensure the safety of utility personnel and contractors working on the electrical power system.
ii) Ensure the safety of utility customers and the general public.
iii)Protect and minimize the possible damage to the electrical power system and other customer's
property.
iv) Ensure proper operation to minimize adverse operating conditions on the electrical power
Interconnection Process for Distributed Generate Systems
SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
system.
C) Protection
The Generation System and Point of Common Coupling shall be designed with proper protective
devices to promptly and automatically disconnect the Generation from the Area EPS in the event of
a fault or other system abnormality. The type of protection required will be determined by:
i) Size and type of the generatingequipment.
ii)The method of connecting and disconnecting the Generation System from the electrical power system.
iii)The location of generating equipment on the Area EPS.
D) Area EPS Modifications
Depending upon the match between the Generation System, the Area EPS and how the
Generation System is operated, certain modifications and/or additions may be required to the
existing Area EPS with the addition of the Generation System. To the extent possible, this standard
describes the modifications which could be necessary to the Area EPS for different types of
Generation Systems. For some unique interconnections, additional and/or different protective
devices, system modifications and/or additions will be required by the Area EPS operator; in these
cases the Area EPS operator will provide the final determination of the required modifications
and/or additions. If any special requirements are necessary they will be identified by the Area EPS
operator during the application review process.
E) Generation System Protection
The Interconnection Customer is solely responsible for providing protection for the Generation
System. Protection systems required in this standard, are structured to protect the Area EPS's
electrical power system and the public. The Generation System Protection is not provided for in this
standard. Additional protection equipment may be required to ensure proper operation for the
Generation System. This is especially true while operating disconnected, from the Area EPS. The
Area EPS does not assume responsibility for protection of the Generation System equipment or of
any portion Local EPS.
F) Electrical Code Compliance
Interconnection Customer shall be responsible for complying with all applicable local, independent,
state and federal codes such as building codes, National Electric Code (NEC), National Electrical
Safety Code (NESC) and noise and emissions standards. As required by Minnesota State law, the
Area EPS will require proof of complying with the National Electrical Code before the
interconnection is made, through installation approval by an electrical inspector recognized by the
Minnesota State Board of Electricity.
The Interconnection Customer's Generation System and installation shall comply with latest
revisions of the ANSI/IEEE standards applicable to the installation, especially IEEE 1547;
"Standard for Interconnecting Distributed Resources with Electric Power Systems". See the
reference section in this document for a partial list of the standards which apply to the generation
installations covered by this standard.
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SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
2. References
The following standards shall be used in conjunction with this standard. When the stated version of
the following standards is superseded by an approved revision then that revision shall apply.
IEEE Std 100-2000, "IEEE Standard Dictionary of Electrical and Electronic Terms"
IEEE Std 519-1992, "IEEE Recommended Practices and Requirements for Harmonic Control in
Electric Power Systems"
IEEE Std 929-2000,"IEEE Recommended Practice for Utility Interface of Photovoltaic(PV) Systems".
IEEE Std 1547, "IEEE Standard for Interconnecting Distributed Resources with Electric Power
Systems"
IEEE Std C37.90.1-1989 (1995), "IEEE Standard Surge Withstand Capability(SEC)Tests for
Protective Relays and Relay Systems".
IEEE Std C37.90.2 (1995), "IEEE Standard Withstand Capability of Relay Systems to Radiated
Electromagnetic Interference from Transceivers".
IEEE Std C62.41.2-2002, "IEEE Recommended Practice on Characterization of Surges in Low
Voltage (1000V and Less)AC Power Circuits"
IEEE Std C62.42-1992 (2002), "IEEE Recommended Practice on Surge Testing for Equipment
Connected to Low Voltage (1000V and less)AC Power Circuits"
ANSI C84.1-1995,"Electric Power Systems and Equipment—Voltage Ratings (60 Hertz)"
ANSI/IEEE 446-1995, "Recommended Practice for Emergency and Standby Power Systems for
Industrial and Commercial Applications".
ANSI/IEEE Standard 142-1991, "IEEE Recommended Practice for Grounding of Industrial
and Commercial Power Systems—Green Book",
UL Std. 1741 "Inverters, Converters, and Controllers for use in Independent Power Systems"
NEC—"National Electrical Code", National Fire Protection Association (NFPA), NFPA-70-2002.
NESC—"National Electrical Safety Code". ANSI C2-2000, Published by the Institute of Electrical and
Electronics Engineers, Inc.
Interconnection Process for Distributed Generate Systems
SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
3. Types of Interconnections
A)The manner in which the Generation System is connected to and disconnected from the Area EPS can vary.
Most transfer systems normally operate using one of the following five methods of transferring the load
from the Area EPS to the Generation System.
B)If a transfer system is installed which has a user accessible selection of several transfer modes,the transfer
mode that has the greatest protection requirements will establish the protection requirements for that
transfer system.
i) Open Transition (Break-Before-Make) Transfer Switch — With this transfer switch, the load to be
supplied from the Distributed Generation is first disconnected from the Area EPS and then connected
to the Generation.This transfer can be relatively quick, but voltage and frequency excursions are to be
expected during transfer. Computer equipment and other sensitive equipment will shut down and
reset.The transfer switch typically consists of a standard UL approved transfer switch with mechanical
interlocks between the two source contactors that drop the Area EPS source before the Distributed
Generation is connected to supply the load.
(1)To qualify as an Open Transition switch and the limited protective requirements, mechanical
interlocks are required between the two source contacts. This is required to ensure that one of
the contacts is always open and the Generation System is never operated in parallel with the Area
EPS. If the mechanical interlock is not present,the protection requirements are as if the switch is
a closed transition switch.
(2)As a practical point of application,this type of transfer switch is typically used for loads less than
500kW.This is due to possible voltage flicker problems created on the Area EPS,when the load is
removed from or returned to the Area EPS source. Depending up the Area EPS's stiffness this level
may be larger or smaller than the 500kW level.
(3) Figure 1 at the end of this document provides a typical one-line of this type of installation.
ii) Quick Open Transition (Break-Before-Make) Transfer Switch — The load to be supplied from the
Distributed Generation is first disconnected from the Area EPS and then connected to the Distributed
Generation, similar to the open transition. However, this transition is typically much faster(under 500
ms) than the conventional open transition transfer operation. Voltage and frequency excursions will
still occur, but some computer equipment and other sensitive equipment will typically not be affected
with a properly designed system. The transfer switch consists of a standard UL approved transfer
switch, with mechanical interlocks between the two source contacts that drop the Area EPS source
before the Distributed Generation is connected to supply the load.
(1) Mechanical interlocks are required between the two source contacts to ensure that one of the
contacts is always open. If the mechanical interlock is not present, the protection requirements
are as if the switch is a closed transition switch
(2)As a practical point of application this type of transfer switch is typically used for loads less than
500kW.This is due to possible voltage flicker problems created on the Area EPS, when the load is
removed from or returned to the Area EPS source. Depending up the Area EPS's stiffness this level
may be larger or smaller than the 500kW level.
(3)Figure 2 at the end of this document provides a typical one-line of this type of installation and
shows the required protective elements.
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SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
iii)Closed Transition (Make-Before-Break) Transfer Switch —The Distributed Generation is synchronized
with the Area EPS prior to the transfer occurring. The transfer switch then parallels with the Area EPS
for a short time(100 msec. or less) and then the Generation System and load is disconnected from the
Area EPS. This transfer is less disruptive than the Quick Open Transition because it allows the
Distributed Generation a brief time to pick up the load before the support of the Area EPS is lost.With
this type of transfer,the load is always being supplied by the Area EPS or the Distributed Generation.
(1)As a practical point of application this type of transfer switch is typically used for loads less than
500kW.This is due to possible voltage flicker problems created on the Area EPS,when the load is
removed from or returned to the Area EPS source. Depending up the Area EPS's stiffness this level
may be larger or smaller than the 500kW level.
(2)Figure 2 at the end of this document provides a typical one-line of this type of installation and
shows the required protective elements. The closed transition switch must include a separate
parallel time limit relay, which is not part of the generation control PLC and trips the generation
from the system for a failure of the transfer switch and/or the transfer switch controls.
iv) Soft Loading Transfer Switch
(1)With Limited Parallel Operation—The Distributed Generation is paralleled with the Area EPS for a
limited amount of time (generally less than 1-2 minutes) to gradually transfer the load from the
Area EPS to the Generation System.This minimizes the voltage and frequency problems, by softly
loading and unloading the Generation System.
(a)The maximum parallel operation shall be controlled, via a parallel timing limit relay (62PL).
This parallel time limit relay shall be a separate relay and not part of the generation control
PLC.
(b) Protective Relaying is required as described in section 6.
(c) Figure 3 at the end of this document provide typical one-line diagrams of this type of
installation and show the required protective elements.
(2)With Extended Parallel Operation — The Generation System is paralleled with the Area EPS in
continuous operation. Special design, coordination and agreements are required before any
extended parallel operation will be permitted. The Area EPS interconnection study will identify
the issues involved.
(a)Any anticipated use in the extended parallel mode requires special agreements and special
protection coordination.
(b) Protective Relaying is required as described in section 6.
(c) Figure 4 at the end of this document provides a typical one-line for this type of
interconnection. It must be emphasized that this is a typical installations only and final
installations may vary from the examples shown due to transformer connections, breaker
configuration,etc.
v) Inverter Connection
This is a continuous parallel connection with the system. Small Generation Systems may
utilize inverters to interface to the Area EPS. Solar, wind and fuel cells are some examples of
Generation which typically use inverters to connect to the Area EPS. The design of such
inverters shall either contain all necessary protection to prevent unintentional islanding, or the
Interconnection Customer shall install conventional protection to affect the same protection.
All required protective elements for a soft-loading transfer switch apply to an inverter
Interconnection Process for Distributed Generate Systems
SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
connection. Figure 5 at the end of this document, shows a typical inverter interconnection.
(1)Inverter Certification—Prior to installation,the inverter shall be Type-Certified for interconnection
to the electrical power system. The certification will confirm its anti- islanding protection and
power quality related levels at the Point of Common Coupling. Also, utility compatibility, electric
shock hazard and fire safety are approved through UL listing of the model. Once this Type
Certification is completed for that specific model, additional design review of the inverter should
not be necessary by the Area EPS operator.
(2)For three-phase operation, the inverter control must also be able to detect and separate for the
loss of one phase. Larger inverters will still require custom protection settings, which must be
calculated and designed to be compatible with the specific Area EPS being interconnected with.
(3)A visible disconnect is required for safely isolating the Distributed Generation when connecting
with an inverter.The inverter shall not be used as a safety isolation device.
(4)When banks of inverter systems are installed at one location, a design review by the Area EPS
must be performed to determine any additional protection systems, metering or other needs.The
issues will be identified by the Area EPS during the interconnection study process
Interconnection Process for Distributed Generates Systems
SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
4. Interconnection Issues and Technical Requirements
A)General Requirements -The following requirements apply to all interconnected generating equipment. The
Area EPS shall be the source side and the customer's system shall be the load side in the following
interconnection requirements.
i)Visible Disconnect-A disconnecting device shall be installed to electrically isolate the Area EPS from the
Generation System.The only exception for the installation of a visible disconnect is if the generation is
interconnected via a mechanically interlocked open transfer switch and installed per the NEC (702.6)
"so as to prevent the inadvertent interconnection of normal and alternate sources of supply in any
operation of the transferequipment."
The visible disconnect shall provide a visible air gap between Interconnection Customer's
Generation and the Area EPS in order to establish the safety isolation required for work on the
Area EPS. This disconnecting device shall be readily accessible 24 hours per day by the Area
EPS field personnel and shall be capable of padlocking by the Area EPS field personnel. The
disconnecting device shall be lockable in the open position.
The visible disconnect shall be a UL approved or National Electrical Manufacture's Association
approved, manual safety disconnect switch of adequate ampere capacity. The visible
disconnect shall not open the neutral when the switch is open. A draw-out type circuit breaker
can be used as a visual open.
The visible disconnect shall be labeled, as required by the Area EPS Operator to inform the
Area EPS field personnel.
ii) Energization of Equipment by Generation System —The Generation System shall not energize a de-
energized Area EPS. The Interconnection Customer shall install the necessary padlocking (lockable)
devices on equipment to prevent the energization of a de-energized electrical power system. Lock out
relays shall automatically block the closing of breakers or transfer switches on to a de-energized Area
EPS.
iii)Power Factor-The power factor of the Generation System and connected load shall be as follows;
(1)Inverter Based interconnections — shall operate at a power factor of no less than 90%.at the
inverterterminals.
(2)Limited Parallel Generation Systems,such as closed transfer or soft-loading transfer systems shall
operate at a power factor of no less than 90%, during the period when the Generation System is
parallel with the Area EPS,as measured at the Point of Common Coupling.
(3)Extended Parallel Generation Systems shall be designed to be capable of operating between 90%
lagging and 95% leading. These Generation Systems shall normally operate near unity power
factor (+/-98%) or as mutually agreed between the Area EPS operator and the Interconnection
Customer.
iv) Grounding Issues
(1)Grounding of sufficient size to handle the maximum available ground fault current shall be
designed and installed to limit step and touch potentials to safe levels as set forth in "IEEE Guide
for Safety in AC Substation Grounding",ANSI/IEEE Standard 80.
(2) It is the responsibility of the Interconnection Customer to provide the required grounding for the
Generation System. Agood standard for this is the IEEE Std. 142-1991
Interconnection Process for Distributed Generate Systems
SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
"Grounding of Industrial and Commercial Power Systems"
(3)All electrical equipment shall be grounded in accordance with local,state and federal electrical
and safety codes and applicable standards
v)Sales to Area EPS or other parties—Transportation of energy on the Transmission system is regulated
by the area reliability council and FERC. Those contractual requirements are not included in this
standard. The Area EPS will provide these additional contractual requirements during the
interconnection approval process.
B)For Inverter based,closed transfer and soft loading interconnections-The following additional
requirements apply:
i) Fault and Line Clearing-The Generation System shall be removed from the Area EPS for any faults,or
outages occurring on the electrical circuit serving the Generation System
ii) Operating Limits in order to minimize objectionable and adverse operating conditions on the electric
service provided to other customers connected to the Area EPS,the Generation System shall meet
the Voltage, Frequency, Harmonic and Flicker operating criteria as defined in the IEEE 1547 standard
during periods when the Generation System is operated in parallel with the Area EPS.
If the Generation System creates voltage changes greater than 4% on the Area EPS, it is the
responsibility of the Interconnection Customer to correct these voltage sag/swell problems
caused by the operation of the Generation System. If the operation of the interconnected
Generation System causes flicker,which causes problems for others customer's
interconnected to the Area EPS, the Interconnection Customer is responsible for correcting the
problem.
iii)Flicker-The operation of Generation System is not allowed to produce excessive flicker to
adjacent customers.See the IEEE 1547 standard for a more complete discussion on this
requirement.
The stiffer the Area EPS,The larger a block load change that it will be able to handle. For any
of the transfer systems the Area EPS voltage shall not drop or rise greater than 4%when the
load is added or removed from the Area EPS. It is important to note, that if another
interconnected customer complains about the voltage change caused by the Generation
System, even if the voltage change is below the 4% level, it is the Interconnection Customer's
responsibility to correct or pay for correcting the problem. Utility experience has shown that
customers have seldom objected to instantaneous voltage changes of less than 2% on the
Area EPS, so most Area EPS operators use a 2% design criteria
iv)Interference-The Interconnection Customer shall disconnect the Distributed Generation from the Area
EPS if the Distributed Generation causes radio, television or electrical service interference to other
customers, via the EPS or interference with the operation of Area EPS. The Interconnection Customer
shall either effect repairs to the Generation System or reimburse the Area EPS Operator for the cost of
any required Area EPS modifications due to the interference.
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SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
v) Synchronization of CustomerGeneration-
(1)An automatic synchronizer with synch-check relaying is required for unattended automatic quick
open transition,closed transition or soft loading transfer systems.
(2)To prevent unnecessary voltage fluctuations on the Area EPS, it is required that the synchronizing
equipment be capable of closing the Distributed Generation into the Area EPS within the limits
defined in IEEE 1547. Actual settings shall be determined by the Registered Professional Engineer
establishing the protective settings for the installation.
(3)Unintended Islanding — Under certain conditions with extended parallel operation, it would be
possible for a part of the Area EPS to be disconnected from the rest of the Area EPS and have the
Generation System continue to operate and provide power to a portion of the isolated circuit.
This condition is called "islanding". It is not possible to successfully reconnect the energized
isolated circuit to the rest of the Area EPS since there are no synchronizing controls associated
with all of the possible locations of disconnection. Therefore, it is a requirement that the
Generation System be automatically disconnected from the Area EPS immediately by protective
relays for any condition that would cause the Area EPS to be de-energized. The Generation
System must either isolate with the customer's load or trip.The Generation System must also be
blocked from closing back into the Area EPS until the Area EPS is reenergized and the Area EPS
voltage is within Range B of ANSI C84.1 Table 1 for a minimum of 1 minute. Depending upon the
size of the Generation System it may be necessary to install direct transfer trip equipment from
the Area EPS source(s) to remotely trip the generation interconnection to prevent islanding for
certain conditions
vi)Disconnection—the Area EPS operator may refuse to connect or may disconnect a Generation System
from the Area EPS under the following conditions:
(1)Lack of approved Standard Application Form and Standard Interconnection Agreement.
(2)Termination of interconnection by mutual agreement.
(3) Non-Compliance with the technical or contractual requirements.
(4)System Emergency or for imminent danger to the public or Area EPS personnel(Safety).
(5)Routine maintenance, repairs and modifications to the Area EPS.The Area EPS operator shall
coordinate planned outages with the Interconnection Customer to the extent possible.
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SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
5. Generation Metering, Monitoring and Control
Metering, Monitoring and Control— Depending upon the method of interconnection and the size of the
Generation System, there are different metering, monitoring and control requirements Table 5A is a
table summarizing the metering, monitoring and control requirements.
Due to the variation in Generation Systems and Area EPS operational needs, the requirements for
metering, monitoring and control listed in this document are the expected maximum requirements that
the Area EPS will apply to the Generation System. It is important to note that for some Generation
System installations the Area EPS may wave some of the requirements of this section if they are not
needed. An example of this is with rural or low capacity feeders which require more monitoring then
larger capacity, typically urban feeders.
Another factor which will affect the metering, monitoring and control requirements will be the tariff
under which the Interconnection Customer is supplied by the Area EPS. Table 5A has been written to
cover most application, but some Area EPS tariffs may have greater or less metering, monitoring and
control requirements then, as shown in Table 5A. .
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SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
TABLE 5A
Metering, Monitoring and Control Requirements
Generation System Generation
Generation Remote
Capacity at Point of Metering Monitoring Remote
Common Coupling Control
<_40 kW with all sales to Bi-Directional metering at the point None Required None Required
Area EPS of common coupling
>40 kW Determined by engineering study Determined by Determined by
engineering study engineering
study
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SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
A) Metering
i) As shown in Table 5A the requirements for metering will depend up on the type of generation and the
type of interconnection. For most installations, the requirement is a single point of metering at the
Point of Common Coupling. The Area EPS Operator will install a special meter that is capable of
measuring and recording energy flow in both directions, for three phase installations or two detented
meters wired in series,for single phase installations. A dedicated
- direct dial phone line may be required to be supplied to the meter for the Area EPS's use to
read the metering. Some monitoring may be done through the meter and the dedicated —
direct dial phone line, so in many installations the remote monitoring and the meter reading can
be done using the same dial-up phone line.
ii) Depending upon which tariff the Generation System and/or customer's load is being supplied under,
additional metering requirements may result. Contact the Area EPS for tariff requirements. In some
cases, the direct dial-phone line requirement may be waived by the Area EPS for smaller Generation
Systems.
iii)All Area EPS's revenue meters shall be supplied, owned and maintained by the Area EPS. All voltage
transformers (VT) and current transformers (CT), used for revenue metering shall be approved and/or
supplied by the Area EPS. Area EPS's standard practices for instrument transformer location and wiring
shall be followed for the revenue metering.
iv)For Generation Systems that sell power and are greater than 40kW in size, separate metering of the
generation and of the load is required. A single meter recording the power flow at the Point of
Common Coupling for both the Generation and the load is not allowed by the rules under which the
area transmission system is operated. The Area EPS is required to report to the regional reliability
council (MAPP) the total peak load requirements and is also required to own or have contracted for,
accredited generation capacity of 115%of the experienced peak load level for each month of the year.
Failure to meet this requirement results in a large monetary penalty for the Area EPS operator.
v) For Generation Systems which are less then 40kW in rated capacity and are qualified facilities under
PURPA (Public Utilities Regulatory Power Act — Federal Gov. 1978), net metering is allowed and
provides the generation system the ability to back feed the Area EPS at some times and bank that
energy for use at other times. Some of the qualified facilities under PURPA are solar,wind, hydro, and
biomass. For these net-metered installations, the Area EPS may use a single meter to record the bi-
directional flow or the Area EPS Operator may elect to use two detented meters, each one to record
the flow of energy in onedirection.
B) Monitoring (SCADA) is required as shown in table 5A. The need for monitoring is based on the need of
the system control center to have the information necessary for the reliable operation of the Area EPS's.This
remote monitoring is especially important during periods of abnormal and emergency operation.
The difference in Table 5A between remote monitoring and SCADA is that SCADA typically is a
system that is in continuous communication with a central computer and provides updated values
and status, to the Area EPS operator, within several seconds of the changes in the field. Remote
monitoring on the other hand will tend to provide updated values and status within minutes of the
change in state of the field. Remote monitoring is typically less expensive to install and operate.
i) Where Remote Monitoring or SCADA is required, as shown in Table 5A, the following monitored and
control points are required:
(1)Real and reactive power flow for each Generation System (kW and kVAR). Only required if
separate metering of the Generation and the load is required, otherwise #4 monitored at the
point of Common Coupling will meet the requirements.
Interconnection Process for Distributed Generatto2Systems
SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
(2) Phase voltage representative of the Area EPS's service to the facility.
(3)Status(open/close)of Distributed Generation and interconnection breaker(s)or if transfer switch
is used,status of transferswitch(s).
(4) Customer load from Area EPS service(kW and kVAR).
(5) Control of interconnection breaker-if required by the Area EPS operator.
When telemetry is required, the Interconnection Customer must provide the communications
medium to the Area EPS's Control Center. This could be radio, dedicated phone circuit or
other form of communication. If a telephone circuit is used, the Interconnection Customer
must also provide the telephone circuit protection. The Interconnection Customer shall
coordinate the RTU (remote terminal unit) addition with the Area EPS. The Area EPS may
require a specific RTU and/or protocol to match their SCADA or remote monitoring system.
Interconnection Process for Distributed GeneratiSystems
SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
6. Protective Devices and Systems
A)Protective devices required to permit safe and proper operation of the Area EPS while interconnected with
customer's Generation System are shown in the figures at the end of this document. In general,an increased
degree of protection is required for increased Distributed Generation size. This is due to the greater
magnitude of short circuit currents and the potential impact to system stability from these installations.
Medium and large installations require more sensitive and faster protection to minimize damage and ensure
safety.
If a transfer system is installed which has a user accessible selection of several transfer modes, the
transfer mode which has the greatest protection requirements will establish the protection
requirements for that transfer system.
The Interconnection Customer shall provide protective devices and systems to detect the Voltage,
Frequency, Harmonic and Flicker levels as defined in the IEEE 1547 standard during periods when
the Generation System is operated in parallel with the Area EPS. The Interconnection Customer
shall be responsible for the purchase, installation, and maintenance of these devices. Discussion
on the requirements for these protective devices and systems follows:
i) Relay settings
(1)If the Generation System is utilizing a Type-Certified system, such as a UL listed inverter a
Professional Electrical Engineer is not required to review and approve the design of the
interconnecting system. If the Generation System interconnecting device is not Type- Certified or
if the Type-Certified Generation System interconnecting device has additional design
modifications made, the Generation System control, the protective system, and the
interconnecting device(s) shall be reviewed and approved by a Professional Electrical Engineer,
registered in the State of Minnesota.
(2)A copy of the proposed protective relay settings shall be supplied to the Area EPS operator for
review and approval,to ensure proper coordination between the generation system and the Area
EPS.
ii) Relays
(1)All equipment providing relaying functions shall meet or exceed ANSI/IEEE Standards for
protective relays,i.e.,C37.90,C37.90.1 andC37.90.2.
(2)Required relays that are not "draw-out" cased relays shall have test plugs or test switches
installed to permit field testing and maintenance of the relay without unwiring or disassembling
the equipment. Inverter based protection is excluded from this requirement for Generation
Systems<40kW at the Point of Common Coupling.
(3)Three phase interconnections shall utilize three phase power relays, which monitor all three
phases of voltage and current, unless so noted in the appendix one-lines.
(4)All relays shall be equipped with setting limit ranges at least as wide as specified in IEEE 1547,and
meet other requirements as specified in the Area EPS interconnect study. Setting limit ranges are
not to be confused with the actual relay settings required for the proper operation of the
installation.At a minimum,all protective systems shall meet the requirements established in IEEE
1547.
(a) Over-current relays(IEEE Device 50/51 or 50/51V)shall operate to trip the protecting breaker
at a level to ensure protection of the equipment and at a speed to allow
Interconnection Process for Distributed GeneratASystems
SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
proper coordination with other protective devices. For example, the over-current relay
monitoring the interconnection breaker shall operate fast enough for a fault on the
customer's equipment, so that no protective devices will operate on the Area EPS.
51V is a voltage restrained or controlled over-current relay and may be required to
provide proper coordination with the Area EPS.
(b) Over-voltage relays (IEEE Device 59) shall operate to trip the Distributed Generation per the
requirements of IEEE 1547.
(c) Under-voltage relays(IEEE Device 27)shall operate to trip the Distributed Generation per the
requirements of IEEE 1547
(d) Over-frequency relays (IEEE Device 810) shall operate to trip the Distributed Generation off-
line per the requirements of IEEE 1547.
(e) Under-frequency relay(IEEE Device 81U)shall operate to trip the Distributed Generation off-
line per the requirements of IEEE 1547. For Generation Systems with an aggregate capacity
greater then 30kW,the Distribution Generation shall trip off-line when the frequency drops
below 57.0-59.8 Hz. typically this is set at 59.5 Hz, with a trip time of 0.16 seconds, but
coordination with the Area EPS is required for this setting.
The Area EPS will provide the reference frequency of 60 Hz. The Distributed
Generation control system must be used to match this reference. The protective
relaying in the interconnection system will be expected to maintain the frequency of
the output of the Generation.
(0 Reverse power relays(IEEE Device 32)(power flowing from the Generation System to the Area
EPS)shall operate to trip the Distributed Generation off-line for a power flow to the system
with a maximum time delay of 2.0seconds.
(g) Lockout Relay (IEEE Device 86) is a mechanically locking device which is wired into the close
circuit of a breaker or switch and when tripped will prevent any close signal from closing that
device.This relay requires that a person manually resets the lockout relay before that device
can be reclosed.These relays are used to ensure that a denergized system is not reenergized
by automatic control action, and prevents a failed control from auto-reclosing an open
breaker or switch.
(h)Transfer Trip —All Generation Systems are required to disconnect from the Area EPS when
the Area EPS is disconnected from its source, to avoid unintentional islanding. With larger
Generation Systems, which remain in parallel with the Area EPS, a transfer trip system may
be required to sense the loss of the Area EPS source. When the Area EPS source is lost, a
signal is sent to the Generation System to separate the Generation from the Area EPS. The
size of the Generation System vs the capacity and minimum loading on the feeder will
dictate the need for transfer trip installation. The Area EPS interconnection study will
identify the specific requirements.
If multiple Area EPS sources are available or multiple points of sectionalizing on the
Area EPS, then more than one transfer trip system may be required. Area EPS
interconnection study will identify the specific requirements. For some installations
the alternate Area EPS source(s) may not be utilized except in rare occasions. If this
is the situation, the Interconnection Customer may elect to have the Generation
System locked out when the alternate source(s) are utilized, if agreeable to the Area
EPS operator.
(i) Parallel limit timing relay (IEEE Device 62PL) set at a maximum of 120 seconds for
Interconnection Process for Distributed Generatio5$ystems
SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
soft transfer installations and set no longer then 100ms for quick transfer installations, shall
trip the Distributed Generation circuit breaker on limited parallel interconnection systems.
Power for the 62 PL relay must be independent of the transfer switch control power. The
62PL timing must be an independent device from the transfer control and shall not be part
of the generation PLC or other control system.
TABLE 6A
SUMMARY OF RELAYING REQUIREMENTS
Over- Reverse Parallel Sync-
Voltage Frequency Lockout Transfer
Type of current (27/59) (81 0/U) Power (86) Limit Check Trip
Interconnection (50/51) (32) Timer (25)
5540 kW Yes Yes Yes Yes
>40 kW Determined Determined by Determined by Determined by Determined by Determined by Determined Determined by
by Engineering Engineering Study Engineering Engineering Engineering by Engineering
Engineering Study Study Study Study Engineering Study
Study Study
Interconnection Process for Distributed Generat}o6Systems
SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
7. Agreements
A)Interconnection Agreement —This agreement is required for all Generation Systems that parallel with the
Area EPS. Each Area EPS's tariffs contain standard interconnection agreements. There are different
interconnection agreements depending upon the size and type of Generation System. This agreement
contains the terms and conditions upon which the Generation System is to be connected, constructed and
maintained, when operated in parallel with the Area EPS.Some of the issues covered in the interconnection
agreement are as follows;
i) Construction Process
ii)Testing Requirements
iii) Maintenance Requirements
iv) Firm Operating Requirements such as Power Factor
v)Access requirements for the Area EPS personnel
vi) Disconnection of the Generation System(Emergency and Non-emergency)
vii)Term of Agreement
viii) Insurance Requirements
ix) Dispute Resolution Procedures
B)Operating Agreement — For Generation Systems that normally operate in parallel with the Area EPS, an
agreement separate from the interconnection agreement, called the "operating agreement", is usually
created. This agreement is created for the benefit of both the Interconnection Customer and the Area EPS
operator and will be agreed to between the Parties. This agreement will be dynamic and is intended to be
updated and reviewed annually. For some smaller systems, the operating agreement can simply be a letter
agreement for larger and more intergraded Generation Systems the operating agreement will tend to be
more involved and more formal. The operating agreement covers items that are necessary for the reliable
operation of the Local and Area EPS. The items typically included in the operating agreement are as follows;
i) Emergency and normal contact information for both the Area EPS operations center and for the
Interconnection Customer
ii) Procedures for periodic Generation System test runs.
iii) Procedures for maintenance on the Area EPS that affect the Generation System.
iv) Emergency Generation Operation Procedures
Interconnection Process for Distributed Genera/Dr/Systems
SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
8. Testing Requirements
A) Pre-Certification of equipment
The most important part of the process to interconnect generation with Local and Area EPS's is
safety. One of the key components of ensuring the safety of the public and employees is to
ensure that the design and implementation of the elements connected to the electrical power
system operate as required. To meet this goal, all of the electrical wiring in a business or
residence, is required by the State of Minnesota to be listed by a recognized testing and
certification laboratory, for its intended purpose. Typically we see this as"UL" listed. Since
Generation Systems have tended to be uniquely designed for each installation they have been
designed and approved by Professional Engineers. As the number of Generation Systems
installed increase, vendors are working towards creating equipment packages which can be
tested in the factory and then will only require limited field testing. This will allow us to move
towards"plug and play" installations. For this reason, this standard recognizes the efficiency of
"pre-certification" of Generation System equipment packages that will help streamline the
design and installation process.
An equipment package shall be considered certified for interconnected operation if it has been
submitted by a manufacture, tested and listed by a nationally recognized testing and
certification laboratory(NRTL)for continuous utility interactive operation in compliance with the
applicable codes and standards. Presently generation paralleling equipment that is listed by a
nationally recognized testing laboratory as having met the applicable type-testing requirements
of UL 1741 and IEEE 929, shall be acceptable for interconnection without additional protection
system requirements. An "equipment package" shall include all interface components
including switchgear, inverters, or other interface devices and may include an integrated
generator or electric source. If the equipment package has been tested and listed as an
integrated package which includes a generator or other electric source, it shall not require
further design review, testing or additional equipment to meet the certification requirements for
interconnection. If the equipment package includes only the interface components (switchgear,
inverters, or other interface devices), then the Interconnection Customer shall show that the
generator or other electric source being utilized with the equipment package is compatible with
the equipment package and consistent with the testing and listing specified for the package.
Provided the generator or electric source combined with the equipment package is consistent
with the testing ad listing performed by the nationally recognized testing and certification
laboratory, no further design review, testing or additional equipment shall be required to meet
the certification requirements of this interconnection procedure. A certified equipment package
does not include equipment provided by the Area EPS.
The use of Pre-Certified equipment does not automatically qualify the Interconnection
Customer to be interconnected to the Area EPS. An application will still need to be submitted
and an interconnection review may still need to be performed, to determine the compatibility of
the Generation System with the Area EPS.
B) Pre-CommissioningTests
i) Non-Certified Equipment
(1) Protective Relaying and Equipment Related to Islanding
(a) Distributed generation that is not Type-Certified (type tested), shall be equipped with
protective hardware and/or software designed to prevent the Generation from being
connected to a de-energized Area EPS.
(b)The Generation may not close into a de-energized Area EPS and protection provided
Interconnection Process for Distributed GenerattmSystems
SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
to prevent this from occurring. It is the Interconnection Customer's responsibility to
provide a final design and to install the protective measures required by the Area
EPS. The Area EPS will review and approve the design, the types of relays specified,
and the installation. Mutually agreed upon exceptions may at timesbe necessary and
desirable. It is strongly recommended that the Interconnection Customer obtain Area
EPS written approval prior to ordering protective equipment for parallel operation.
The Interconnection Customer will own these protective measures installed at their
facility.
(c)The Interconnection Customer shall obtain prior approval from the Area EPS for any revisions
to the specified relay calibrations.
C) Commissioning Testing
The following tests shall be completed by the Interconnection Customer. All of the required tests in
each section shall be completed prior to moving on to the next section of tests. The Area EPS
operator has the right to witness all field testing and to review all records prior to allowing the system
to be made ready for normal operation The Area EPS shall be notified, with sufficient lead time to
allow the opportunity for Area EPS personnel to witness any or all of the testing.
i) Pre-testing The following tests are required to be completed on the Generation System prior to
energization by the Generator or the Area EPS. Some of these tests may be completed in the factory if
no additional wiring or connections were made to that component.These tests are marked with a"*"
(1)Grounding shall be verified to ensure that it complies with this standard,the NESC and the NEC.
(2)* CT's (Current Transformers) and VT's (Voltage Transformers) used for monitoring and
protection,shall be tested to ensure correct polarity, ratio and wiring
(3)CT's shall be visually inspected to ensure that all grounding and shorting connections have been
removed where required.
(4)Breaker/Switch tests —Verify that the breaker or switch cannot be operated with interlocks in
place or that the breaker or switch cannot be automatically operated when in manual mode.
Various Generation Systems have different interlocks, local or manual modes etc. The intent of
this section is to ensure that the breaker or switches controls are operating properly.
(5)* Relay Tests—All Protective relays shall be calibrated and tested to ensure the correct operation
of the protective element. Documentation of all relay calibration tests and settings shall be
furnished to the Area EPS operator.
(6)Trip Checks - Protective relaying shall functionally tested to ensure the correct operation of the
complete system. Functional testing requires that the complete system is operated by the
injection of current and/or voltage to trigger the relay element and proving that the relay element
trips the required breaker, lockout relay or provides the correct signal to the next control
element.Trip circuits shall be proven through the entire scheme(including breaker trip)
For factory assembled systems, such as inverters the setting of the protective elements
may occur at the factory. This section requires that the complete system including the
wiring and the device being tripped or activated is proven to be in working condition
through the injection of current and/or voltage.
Interconnection Process for Distributed Generat o9Systems
SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
(7)Remote Control, SCADA and Remote Monitoring tests—All remote control functions and remote
monitoring points shall be verified operational. In some cases, it may not be possible to verify all
of the analog values prior to energization.Where appropriate,those points may be verified during
the energization process
(8)Phase Tests—the Interconnection Customer shall work with the Area EPS operator to complete
the phase test to ensure proper phase rotation of the Generation and wiring.
(9)Synchronizing test — The following tests shall be done across an open switch or racked out
breaker. The switch or breaker shall be in a position that it is incapable of closing between the
Generation System and the Area EPS for this test.This test shall demonstrate that at the moment
of the paralleling-device closure, the frequency, voltage and phase angle are within the required
ranges, stated in IEEE 1547. This test shall also demonstrate that is any of the parameters are
outside of the ranges stated; the paralleling-device shall not close. For inverter-based
interconnected systems this test may not be required unless the inverter creates fundamental
voltages before the paralleling device is closed.
ii) On-Line Commissioning Test — the following tests will proceed once the Generation System has
completed Pre-testing and the results have been reviewed and approved by the Area EPS operator. For
smaller Generation Systems the Area EPS may have a set of standard interconnection tests that will be
required. On larger and more complex Generation Systems the Interconnection Customer and the Area
EPS operator will get together to develop the required testing procedure. All on-line commissioning
tests shall be based on written test procedures agreed to between the Area EPS operator and the
Interconnection Customer.
Generation System functionally shall be verified for specific interconnections as follows:
(1)Anti-Islanding Test—For Generation Systems that parallel with the utility for longer than 100msec.
(a)The Generation System shall be started and connected in parallel with the Area EPS source
(b)The Area EPS source shall be removed by opening a switch, breaker etc.
(c)The Generation System shall either separate with the local load or stop generating
(d)The device that was opened to remove the Area EPS source shall be closed and the
Generation System shall not re-parallel with the Area EPS for at least 5 minutes.
iii) Final System Sign-off.
(1)To ensure the safety of the public, all interconnected customer owned generation systems which
do not utilize a Type-Certified system shall be certified as ready to operate by a Professional
Electrical Engineer registered in the State of Minnesota, prior to the installation being considered
ready for commercial use.
iv) Periodic Testing and Record Keeping
Interconnection Process for Distributed Generatte(roSystems
SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
(1)Any time the interface hardware or software, including protective relaying and generation control
systems are replaced and/or modified, the Area EPS operator shall be notified. This notification
shall, if possible, be with sufficient warning so that the Area EPS personnel can be involved in the
planning for the modification and/or witness the verification testing. Verification testing shall be
completed on the replaced and/or modified equipment and systems.The involvement of the Area
EPS personnel will depend upon the complexity of the Generation System and the component
being replaced and/or modified. Since the Interconnection Customer and the Area EPS operator
are now operating an interconnected system. It is important for each to communicate changes in
operation, procedures and/or equipment to ensure the safety and reliability of the Local and Area
EPSs.
(2)All interconnection-related protection systems shall be periodically tested and maintained, by the
Interconnection Customer, at intervals specified by the manufacture or system integrator.These
intervals shall not exceed 5 years. Periodic test reports and a log of inspections shall be
maintained, by the Interconnection Customer and made available to the Area EPS operator upon
request. The Area EPS operator shall be notified prior to the period testing of the protective
systems,so that Area EPS personnel may witness the testing if so desired.
(a)Verification of inverter connected system rated 15kVA and below may be completed as
follows; The Interconnection Customer shall operate the load break disconnect switch and
verify the Generator automatically shuts down and does not restart for at least 5 minutes
after the switch is close
(b)Any system that depends upon a battery for trip/protection power shall be checked and
logged once per month for proper voltage. Once every four years the battery(s) must be
either replaced or a discharge test performed. Longer intervals are possible through the use
of"station class batteries"and Area EPS operator approval.
Interconnection Process for Distributed Generatic Systems
SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
Source-Area EPS
/\/'\/\!\
aMETERING(SEE TABLE 5A)
AREA EPS
LOCAL EPS SERVICE ENTRANCE EQUIPMENT
(ACCESSIBLE,VISIBLE&LOCKABLE
DISCONNECT DEVICE)
OPTIONAL,BUT RECOMMENDED
1 TRANSFER SWITCH
-BREAK-BEFORE-MAKE
I -MECHANICALLY INTERLOCKED
LOAD
ACCESSIBLE.VISIBLE&
O--
7LOCKABLE DISCONNECT DEVICE
(OPTIONAL BUT RECOMMENDED)
1-PHASE OR
3-PHASE
GENERATOR
NOTE: BREAK-BEFORE-MAKE
AUTOMATIC TRANSFER
SWITCHES SHALL BE
MECHANICALLY INTERLOCKED
OPEN TRANSITION
"BREAK-BEFORE-MAKE"
DATE: Figure 1
JAN 2003 g
Interconnection Process for Distributed Generatter2Systems
SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
Source-Area EPS
AREA EPS
11! METERING(SEE TABLE 5A)
LOCAL EPS 0 SERVICE ENTRANCE EQUIPMENT
(ACCESSIBLE,VISIBLE&LOCKABLE
.. DISCONNECT DEVICE)
i pie
.
E--- 1
ACCESSIBLE.VISIBLE&
TRANSFER SWITCH QUICK OPEN OR AMICABLE DISCONNECT DEVICE
LOAD CLOSED TRANSITION-'MAKE BEFORE BREAK' •(OPTIONAL BUT RECOMMENDED)
0.5 SEC.MAX PARALLEL TIME
CT(3) 50451GI
(3)
...0.2100No, Trios
25
synchronizer
BREAKER 71`MAY SERVE AS
ACCESSIBLE DISCONNECT A
25SC 'Synch-check Relay DEVICE IF DRAWOUT
50!51 Phase Overcurrent 861A el\
51N Ground Overcurrent 3-PHASE Tripped by
GENERATOR 6L
62PL 'ParaUei Limit Timer 861A
86 'Lockout Relay A
QUICK OPEN OR
CLOSED TRANSITION
(1)(2)(3) Indicates Nunes of Phases to be Monitored "MAKE-BEFORE-BREAK"
'Indicates Minimum Requried Protection DATE:
Other Relays Shown are Recommended for Generator Protection. JAN 2003 Figure 2
Interconnection Process for Distributed Generatier Systems
SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
SOURCE-AREA EPS
1 i PROTECTION SHOWN ISNSFORMEROR
FOR GROUNDED WYE-
GROUWYE TRA
FOR OTHER TRANSFORMER CONNECTIONS CONTACT E
irsv..s.foss" i AREA EPSECTIVE OPERATOR FORREQUIREMENT POSSIBLE ADDITIONAL
PROT
CMETERING(SEE TABLE 5A)
AREA EPS
LOCAL EPS o SERVICE ENTRANCE EQUIPMENT
Gv_'r//J (ACCESSIBLE,VISIBLE 8 LOCKABLE DISCONNECT DEVICE)
BREAKER A MAY SERVE AS VISIBLE DISCONNECT DEVICE IF
DRAW-OUT BREAKER
• • •
. el50/51 51N
(3) (3) (3) CT(3) 3 al 81 au 47
(1)
(3) (3)GI (3)
(1)
A
0(
3)
I 1
IACCESSIBLE,VISIBLE&
LOCKABLE DISCONNECT DEVICE
LO♦♦AD
(OPTIONAL BUT RECOMMENDED)
Device No, Function Trios
25 Synchronizer
50J51
0
25SC 'Synch-check Relay CT(3) (3)
27/59 'Under/Over Voltage 86/B
32 'Reverse Power(Trip
for power toward Utility 86rB BREAKER MAY SERVE AS M13149
VISIBLE DISCONNECT
47 Negative Sequence 86/B DEVICE IF DRAW-OUT BKR.
(1)
50151 'Phase Overcurrent 86/B
51N 'Ground Overarrent 8618 3-PHASE
GENERATOR
62PL 'Parallel Limit Timer 86/B
81 -Over/Under Frequency 86S
86 'Lockout Relay B SOFT LOADING TRANSFER
LIMITED PARALLEL
(1)(2)(3) Indicates Number of Phases Monitored OPERATION
'Indicates Minimum Requried Protection. DATE:
Other Relays Shown are Recommended for generator Protection. JAN 2003 Figure 3
Interconnection Process for Distributed GeneratieISystems
SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
SOURCE-AREA EPS
1 PROTECTION SHOWN IS FOR WYE-
GROUNDED WYE TRANSFORMERGROUNDED
FOR OTHER TRANSFORMER CONNECTIONS CONTACT E
./..„/\",\,\ 4. AREATECTIVE EPS OPERATORREQUIREMEFORNT POSSIBLE ADDITIONAL
PRO
EMETERING(SEE TABLE 5A)
AREA EPS
LOCAL EPS o SERVICE ENTRANCE EQUIPMENT
/ (ACCESSIBLE,VISIBLE&LOCI
KABLE DSCONNECT DEVICE)
BREAKER A MAY SERVE AS VISIBLE DSCONNECT DEVICE IF
DRAW-OUT BREAKER.
• • •
so/s1
3) (3) (3)
CT(3) 3 25 1 el 810/U 0 0 59
(1) (1) (3) (3) (3)
0 0 A
• •
LOAD, 1 ACCESSIBLE,VISIBLE&
LOCKABLE ECT VICE
Dem No Function 1811,5DEPENDING UPON (OPTIONAL BUTS RECOMMENDED)
25 Synchronizer THE RELATIVE SIZE
OF THE LOAD TO THE
25SC 'Synch check Relay GENERATION,
BREAKER B MAY BE
27159 'Under/Over Voltage 86/A TRIPPED INSTEAD OF
BREAKER A,FOR 50/51 0
32 'Reverse Power(Trip SOME OR ALL OF THE
for power toward Area EPS 86/B PROCTIONS.TECTIVE CT(3) (3)
F47 Negative Sequence 86/A
BREAKERS'MAY
50151 'Phase Overcurrent 86/A SERVEVISIBLE
DISCONNECT ECT
51N 'Ground Overcurrent 86/A DEVICE IF DRAW-OUT 1111111 4a0/09
BREAKER. (1)
62PL 'Parallel Limit Timer 86/A
67 Directional Overcaurent 86/A 3-PHASE
81 'Over/Under Frequency 86/A GENERATOR
86A 'Lockout Relay A
86B 'Lockout Relay B SOFT LOADING
TT 'Transfer Trip 86/A EXTENDED PARALLEL
TT is not required for Generation Systems smaller then 250kW OPERATION
(1)(2)(3) Indicates Number of Phases Monitored
•Indicates Minimum Requited Protection. DATE: I FI ure 4
Other Relays Shown are Recommended for generator Protection. JAN 2003 g
Interconnection Process for Distributed Generat'cSystems
SCHEDULE 3—INTERCONNECTION PROCESS,TECHNICAL REQUIREMENTS,AND OPERATING PROCEDURES
Source-Area EPS
1 PROTECTION SHOWN IS FOR GROUNDED WYE•GROUNDED WYE
TRANSFORMER FOR OTHER TRANSFORMER CONNECTIONS
CONTACT THE AREA EPS FOR POSSIBLE ADDITIONAL PROTECTIVE
REQUIREII MENTS
METERING(SEE TABLE 5A)
Area EPS
Local EPS
SERVICE ENTRANCE EQUIPMENT
•
(ACCESSIBLE,VISIBLE A LOCKABLE
DISCONNECT DEVICE)
�
810/U
lb
4111(3) 4103) (3)
541510
(3)
UL LISTED I
NON-ISLANDING
^- -___-_-_---
LOAD
REVIEW NEC CODE FOR OTHER
GENERATOR PROTECTIVE DEVICES REQUIRED TO
PROTECT THE LOCAL EPS
FOR INVERTER CONNECTED
Device No, E GENERATION SYSTEMS,GREATER THEN
27159 'Under/Over Voltage 250KW,TRANSFER TRIP MAY BE
az Negative Sequence REQUIRED BY THE AREA EPS
OPERATOR
50151 Phase Overcurrent
51N Ground Overaurent
8101U 'Over/Under Frequency
INVERTER CONNECTED
(1)(2)(3) Indicates Number of Phases Monitored
Indicates Mknknum Requried Protection. DATE:
Other Relays Shown are Recommended for Generator Protection, JAN 2003 Figure
Interconnection Process for Distributed Generatteiystems
SCHEDULE 4—PURCHASE INTERRUPTION NOTIFICATION PROCEDURE
Elk River Municipal Utilities (Utility)does not foresee an event necessitating Utility to stop purchasing
energy from a Qualifying Facility(QF). However, if such an event occurs, Utility shall notify the QF owner
by mail,phone, email or other form of electronic communication approved by the QF owner.
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SCHEDULE 5—AVERAGE INCREMENTAL COSTS
GRE- 2018 Avoided Cost Rates
(Effective January 1,2018-September 30,2018)
Summer Months(May-Oct) Energy($/kWh) Capacity($/kWh) REC($/kWh)
On Peak 0.03148 0 0.001
Off Peak 0.01801 0.001
All Hours 0.02406 0 0.001
Winter Months(Nov-Apr)
On Peak 0.02856 0 0.001
Off Peak 0.01974 0.001
All Hours 0.02367 0 0.001
Annual (Jan-Dec)
All Hours 0.02387 0 0.001
MMPA-2018 Avoided Cost Rates
(Effective October 1,2018-December,31,2018)
Summer Months(Jun-Sep) Energy($/kWh) Capacity($/kWh) REC($/kWh)
On Peak 0.0308 0 0
Off Peak 0.0180 0 0
All Hours 0.0239 0 0
Winter Months(Oct-May)
On Peak 0.0301 0 0
Off Peak 0.0215 0 0
All Hours 0.0255 0 0
Annual (Jan- Dec)
All Hours 0.0250 0 0
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