5.3. ERMU SR 12-11-2007~/
Elk River ^-~
Municipal Utilities w
13069 Orono Parkway • P.O. Box 430
Elk River, MN 55330-0430
December 3, 2007
To: Elk River Municipal Utilities Commission
Jerry Takle
Jerry Gumphrey
Jim Tralle
From: Bryan Adams
Subject: Dispersed Generation Rate
Phone: 763.441.2020
Fax: 763.441.8099
The dispersed generation program has been offered for a number of years to our demand
customers who have on site generation or the ability to curtail load during times of peak load.
Because our demand rate is higher than our competition, we have offered this program as a way
for the participating customers to reduce their energy costs. The two large data centers will be
eligible for this program and it is in our interest to get them to participate. Enclosed is the
following information for your review.
1) Proposed program description.
2) Dispersed Generation Program Agreement.
3) Dispersed Generation Program saving calculation for Target and United Health Group
data centers.
With this program, the customer will experience the approximate savings:
Existing Program Proposed Program
Cub Foods 12.2% 15.8
Target Data Center - 20.0
United Health Group Data Center - 20.0
Using Cub Foods as an example and applying Excel Energy and Connexus Energy disperse
generation rates, Cub Foods would save approximately 9.4% and 28.5%. Sherburne County
Government Center has standby generation and is eligible for this program but to date have not
shown any interest.
The proposed major changes from the existing agreement are as follows.
a) Change level of KW reimbursement from pre-determined level to load at Great River
Energy's peak (coincident peak).
b) Change reimbursement amount.
Existing Proposed
Winter $ 5.50 $ 7.00
Spring/Fall $ 2.50 $ 4.00
Summer $11.00 $12.00
DISPERSED GENERATION/INTERRUPTIBLE LOAD PROGRAM
DESCRIPTION: Beginning January 1, 2000, Elk River Municipal Utilities (ERMU) provided
an incentive to encourage on-site customer-owned generation. The target market consisted of
those commercial accounts that already own backup generators of at least 100 kW, or were
considering an investment in backup generation of at least 100 kW due to the critical nature of
their business. Effective May 1, 2003, that program was expanded to include commercial
accounts of at least 100 kW that are willing and able to interrupt at least 100 kW of load.
AVAILABILITY: This Program is available to commercial customers served by ERMU which
have sufficient load to fully utilize the output of between 100 kW and 1500 kW of on-site
generation capacity or that can interrupt between 100 kW and 1500 kW of load. Customers with
on-site generation in excess of 1500 kW or with in excess of 1500 kW of interruptible load may
also qualify for this Program, but special terms and conditions may apply. Program participants
must agree to operate their on-site generator, or limit operations to interrupt all or a mutually
agreed upon portion of their electric load upon notification by ERMU or its designated agent.
This Program applies to qualifying customers subject to the following Conditions of Service:
1. The Customer must be operating between the hours of 4 PM and 9 PM and have
between 100 kW and 1500 kW of electric load that can be either switched to a
standby generator or interrupted upon notification by ERMU or its designated agent.
2. The Customer must provide access to a phone line for notification and remote
meter reading.
3. The Customer who selects billing under this Dispersed Generation/Interruptible Load
Program must agree to remain on the Program for at least one year. A written
Agreement stating term, incentive, terms and conditions of service, and safety and
operating standards will be required. See either the Dispersed Generation Agreement
or Commercial Interruptible Load Agreement for details.
4. The Customer must provide an acceptable means to transfer all, or a mutually
agreed upon portion of the Customer load to the on-site generator upon
notification by ERMU. If the Customer does not have on-site generation,
the Customer must have a means to reduce load to a predetermined demand
level (PDL) within 30 minutes following notification by ERMU.
5. Time and duration of on-site generator operation or interruption shall be at the
discretion of ERMU but will not exceed 10 hours per occurrence and 300 hours per
year for those with a generator or 6 hours per occurrence and 300 hours per year for
those who have interruptible load.
6. Operation of Customer's generation and collateral equipment or interruption of load
must not cause any reduction in the quality of service provided by ERMU to any
other customer.
7. It is the Customer's responsibility to supply fuel and maintain the on-site
generator and collateral equipment to meet the electric power requirements
during periods of operation. Customer will be reimbursed for fuel used in
excess of 80 hours per year run time. That reimbursement will be based on current
cost of diesel fuel converted to a cost per kilowatt-hour as determined by ERMLT's
wholesale power supplier. There is no fuel reimbursement for those Customers
who do not have on-site generation.
8. Notification of intent to operate Customer's on-site generator by ERMU will
be made to give at least thirty minutes notice. In emergency situations,
automatic startup may occur simultaneously with notification. Customers
without on-site generation will be given 30 minutes to reduce load to the PDL.
9. If the on-site generator fails to perform or the load is not reduced to the PDL during
any calendar month, the Customer will not receive the monthly demand credit. If this
failure to perform occurs during June, July, or August a penalty fee may be assessed.
If the on-site generator fails to perform or the load is not reduced to the PDL more
than two times in any calendar year, ERMiJ reserves the right to remove the
Customer from the Program.
10. The generator installation or method used to interrupt load must conform to
ERMU service requirements, and must conform to all local and national safety
codes.
11. The Customer must continue to purchase all electric energy and electric
energy delivery services from ERMU for the contract period.
INCENTIVE: Customers under contract to intemtpt load down to a PDL, or with operational
on-site generation participating in this Program will receive monthly credits based on the amount
of electric demand (kW) which can be interrupted or transferred from ERMU's delivery system
to the on-site generator. The monthly credit varies by season as follows:
Monthly Credit Per KW Transferred*
Summer (June, July and Aug) $12.00 per kw
Winter (Dec, Jan, and Feb) $ 7.50 per kw
Spring/Fall (Sept, Oct, Nov, $ 4.00 per kw
Mar, Apr, and May)
*Credit applies only during months in which Customer interrupts or can interrupt load
down to the PDL or when the Customer's generator is fully operational and/or operates
within limits prescribed in the Agreement.
CREDIT DETERMINATION: Customer's monthly demand credit shall be based on the
amount of load which can be either interrupted or transferred from ERMtJ's delivery system to
the Customer's on-site generator at a time specified by ERMU or its designated agent. There
must be sufficient load to interrupt or transfer to the standby generator between the hours of 4
PM and 9 PM to allow for a reduction of at least 100 kW.
Compensation to Customer shall be paid as a credit applied to Customer's monthly electric bill
from ERMU, and shall not be paid to Customer in cash. The monthly credit during control shall
be determined by multiplying the coincidental peak demand transferred to the generator or
interrupted down to the PDL by the appropriate seasonal rate in effect for that month as stated
above. In the event no control is deemed necessary, the monthly credit shall be determined by
multiplying the coincidental peak demand that could be transferred to the generator or
interrupted down to the PDL by the appropriate seasonal rate in effect for that month as stated
above. Coincidental Peak Demand is ERMU's monthly billing peak and is coincidental with
ERMU's wholesale power suppliers monthly peak.
No other credits or financial incentives will be provided by ERMII to the Customer participating
in this Program.
METERING: The Basic Monthly Charge will be $ ,and it covers the cost of metering and
administrative costs. This charge is subject to change if additional special metering is required
by the customer or ERMU's wholesale power supplier. ERMU will retain ownership of and
maintenance for. all special metering required to administer this Program.
Revised 12/07
DISPERSED GENERATION PROGRAM AGREEMENT
THIS DISPERSED GENERATION AGREEMENT, made as of this day of
by and among Elk River Municipal Utilities, "ERMU" and
"Customer", applies to customer-owned or
leased, on-site generation of 100 kilowatts and lazger. Special contract terms may apply to
customer-owned or leased on-site generation exceeding 1500 kilowatts.
Subject to the terms and conditions of this Agreement, and in reliance to the representations
and covenants herein contained, ERMU and Customer agree as follows:
ARTICLE 1. DEFINITIONS. As used in this Agreement the following terms have the
meanings given them unless the context requires otherwise:
Agreement means this Agreement, as it may be from time to time modified,
amended or supplemented.
Coincidental Peak Demand means Customer electrical power use measured in
kilowatts (kV~ averaged over a continuous 60 minute period at the time of ERMU's
monthly billing peak.
Demand means Customer electrical power use measured in kilowatts (kV~
Averaged over a continuous 60 minute period.
Distribution System means ERMLJ's electric delivery system.
Customer Generator means the following generator (s) located at
Generator number one:
Mfg Model number
Continuous run nameplate rating in kw
Contract demand if other than continuous run nameplate rating in
kw
Fuel type
Generator number two:
Mfg Model number
Continuous run nameplate rating in kw
Contract demand if other than continuous run nameplate rating in
kw
Fuel type
Type of interconnected operation (Interconnection/Transfer method)
--Open, -Quick open, -Closed, -Soft loading
Isolated means a condition whereby the generating equipment is not
interconnected with ERMU's electric system.
Kilowatt (kW) means unit of electric power equal to 1000 watts.
Kilowatthour (kWh) means unit of electric energy equal to one kilowatt of power
supplied to or taken from an electric system steadily for one hour.
Parallel means a condition whereby the generating equipment is interconnected
with ERMU's electric system.
Sprin~/fall season means the period from March 1 through May 31, and
September 1 through November 30.
Summer means the period from June 1 through August 31.
Utili means Elk River Municipal Utilities or (ERMU)
Winter means the period from December 1 through February 28 or 29.
ARTICLE 2. TERM. This Agreement shall begin at 12:01 a.m. on
and shall continue until termination as provided for in Article 12.
ARTICLE 3. GENERATOR AVAILABILITY. Customer represents and warrants to
ERMU that the Customer Generator shall be available for operation upon request by
ERMU or its designated agent during the term of this Agreement.
ARTICLE 4. SAFETY AND OPERATING STANDARDS. Safety and Operating
Standards under which ERMU operates are imposed to protect ERMU employees and the
general public, and are intended to guarantee a quality of service to the other customers.
Customer must operate Customer Generator in a manner that insures the safety of ERMU
employees and the general public, and must allow electric service to other customers to
remain within prescribed limits.
Section 1: Inspection. An inspection certificate issued by the state electrical
inspector having jurisdiction at Customer location is required to assure wiring
complies with the IEEE, National Electrical Code, National Electric Safety Code,
and applicable local codes. An inspection by ERMU personnel is also required
prior to finalizing this Agreement. All Federal, State, and local safety codes
pertaining to installation, operation, and maintenance of Customer Generator and
collateral equipment shall be followed and are the responsibility of Customer.
Section 2: Safety Equipment. The following requirements apply to all
interconnected generating equipment. ERMU's Distribution System shall be the
source side and Customer Generator shall be the load side in the following
interconnection requirements.
Visible Disconnect - A disconnecting device shall be installed to electrically
isolate the Distribution System from the Customer Genertor. The only exception
for the installation of a visible disconnect is if the Customer Generator is
interconnected via a mechanically interlocked open transfer switch and installed
per the NEC (702.6) "so as to rp event the inadvertent interconnection of normal
and alternate sources of supply in ~ operation of the transfer equipment."
The visible disconnect shall provide a visible air gap between the Customer
Generator and the Distribution System in order to establish the safety isolation
required for work on the Distribution System. This disconnecting device
shall be readily accessible 24 hours per day by ERMU personnel and shall be
capable of padlocking by ERMU personnel. The disconnecting device shall be
lockable in the open position.
The visible disconnect shall be a UL approved or National Electrical
Manufacturers Association (NEMA) 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 may be used as a visual open.
The visible disconnect shall be labeled "Generation Disconnect" to inform ERMU
personnel.
Energizing of Equipment by Generation System -The Customer Generator
Shall not energize the de-energized Distribution System. The Customer shall
Install the necessary padlocking (lockable) devices on Customer Generator to
prevent energizing the de-energized Distribution System. Lock out relays shall
automatically block the closing of breakers or transfer switches onto the de-
energized Distribution System.
Grounding Issues -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", ANSUIEEE Standard 80".
It is the responsibility of the Customer to provide the required grounding for the
Customer Generator. A good standard for this is the IEEE Std. 142-1991
"Grounding of Industrial and Commercial Power Systems".
All electrical equipment shall be grounded in accordance with local, state, and
federal electrical and safety codes and applicable standazds.
Section 3: Types Of Interconnections -Interconnections are defined based on the
manner in which the Customer Generator is connected to and disconnected from the
Distribution System. Most transfer systems normally operate using one of the
following four methods:
Open Transition (Break-Before-Make) Transfer Switch -With this transfer
switch, the load to be supplied from the Customer Generator is fast disconnected
from the Distribution System and then connected to the Customer Generator. This
transfer can be relatively quick, but voltage and frequency excursions are to be
expected during transfer. Computer equipment and other sensitive equipment may
shut down and need to be reset. The transfer switch typically consists of a
standard UL approved transfer switch with mechanical interlocks between the two
source contactors that drop the Distribution System before the Customer
Generator is connected to supply the Customer load.
To qualify as an open transition switch with limited protective requirements,
mechanical interlocks are required between the two source contacts to ensure that
one of the contacts is always open and the Customer Generator is never operated
in parallel with the Distribution System. If the mechanical interlock is not present,
the protection requirements are as if the switch is a closed transition switch.
As a practical point of application, this type of transfer switch is typically used for
loads less than SOOkW due to possible voltage flicker problems created on the
Distribution System when the Customer load is removed from or returned to the
Distribution System. This level may be larger or smaller than the SOOkW level
depending on the Distribution System stiffness.
Quick Open Transition (Break-Before-Make) Transfer Switch -The load to
be supplied from the Customer Generator is first disconnected from the
Distribution System and then connected to the Customer Generator, similar to the
open transition. However, this transition is typically much faster (under 500
milliseconds) 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
Distribution System source before the Customer Generator is connected to supply
the Customer load.
Mechanical interlocks aze 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.
As a practical point of application, this type of transfer switch is typically used for
loads less than SOOkW due to possible voltage flicker problems created on the
Distribution System when the Customer load is removed from or returned to the
Distribution System. This level may be larger or smaller than the SOOkW level,
depending of the stiffness of the Distribution System.
A synchronization check relay is required for quick open transition transfer
Switches.
Closed Transition (Make-Before-Break) Transfer Switch -The Customer
Generator is synchronized with the Distribution System prior to the transfer.
The transfer switch then parallels with the Distribution System for a short time
(100 milliseconds or less) and then the Customer load is disconnected from the
Distribution System. This transfer is less disruptive than the Quick Open
Transition because it allows the Customer Generator a brief time to pick up the
Customer load before the support of the Distribution System is lost. With this type
of transfer, the Distribution System or the Customer Generator is always
supplying the Customer load.
As a practical point of application, this type of transfer switch is typically used for
loads less than SOOkW due to possible voltage flicker problems created on the
Distribution System when the Customer load is removed from or returned to the
Distribution System. Depending on the Distribution System stiffness, this level
may be larger or smaller than the SOOkW level.
The closed transition switch must include a separate parallel time limit relay
which is not part of the Customer Generator control PLC and trips the Customer
Generator from the Distribution System for a failure of the transfer switch and/or
transfer switch controls.
Soft Loading Transfer Switch
(1)With Limited Pazallel Operation, the Customer Generator is pazalleled with the
Distribution System for a limited amount of time (generally less than 1-2 minutes)
to gradually transfer the Customer load from the Distribution System to the
Customer Generator. This minimizes the voltage and frequency problems by
softly loading and unloading the Customer Generator.
The maximum pazallel operation shall be controlled via a parallel timing limit
relay (62PL). This pazallel time limit relay shall be a separate relay and not part
of the generator control PLC.
Protective devices are required to permit safe and proper operation of the
Distribution System while interconnected with a Customer Generator. In general,
an increased degree of protection is required for a lazger Customer Generator due
to the greater magnitude of short circuit currents and the potential impact to
Distribution System stability. Large installations may require more sensitive and
faster protection to minimize damage and ensure safety. Customer shall provide
protective devices and systems to detect the Voltage, Frequency, Harmonic and
Flicker levels as defined in IEEE 1547 D11 standard during periods when the
Customer Generator is operated in parallel with the Distribution System.
(2)With Extended Parallel Operation, the Customer Generator is paralleled with
the Distribution System in continuous operation. Special design, coordination and
agreements are required before any extended parallel operation will be permitted.
An interconnection study will need to be performed by ERMU to identify the
issues involved.
Protective devices aze required to permit safe and proper operation of the
Distribution System while interconnected with Customer Generator. In general,
an increased degree of protection is required for a larger Customer Generator due
to the greater magnitude of short circuit currents and the potential impact to
Distribution System stability. Lazger installations may require more sensitive and
faster protection to minimize damage and ensure safety. Customer shall provide
protective devices and systems to detect the Voltage, Frequency, Harmonic and
Flicker levels as defined in IEEE 1547 D 11 standard during periods when the
Customer Generator is operated in parallel with the Distribution System.
Section 4: Power Oualitv. Operation of Customer Generator and auxiliary
equipment must not cause any reduction in the quality of service provided by
E1ZMU to its customers nor interfere with the operation of ERMU's Distribution
System or ERMTJ's power supplier's transmission system. The equipment shall not
put any undesirable voltages, frequencies, or transients on to ERMU's Distribution
System or ERMU's power supplier's transmission system. If any of the
aforementioned events occur, the equipment shall be disconnected until such time
as the harmful conditions have been corrected. Customer shall be responsible
for taking any corrective action that may be required and/or reimbursing ERMU
for the cost of corrective action which ERMU deems necessary to provide and
restore services to prescribed limits. The Customer Generator will generate 3 phase,
60 hertz power when interconnected to ERMU's Distribution System at normal
12.47 Kv at a power factor of 98% lagging. Total Harmonic Distortion (THD)
levels produced by the equipment shall be less than 1 %.
ARTICLE 5. GENERATING EQUIPMENT OPERATION Upon not less than
thriy minutes notice by ERMU to Customer prior to generator start-up time, Customer
shall operate the Customer Generator at the output level stated in Article 1, under Customer
Generator during the period requested by ERMU. During such period ERMU shall not be
obligated to serve Customer electric load to the extent of the Customer Generator (s)
output. Customer shall comply with all applicable generation regulations of the Mid-
Continent Area Power Pool, or other regulatory body, applicable to ERMU and Customer.
Exceptions to the thirty minute notice may occur in system emergency situations. Every
attempt will be made to give as much advance notice as possible under system emergency
situations.
ARTICLE 6. COMPENSATION TU CUSTOMER.
Section 1: ERMIJ shall compensate Customer for the rated output of the
Customer Generator (times .95), or Customer's coincidental peak demand at
rates Indicated below:
Monthly Credit/Kw*
Summer (June, July, and Aug) $12.00 per kw
Winter (Dec, Jan, and Feb) $ 7.50 per kw
Spring/Fall (Maz, Apr, May, Sept, Oct, Nov) $ 4.00 per kw
6
*Credit applies only during months in which Customer Generator is
fully operational and/or operates within the prescribed limits as set forth
in this entire Agreement.
If Customer Generator output does not typically meet Customer demand at
time of ERMU's coincidental peak demand, then the continuous run nameplate
rating of the Customer Generator multiplied by a factor of .95, shall be used as a
basis for establishing the monthly Customer credit. However, if Customer
Generator output typically meets or exceeds Customer demand, then Customer
coincidental peak demand shall be used as a basis for establishing monthly
Customer credit.
If Customer Generator fails to perform in any calendar month, Customer
will not receive the monthly credit for that month or any succeeding months until
performance has been demonstrated to the satisfaction of ERMU personnel. If
Customer Generator fails to perform more than two times in any calendar year,
ERMU reserves the right to terminate this Agreement as indicated in Article 12.
Section 2: ERMU has no obligation to Customer for fuel used during either
requested run times up to and including 80 hours annually, or during required
monthly tests. In the event more than 80 hours of run time per annum is required
of the Customer Generator by ERMU, Customer will be reimbursed for fuel used.
That reimbursement will be based on the current cost of diesel fuel converted to a
cost per kilowatt-hour as determined by ERMU's wholesale power supplier. ERMU
has no obligation to Customer for maintenance costs, repair costs, or replacement
costs of Customer Generator or auxiliary equipment.
Section 3: Compensation to Customer pursuant to Article 6, Section 1 above
shall be paid as a credit applied to Customer's monthly electric bill from ERMU,
and shall not be paid to Customer in cash. That monthly credit shall be determined
by multiplying the Customer Generator output in kW times .95 or Customer
coincidental peak demand in kW (which ever is less), by the appropriate seasonal
rate in effect for that month. That kw demand will be derived from either (1)
metering (2) or in the case of meter failure, from billing history.
ARTICLE 7. MAXIMUM HOURS OF REQUESTED OPERATION. Except as
otherwise agreed upon in writing, ERMU shall not request Customer to operate Customer
Generator more than 10 hours per day and not more than 300 hours per calendar year.
ARTICLE 8. METERING. Appropriate electronic demand and energy metering
equipment will be installed and maintained by ERMU in such a manner that it records
energy and demand on a one-hour basis with regard to Customer's load. Customer shall
provide access to a telephone line for remote meter reading and notification, and reimburse
ERMU for the cost of the meter. Customer shall pay a $ per month customer charge
to compensate ERMU for special metering and additional administrative costs. ERMU
reserves the right to install additional metering to measure Customer Generator output
directly.
ARTICLE 9. TESTING. Customer shall test the start-up and operation of the Customer
Generator for at least a 15 minute period during each month of the term of this Agreement.
ARTICLE 10. INSPECTION. ERMU shall have the right at all reasonable times to
enter upon Customer premises to inspect the Customer Generator, collateral equipment, and
metering equipment, and to remove the metering equipment upon the termination of this
Agreement.
ARTICLE 11. GENERATING EQUIPMENT MAINTENANCE. Customer shall be
solely responsible for the maintenance, repair, and replacement of the Customer Generator
and collateral equipment. Customer shall not take Customer Generator out of service for
scheduled maintenance during December, January, February, June, July or August in any
year during the term of this Agreement. At other times, Customer shall give ERMU not
less than thirty (30) days notice prior to taking the Customer Generator out of service for
scheduled maintenance.
ARTICLE 12. TERMINATION. ERMU or Customer may terminate this Agreement
by giving not less than six (6) months written notice to the other party. In the event of two
consecutive failures of Customer to perform the obligations set forth in Articles 4, 5, and 8
of this Agreement during any calendar year, ERMU may terminate the Agreement upon
fourteen (14) days written notice to Customer prior to the termination date. This
Agreement shall terminate immediately in the event Customer terminates its service from
ERMU.
ARTICLE 13. NOTICES. All startup notices shall be made by Internet. Written
notices pursuant to this Agreement shall be conveyed by first class mail, postage prepaid to
Customer and ERMU at the following addresses:
To Customer: Company name
Address
Attention
Telephone number
To ERMU: Elk River Municipal Utilities
PO Box 430
Elk River, MN 55330
Attention: Bryan Adams
Phone number 612/441-2020
Notification of change of address, contact person, or telephone number must be made by
similaz written notice.
ARTICLE 14. HEADINGS. The headings used in the Agreement are for convenience
only and shall not be deemed to constitute a part hereof, and shall not be deemed to limit,
characterize or in any way affect the provisions of the Agreement.
ARTICLE 15. ENTIRE AGREEMENT. This Agreement contains all of the terms and
conditions agreed upon by the parties hereto with respect to the subject matter of the
Agreement, and no other promises, agreements or undertakings, written or oral, regarding
the subject matter of this Agreement shall be of any force or effect.
ARTICLE 16. MODIFICATIONS. No change, amendment or modification of any
provision of the Agreement shall be valid unless it is in writing, dated subsequent to the
date hereof, and signed by the parties hereto.
IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the day
.and year first above written.
Elk River Municipal Utilities Customer (company name)
By:
(General Manager)
By:
Elk River Municipal Utilities Disperse Generation Calculation
2008 Rate Structure
Target Rate Impact Inltl8l ERMU Disp Gen Credit
GRE Wholescale ERMU Retail GRE Whol escale ERMU Retail
Winter $ 13.58 $ 10.60 $ 13.58 $ 7.00
Spring $ 9.40 $ 9.40 $ 4.00
On Peak/Off Peak Rato Summer $ 17.76 $ 14.98 $ 17.76 $ 12.00
32% Energy Off $0.02927 $ 0.04542
Energy On $ 0.04406
Energy Critical Peak $ 0.09535
Ener Ener Costs Costs Rev IRev Cost Cost Rev IRev
Month Demand 65% LF 85% LF 65% 85% 65% 85% 65% 85% 65% 85%
Jan 1200 580,320 758,880 $36,029 $42,100 $39,078 $47,188 $19,733 $25,804 $30,678 $38,788
Feb 1200 524,160 685,440 $34,119 $39,603 $36,527 $43,853 $17,823 $23,307 $28,127 $35,453
Mar 1200 580,320 758,880 $31,013 $37,084 $39,078 $47,188 $19,733 $25,804 $34,278 $42,388
April 1200 561,600 734,400 $30,376 $36,252 $38,228 $46,076 $19,096 $24,972 $33,428 $41,276
May 1200 580,320 758,880 $31,013 $37,084 $44,334 $52,444 $19,733 $25,804 $39,534 $47,644
June 1350 631,800 826,200 $45,459 $52,069 $48,919 $57,749 $21,483 $28,093 $32,719 $41,549
July 1350 652,860 853,740 $46,175 $53,006 $49,876 $59,000 $22,199 $29,030 $33,676 $42,800
Aug 1350 652,860 853,740 $46,175 $53,006 $49,876 $59,000 $22,199 $29,030 $33,676 $42,800
Sept 1200 561,600 734,400 $30,376 $36,252 $43,484 $51,332 $19,096 $24,972 $38,684 $46,532
Oct 1200 580,320 758,880 $31,013 $37,084 $39,078 $47,188 $19,733 $25,804 $34,278 $42,388
Nov 1200 561,600 734,400 $30,376 $36,252 $38,228 $46,076 $19,096 $24,972 $33,428 $41,276
Dec 1200 580,320 758,880 $36,029 $42,100 $39,078 $47,188 $19,733 $25,804 $30,678 $38,788
Critical Peak $2,493 $2,493 $0 $0 $2,493 $2,493 $0 $0
Total 7,048,080 9,216,720 $430,643 $504,383 $505,785 $604,284 $242,147 $315,887 $403,185 $501,684
Unit Costs $0.061101 $0.054725 $0.07176 $0.06556 $0.03436 $0.03427 $0.05720 $0.05443
Utility Margin $75,142 $99,901 $161,038 $185,797
Customer Savings $ - $ - $102,600 $102,600
Net Unit Cost $0.0107 $0.0108 $0.0228 $0.0202
Target Rate Impact Final
Ener Ener Costs Costs Rev IRev Cost (Cost Rev IRev
Month Demand 65% LF 85% LF 65% 85% 66% 86% 65% 85% 65% 85%
Jan
Feb
Mar
April
May
June
July
Aug
Sept
Oct
Nov
Dec
Critical Peak
Total
Unit Costs
Utility Margin
Customer Savings
Net Unit Cost
5000 2,418,000 3,162,000 $150,119 $175,417 $162,826 $196,618 $82,219 $107,517 $127,826 $161,618
5000 2,184,000 2,856,000 $142,162 $165,012 $152,197 $182,720 $74,262 $97,112 $117,197 $147,720
5000 2,418,000 3,162,000 $129,219 $154,517 $162,826 $196,618 $82,219 $107,517 $142,826 $176,618
5000 2,340,000 3,060,000 $126,567 $151,049 $159,283 $191,985 $79,567 $104,049 $139,283 $171,985
5000 2,418,000 3,162,000 $129,219 $154,517 $184,726 $218,518 $82,219 $107,517 $164,726 $198,518
6000 2,808,000 3,672,000 $202,040 $231,418 $217,419 $256,662 $95,480 $124,858 $145,419 $184,662
6000 2,901,600 3,794,400 $205,223 $235,580 $221,671 $262,222 $98,663 $129,020 $149,671 $190,222
6000 2,901,600 3,794,400 $205,223 $235,580 $221,671 $262,222 $98,663 $129,020 $149,671 $190,222
5000 2,340,000 3,060,000 $126,567 $151,049 $181,183 $213,885 $79,567 $104,049 $161,183 $193,885
5000 2,418,000 3,162,000 $129,219 $154,517 $162,826 $196,618 $82,219 $107,517 $142,826 $176,618
5000 2,340,000 3,060,000 $126,567 $151,049 $159,283 $191,985 $79,567 $104,049 $139,283 $171,985
5000 2,418,000 3,162,000 $150,119 $175,417 $162,826 $196,618 $82,219 $107,517 $127,826 $161,618
$11,079 $11,079 $0 $0 $11,079 $11,079 $0 $0
29,905,200 39,106,800 $1,833,319 $2,146,199 $2,148,734 $2,566,671 $1,027,939 $1,340,819 $1,707,734 $2,125,671
$0.061304 $0.054880 $0.07185 $0.06563 $0.03437 $0.03429 $0.05710 $0.05436
$315,415 $420,472 $679,795 $784,852
$ - $ - $aal,ooo $aal,ooo
So.olos $o.olos $o.ozv $o.ozol
Disperse Generation Model 2003
Elk River Municipal Utilities Disperse Generation Calculation
2008 Rate Structure
UHG Rate Impact Initial ERM U Disp Gen Credit
GRE Wholescale ERMU Retail GRE Wholescale ERMU Retail
Winter $ 13.58 $ 10.60 $ 13.58 $ 7.00
Spring $ 9.40 $ 9.40
$ 4.00
On Peak/Off Peak Rato Summer $ 17.76 $ 14.98 $ 17.76 $ 12.00
32% Energy Off $0.02927 $ 0.04542
Energy On $ 0.04406
Energy Critical Peak $ 0.09535
Ener Ener Costs Costs Rev IRev Cost Cost Rev IRev
Month Demand 65% LF 85% LF 65% 85% 65% 85% 65% 85% 65% 85%
Jan 4000 1,934,400 2,529,600 $120,095 $140,333 $130,260 $157,294 $65,775 $86,013 $102,260 $129,294
Feb 4000 1,747,200 2,284,800 $113,730 $132,010 $121,758 $146,176 $59,410 $77,690 $93,758 $118,176
Mar 4000 1,934,400 2,529,600 $103,375 $123,613 $130,260 $157,294 $65,775 $86,013 $114,260 $141,294
April 4000 1,872,000 2,448,000 $101,253 $120,839 $127,426 $153,588 $63,653 $83,239 $111,426 $137,588
May 4000 1,934,400 2,529,600 $103,375 $123,613 $147,780 $174,814 $65,775 $86,013 $131,780 $158,814
June 5500 2,574,000 3,366,000 $185,203 $212,133 $199,301 $235,274 $87,523 $114,453 $133,301 $169,274
July 5500 2,659,800 3,478,200 $188,121 $215,949 $203,198 $240,370 $90,441 $118,269 $137,198 $174,370
Aug 5500 2,659,800 3,478,200 $188,121 $215,949 $203,198 $240,370 $90,441 $118,269 $137,198 $174,370
Sept 4000 1,872,000 2,448,000 $101,253 $120,839 $144,946 $171,108 $63,653 $83,239 $128,946 $155,108
Oct 4000 1,934,400 2,529,600 $103,375 $123,613 $130,260 $157,294 $65,775 $86,013 $114,260 $141,294
Nov 4000 1,872,000 2,448,000 $101,253 $120,839 $127,426 $153,588 $63,653 $83,239 $111,426 $137,588
Dec 4000 1,934,400 2,529,600 $120,095 $140,333 $130,260 $157,294 $65,775 $86,013 $102,260 $129,294
Critical Peak $10,155 $10,155 $0 $0 $10,155 $10,155 $0 $0
Total 24,928,800 32,599,200 $1,539,404 $1,800,219 $1,796,076 $2,144,466 $857,804 $1,118,619 $1,418,076 $1,766,466
Unit Costs $0.061752 $0.055223 $0.07205 $0.06578 $0.03441 $0.03431 $0.05689 $0.05419
Utility Margin $256,672 $344,246 $560,272 $647,846
Customer Savings $ - $ - $378,000 $378,000
Net Unit Cost $0.0103 $0.0106 $0.0225 $0.0199
UHG Rate Impact Final
Ener Ener Costs Costs Rev IRev Cost ( Cost Rev IRev
Month Demand 65% LF 85% LF 65% 853'° 65% 85% 65% 85% 65% 85%
Jan 9000 4,352,400 5,691,600 $270,214 $315,750 $293,086 $353,912 $147,994 $193,530 $230,086 $290,912
Feb 9000 3,931,200 5,140,800 $255,892 $297,022 $273,955 $328,895 $133,672 $174,802 $210,955 $265,895
Mar 9000 4,352,400 5,691,600 $232,594 $278,130 $293,086 $353,912 $147,994 $193,530 $257,086 $317,912
April 9000 4,212,000 5,508,000 $227,820 $271,887 $286,709 $345,573 $143,220 $187,287 $250,709 $309,573
May 10000 4,836,000 6,324,000 $258,438 $309,034 $369,451 $437,036 $164,438 $215,034 $329,451 $397,036
June 11500 5,382,000 7,038,000 $387,243 $443,552 $416,720 $491,936 $183,003 $239,312 $278,720 $353,936
July 11500 5,561,400 7,272,600 $393,343 $451,529 $424,869 $502,591 $189,103 $247,289 $286,869 $364,591
Aug 11500 5,561,400 7,272,600 $393,343 $451,529 $424,869 $502,591 $189,103 $247,289 $286,869 $364,591
Sept 10000 4,680,000 6,120,000 $253,133 $302,097 $362,366 $427,770 $159,133 $208,097 $322,366 $387,770
Oct 9000 4,352,400 5,691,600 $232,594 $278,130 $293,086 $353,912 $147,994 $193,530 $257,086 $317,912
Nov 9000 4,212,000 5,508,000 $227,820 $271,887 $286,709 $345,573 $143,220 $187,287 $250,709 $309,573
Dec 9000 4,352,400 5,691,600 $270,214 $315,750 $293,086 $353,912 $147,994 $193,530 $230,086 $290,912
Critical Peak $21,234 $21,234 $0 $0 $21,234 $21,234 $0 $0
Total 55,785,600 72,950,400 $3,423,881 $4,007,532 $4,017,992 $4,797,617 $1,918,101 $2,501,752 $3,190,992 $3,970,617
Unit Costs $0.061376 $0.054935 $0.07203 $0.06577 $0.03438 $0.03429 $0.05720 $0.05443
Utility Margin $594,111 $790,085 $1,272,891 $1,468,865
Customer Savings $ - $ - $827,000 $827,000
Net Unit Cost $0.0106 $0.0108
$0.0228
$0.0201