20130626Technical Hearing Exhibits.pdf

ORIGINAL
BEFORE THE ]DAHO PUBLIC UTTLITIES COMM]SSION ?ilIJ JLIii
IN THE MATTER OF ]DAHO POWER
COMPANY'S APPLICATION FOR
AUTHORITY TO MODIFY ]TS NET
METERING SERVICE AND TO INCREASE
THE GENERAT]ON CAPACITY LIMIT
CASE NO.
rPC-E-72-27
EXHIBITS
PLACE: Commission Hearj-ng Room
472 West Washington StreetBoise, Idaho
DATE: June 11, 2013
POST OFFICE BOX 578
BOISE, TDAHO 83701
208-336-9208
HEIIRI
COURT REPOFITING
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ORIGINAL
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EXH]BITS
NUMBER PAGE
For Idaho Power Company:
1. Rate Schedule Comparison Premarked
Admitted B5
2. Schedule 6, Residential- Premarked
Admitted B5
3. Schedule B, Smal-I Genera] Premarked
Admitted B5
4. Schedule 72, fnterconnections to Premarked
Non-Util-ity Generatlon Admitted 85
5. Schedul-e 84, Large Customer Premarked
Admitted B5
6. Frequently Asked Questions Premarked
Admitted B5
7. Response to Request No. 1 Premarked
Admitted B5
8.Resol-ution of Net Metering
Interconnecti-on Issues
PremarkedAdmitted B5
9. Net Metering fnstallatlons as of Marked 3BB
,-June L, 2013 Admitted 459
HEDRICK COURT REPORTING
P. O. BOX 578, BOTSE, fD 83701
EXHIBITS
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HEDRICK COURT REPORT]NG
P. O. BOX 578, BOTSE, fD
Eor Idaho Conservation League:
20L. Curricul-um Vitae for R. Thomas Beach PremarkedAdmitted tB2
202. Eval-uation of Net Metering j-n Vermont Premarked
Admitted 782
203. (Confidential) PremarkedAdmitted 782
204. Idaho Power Response to ICL
Production Request No. 1
Premarked
Admitted lB2
205. fdaho Power 201,3 IRP DSM Status Update PremarkedOctober 71, 2073 Admitted LB2
Eor Pioneer Power:
401. Dawn Marie Cardwel-l- Curriculum Vitae PremarkedAdmitted 193
402. Photograph PremarkedAdmitted 193
403. Disruptive Challenges, January 2013 Marked 411Admitted 459
404. Risk Analysis Resource Al-ternatives Marked 426Admitted 459
For Idaho Clean Energy Association:
701. Response Staff's Request No. 9 PremarkAdmitted 297
102. Growth trends chart PremarkAdmi-tted 297
703. Potential inequity chart Premarked
Admitted 291
704. Net meter chart PremarkedAdmitted 297
705. Analysis PremarkedAdmitted 297
83701
EXHIB]TS
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B
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t4
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HEDRICK COURT REPORT]NG
P. O. BOX 578, BOTSE, rD
706. Premj-um paid chart PremarkedAdmitted 297
701. Einancial- benefit chart PremarkedAdmitted 291
708. Empiri-ca1 example chart PremarkedAdmitted 297
709. kVVh chart PremarkedAdmitted 291
710. Estimation of potential revenue
reduction
Premarked
Admitted 291
1ll. Cumulative Insta1led Net Metering Premarked
Capacity Admitted 324
83701
EXHIBITS
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Exhibit No. 1
Case No. IPC-E-12-27
M. Larkin, IPC
Page 1 of 1
ldaho Power Company
I.P.U.C. No.29. TariffNo. 101 OrioinalSheet No. &1
Exhibit No. 2
Case No. IPC-E-12-27
M. Larkin,IPC
Page 1 ofS
SCHEDULE 6
RESIDENTIAL
NET METERING SERVICE
AVAILABILIry
Service under this schedule is available at points on the Company's interconnected system
within the State of ldaho where existing facilities of adequate capacity and desired phase and voltage
are adjacent to the Premises to be served, and additional investment by the Company for new
transmission, substation or terminal facilities is not necessary to supply the desired service. This
service is available to Customers intending to operate Net Metering Systems under this schedule to
generate electricity to reduce all or part of their monthly energy usage.
APPLICABILITY
Service under this schedule is applicable to Electric Service required for residential service
Customers for general domestic uses, including single phase motors ot7% horsepower rating or less,
subject to the following conditions:
1. \Men a portion of a dwelling is used regularly for business, professional or other gainful
purposes, or when service is supplied in whole or in part for business, professional, or other gainful
purposes, the Premises will be classified as non-residential and the appropriate general service
schedule will apply. However, if the wiring is so ananged that the service for residential purposes can
be metered separately, this schedule will be applied to such service.
2. \y'Uhenever the Customer's equipment does not conform to the Company's specifications
for service under this schedule, service will be supplied under the appropriate General Service
Schedule.
3. This schedule is not applicable to standby service, service for resale, or shared service.
4. Customer owns/and or operates a Generation Facility fueled by solar, wind, biomass,
geotherma!, or hydropower, or represents fuel celltechnology, with a total nameplate capacity rating of
25 kilowatts (kW) or less.
5. Customer maintains its electric service account for the loads served at the Point of
Delivery adjacent to the Generation lnterconnection Point as active and in good standing.
6. Customer meets all requirements applicable to Net Metering Systems detailed in the
Company's Schedule 72, lnterconnections to Non-Utility Generation.
DEF!NITIONS
Basic Load Caoacitv (BLC) is the average of the two greatest non-zero monthly Billing Demands
established during the 12-month period which includes and ends with the cunent Billing Period.
IDAHO
lssued per Order No.
Effective - October 1,2013
lssued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221 West ldaho Street, Boise, ldaho
ldaho Power Company
|.P.U.C. No.29. Tariff No. 101 OriginalSheet No.6-2
SCHEDULE 6
RESIDENTIAL
NET METERING SERVICE
(Continued)
DEFINITIONS (Continued)
Billinq Demand is the average kW supplied during the '1S-consecutive-minute period of maximum
use during the Billing Period.
Excess Net Enerov means the positive difference between the kilowatt-hours (kwh) generated
by a Customer and the kWh supplied by the Company over the applicable Billing Period.
Generation Facilitv means all equipment used to generate electric energy where the resulting
energy is either delivered to the Company via a single meter at the Point of Delivery or Generation
lnterconnection Point, or is consumed by the Customer.
Generation lnterconnection Point is the point where the conductors installed to allow receipt of
the Customer's generation connect to the Company's facilities adjacent to the Customeds Point of
Delivery.
lnterconnection Facilities are all facilities reasonably required by Prudent Electrical Practices and
the applicable electric and safety codes to interconnect and safely deliver energy from the Generation
Facility to the Point of Delivery or Generation lnterconnection Point.
Net Meterinq Service is the Company's service which provides for transfer of electric energy to
the Company by means of a net metering arrangement or its successor(s) as approved by the
Commission. This optional service provides for Customers to install Generation Facilities to
interconnect to the Company's system to offset all or a portion of their electrical usage. This service is
comprised of all customers taking service under Schedule 6, Schedule 8, or Schedule 84.
Net Meterinq Svstem is a Customer-owned Generation Facility interconnected to the
Company's system under the terms of Schedule 6, Schedule 8, or Schedule 84.
Point of Deliverv is the retail metering point where the Company's and the Customer's electrical
facilities are interconnected to allow the Customer to take retail electric service from the Company.
Prudent Electrical Practices are those practices, methods and equipment that are commonly used
in prudent electrical engineering and operations to operate electric equipment lawfully and with safety,
dependability, efficiency and economy.
Schedule 72 is the Company's service schedule which provides for interconnection to non-utility
generation or its successor schedule(s)as approved by the Commission.
TYPE OF SERVICE
The type of service provided under this schedule is single phase, alternating current at
approximately 120 or 240 volts and 60 cycles, supplied through one meter at one Point of Delivery.
Upon request by the owner of multi-famity dwellings, the Company may provide 1201208 volt service for
multi-family dwellings when all equipment is U L approved to operate at 120/208 volts.
IDAHO
lssued per Order No.
Effective - October 1,2013
lssued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221Wesl ldaho Street, Boise, ldaho
Exhibit No. 2
Case No. IPC-E-'12-27
M. Larkin, IPC
Page 2 of 5
ldaho Power Company
I.P.U.C. No. 29. Tariff No. 101 OriqinalSheet No. 6-3
SCHEDULE 6
RESIDENTIAL
NET METERING SERVICE
(Continued)
WATER HEATING
All electric water heating equipment, including water storage and tankless water heaters (hot
water on demand), shall conform to specifications of the Underwriters' Laboratories, lnc., and the
Company. The installation of the water heating equipment shall conform to all National, State, and
Municipal Codes. No single electric water heating unit shall exceed 6 kW; and where two or more
heating units are used, these units shall be so interlocked that not more than 6 kW can be connected at
any one time.
Where electric water heaters not complying with these specifications are installed, the Customer
will be required to pay the original installation or upgrade costs for any nonstandard facilities needed to
supply the electrical capacity to meet the water heater demand. Water heating equipment must not
impair or interfere with service to any other customer.
RESIDENTIAL SPACE HEATING
All space heating equipment to be served by the Company's system shall be single-phase
equipment approved by Underwriters' Laboratories, lnc., and the equipment and its installation shall
conform to all National, State, and Municipal Codes and to the following:
lndividual resistance-type units for space heating larger than 1,650 watts shall be
designed to operate a|240 or 208 volts, and no single unit shall be larger than 6 kW. Heating units of 2
kW or larger shall be controlled by approved thermostatic devices. When a group of heating units, with
a total capacity of more than 6 kW, is to be actuated by a single thermostat, the controlling switch shall
be so designed that not more than 6 kW can be switched on or off at any one time. Supplemental
resistanc+type heaters, that may be used with a heat exchanger, shall comply with the specifications
listed above for such units.
CONDITIONS OF PURCHASE AND SALE
The conditions listed below shall apply to all transactions under this schedule.
1. Balances of generation and usage by the Customer:
a. lf electricity supplied by the Company during the Billing Period exceeds the
electricity generated by the Customer and delivered to the Company during the Billing Period,
the Customer shall be billed for the net electricity supplied by the Company at the rates
contained within this schedule, in accordance with normal metering practices.
b. Effective as of the Custome/s January 2014 Billing Period, if electricity generated
by the Customer during the Billing Period exceeds the electricity supplied by the Company during
the Billing Period, the Excess Net Energy shall be carried forward into the following Billing Period
as a kWh credit to be applied against future usage. Any Excess Net Energy credits remaining
after the Custome/s bill for the December Billing Period is prepared shall expire.
IDAHO
lssued per Order No.
Effective - October 1,2013
lssued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221 West ldaho Street, Boise, ldaho
Exhibit No. 2
Case No. IPC-E-12-27
M. Larkin, IPC
Page 3 of 5
ldaho Power Company
|.P.U.C. No. 29. Tariff No. 101 OrioinalSheet No. 6*4
SCHEDULE 6
RESIDENTIAL
NET METERING SERVICE
(Continued)
CONDITIONS OF PURCHASE AND SALE (Continued)
2. The Customer shall never deliver or attempt to deliver energy to the Company's system
when the Company's system serving the Custome/s Generation Facility is de-energized for any
reason.
3. The Company shall not be liable directly or indirectly for permitting or continuing to allow
an attachment of a Net Metering System to the Company's system, or for the acts or omissions of the
Customer that cause loss or injury, including death, to any third pafi.
4. The Customer is responsible for all costs associated with the Generation Facility and
lnterconnection Facilities. The Customer is also responsible for all costs associated with any Company
additions, modifications, or upgrades to any Company facilities that the Company determines are
necessary as a result of the installation of the Generation Facility in order to maintain a safe, reliable
electrical system.
5. The Company shall not be obligated to accept, and the Company may require the
Customer to curtail, interrupt or reduce deliveries of Energy if the Company, consistent with Prudent
Electrical Practices, determines that curtailment, interruption, or reduction is necessary because of line
construction or maintenance requirements, emergencies, or other critical operating conditions on its
system.
6. lf the Company is required by the Commission to institute curtailment of deliveries of
electricity to its customers, the Company may require the Customer to curtail its consumption of
electricity in the same manner and to the same degree as other Customers on the Company's standard
service schedules.
7. The Customer shall grant to the Company all access to all Company equipment and
facilities including adequate and continuing access rights to the propefi of the Customer for the
purpose of installation, operation, maintenance, replacement, or any other service required of said
equipment as well as all necessary access for inspection, switching, and any other operational
requirements of the Customer's lnterconnections Facilities.
8. The Customer shall notiff the Company immediately if a Net Metering System is
permanently removed or disabled. Permanent removal or disablement for the purposes of this
Schedule is any removal or disablement of a project lasting longer than six (6) months. Customers with
permanently removed systems will be removed from service under this schedule and placed on the
appropriate standard service schedule.
SUMMER AND NON-SUMMER SEASONS
The summer season begins on June 1 of each year and ends on August 31 of each year. The
non-summer season begins on September 1 of each year and ends on May 31 of each year.
IDAHO
lssued per Order No.
Effective - October, 1,2013
lssued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221West ldaho Street, Boise, ldaho
Exhibit No. 2
Case No. IPC-E-12-27
M. Larkin, IPC
Page 4 of 5
ldaho Power Company
I.P.U.C. No. 29. Tariff No. 101 Orioinal Sheet No. &5
Service Charge, per month
Basic Charge
Summer
$20.92
per kW of Basic Load Capacity $1.48
Energy Charge, per k\&h
Exhibit No. 2
Case No. IPC-E-12-27
M. Larkin, IPC
Page 5 of 5
SCHEDULE 6
RESIDENTIAL
NET M.ETERING SERVICE
(Continued)
MONTHLY CHARGE
The Monthly Charge is the sum of the following charges, and may also include charges as set
forth in Schedule 55 (Power Cost Adjustment), Schedule 91 (Energy Efficiency Rider), Schedule 95
(Adjustment for Municipal Franchise Fees), and Schedule 98 (Residential and Small Farm Energy Credit).
First 800 k\ffh
801-2000 k\ /rr
AllAdditional kV/h Over 2000
5.25830,
6.4223Q,
7.7215i,
Non-summer
$20.92
$1.48
4.85120,
s.3e856
6.0315d
PAYMENT
The monthly bill rendered for service supplied hereunder is payable upon receipt, and becomes
past due 15 days from the date on which rendered.
!DAHO
lssued per Order No.
Effective - October 1,2013
lssued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs, 1221West ldaho Street, Boise, ldaho
ldaho Power Company
l.P.U.C. No.29. Tariff No. 101 OrioinalSheet No. 8-1
SCHEDULE 8
SMALL GENERAL
NET METERING SERVICE
AVAILABILIry
Service under this schedule is available at points on the Company's interconnected system
within the State of ldaho where existing facilities of adequate capacity and desired phase and voltage
are adjacent to the Premises to be served, and additional investment by the Company for new
transmission, substation or terminal facilities is not necessary to supply the desired service. This
service is available to Customers intending to operate Net Metering Systems under this schedule to
generate electricity to reduce allor part of their monthly energy usage.
APPLICABILITY
Service under this schedule is applicable to Electric Service supplied to a Customer at one Point
of Delivery and measured through one meter. This schedule is applicable to Customers whose
metered energy usage is 2,000 kWh, or !ess, per Billing Period for ten or more Billing Periods during
the most recent 12 consecutive Billing Periods. When the Custome/s Billing Period is less than 27
days or greater than 36 days, the energy usage wi!! be prorated to 30 days for purposes of determining
eligibility under this schedule. Customers whose metered energy usage exceeds 2,000 kWh per Billing
Period on an actual or prorated basis three times during the most recent 12 consecutive Billing Periods
are not eligible for service under this schedule and will be automatically transfened to the applicable
schedule effective with the next Billing Period. New customers may initialty be placed on this schedule
based on estimated usage.
This schedule is also applicable to non-profit or tax supported ball fields, fairgrounds or rodeo
grounds with high demands and intermittent use exceeding 2,000 kWh per month. This schedule is not
applicable to standby service, service for resale, shared seruice, to individual or multiple family
dwellings first served through one meter afier February 9, 1982, or to agricultura! irrigation service after
October 31,2004.
Service under this schedule is also subject to the following conditions:
1. Customer owns/and or operates a Generation Facility fueled by solar, wind, biomass,
geotherma!, or hydropower, or represents fuel ce!!technology, with a total nameplate capacity rating of
25 kilowatts (kW) or !ess.
2. Customer maintains its electric service account for the loads served at the Point of
Delivery adjacent to the Generation lnterconnection Point as active and in good standing.
3. Customer meets all requirements applicable to Net Metering Systems detailed in the
Company's Schedule 72, lnterconnections to Non-Utility Generation.
DEFINITIONS
Basic Load Capacitv (BLC) is the average of the two greatest non-zero monthly Billing Demands
established during the 12-month period which includes and ends with the cunent Billing Period.
lDAHO
lssued rper Order No.
Effective - October 1,2013
lssued by IDAHO POWER COMP
Gregory W. Said, Vice President, Regulatory
Exhibit No. 3
Case No. IPC-E-12-27
M. Larkin, IPC
Page 1 of4
1221 West ldaho Street, Boise, I
ldaho Power Company
|.P.U.C. No. 29. Tariff No. 101 Orioinal Sheet No. &2
SCHEDULE 8
SMALL GENEML
NET METERING SERVICE
(Continued)
DEFINITIONS (Continued)
Billino Demand is the average kW supplied during the 1S-consecutive-minute period of maximum
use during the Billing Period.
Excess Net Enerov means the positive difference between the kilowatt-hours (kwh) generated
by a Customer and the kWh supplied by the Company over the applicable Billing Period.
Generation Facilitv means all equipment used to generate electric energy where the resulting
energy is either delivered to the Company via a single meter at the Point of Delivery or Generation
lnterconnection Point, or is consumed by the Customer.
Generation lnterconnection Point is the point where the conductors installed to allow receipt of
the Customer's generation connect to the Company's facilities adjacent to the Customeds Point of
Delivery.
lnterconnection Facilities are allfacilities reasonably required by Prudent Electrical Practices and
the applicable electric and safety codes to interconnect and safely deliver energy from the Generation
Facility to the Point of Delivery or Generation lnterconnection Point.
Net Meterino Service is the Company's service which provides for transfer of electric energy to
the Company by means of a net metering arrangement or its successor(s) as approved by the
Commission. This optional service provides for Customers to install Generation Facilities to
interconnect to the Company's system to offset all or a portion of their eleclrical usage. This service is
comprised of all customers taking service under Schedule 6, Schedule 8, or Schedule 84.
Net Meterinq Svstem is a Customer-owned Generation Facility interconnected to the
Company's system under the terms of Schedule 6, Schedule 8, or Schedule 84.
Point of Deliverv is the retail metering point where the Company's and the Customer's electrical
facilities are interconnected to allow the Customer to take retail electric service from the Company.
Prudent Electrical Practices are those practices, methods, and equipment that are eommonly
used in prudent electrical engineering and operations to operate electric equipment lavufully and with
safety, dependability, efficiency and economy.
Schedule 72 is the Company's service schedule which provides for interconnection to non-utility
generation or its successor schedule(s) as approved by the Commission.
TYPE OF SERVICE
The type of service provided under this schedule is single and/or three-phase, at approximately
60 cycles and at the standard service voltage available at the Premises to be served.
IDAHO
lssued per Order No.
Effective r- October 1, 2013
lssued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221 West ldaho Street, Boise, ldaho
Exhibit No. 3
Case No. IPC-E-12-27
M. Larkin, IPC
Page 2 of 4
ldaho Power Company
|.P.U.C. No.29. Tariff No. 101 OriqinalSheet No. 8-3
SCHEDULE 8
SMALL GENEML
NET METERING SERVICE
(Continued)
CONDITIONS OF PURCHASE AND SALE
The conditions listed below shall apply to all transactions under this schedule.
1. Balances of generation and usage by the Customer:
a. lf electricity supplied by the Company during the Billing Period exceeds the
electricity generated by the Customer and delivered to the Company during the Billing Period,
the Customer shall be billed for the net electricity supplied by the Company at the rates
contained within this schedule, in accordance with normal metering practices.
b. Effective as of the Custome/s January 2014 Billing Period, if electricity generated
by the Customer during the Billing Period exceeds the electricity supplied by the Company during
the Billing Period, the Excess Net Energy shall be carried fonrard into the following Billing Period
as a kWh credit to be applied against future usage. Any Excess Net Energy credits remaining
afier the Customef s bill for the December Billing Period is prepared shall expire.
2. The Customer shall never deliver or attempt to deliver energy to the Company's system
when the Company's system serving the Customer's Generation Facility is de-energized for any
reason.
3. The Company shall not be liable directly or indirectly for permitting or continuing to allow
an attachment of a Net Metering System to the Company's system, or for the acts or omissions of the
Customer that cause loss or injury, including death, to any third party.
4. The Customer is responsible for all costs associated with the Generation Facility and
lnterconnection Facilities. The Customer is also responsible for all costs associated with any Company
additions, modifications, or upgrades to any Company facilities that the Company determines are
necessary as a result of the installation of the Generation Facility in order to maintain a safe, reliable
electrical system.
5. The Company shall not be obligated to accept, and the Company may require the
Customer to curtail, interrupt, or reduce deliveries of Energy if the Company, consistent with Prudent
Electrical Practices, determines that curtailment, interruption, or reduction is necessary because of line
construction or maintenance requirements, emergencies, or other critical operating conditions on its
system.
6. lf the Company is required by the Commission to institute curtailment of deliveries of
electricity to its customers, the Company may require the Customer to curtail its consumption of
electricity in the same manner and to the same degree as other Customers on the Company's standard
service schedules.
IDAHO
lssued per Order No.
Effective - October 1,2013
lssued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221West ldaho Street, Boise, ldaho
Exhibit No. 3
Case No. IPC-E-'12-27
M. Larkin, IPC
Page 3 of 4
ldaho Power Company
].P.U.C. No. 29, Tariff No. 101 Oriqinal Sheet No. 8-4
Service Charge, per month
Basic Charge
Summer
$22.49
per kW of Basic Load Capacity $1.37
Exhibit No. 3
Case No. IPC-E-12-27
M. Larkin, IPC
Page 4 of 4
SCHEDULE 8
SMALL GENERAL
NET METERING SERVICE
(Continued)
CONDITIONS OF PURCHASE AND SALE (Continued)
7. The Customer shall grant to the Company all access to all Company equipment and
facilities including adequate and continuing access rights to the property of the Customer for the
purpose of installation, operation, maintenance, replacement, or any other service required of said
equipment as well as all necessary access for inspection, switching, and any other operational
req u irements of the Custome/s I ntercon nections Facilities.
8. The Customer shall notify the Company immediately if a Net Metering System is
permanently removed or disabled. Permanent removal or disablement for the purposes of this
Schedule is any removal or disablement of a project lasting longer than six (6) months. Customers with
permanently removed systems will be removed from service under this schedule and placed on the
appropriate standard service schedule.
SUMMER AND NON-SUMMER SEASONS
The summer season begins on June 1 of each year and ends on August 31 of each year. The
non-summer season begins on September 1 of each year and ends on May 31 of each year.
MONTHLY CHARGE
The Monthly Charge is the sum of the following charges, and may also include charges as set
forth in Schedule 55 (Power Cost Adjustment), Schedule 91 (Energy Efficiency Rider), Schedule 95
(Adjustment for Municipal Franchise Fees), and Schedule 98 (Residential and Small Farm Energy Credit).
Energy Charge, per kWh
First 300 kWh
AllAdditional kWh
4.31480
5.20570
Non-summer
$22.49
$1.37
4.31480,
4.5442A
PAYMENT
The monthly bill rendered for service supplied hereunder is payable upon receipt, and becomes
past due 15 days from the date on which rendered.
IDAHO
lssued per Order No.
Effective - October 1,2013
lssued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221 West ldaho Street, Boise, ldaho
GLEAN FORMAT
ldaho Power Company Second Revised Sheet No. 72-1
Cancels
|.P.U.C. No. 29. Tariff No. 101 First Revised Sheet No. 72-1
SCHEDULE 72
!NTERCONNECTIONS TO
NON-UTILITY GENERATION
AVAILABILITY
Service under this schedule is available throughout the Company's service area within the State
of ldaho to Sellers owning or operating Qualiffing Facilities that sign a Uniform lnterconnection
Agreement or Generation Facilities that qualiff for Net Metering Service. Generation Facilities that
qualiflt for Net Metering Service are not required to sign a Uniform lnterconnection Agreement.
APPLICABILITY
Service under this schedule applies to the construction, operation, maintenance, Upgrade,
Relocation, or removal of transmission and/or distribution lines and equipment necessary to safely
interconnect a Selle/s Generation Facility to the Company's system.
DEFINITIONS
Additional Applicant is a person or entity whose request for electrical connection requires the
Company to utilize existing lnterconnection Facilities which are subject to a Vested lnterest.
Companv is the ldaho Power Company.
Connected Load is the combined input rating of the Custome/s motors and other energy
consuming devices.
Construction Cost is the cost, as determined by the Company, of Upgrades, Relocation or
construction of Company fu rn ished I ntercon nection Facilities.
Disconnection Eouipment is any device or combination of devices by which the Company can
manually and/or automatically interrupt the flow of energy from the Seller to the Company's system,
including enclosures or other equipment as may be required to ensure that only the Company will have
access to certain of the devices.
First Enerov Date is the date when the Seller begins delivering energy to the Company's
system.
Generation Facilitv means equipment used to produce electric energy at a specific physical
location which meets the requirements to be a Qualiffing Facility or that qualifies for Net Metering
Service.
Generator lnterconnection Process is the Company's Generation Facility interconnection
application, engineering review and construction process. The intent of the Generator lnterconnection
Process is to ensure a safe and reliable generation interconnection in compliance with all applicable
regulatory requirements, good utility practices and national safety standards.
IDAHO
lssued per IPUC Order No.
Effective - October 1,2013
lssued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221 West ldaho Street, Boise, ldaho
Exhibit No. 4
Case No. IPC-E-12-27
M. Larkin,lPC
Page'l of 72
ldaho Power Company Second Revised Sheet No.72-2
Cancels
!.P.U.C. No. 29, Tariff No. 101 First Revised Sheet No. 72-2
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTI LITY GENERATION
(Continued)
DEFINITIONS (Continued)
lnterconnection Facilities are all facilities which are reasonably required by good utility practices
and the National Electric Safety Code to interconnect and to allow the delivery of energy from the
Seller's Generation Facility to the Company's system, including, but not limited to, Special Facilities,
Disconnection Equipment and Metering Equipment.
lnterconnection Point is the point where the Seller's conductors connect to the facilities owned
by the Company.
Meterino Equipment is the Company owned equipment required to measure, record or
telemeter power flows between the Selle/s Generation Facility and the Company's system.
Net Meterinq Feasibilitv Review is the Company's standard engineering review of proposed Net
Metering Systems. This review is intended to ensure that the Company's system is sufficiently
equipped to incorporate proposed Net Metering Systems in a manner that conforms with good utility
practices and the National Electric Safety Code.
Net Meterinq Service is the Company's service which provides for transfer of electric energy to
the Company by means of a net metering arrangement or its successor(s) as approved by the
Commission. This optional service provides for Customers to install Generation Facilities to
interconnect to the Company's system to offset all or a portion of their electrical usage. This service is
comprised of all customers taking service under Schedule 6, Schedule 8, or Schedule 84.
Net Meterinq Svstem is a Customer-owned Generation Facility interconnected to the
Company's system under the terms of Schedule 6, Schedule 8, or Schedule 84.
OATT is the Company's Federal Energy Regulatory Commission (FERC) approved Open
Access Transmission Tariff.
Protection Equipment is the circuit-interrupting device, protective relaying, and associated
instrument transformers.
PURPA means the Public Utility Regulatory Policies Act of 1978.
Qualifoinq Facilitv is a cogeneration facility or a small power production facility which meets the
PURPA criteria for qualification set forth in Subpart B of Part 292, Subchapter K, Chapter l, Title 18, of
the Code of Federal Regulations.
Relocation is a change in the location of existing Company-owned transmission and/or
distribution lines, poles or equipment.
IDAHO
lssued per IPUC Order No.
Effective - October 1,2013
lssued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221 West ldaho Street, Boise, ldaho
Exhibit No. 4
Case No. IPC-E-12-27
M. Larkin, IPC
Page2 of72
ldaho Power Company
l.P.U.C. No.29. Tariff No. 101
Second Revised Sheet No. 72-3
Cancels
First Revised Sheet No. 72-3
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILITY GENERATION
(Continued)
DEFINITIONS (Continued)
Seller is a non-utility generator who has contracted or will contract with the Company to
interconnect a Generation Facility to the Company's system to sell electric energy to the Company, or a
Customer taking service under the Company's net metering tariffs, Schedule 6, Schedule 8, or
Schedule 84.
Seller-Furnished Facilities are those portions of the lnterconnection Facilities provided by the
Seller.
Special Facilities are additions to or alterations of transmission and/or distribution lines and
transformers, including, but not limited to, Upgrades and Relocation, to safely interconnect the Seller's
Generation Facility to the Company's system.
Transfer Cost is the cost, as determined by the Company, for acceptance by the Company of
Seller-Furnished Facilities.
Uporades are those improvements to the Company's existing system which are reasonably
required by good practices and the National Electric Safety Code to safely interconnect the Seller's
Generation Facility. Such improvements include, but are not limited to, additional or larger conductors,
transformers, poles, and related equipment.
Vested lnterest is the claim for refund that a Seller or Additional Applicant holds in a specific
portion of Company-owned lnterconnection Facilities. The Vested lnterest expires 5 years from the
date the Company completes construction of its portion of the lnterconnection Facilities unless fully
refunded earlier.
SECTION 1 : GENERAL INTERGONNECTION REQUIREMENTS
The following provisions apply to all Sellers requesting interconnection to the Company's
system.
CONSTRUCTION AND OPERAT]ON OF INTERCONNECTION FACILITIES
All Seller-Furnished lnterconnection Facilities will be constructed and maintained in a manner to
be in ful! compliance with all good utility practices, Nationa! Electric Safety Code, and all other
applicable Federal, state, and local safety and electrical codes and standards at all times.
The Seller shall:
1. Submit proof to the Company that all licenses, permits, inspections and approvals
necessary for the construction and operation of the Seller's Generation and lnterconnection Facilities
under this schedule have been obtained from applicable Federal, state, or local authorities.
IDAHO
lssued per IPUC Order No.
Effective - October 1i 2013
lssued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221 West ldaho Street, Boise, ldaho
Exhibit No. 4
Case No. IPC-E-12-27
M. Larkin, IPC
Page3 of72
ldaho Power Company Second Revised Sheet No.724
Cancels
I.P.U.C. No. 29. Tariff No. 101 First Revised Sheet No. 72-4
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILIry GENERATION
(Continued)
CONSTRUCTION AND OPERATION OF INTERCONNECTION FACI LITIES (Continued)
2. Submit the designs, plans, specifications, and performance data for the Generation
Facility and Seller-Furnished Facilities to the Company for review. The Company's acceptance shall
not be construed as confirming or endorsing the design, or as a warranty of safety, durability, or
reliability of the Generation Facility or Seller-Furnished Facilities. The Company will retain the right to
inspect this equipment at its discretion.
3. Demonstrate to the Company's satisfaction that the Seller's Generation Facility and
Seller-Furnished Facilities have been completed, and that all features and equipment of the Seller's
Generation Facility and Seller-Furnished Facilities are capable of operating safely to commence
deliveries of Energy into the Company's system.
4. Provide and maintain adequate protective equipment sufficient to prevent damage to the
Generation Facility, Seller-Furnished Facilities and any other Seller-owned facilities in conformance
with all applicable electrical and safety codes and requirements.
5. Provide and maintain Disconnection Equipment in accordance with all applicable
electrical and safety codes and requirements as described within this Schedule.
6. Provide a 24-hour telephone contact(s). This contact will be used by the Company to
arrange for repairs and inspections or in case of an emergency. The Company will make its best effort
to arrange repairs and inspections during normal business hours and to notiff the Seller of such
arrangements in advance. The Company will provide a telephone number to the Seller so that the
Seller can obtain information about Company activity impacting the Seller's facility.
DISCONNECTION EQUIPMENT
Disconnection Equipment is required for all Seller Generation Facilities. The Disconnection
Equipment shall be installed at an electrical location to allow complete isolation of Seller's Generation
and lnterconnection Facilities from the Company's system. Disconnection Equipment for Net Metering
Systems will be installed at an electrical location on the Seller's side of the Company's retail metering
point to allow complete isolation of the Selle/s Generation and lnterconnection Facilities from the
Seller's other electrical load and service.
The Disconnection Equipment's operating device shall be:
1. Readily accessible by the Company at all times.
2. Clearly marked "Generation Disconnect Switch" with permanent 3/8 inch or larger letters.
3. Physically installed at a location within 10 feet of the lnterconnection Point or exact,
permanent instructions posted at the lnterconnection Point indicating the precise location of the
Disconnection Equipment's operating device.
IDAHO
lssued per IPUC Order No.
Effective - October 1,2013
lssued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
'1221 West ldaho Street, Boise, ldaho
Exhibit No.4
Case No. IPC-E-12-27
M. Larkin, IPC
Page 4 ol 72
ldaho Power Company Second Revised Sheet No. 72-5
Cancels
LP.U.C. No. 29. Tariff No. 101 First Revised Sheet No. 72-5
SCHEDULE 72
INTERCONNECTIONS TO
NON.UTL!ry GENERATION
(Continued)
DISCONNECTION EQUIPMENT (Continued)
4. Of a design manually operated and lockable in the open position with a standard
Company padlock.
5. For Net Metering Systems under Schedule 6, Schedule 8, or Schedule 84, equipped
with a visual disconnect that enables the Company to visually confirm that the Custome/s and
Company's conductors are physically disconnected. This requires the ability to visually inspect the
actual conductors. Circuit breakers and/or switches do not satisff this requirement if the conductors
are not visible.
Operation of Disconnection Equioment. lf, in the reasonable opinion of the Company, the
SelleCs operation or maintenance of the Generation Facility or lnterconnection Facilities is unsafe or
may otherwise adversely affect the Company's equipment, personnel, or service to its customers, the
Company may physically disconnect the Seller's Generation Facility or lnterconnection Facilities by
operation of the disconnection device or by any other means the Company deems necessary to
adequately disconnect the Seller's Generation and lnterconnection Facilities from the Company's
system. At such time as the unsafe condition is remedied or other condition adversely affecting the
Company is resolved to the Company's satisfaction, the interconnection will be restored.
The Company will disconnect the Selle/s Generation and lnterconnection Facilities in the event
of any planned or unplanned maintenance or repair of the Company's system connected to the Seller's
Generation and lnterconnection Facilities. ln the event of unplanned maintenance or repairs, no prior
notice will be provided. ln the event of planned repairs, the Company will attempt to notify the Seller of
the time and duration of the planned outage.
The Company will disconnect the Seller's Generation Facility and lnterconnection Facilities in
the event that any terms and conditions of any applicable Company tariff or contract enabling the
interconnection of the Seller's Generation Facility is deemed by the Company to be in default or
delinquent.
AII expenses of disconnection and reconnection incuned by the Company will be billed to the
Seller.
ln the case of a Net Metering System, disconnection of the service may be necessary. The
disconnection may result in interruption of both energy deliveries from the Seller's Generation Facility to
the Company as well as interruption of energy deliveries from the Company to the Seller.
Disconnection provisions specific to Customers taking service under Schedule 6, Schedule 8, or
Schedule 84 are described further in Section 2 of this tariff.
IDAHO
lssued per IPUC Order No.
Effective - October 1,2013
lssued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221 West ldaho Street, Boise, ldaho
Exhibit No.4
Case No. IPC-E-'12-27
M. Larkin, IPC
Page 5 of 72
ldaho Power Company Second Revised Sheet No. 72-6
Cancels
|.P.U.C. No. 29. Tariff No. 101 First Revised Sheet No. 72-6
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILIry GENERATION
(Continued)
DISCONNECTION EQUIPMENT (Continued)
The Company will establish the settings of Protection Equipment to disconnect the Seller's
Generation Facility and lnterconnection Facilities for the protection of the Company's system and
personnel consistent with good utility practices. lf the Seller attempts to modiff, adjust or otherwise
interfere with the protection equipment or its settings as established by the Company, such action may
be grounds for the Company's refusal to continue interconnection of the Selle/s Generation and
lnterconnection Facilities to the Company's system.
GENERAL REQUIREMENTS OF INTERCONNECTED PROJECTS
1. The Company will construct, own, operate and maintain all equipment, Upgrades and
Relocations on the Company's electricalside of the lnterconnection Point.
2. The Company will clearly mark the Metering Equipment and any other Company
equipment associated with the Seller's Generation Facility and/or lnterconnection Facilities designating
the existence of the Sellef s Generation Facility as required by good utility practices.
3. The Seller will be required to submit all specific designs, equipment specifications, and
test results of the Seller-Furnished Facilities to the Company for review. Upon receipt of the design and
equipment specifications, the Company will review the design and equipment specifications for
conformance with applicable electrical and safety codes and standards.
OPERATIONS AND MAINTENANCE OBLIGATIONS AND EXPENSES
The Company will operate and maintain Company furnished lnterconnection Facilities as well as
any Seller-Furnished Facilities transferred to the Company.
SECTION 2: INTERCONNEGTION OF NET METERING GENERATION FACILITIES
The following section is applicable to all Customers taking Net Metering Service under Schedule
6, Schedule 8, or Schedule 84. lnterconnection of Net Metering Systems is available on a first-come,
first-served basis until the cumulative generation nameplate capacity of Net Metering Systems equals
5.8 megawatts (MW). This cap is applicable to all Net Metering Systems installed in all retail
jurisdictions in which the Company provides electrical service.
APPLICATION PROCESS
Customers requesting Net Metering Service are required to complete the following application
process prior to interconnection:
1. Customers must submit a completed application form and $100 application fee to the
Company. Applications are available on the Company's website.
IDAHO
lssued per IPUC Order No.
Effective - October 1,2013
lssued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221 West ldaho Street, Boise, ldaho
Exhibit No.4
Case No. IPC-E-12-27
M. Larkin, IPC
Page 6 of 72
ldaho Power Company Second Revised Sheet No. 72-7
Cancels
|.P.U.C. No. 29. Tariff No. 10'1 First Revised Sheet No. 72-7
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILIry GENERATION
(Continued)
APPLICATION PROCESS (Continued)
2. Upon receipt of a completed application and $100 fee, the Company will provide the
Customer with written or electronic mail notification that the application has been received and all
necessary information has been provided. Company verification of a completed application constitutes
a reservation of capacity under the Company's aggregate system net metering cap described above in
the amount listed on the application.
3. The Company will perform within a reasonable timeframe the Net Metering Feasibility
Review based on project information provided in the application. The Net Metering Feasibility Review
for Net Metering Systems determines the capability of the Company's electrical system to incorporate
the proposed Net Metering System and determines if Upgrades are necessary.
a. lf the results of the Net Metering Feasibility Review indicate satisfactory system
capability, the Company will provide the Customer with an official "Approval to
Proceed" notification via written or electronic mail.
b. lf the results of the Net Metering Feasibility Review indicate that Upgrades are
necessary to accommodate the proposed project, the Company will notiff the
Customer through written or electronic mail of such Upgrades. Funding,
construction, installation, and maintenance of required Upgrades will be subject
to the Company's standard Rule H regarding New Service Attachments and
Distribution Line lnstallations or Alterations.
4. Following receipt of "Approval to Proceed" the Customer is responsible for completing
the installation of the Net Metering System and fulfilling all applicable Federa!, State, and local
inspection requirements. Upon completion the Customer must provide all forms of documentation
outlined in Section 1-1 above veriffing that all Federal, state, and local requirements have been met.
Customers must also provide the Company with final invoices for all installed components of the
completed Net Metering System.
5. Once all required documentation has been submitted, the Company will complete an on-
site inspection within ten (10) business days, subject to work constraints. Company on-site inspections
will not be performed until the system has passed all applicable Federal, State, and local inspection
requirements as described above. The Company on-site inspection includes the following:
a. Verification that actual installed components correspond to information provided
on the initial applicationb. Verification that the disconnect is functional and reconnection time is no less than
five (5) minutesc. Verification of the proximity and visibility of the disconnect or a sign indicating the
location of the disconnectd. Photographic documentation of the installatione. Posting of appropriate Company signage
Exhibit No. 4
Case No. IPC-E-12-27
M. Larkin, IPC
PageT ol72
IDAHO
lssued per IPUC Order No.
Effective - October 1,2013
lssued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221 West ldaho Street, Boise, ldaho
ldaho Power Company Second Revised Sheet No. 72-8
Cancels
!.P.U.C. No. 29. Tariff No. 101 First Revised Sheet No. 72-8
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILITY GENERATION
(Continued)
APPLICATION PROCESS (Continued)
f. Documentation of the meter number and system configurationg. Evaluation of inverters:
i. Systems utilizing verifiable UL 1741 or IEEE 1547 inverters will not be
subject to additional testingii. Systems utilizing all inverters other than Ul 1741 or IEEE 1547 will be
subject to third-party testing performed at the Customer's expense
6. Successful completion of the Company on-site inspection constitutes the conclusion of
the application process. The Customer will be moved to the appropriate Net Metering Service rate
schedule within three (3) business days, subject to work constraints. Upon completion of this process,
the Customer will receive written or electronic mail confirmation that the application process has been
successfully completed.
APPLICATION EXPIRATION AND FORFEITURE OF CAPACITY RESERVATION
1. Customers that fail to complete the application process within one year of receipt of the
initial Net Metering Feasibility Review forfeit their capacity reservation described in Section 2-2 above.
Customers requesting connection or approval of expired applications are required to resubmit a
completed application form and $100 application fee, and are subject to the full application process
described above.
RECERTIFICATION
1. The Company will perform full recertification inspections of all Net Metering Systems
once every three years. Recertification inspections will be performed in the same manner as new Net
Metering System inspections described above. The Company reserves the right to inspect any Net
Metering System at any time.
NET METERING SYSTEM EXPANSIONS
1. Any modifications to Net Metering Systems that impact the generation capacity of the
system or modiff the system in any way that may impact the safeg or reliability of the Company's
electrical system are considered system expansions for the purposes of this tariff.
2. Customers wishing to install system expansions must submit a new application and
$100 application fee, and complete the application process according to the procedures required of a
new installation.
3. Systems that have been expanded in the manner described above without gaining prior
Company approval are considered unauthorized installations subject to the provisions of this Schedule
described below.
IDAHO
lssued per IPUC Order No.
Effective - October 1,2013
lssued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221 West ldaho Street, Boise, ldaho
Exhibit No.4
Case No. IPC-E-12-27
M. Larkin, IPC
Page 8 of 72
ldaho Power Company Second Revised Sheet No.72-9
Cancels
|.P.U.C. No. 29. Tariff No. 101 First Revised Sheet No. 72-9
Exhibit No.4
Case No. IPC-E-'12-27
M. Larkin, IPC
Page 9 of 72
SCHEDULE 72
INTERCONNECTIONS TO
NON.UTILITY GENERATION
(Continued)
UNAUTHORIZED INSTALLATIONS AND EXPANSIONS
1. Net Metering Systems that have been interconnected to the Company's system without
Company approval are considered unauthorized installations that jeopardize the reliability of ldaho
Power's system and the safety of its employees. This includes, but is not Iimited to, newly installed
systems, and unapproved expansions of approved systems. The process described herein provides
the Company the abilig to offer net metering service in an efficient, safe, and reliable manner.
2. Unauthorized installations are subject to immediate Company inspection without notice.
a. lf proper disconnection equipment is present, the Company will open and lock
the disconnect and provide written notice that the Net Metering System has been
disconnected from the Company's system. The Company will contact the
Customer either in person or via telephone and make the Customer aware of
necessary steps to bring the system into compliance according to the provisions
of this Schedule. Upon completion of the full application process the system will
be reinstated.
b. lf proper disconnection equipment is not present, the Company will evaluate
installed inverters:
i. !f the system utilizes Ul 1741 or IEEE 1547 inverters, the Company will
contact the Customer either in person or via telephone in addition to
written communication regarding the unauthorized installation. This
communication will include the necessary steps to bring the system into
compliance according to the following procedures:
1. Within fifteen (15) days of notification, the Customer must submit
a completed net metering application and $100 fee.
2. Within thirty (30) days of completion of the Net Metering Feasibility
Review, the Customer must complete the remainder of the
inspection requirements described above.
3. Customers that do not wish to bring their systems into compliance
with this schedule may choose to disable their systems.
Customers wishing to disconnect their systems must notiff the
Company within thirty (30) days of the date of notification that their
system is unauthorized and out of compliance with Company
regulation.
4. Customers that fail to complete the application process within the
allotted timeframe and/or do not disable their systems within thir$
(30) days will be subject to termination of electric service.
IDAHO
lssued per IPUC Order No.
Effective - October 1,2013
lssued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221 West ldaho Street, Boise, ldaho
ldaho Power Company Second Revised Sheet No. 72-10
Cancels
l.P.U.C. No. 29. Tariff No. 101 First Revised Sheet No. 72-10
Exhibit No. 4
Case No. IPC-E-12-27
M. Larkin, IPC
Page 10 of72
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILITY GENERATION
(Continued)
U NAUTHORIZED INSTALLATI ONS AND EXPANSIONS (Continued)
ii. lf the system utilizes inverters other than UL 1741 or IEEE 1547, or if the
presence of UL 1741 or IEEE 1547 inverters cannot be verified, the
Customer will be subject to immediate termination of service without
notice.
3. Customers subject to termination of service under this Schedule are provided two
options for restoration of service. Under both options Customers are responsible for reconnection costs
per the Company's standard fees contained in Schedule 66.
a. Customers may choose to disconnect Net Metering Systems from service.
Customers choosing to do so must receive confirmation from a State electrical
inspector that the Net Metering System is no longer operational and
interconnected to the Company's system. The results of this inspection must be
provided to the Company prior to restoration of service.
b. Customers can bring the system into compliance with the provisions of this
schedule by completing the full application process described above.
SECTION 3: INTERGONNECTION OF NON-NET METERING GENERATION FACILITIES
The following section is applicable to all Sellers requesting interconnection of non-utility
generation not taking service under the Company's net metering tariffs, Schedule 6, Schedule 8, or
Schedule 84.
SPECIFIC PROJECT REQUIREMENTS
1. Generation Facilities Less than 1 MW Nameplate Ratino
The following requirements are for Generation Facilities with nameplate ratings of less than 1
MW.
a. The Company shall procure, install, own and maintain Metering Equipment to
record energy deliveries to the Company. This metering wil! be separate from
any other metering of the Selleds load and may be located on either side of the
lnterconnection Point. All acquisition, installation, maintenance, inspection, and
testing costs related to Meter Equipment installed to measure the Selle/s energy
deliveries to the Company shall be borne by the Seller.
b. The Seller is responsible for all costs incurred by the Company for the review,
evaluation and testing of Seller supplied designs and equipment regardless as to
the outcome of the review or test results.
IDAHO
lssued per IPUC Order No.
Effective - October 1,2013
lssued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221 West ldaho Street, Boise, ldaho
ldaho Power Company Second Revised Sheet No. 72-11
Cancels
|.P.U.C. No. 29. Tarifi No. 101 First Revised Sheet No. 72-11
Exhibit No. 4
Case No. IPC-E-12-27
M. Larkin, IPC
Page 1 1 ot72
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILITY GENERATION
(Continued)
SPECIFIC PROJECT REQUIREMENTS (Continued)
The Seller, upon completion of installation and prior to interconnection of the
Generation Facility to the Company's system, will provide the Company with
certification from a professional engineer licensed in the State of ldaho stating
that the Seller's Generation Facility and lnterconnection Facilities are in
compliance with IEEE Standard 1547 and all applicable electrical and safety
codes to enable safe and reliable operation.
The Seller will obtain and provide to the Company an annual certification and
testing by a professional engineer Iicensed in the State of ldaho, certiffing the
ongoing compliance with IEEE Standard 1547 and all applicable electrical and
safety codes and that the Seller-Furnished Facilities successfully meet applicable
testing requirements and standards. ln the event the Company does not receive
and accept the annual certification within thirty (30) days of the annual
anniversary date of the agreement, the project wil! be disconnected from the
Company's system until such time as the certification is completed and accepted
by the Company.
e. ln addition to the requirements specified in sections a through d, Generation
Facilities that are greater than 100 kW and less than 1 MW total nameplate rating
require the following:
i. lf the Company owns the transformer interconnecting the Selle/s
Generation Facility, then the Seller may own and maintain a secondary
voltage disconnection device that can be operated by both the Seller and
the Company.
ii. !f the Seller owns the transformer interconnecting the Seller's Generation
Facility, then the Company will own, operate, and maintain a primary
voltage disconnection device at the Selleds expense.
iii. The Company will construct, own, operate, and maintain all protective
relays and any associated equipment required to operate the protective
relays.
2. Generation Facilities Greater Than 1 MW Nameplate Ratino
The Company will own, maintain, and operate all lnterconnection Facilities and
Disconnection Equipment at the Selle/s expense.
c.
d.
IDAHO
lssued per IPUC Order No.
Effective - October 1,2013
lssued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221 West ldaho Street, Boise, ldaho
ldaho Power Company Second Revised Sheet No.72-12
Cancels
I.P.U.C. No. 29. Tariff No. 101 First Revised Sheet No. 72-12
Exhibit No. 4
Case No. IPC-E-12-27
M. Larkin, IPC
Page 12 ot 72
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILITY GENERATION
(Continued)
GENERATOR INTERCONNECTION PROCESS
1. Seller shall pay the actual costs of all required interconnection studies. Any difference
between the deposit (if required) and the actual cost of the study shall be paid by or refunded to Seller,
as appropriate. lf, during the course of preparing a study, the Company incurs costs in excess of the
deposit amount, the Company may require that the deposit amount be replenished in an amount equal
to the estimated costs for completion of the study. lf a deposit amount sufficient to pay for completion
of the study is not maintained, the Company may suspend work on the study.
2. Unless modified by the provisions of this schedule, the FERC-approved Large Generator
lnterconnection Procedures and Small Generator Interconnection Procedures posted on the
Company's website will apply to the Generator lnterconnection Process.
3. The deposit amounts for Generation Facilities up to 30 MW are specified in this
schedule. Deposit amounts for Generation Facilities 30 MW and larger are covered by the FERC-
approved Large Generator lnterconnection Procedures posted on the Company's website.
4. Application. The Seller will submit a completed interconnection application in the form
posted on the Company's website. The application form includes a general description of the
Generation Facility and its location. The application includes payment of an application fee to be
applied against costs the Company incurs to perform the Feasibility Study described below. The
amount of the application fee is $1,000 for a Generation Facility up to 30 MW.
5. Studv Aqreements. lf the Seller desires to proceed beyond the Application stage, the
Seller will be offered a series of study agreements. The individual study agreements establish the time
to perform the study and the deposit the Seller is to provide prior to commencement of the study. The
deposit amount may be waived if a Seller meets the Company's credit worthiness standards for
unsecured credit specified in Attachment L to the Company's OATT. The studies consist of:
The Feasibilitv Studv: The Feasibility Study includes a general review of project
impact, e.g. exceeding equipment capabilities and violation of electrical
performance requirements. The Feasibility Study Agreement states that no
deposit is required, since the deposit is covered by the application fee.
The Svstem lmpact Studv: The System lmpact Study provides a detailed
assessment of the distribution and/or transmission system adequacy to
accommodate the Generation Facility through the evaluation of equipment
capabilities and electrical performance requirements. This step may not be
necessary for some projects depending on the size and location of the project.
The System lmpact Study Agreement includes a deposit of $2,000 for a
distribution system impact study or a $10,000 deposit for a transmission system
impact study.
a.
b.
IDAHO
lssued per IPUC Order No.
Effective - October 1,2013 ,
lssued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221 West ldaho Street, Boise, ldaho
ldaho Power Company Second Revised Sheet No. 72-13
Cancels
!.P.U.C. No. 29. Tariff No. 101 First Revised Sheet No. 72-13
SCHEDULE 72
INTERCONNECTIONS TO
NON.UTILITY GENERATION
(Continued)
GENERATOR INTERCONNECTION PROCESS (Continued)
c. The Facilitv Studv: The Facility Study includes the engineering to determine the
design specifications of the project. The Facility Study Agreement includes a
deposit of 5% of the total project costs that were determined in the System
lmpact Study Report ("S|SR') or the Feasibility Study Report if a SISR is not
required, capped at $30,000.
At the end of each stage of the three-step study process, the Company will provide the Seller
with an increasingly more refined and detailed report that, among other things, will present a list of
required lnterconnection Facilities and a non-binding, good faith estimate of Seller's cost responsibility
for the lnterconnection Facilities. !f long-lead time equipment items need to be ordered to meet Seller's
construction schedule, the Company will request advance funding by the Seller to cover these
equipment costs.
6. Generator lnterconnection Aoreement. The Generator lnterconnection Agreement
('GlA'), will be offered to Seller following completion of the Facility Study. The GIA will utilize the
Uniform lnterconnection Agreement template included in this schedule.
COST OF INTERCONNECTION FACILITIES
All lnterconnection Facilities provided under this schedule wil! be valued at the Company's
Construction Cost and/or the Transfer Cost for vesting purposes as well as for operation and
maintenance payment obligations.
PAYMENT FOR ! NTERCONNECTION FACILIT!ES
Unless specifically agreed otherwise by written agreement between the Seller and the
Company, the Seller will pay all costs of interconnecting a Generation Facility to the Company's
system. Costs of interconnection include the costs of furnishing and constructing required
lnterconnection Facilities, including Upgrades.
Each request for interconnection will go through the Generator lnterconnection Process.
Throughout the Generator lnterconnection Process, the Company will periodically bill the Seller for
costs incurred or obligated. Failure to pay an invoice within the time specified in the invoice will result
in suspension of work on the interconnection and if the suspension of work extends beyond 30 calendar
days, the Generation Facility will be removed from the interconnection queue. Seller can end the
Generator lnterconnection Process at any time. lf Seller decides to end the Generator lnterconnection
Process prior to completion, the Company will either refund any monies held for security that have not
been spent or obligated, or issue an invoice to Seller for costs incurred prior to cancellation.
IDAHO
lssued per IPUC Order No. 30574
Effective -October 1, 2013
lssued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221 West ldaho Street, Boise, ldaho
Exhibit No.4
Case No. IPC-E-12-27
M. Larkin, IPC
Page 13 of72
ldaho Power Company Second Revised Sheet No.72-14
Cancels
I.P.U.C. No. 29. Tariff No. 101 First Revised Sheet No. 72-14
Exhibit No.4
Case No. IPC-E-12-27
M. Larkin,lPC
Page 14 of72
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILITY GENERATION
(Continued)
SECURITY FOR PAYMENT OF INTERCONNECTION COSTS
Sellers will provide adequate security for payment of the costs of the Generator lnterconnection
Process. Adequate security for Generation Facilities larger than 30 MW can be provided in accordance
with the Large Generator lnterconnection Procedures contained in Attachment M to the Company's
OATT. Adequate securig for Generation Facilities up to 30 MW can be provided in one of the following
ways
1. Sellers that meet the Company's credit worthiness standards for unsecured credit are
not required to provide additional security. The Company's minimum credit standards for unsecured
credit are described in Attachment L to the OATT.
2. Sellers that do not meet the credit worthiness standards for unsecured credit will be
notified of the reason for the determination and shall be given the option to provide alternative security
acceptable to ldaho Power. ln lieu of providing a cash deposit, Seller may establish an escrow
account, provide a letter of credit or provide guarantee of payment by another person or entity which
meets the credit worthiness standards for unsecured credit. Arrangements for alternative security must
be acceptable to ldaho Power.
TRANSFER OF INTERCONNECTION FACILITIES
Transfer of lnterconnection Facilities is available only for Generation Facilities with nameplate
ratings greater than 100 kW.
1. Transfer at First Enerqv Date. lf the Seller desires to transfer and the Company desires
to accept any Seller-Furnished Facilities at the First Energy Date, the following willapply:
a. Prior to the beginning of construction, the Seller shall cause the contractor that is
constructing the Seller-Furnished Facilities to provide the Company with a
certificate naming the Company as an additional insured in the amount of not
less than $1,000,000 under the contractor's general liability policy.
b. The Company will provide the Seller's contractor with construction and material
specifications and will have final approval of the design of the Seller-Furnished
Facilities.
c. During construction and upon completion, the Company will inspect the Seller-
Furnished Facilities to be transferred to the Company. The cost of such
inspection will be borne by the Seller.
IDAHO
lssued per IPUC Order No.
Effective - October 1,2013
lssued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221 West ldaho Street, Boise, ldaho
ldaho Power Company Second Revised Sheet No. 72-15
Cancels
LP.U.C. No. 29. Tariff No. 101 First Revised Sheet No. 72-15
Exhibit No.4
Case No. IPC-E-12-27
M. Larkin, IPC
Page 15 ot72
SCHEDULE 72
!NTERCONNECTIONS TO
NON-UTILITY GENERATION
(Continued)
TRANSFER OF INTERCONNECTION FACILITIES (Continued)
d. !f the Seller-Furnished Facilities meet the Company's design, materia! and
construction specifications, are free from defects in materials and workmanship,
and the Seller has provided the Company with acceptable easements, bills of
sale and assurance against labor or materials liens, the Company will accept
ownership effective as of the First Energy Date. ln the bill of sale, the Seller will
warrant to the Company that the Seller-Furnished Facilities are free of any liens
or encumbrances and will be free from any defects in materials and workmanship
for a period of one year from the First Energy Date.
2. Subseouent Transfer. lf, after the First Energy Date, the Seller desires to transfer and
the Company desires to accept any Seller-Furnished Facilities, the following will apply:
The Company will inspect the facilities proposed for sale to determine if they
meet the Company's design, material and construction specifications.
The Company will determine the Transfer Cost of such facilities. The Transfer
Cost will be equalto the depreciated Construction Cost the Company would have
incurred if it had originally constructed the facilities plus the cost, if any, of
bringing the facilities into compliance with the Company's design, material and
construction specifications. Depreciation of the facilities proposed for transfer will
be determined on the same basis as the Company depreciates its own facilities
in accordance with the appropriate FERC account numbers for the type and size
of line or equipment involved. The time period used for the calculation of the
depreciated transfer cost will extend from the First Energy Date until the agreed
upon transfer date. The Transfer Cost will be paid to the Company in cash at the
time of transfer. At the same time, the Company will pay the Seller in cash an
amount equalto the depreciated Construction Cost.
As a condition of the Company's acceptance, the Seller will provide the Company
with acceptable easements, bills of sale and acceptable assurance against labor
and material liens. The bill of sale wil! include a warranty that the transferred
facilities are free of all liens and encumbrances and will be free from any defects
in materials and workmanship for a period of one year from the date of transfer.
Effective as of the date of the transfer, the Company will operate and maintain
the transferred facilities.
VESTED INTEREST
A Seller's eligibility for a Vested lnterest refund will exist for 5 years after the date the Company
completes construction of its portion of the lnterconnection Facilities.
a.
b.
c.
d.
IDAHO
lssued per IPUC Order No.
Effective - October 1,2013
lssued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
'1221 West ldaho Street, Boise, ldaho
ldaho Power Company Second Revised Sheet No. 72-16
Cancels
I.P.U.C. No. 29. Tariff No. 101 First Revised Sheet No. 72-16
Exhibit No. 4
Case No. IPC-E-12-27
M. Larkin, IPC
Page 16 ot72
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILITY GENERATION
(Cdntinued)
VESTED INTEREST (Continued)
1. The Company will provide a refund payment to each Seller holding a Vested lnterest in
Company-owned lnterconnection Facilities when an Additional Applicant shares use of those
lnterconnection Facilities.
2. The refund payment will be based on the following formula:
Linear
Refund = Footage
Ratio
Connectedx Load/Peak Generation
Ratio
Originalx lnterconnection
Cost
a. The Linear Footage Ratio is the length of jointly used Special Facilities divided by
the length of the vested Special Facilities.b. The Connected Load/Peak Generation Ratio is the Connected Load or Peak
Generation of the Additional Applicant divided by the sum of the Connected Load
or Peak Generation of the Additional Applicant and al! other Connected Loads
and/or Peak Generation on the Special Facilities.
c. The Original lnterconnection Cost is the sum of the Company's Construction Cost
and any Transfer Costs for the lnterconnection Facilities to which the Additional
Applicant intends to connect and share usage.
3. The Additional Applicant will pay the Company the amount of the Vested lnterest
refund(s). AdditionalApplicants making Vested lnterest payments are in turn eligible to receive refunds
within the 5 year limit described above.
4. Vested lnterest refunds will not exceed 100 percent of the refundable portion of any
party's cash payment to the Company.
5. Vested lnterest refund payments may be waived by notiffing the Company in writing.
OPERATION AND MAINTENANCE OBLIGATIONS AND EXPENSES
The Company will operate and maintain Company furnished lnterconnection Facilities as well as
any Seller-Furnished Facilities transferred to the Company. For all projects not interconnecting as a
Schedule 84 customer, the Seller will pay the Csmpany a monthly operation and maintenance charge
equal to a percentage of the Construction CosFand Transfer Cost paid by the Seller. The percentage
will change annually on the anniversary of the First Energy Date in accordance with the following table:
IDAHO
lssued per IPUC Order No.
Effective - October 1,2013
lssued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221West ldaho Street, Boise, ldaho
ldaho Power Company Second Revised Sheet No.72-17
Cancels
|.P.U.C. No. 29. Tariff No. 101 First Revised Sheet No. 72-17
Exhibit No. 4
Case No. IPC-E-12-27
M. Larkin, IPC
Page 17 of72
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILITY GENERATION
(Continued)
OPERATION AND MAINTENANCE OBLIGATIONS AND EXPENSES (Continued)
MONTHLY OPERATION AND MAINTENANCE CHARGES
MONTHLY OPERATING AND MAINTENANCE CHARGES
Where a Selle/s interconnection will utilize lnterconnection Facilities provided under a prior
agreement(s), the term of which was shorter than 35 years, the operation and maintenance charge for
the Seller's interconnection will be computed to include the expired term of the prior agreement(s).
The cost upon which an individual Seller's operation and maintenance charge is based will be
reduced by subsequent Vested lnterest refunds. Additional Applicants who are Sellers will pay the
monthly operation and maintenance charge on the amount they paid as an AdditionalApplicant.
Seller-Furnished Facilities not transferred to the Company will be operated and maintained by
the Seller at the Selle/s sole risk and expense.
IDAHO
lssued per IPUC Order No.
Effective - Octoben 1,2013
lssued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221 West ldaho Street, Boise, ldaho
138 kVand 161 kV
Year 1 2 3 4 5 6 7 I I 10 11 12
O&M Charge 0.260/o O.27o/o 0.28o/o 0.29o/o 0.300/6 0.32o/o 0.33%0.35%0.36%0.38%0.400/o 0.4'to/o
Year 13 14 15 16 17 18 19 20 21 22 23 24
O&M Charge O.43o/o 0.45o/o 0.4'lo/o 0.19%0.52o/o 0.54o/o 0.56%0.59%0.62%0.640/0 0.67o/0 0.70o/o
Year 25 26 27 28 29 30 31 32 33 34 35
O&M Charge 0.73o/o o.7704 0.80%O.84o/o O.87o/o 0.91o/o 0.96%1.00o/o 1.04o/o 1.09%1.',140/o
Below 138 kV
Year ,l 2 3 4 5 rt 7 I o 10 11 12
O&M Charge 0.47o/o O.4go/o O.52o/o O.54o/o 0.560/6 0.59%0.61%0.64%0.67o/o 0.70o/o 0.73o/o 0.77o/o
Year 13 14 15 16 17 18 19 20 21 22 23 24
O&M Charge 0.80%0.84%0.87o/o 0.91o/o 0.95%1.00o/o 1.O4o/o 1.09%'1.110/o 1.190h 1.24o/o 't.30%
Year 25 26 27 28 29 30 31 32 33 34 35
O&M Charqe 1.36o/o '1.420/o 1.48o/o 1.55%1.62%1.69%1.77o/o 1.85o/o '1.930/o 2.02o/o 2.',\10/o
ldaho Power Company Second Revised Sheet No. 72-'18
Cancels
|.P.U.C. No. 29. Tariff No. 101 First Revised Sheet No. 72-18
Exhibit No.4
Case No. IPC-E-12-27
M. Larkin, IPC
Page 18 of72
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILIry GENERATION
(Continued)
IDAHO POWER COMPANY
UNIFORM INTERCONNECTION
AGREEMENT
(PURPA)
ThislnterconnectionAgreement(.,Agreement,,)iseffectiveaSofthe-dayof-,20--, between hereinafter called "Seller," and ldaho Power
Company, hereinafter called "Company."
RECITALS
A. Seller will own or operate a Generation Facility that qualifies for service under ldaho
Power's Gommission-approved Schedule 72 and any successor schedule.
B. The Generation Facility covered by this Agreement is more particularly described in
Attachment 1.
AGREEMENTS
1. Capitalized terms used herein shall have the same meanings as defined in Schedule 72
or in the body of this Agreement.
2. This Agreement and Schedule 72 provide the rates, charges, terms and conditions
under which the Seller's Generation Facility will interconnect with, and operate in parallel with, the
Company's transmission/distribution system. Terms defined in Schedule 72will have the same defined
meaning in this Agreement. lf there is any conflict between the terms of this Agreement and Schedule
72, Schedule 72 shall prevail.
3. This Agreement is not an agreement to purchase Sellefs power. Purchase of Selle/s
power and other services that Seller may require will be covered under separate agreements. Nothing
in this Agreement is intended to affect any other agreement between the Company and Seller.
4. Attached to this Agreement and included by reference are the following:
Attachment 1 - Description and Costs of the Generation Facility, lnterconnection
Facilities, and Metering Equipment.
Attachment 2 - One.line Diagram Depicting the Generation Facility, Interconnection
Facilities, Metering Equipment and Upgrades.
Attachment 3 - Milestones For lnterconnecting the Generation Facility.
IDAHO
lssued per IPUC Order No.
Effective - October 1,201;3
lssued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221 West ldaho Street, Boise, ldaho
ldaho Power Company Second Revised Sheet No. 72-19
Cancels
|.P.U.C. No. 29. Tariff No. 101 First Revised Sheet No. 72-19
Exhibit No. 4
Case No. IPC-E-12-27
M. Larkin, IPC
Page 19 of72
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILITY GENERATION
(Continued)
IDAHO POWER COMPANY
UNIFORM !NTERCONNECTION
AGREEMENT
(PURPA)
(Continued)
AGREEM ENTS (Continued)
Attachment 4 - Additional Operating Requirements for the Company's Transmission
System Needed to Support the Selle/s Generation Facility.
Attachment 5 - Reactive Power.
Attachment 6 - Description of Upgrades required to integrate the Generation Facility and
Best Estimate of Upgrade Costs.
5. Effective Date. Term. Termination and Disconnection.
5.1 Term of Aqreement. Unless terminated earlier in accordance with the provisions
of this Agreement, this Agreement shall become effective on the date specified above and
remain effective as long as Seller's Generation Facility is eligible for service under Schedule 72.
5.2 Termination.
5.2.1 Seller may voluntarily terminate this Agreement upon expiration or
termination of an agreement to sell power to the Company.
5.2.2 Afier a Default, either Party may terminate this Agreement pursuant to
Section 6.5.
5.2.3 Upon termination or expiration of this Agreement, the Selle/s Generation
Facility will be disconnected from the Company's transmission/distribution system. The
termination or expiration of this Agreement shall not relieve either Party of its liabilities
and obligations, owed or continuing at the time of the termination. The provisions of this
Section shall survive termination or expiration of this Agreement.
IDAHO
lssued per IPUC Order No.
Effective - October 1,2013
lssued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221 West ldaho Street, Boise, ldaho
ldaho Power Company Second Revised Sheet No. 72-20
Cancels
|.P.U.C. No. 29. Tariff No. 101 First Revised Sheet No. 72-20
Exhibit No.4
Case No. IPC-E-12-27
M. Larkin, IPC
Page20 ol72
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILIry GENERATION
(Continued)
IDAHO POWER COMPANY
UNIFORM INTERCONNECTION
AGREEMENT
(PURPA)
(Continued)
AGREEMENTS (Continued)
5.3 Temporarv Disconnection. Temporary disconnection shall continue only for so
long as reasonably necessary under "Good Utility Practice." Good Utility Practice means any of
the practices, methods and acts engaged in or approved by a significant portion of the electric
industry during the relevant time period, or any of the practices, methods and acts which, in the
exercise of reasonable judgment in light of the facts known at the time the decision was made,
could have been expected to accomplish the desired result at a reasonable cost consistent with
good business practices, reliability, safety and expedition. Good Utility Practice is not intended
to be limited to the optimum practice, method, or act to the exclusion of all others, but rather to
be acceptable practices, methods, or acts generally accepted in the region. Good Utility
Practice includes compliance with WECC or NERC requirements. Payment of lost revenue
resulting from temporary disconnection shall be governed by the power purchase agreement.
5.3.1 Emerqencv Conditions. "Emergency Condition" means a condition or
situation: (1) that in the judgment of the Pafi making the claim is imminently likely to
endanger life or property; or (2) that, in the case of the Company, is imminently likely (as
determined in a non-discriminatory manner) to cause a material adverse effect on the
security of, or damage to the Company's transmission/distribution system, the
Company's lnterconnection Facilities or the equipment of the Company's customers; or
(3) that, in the case of the Seller, is imminently likely (as determined in a non-
discriminatory manner) to cause a material adverse effect on the reliability and security
of, or damage to, the Generation Facility or the Seller's lnterconnection Facilities. Under
Emergency Conditions, either the Company or the Seller may immediately suspend
interconnection service and temporarily disconnect the Generation Facility. The
Company shall notify the Seller promptly when it becomes aware of an Emergency
Condition that may reasonably be expected to affect the Selle/s operation of the
Generation Facility. The Seller shall notiff the Company promptly when it becomes
aware of an Emergency Condition that may reasonably be expected to affect the
Company's equipment or service to the Company's customers. To the extent
information is known, the notification shall describe the Emergency Condition, the extent
of the damage or deficiency, the expected effect on the operation of both Parties'
facilities and operations, its anticipated duration, and the necessary corrective action.
IDAHO
lssued per IPUC Order No.
Effective - October 1,2013
lssued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221 West ldaho Street, Boise, ldaho
ldaho Power Company Second Revised Sheet No.72-21
Cancels
!.P.U.C. No. 29. Tariff No. 101 First Revised Sheet No. 72-21
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILITY GENERATION
(Continued)
IDAHO POWER COMPANY
UN IFORM INTERCONNECTION
AGREEMENT
(PURPA)
(Continued)
AGREEMENTS (Continued)
Exhibit No. 4
Case No. IPC-E-12-27
M. Larkin,lPC
Page21 of72
5.3.2 Routine Maintenance. Construction. and Repair. The Company may
interrupt interconnection service or curtail the output of the Seller's Generation Facilityand temporarily disconnect the Generation Facility from the Company's
transmission/distribution system when necessary for routine maintenance, construction,
and repairs on the Company's transmission/distribution system. The Company will
make a reasonable attempt to contact the Seller prior to exercising its rights to interrupt
interconnection or curtail deliveries from the Selle/s Facility. Seller understands that in
the case of emergency circumstances, real time operations of the electrical system,
and/or unplanned events, the Company may not be able to provide notice to the Seller
prior to interruption, curtailment or reduction of electrical energy deliveries to the
Company. The Company shall use reasonable efforts to coordinate such reduction or
temporary disconnection with the Seller.
5.3.3 Scheduled Maintenance. On or before January 31 of each calendar year,
Seller shall submit a written proposed maintenance schedule of significant Facility
maintenance for that calendar year and the Company and Seller shall mutually agree as
to the acceptability of the proposed schedule. The Parties determination as to the
acceptability of the Selle/s timetable for scheduled maintenance will take into
consideration Good Utility Practices, ldaho Power system requirements and the Seller's
preferred schedule. Neither Party shall unreasonably withhold acceptance of the
proposed maintenance schedule.
5.3.4. Maintenance Coordination. The Seller and the Company shall, to the
extent practical, coordinate their respective transmission/distribution system and
Generation Facility maintenance schedules such that they occur simultaneously. Seller
shall provide and maintain adequate protective equipment sufficient to prevent damage
to the Generation Facility and Seller-furnished lnterconnection Facilities. ln some cases,
some of Seller's protective relays will provide back-up protection for ldaho Powefs
facilities. ln that event, ldaho Power will test such relays annually and Seller will pay the
actual cost of such annual testing.
IDAHO
lssued per IPUC Order No.
Effective - October 1,2013
lssued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221 West ldaho Street, Boise, ldaho
ldaho Power Company Second Revised Sheet No.72-22
Cancels
!.P.U.C. No. 29. Tariff No. 101 First Revised Sheet No. 72-22
SCHEDULE 72
INTERCONNECTIONS TO
NON-UT!LITY GENERATION
(Continued)
IDAHO POWER COMPANY
UNIFORM INTERCONNECTION
AGREEMENT
(PURPA)
(Continued)
AGREEMENTS (Continued)
Exhibit No.4
Case No. IPC-E-12-27
M. Larkin, IPC
Page 22 of 72
5.3.5 Forced Outaoes. During any forced outage, the Company may suspend
interconnection service to effect immediate repairs on the Company's
transmission/distribution system. The Company shall use reasonable efforts to provide
the Seller with prior notice. lf prior notice is not given, the Company shall, upon request,
provide the Seller written documentation after the fact explaining the circumstances of
the disconnection.
5.3.6 Adverse Operatinq Effects. The Company shall notify the Seller as soon
as practicable if, based on Good Utili$ Practice, operation of the Seller's Generation
Facility may cause disruption or deterioration of service to other customers served from
the same electric system, or if operating the Generation Facility could cause damage to
the Company's transmission/distribution system or other affected systems. Supporting
documentation used to reach the decision to disconnect shall be provided to the Seller
upon request. lf, after notice, the Seller fails to remedy the adverse operating effect
within a reasonable time, the Company may disconnect the Generation Facility. The
Company shall provide the Seller with reasonable notice of such disconnection, unless
the provisions of Article 5.3.1 apply.
5.3.7 Modification of the Generation Facilitv. The Seller must receive written
authorization from the Company before making any change to the Generation Facility
that may have a material impact on the safety or reliability of the Company's
transmission/distribution system. Such authorization shall not be unreasonably withheld.
Modifications shall be done in accordance with Good Utility Practice. lf the Seller makes
such modification without the Company's prior written authorization, the latter shall have
the right to temporarily disconnect the Generation Facility.
5.3.8 Reconnection. The Parties shall cooperate with each other to restore the
Generation Facility, lnterconnection Facilities, and the Company's
transmission/distribution system to their normal operating state as soon as reasonably
practicable following a temporary disconnection.
IDAHO
lssued per IPUC Order No.
Effective - October 1,2013
lssued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221Wesl ldaho Street, Boise, ldaho
ldaho Power Company Second Revised Sheet No. 72-23
Cancels
!.P.U.C. No. 29. Tariff No. 101 First Revised Sheet No. 72-23
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILITY GENERATION
(Continued)
IDAHO POWER COMPANY
UNIFORM INTERCONNECTION
AGREEMENT
(PURPA)
(Continued)
AGREEMENTS (Continued)
Exhibit No.4
Case No. IPC-E-12-27
M. Larkin, IPC
Page23 of72
5.3.9 Voltaoe Levels. Seller, in accordance with Good Utility Practices, shall
minimize voltage fluctuations and maintain voltage levels acceptable to ldaho Power.
ldaho Power may, in accordance with Good Utility Practices, upon one hundred eighty
(180) days' notice to the Seller, change its nominal operating voltage level by more than
ten percent (10%) at the Point of Delivery, in which case Seller shall modiff, at ldaho
Power's expense, Seller's equipment as necessary to accommodate the modified
nominal operating voltage level.
5.4 Land Riqhts.
5.4.1 Seller to Provide Access. Seller hereby grants to ldaho Power for the
term of this Agreement all necessary rights-of-way and easements to install, operate,
maintain, replace, and remove ldaho Power's Metering Equipment, Interconnection
Equipment, Disconnection Equipment, Protection Equipment and other Special Facilities
necessary or useful to this Agreement, including adequate and continuing access rights
on propefi of Seller. Seller warrants that it has procured sufficient easements and
rights-of-way from third parties so as to provide ldaho Power with the access described
above. All documents granting such easements or rights-of-way shall be subject to
ldaho Power's approval and in recordable form.
5.4.2 Use of Public Riohts-of-Wav. The Parties agree that it is necessary to
avoid the adverse environmental and operating impacts that would occur as a result of
duplicate electric lines being constructed in close proximity. Therefore, subject to ldaho
Power's compliance with Paragraph 5.4.4, Seller agrees that should Seller seek and
receive from any local, state or federal governmental body the right to erect, construct
and maintain Seller-furnished lnterconnection Facilities upon, along and over any and all
public roads, streets and highways, then the use by Seller of such public right-of-way
shall be subordinate to any future use by ldaho Power of such public right-of-way for
construction and/or maintenance of electric distribution and transmission facilities and
ldaho Power may claim use of such public right-of-way for such purposes at any time.
Except as required by Paragraph 5.4.4, ldaho Power shall not be required to
compensate Seller for exercising its rights under this Paragraph 5.4.2.
IDAHO
lssued per IPUC Order No.
Effective - October 1,2013
lssued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221 West ldaho Street, Boise, ldaho
ldaho Power Company Second Revised Sheet No.72-24
Cancels
|.P.U.C. No. 29. Tariff No. 101 First Revised Sheet No. 72-24
Exhibit No.4
Case No. IPC-E-12-27
M. Larkin, IPC
Page24 of72
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILITY GENERATION
(Continued)
IDAHO POWER COMPANY
UNIFORM INTERCONNECTION
AGREEMENT
(PURPA)
(Continued)
AGREEM ENTS (Continued)
5.4.3 Joint Use of Facilities. Subject to ldaho Power's compliance with
Paragraph 15.4.4,ldaho Power may use and attach its distribution and/or transmission
facilities to Seller's lnterconnection Facilities, may reconstruct Seller's lnterconnection
Facilities to accommodate ldaho Power's usage or ldaho Power may construct its own
distribution or transmission facilities along, over and above any public right-of-way
acquired from Seller pursuant to Paragraph 5.4.2, attaching Seller's lnterconnection
Facilities to such newly constructed facilities. Except as required by Paragraph 5.4.4,
ldaho Power shall not be required to compensate Seller for exercising its rights under
this Paragraph 5.4.3.
5.4.4 Conditions of Use. lt is the intention of the Parties that the Seller be lefi in
substantially the same condition, both financially and electrically, as Seller existed prior
to ldaho Power's exercising its rights under this Paragraph 5.4. Therefore, the Parties
agree that the exercise by ldaho Power of any of the rights enumerated in Paragraphs
5.4.2 and 5.4.3 shall: (1) comply with all applicable !aws, codes and Good Utility
Practices, (2) equitably share the costs of installing, owning and operating jointly used
facilities and rights-of-way. lf the Parties are unable to agree on the method of
apportioning these costs, the dispute will be submitted to the Commission for resolution
and the decision of the Commission will be binding on the Parties, and (3) shall provide
Seller with an interconnection to ldaho Power's system of equal capacity and durability
as existed prior to ldaho Power exercising its rights under this Paragraph 5.4.
6. Assiqnment. Liabilitv. lndemnitv. Force maieure. Consequential Damaqes and Default.
6.1 Assiqnment. This Agreement may be assigned by either Party upon twenty-one
(21) calendar days prior written notice and opportunity to object by the other Party; provided
that:
6.1.1 Either Party may assign this Agreement without the consent of the other
Party to any affiliate of the assigning Pafi with an equal or greater credit rating and with
the legal authority and operational ability to satisff the obligations of the assigning Party
under this Agreement.
IDAHO
lssued per IPUC Order No.
Effective - October 1,2013
lssued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221 West ldaho Street, Boise, ldaho
ldaho Power Company Second Revised Sheet No.72-25
Cancels
!.P.U.C. No. 29. Tariff No. 101 First Revised Sheet No. 72-25
Exhibit No. 4
Case No. IPC-E-12-27
M. Larkin,lPC
Page25 of72
SCHEDULE 72
INTERCONNECTIONS TO
NON.UTILIry GENERATION
(Continued)
IDAHO POWER COMPANY
UNIFORM !NTERCONNECTION
AGREEMENT
(PURPA)
(Continued)
AGREEM ENTS (Continued)
6.1.2 The Seller shall have the right to contingently assign this Agreement,
without the consent of the Company, for collateral security purposes to aid in providing
financing for the Generation Facility, provided that the Seller will promptly notiff the
Company of any such contingent assignment.
6.1.3 Any attempted assignment that violates this article is void and ineffective.
Assignment shall not relieve a Party of its obligations, nor shall a Pafi's obligations be
enlarged, in whole or in part, by reason thereof. An assignee is responsible for meeting
the same financial, credit, and insurance obligations as the Seller. Where required,
consent to assignment will not be unreasonably withheld, conditioned or delayed.
6.2 Limitation of Liabilitv. Each Party's Iiability to the other Party for any loss, cost,
claim, injury, liability, or expense, including reasonable attorney's fees, relating to or arising from
any act or omission in its performance of this Agreement, shall be limited to the amount of direct
damage actually incurred. ln no event shall either Pafi be liable to the other Pafi for any
indirect, special, consequential, or punitive damages, except as authorized by this Agreement.
6.3 lndemnitv.
6.3.1 This provision protects each Party from liability incurred to third parties as
a result of carrying out the provisions of this Agreement. Liability under this provision is
exempt from the general limitations on liability found in Article 6.2.
6.3.2 The Parties shall at all times indemniff, defend, and hold the other Party
harmless from, any and all damages, losses, claims, including claims and actions
relating to injury to or death of any person or damage to property, demand, suits,
recoveries, costs and expenses, court costs, attorney fees, and all other obligations by
or to third parties, arising out of or resulting from the other Party's action or failure to
meet its obligations under this Agreement on behalf of the indemniffing Party, except in
cases of gross negligence or intentional wrongdoing by the indemnified Party.
IDAHO
tssued per IPUC Order No.
Effective - October 1,2013
lssued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221 West ldaho Street, Boise, ldaho
ldaho Power Company Second Revised Sheet No. 72-26
Cancels
|.P.U.C. No. 29. Tariff No. 101 First Revised Sheet No. 72-26
Exhibit No.4
Case No. IPC-E-12-27
M. Larkin, IPC
Page26 ol72
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILITY GENERATION
(Continued)
IDAHO POWER COMPANY
UNIFORM INTERCONNECTION
AGREEMENT
(PURPA)
(Continued)
AGREEMENTS (Continued)
6.3.3 lf an indemnified person is entitled to indemnification under this article as
a result of a claim by a third party, and the indemniffing Pafi fails, afier notice and
reasonable opportunity to proceed under this article, to assume the defense of such
claim, such indemnified person may at the expense of the indemniffing Party contest,
settle or consent to the entry of any judgment with respect to, or pay in full, such claim.
Failure to defend is a Material Breach.
6.3.4 lf an indemniffing party is obligated to indemniff and hold any
indemnified person harmless under this article, the amount owing to the indemnified
person shall be the amount of such indemnified person's actual loss, net of any
insurance or other recovery.
6.3.5 Promptly after receipt by an indemnified person of any claim or notice of
the commencement of any action or administrative or legal proceeding or investigation
as to which the indemnity provided for in this article may apply, the indemnified person
shall notiff the indemnifiTing party of such fact. Any failure of or delay in such notification
shall be a Material Breach and sha!! not affect a Party's indemnification obligation unless
such failure or delay is materially prejudicialto the indemniffing party.
6.4 Force Maieure. As used in this Agreement, "Force Majeure" or "an event of
Force Majeure" means any cause beyond the control of the Seller or of the Company which,
despite the exercise of due diligence, such Party is unable to prevent or overcome. Force
Majeure includes, but is not limited to, acts of God, fire, flood, storms, wars, hostilities, civil
strife, strikes and other labor disturbances, earthquakes, fires, lightning, epidemics, sabotage, or
changes in law or regulation occurring after the Operation Date, which, by the exercise of
reasonable foresight such pafi could not reasonably have been expected to avoid and by the
exercise of due diligence, it shall be unable to overcome. lf either Party is rendered wholly or in
part unable to perform its obligations under this Agreement because of an event of Force
Majeure, both Parties shall be excused from whatever performance is affected by the event of
Force Majeure, provided that:
(1) The non-performing Pafi shal!, as soon as is reasonably possible after
the occurrence of the Force Majeure, give the other Pafi written notice describing the
particulars of the occurrence.
IDAHO
lssued per IPUC Order No.
Effective - October 1,2013t
lssued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221 West ldaho Street, Boise, ldaho
ldaho Power Company Second Revised Sheet No.72-27
Cancels
!.P.U.C. No. 29. Tariff No. 101 First Revised Sheet No. 72-27
Exhibit No. 4
Case No. IPC-E-12-27
M. Larkin, IPC
Page27 of72
SCHEDULE 72
INTERCONNECTIONS TO
NON-UT!LITY GENERATION
(Continued)
IDAHO POWER COMPANY
UNIFORM INTERCONNECTION
AGREEMENT
(PURPA)
(Continued)
AGREEMENTS (Continued)
(2) The suspension of performance shall be of no greater scope and of no
longer duration than is required by the event of Force Majeure.
(3) No obligations of either Party which arose before the occurrence causing
the suspension of performance and which could and should have been fully performed
before such occurrence shall be excused as a result of such occurrence.
6.5 Default and Material Breaches.
a-
-
fails to perform any of the terms or conditions of
this Agreement (a "Default" or an "Event of Default"), the nondefaulting Party shallcause
notice in writing to be given to the defaulting Party, specifying the manner in which such
default occuned. lf the defaulting Party shall fai! to cure such Default within the sixty
(60) days after service of such notice, or if the defaulting Party reasonably demonstrates
to the other Pafi that the Default can be cured within a commercially reasonable time
but not within such sixty (60) day period and then fails to diligently pursue such cure,
then, the nondefaulting Party may, at its option, terminate this Agreement and/or pursue
its legal or equitable remedies.
6.5.2 Material Breaches. The notice and cure provisions in Paragraph 6.6.1 do
not apply to Defaults identified in this Agreement as Material Breaches. Material
Breaches must be cured as expeditiously as possible following occurrence of the
breach.
7. lnsurance. During the term of this Agreement, Seller shall secure and continuously carry
the following insurance coverage:
7.1 Comprehensive General Liability Insurance for both bodily injury and property
damage with limits equa! to $1,000,000, each occurrence, combined single limit. The deductible
for such insurance shall be consistent with cunent lnsurance lndustry Utility practices for similar
property.
7.2 The above insurance coverage shall be placed with an insurance company with
an A.M. Best Company rating of A- or better and shall include:
IDAHO
lssued per IPUC Order No.
Effective - October 1,2013
lssued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221 West ldaho Street, Boise, ldaho
ldaho Power Company First Revised Sheet No. 72-28
Cancels
|.P.U.C. No.29. TariffNo. 101 OriqinalSheet No. 72-28
Exhibit No. 4
Case No. IPC-E-12-27
M. Larkin, IPC
Page28 of72
SCHEDULE 72
!NTERCONNECTIONS TO
NON-UTILITY GENERATION
(Continued)
IDAHO POWER COMPANY
UNIFORM INTERCONNECTION
AGREEMENT
(PURPA)
(Continued)
AGREEMENTS (Continued)
(a) An endorsement naming ldaho Power as an additional insured and loss
payee as applicable; and
(b) A provision stating that such policy shall not be canceled or the limits of
liability reduced without sixty (60) days' prior written notice to ldaho Power.
7.3 Seller to Provide Certificate of lnsurance. As required in Paragraph 7 herein and
annually thereafter, Seller shall furnish the Company a certiflcate of insurance, together with the
endorsements required therein, evidencing the coverage as set forth above.
7.4 Seller to Notifo ldaho Power of Loss of Coveraoe - lf the insurance coverage
required by Paragraph 7.1 shall lapse for any reason, Seller will immediately notiff ldaho Power
in writing. The notice will advise ldaho Power of the specific reason for the lapse and the steps
Seller is taking to reinstate the coverage. Failure to provide this notice and to expeditiously
reinstate or replace the coverage will constitute grounds for a temporary disconnection under
Section 5.3 and will be a Material Breach.
8. Miscellaneous.
8.1 Governinq Law. The validity, interpretation and enforcement of this Agreement
and each of its provisions shall be governed by the laws of the state of ldaho without regard to
its conflicts of law principles.
8.2 Salvaqe. No later than sixty (60) days after the termination or expiration of this
Agreement, ldaho Power will prepare and forward to Seller an estimate of the remaining value
of those ldaho Power furnished lnterconnection Facilities as required under Schedule 72 andlor
described in this Agreement, less the cost of removal and transfer to ldaho Power's nearest
warehouse, if the lnterconnection Facilities will be removed. lf Seller elects not to obtain
ownership of the lnterconnection Facilities but instead wishes that ldaho Power reimburse the
Seller for said Facilities the Seller may invoice ldaho Power for the net salvage value as
estimated by ldaho Power and ldaho Power shall pay such amount to Seller within thirty (30)
days after receipt of the invoice. Seller shall have the right to offset the invoice amount against
any present or future payments due ldaho Power.
IDAHO
lssued per IPUC Order No.
Effective - Odtober 1,2013
lssued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221 West ldaho Street, Boise, ldaho
ldaho Power Company First Revised Sheet No. 72-29
Cancels
LP.U.C. No. 29. Tariff No. 101 Oriqinal Sheet No. 72-29
Exhibit No.4
Case No. IPC-E-'12-27
M. Larkin, IPC
Page29 of72
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILIry GENERATION
(Continued)
IDAHO POWER COMPANY
UNIFORM INTERCONNECTION
AGREEMENT
(PURPA)
(Continued)
AGREEMENTS (Continued)
9. Notices.
9.1 General. Unless otherwise provided in this Agreement, any written notice,
demand, or request required or authorized in connection with this Agreement ("Notice") shall be
deemed properly given if delivered in person, delivered by recognized national currier service,
or sent by first class mail, postage prepaid, to the person specified below:
lf to the Seller:
Seller:
Attention
Address
City:State: Zip:
Phone:
lf to the Company:
Company
Attention:
Address:
City:State: Zip:Phone: Fax:
9.2
out below:
Billinq and Pavment. Billings and payments shall be sent to the addresses set
State: Zip:
Fax:
Zto:.
Seller:
Attention:
Address:
Phone:
City:
City:
Company:
Attention:
Address:
Phone:Fax:
State:
IDAHO
lssued per IPUC Order No.
Effective - October 1,2013
lssued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221 West ldaho Street, Boise, ldaho
ldaho Power Company
!.P.U.C. No.29. TariffNo. 101 OriqinalSheet No.72-30
Exhibit No. 4
Case No. IPC-E-12-27
M. Larkin, IPC
Page 30 of 72
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILITY GENERATION
(Continued)
IDAHO POWER COMPANY
UNIFORM INTERCONNECTION
AGREEMENT
(PURPA)
(Continued)
AGREEMENTS (Continued)
9.3 Desionated Operatinq Representative. The Parties may also designate
operating representatives to conduct the communications which may be necessary or
convenient for the administration of this Agreement. This person will also serve as the point of
contact with respect to operations and maintenance of the Pafi's facilities.
Seller's Operating Representative:
Seller:
Attention:
Add
City:State: Zip:_Phone:_Fax:
Company's Operating Representative:
Company:
Attention:
Address:
City:State: ZipPhone:_Fax:
9.5 Chanoes to the Notice lnformation. Either Pafi may change this information by
giving five Business Days written notice prior to the effective date of the change.
10. Siqnatures.
lN WITNESS WHEREOF, the Parties have caused this Agreement to be executed by their
respective duly authorized representatives.
For the Companv
Name:
Title:
Date:
For the Seller
Name:
Title:
Date:
IDAHO
lssued per IPUC Order No.
Effective - October 1,2013
lssued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221 West ldaho Street, Boise, ldaho
Idaho Power Company
|.P.U.C. No. 29. Tariff No. 101 Orioina! Sheet No. 72-31
Exhibit No.4
Case No. IPC-E-12-27
M. Larkin, IPC
Page 31 of 72
SCHEDULE 72
!NTERCONNECTIONS TO
NON-UTILITY GENERATION
(Continued)
IDAHO POWER COMPANY
UNIFORM !NTERCONNECTION
AGREEMENT
(PURPA)
(Continued)
Attachment 1
Description and Costs of the Generation Facilitv. lnterconnection Facilities and Meterino
Equipment
ln this attachment the Generation Facility and lnterconnection Facilities, including Special
Facilities and upgrades, are itemized and identified as being owned by the Seller or the Company. As
provided in Schedule 72, Pavment For lnterconnection Facilities, the Company wil! provide a best
estimate itemized cost of its lnterconnection Facilities, including Special Facilities, upgrades and
Metering Equipment.
Attachment 2
One-line Diaqram Depictinq the Small Generation Facilitv. lnterconnection Facilities. Meterino
Eouipment and Upqrades
IDAHO
lssued per IPUC Order No.
Effective - October 1:,2013
lssued by IDAHO POWER COMPANY -
Gregory W. Said, Vice President, Regulatory Affairs ,
1221 West ldaho Street, Boise, ldaho :
ldaho Power Company
I.P.U.C. No.29. TariffNo. 101 OrioinalSheet No.72-32
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTI LITY GENERATION
(Continued)
IDAHO POWER COMPANY
UNIFORM I NTERCONNECTION
AGREEMENT
(PURPA)
(Continued)
Attachment 3
Milestones
ln-Service Date:
Critical milestones and responsibility as agreed to by the Parties:
Milestone/Date
Exhibit No. 4
Case No. IPC-E-12-27
M. Larkin, IPC
Page 32 of 72
Responsible Party
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
(e)
(10)
Agreed to by:
For the Company Date
For the Seller Date
IDAHO
lssued per IPUC Order No.
Effective - October 1,2013
Issued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221 West ldaho Street, Boise, ldaho
ldaho Power Company
!.P.U.C. No. 29. Tariff No. 101 Oriqinal Sheet No. 72-33
Exhibit No.4
Case No. IPC-E-12-27
M. Larkin, IPC
Page 33 of 72
SCHEDULE 72
!NTERCONNECTIONS TO
NON-UTILITY GENERATION
(Continued)
IDAHO POWER COMPANY
UNIFORM INTERCONNECTION
AGREEMENT
(PURPA)
(Continued)
Attachment 4
Additional Operatinq Requirements for the Companv's Transmission Svstem and Affected
Svstems Needed to Suoport the Selle/s Needs
The Company shall also provide requirements that must be met by the Seller prior to initiating
parallel operation with the Company's Transmission System.
Attachment 5
Reactive Power Requirements
ldaho Power will determine the reactive power required to be supplied by the Company to the
Seller, based upon information provided by the Seller. The Company will speciff the equipment
required on the Company's system to meet the Facility's reactive power requirements. These
specifications wil! include but not be limited to equipment specifications, equipment location, Company-
provided equipment, Seller provided equipment, and all costs associated with the equipment, design
and installation of the Company-provided equipment. The equipment specifications and requirements
will become an integral part of this Agreement. The Company-owned equipment will be maintained bythe Company, with total cost of purchase, installation, operation, and maintenance, including
administrative cost to be reimbursed to the Company by the Seller. Payment of these costs will be in
accordance with ScheduleT2 and the total reactive power cost will be included in the calculation of the
Monthly Operation and Maintenance Charges specified in Schedule 72.
Attachment 6
Companv's Description of Uporades Required to lnteqrate the Generation Facilitv and Best
Estimate of Uporade Costs
As provided in Schedule 72 this Attachment describes Upgrades, including best work upgrades,
and provides an itemized best estimate of the cost of the Upgrades.
IDAHO
lssued per IPUC Order No.
Effective - October 1,2013
lssued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221 West ldaho Street, Boise, ldaho
LEGISLATIVE FORMAT
ldaho Power Company FirstSecond Revised Sheet No. 72-1
Cancels
I.P.U.C. No. 29. Tariff No. 101 OrieinalFirst Revised Sheet No. 72-1
SCHEDULE 72
INTERCONNECTIONS TO
NON.UTILIW GENEMTION
AVA!LABILITY
Service under this schedule is available throughout the Company's service area within the State
of ldaho to Sellers owning or operating Qualiffing Facilities that sign a Uniform lnterconnectionAgreementorGenerationFaci!itiesthatqualifffor.GenerationFacilitiesthatqua!iffforrenotrequiredtosignaUniform
lnterconnection Ag reement.
APPLICABILITY
Service under this schedule applies to the construction, operation, maintenance, Upgrade,
Relocation, or removal of transmission and/or distribution lines and equipment necessary to safely
interconnect a Selle/s Generation Facility to the Company's system.
DEFINITIONS
Additional Apolicant is a person or entity whose request for electrical connection requires the
Company to utilize existing lnterconnection Facilities which are subject to a Vested lnterest.
Comoanv is the ldaho Power Company.
Connec{ed Load is the combined input rating of the Customeds motors and other energy
consuming devices.
Construction Cost is the cost, as determined by the Company, of Upgrades, Relocation or
construction of Company fumished !nterconnection Facilities.
Disconnection Equipment is any device or combination of devices by which the Company can
manually and/or automatically intenupt the flow of energy from the Seller to the Company's system,
including enclosures or other equipment as may be required to ensure that only the Company will have
ao@ss to certiain of the devices.
First Enerov Date is the date when the Seller begins delivering energy to the Company's
system.
Generation Facilitv means equipment used to produce electric energy at a specific physical
location which meets the requirements to be a Qualiffing Facility or that qualifies for-SeheCuleS4Ne!
Meterinq Service.
Generator lnterconnection Process is the Company's Generation Facility interconnection
application, engineering review and construction process. The intent of the Generator lnterconnection
Process is to ensure a safe and reliable generation interconnection in compliance with all applicable
regulatory requirements, good utility practices and national safety standards.
IDAHO lssued by IDAHO POWER COMPANYlssuedperlPUCorder11g.3e574@,VicePresident,RegulatoryAffairsEffective-@ 1221 West ldaho Street, Boise, ldaho
Exhibit No. 4
Case No. IPC-E-12-27
M. Larkin, IPC
Page 34 of 72
ldaho Power Company +Eretsecond Revised Sheet No.72-2
Cancels
LP.U.C. No. 29. Tariff No. 101 OrieinalFirst Revised Sheet No. 72-2
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILITY GENERATION
(Continued)
DEFINITIONS (Continued)
lnterconnection Facilities are allfacilities which are reasonably required by good utility practices
and the Nationa! Electric Safety Code to interconnec{ and to allow the delivery of energy from the
Selle/s Generation Facility to the Company's system, including, but not limited to, Special Facilities,
Disconnection Equipment and Metering Equipment.
lnterconnection Point is the point where the Seller's conductors connect to the facilities owned
by the Company.
Meterino Eouipment is the Company owned equipment required to measure, record or
telemeter power flows between the Selle/s Generation Facility and the Company's system.
Net Meterino Feasibilitv Review is the Companv's standard enqineerino review of prooosed Net
Meterinq Svstems. This review is intended to ensure that the Comoanv's svstem is sufficientlv
equioped to incorporate proposed Net Meterinq Svstems in a manner that conforms with qood utilitv
practices and the National Electric Safetv Code.
Net Meterinq Service is the Companv's service which orovides for transfer of electric enerqv to
the Companv bv means of a net meterinq arranoement or its successor(s) as approved bv the
Commission. This optional service provides for Customers to install Generation Facilities to
interconnect to the Companv's svstem to offset all or a portion of their electrical usaoe. This service is
comprised of all customers takino service under Schedule 6, Schedule 8. or Schedule 84.
Net Meterino Svstem is a Customer-owned Generation Facilitv interconnected to the
Companv's svstem under the terms of Schedule 6. Schedule 8. or Schedule 84.
OATT is the Company's Federal Energy Regulatory Commission (FERC) approved Open
Access Transmission Tariff.
Protection Equipment is the circuit-interrupting device, protective relaying, and associated
instrument transformers.
PURPA means the Public Utility Regulatory Policies Act of 1978.
Qualifoinq Facilitv is a cogeneration facility or a small power production facility which meets the
PURPA criteria for qualification set forth in Subpart B of Part 292, Subchapter K, Chapter l, Title 18, of
the Code of Federal Regulations.
Relocation is a change in the location of existing Company-owned transmission and/or
distribution lines, poles or equipment.
Q^h^d"r^ o is the Cempany's serviee sehedule whieh prevides fer sales ef eleetrie energy te
Gemmissien"
IDAHO lssued by IDAHO POWER COMPANYlssuedperlPUCorderNo.30571@,VicePresident,Regu|atoryAffairs
Exhibit No. 4
Case No. IPC-E-12-27
M. Larkin, IPC
Page 35 of 72
Effective-@ 1221 West ldaho Street, Boise, ldaho
ldaho Power Company Fi+€[Seconll Revised Sheet No.72-2
Cancels
!.P.U.C. No.29. TariffNo. 101 edqinalFirst Revised Sheet No.72-2
Exhibit No.4
Case No. IPC-E-12-27
M. Larkin, IPC
Page 36 of 72
c^r^- is a non etil
o tr ' -"--'^'^" E^^r"''^^ are theee pertiens ef the lntereenneetien Faeilitiee previCed by the
S€lbr
a^ ^'^' '^ "'*'^^ sre adCitiene te er elteretbne ef tranemieeien end/er dHributien lines and
IDAHO lssued by IDAHO POWER COMPANYlssuedperlPUCorderNo.30'57+@,VicePresident,RegulatoryAffairsEffective-@ ' 1221 West ldaho Street, Boise, ldaho
ldaho Power Company FirstSecond Revised Sheet No. 72-3
Cancels
LP.U.C. No. 29. Tariff No. 101 OriqinalFirst Revised Sheet No. 72-3
Exhibit No. 4
Case No. IPC-E-'12-27
M. Larkin, IPC
Page37 of72
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILITY GENERAT!ON
(Continued)
DEFINITIONS (Continued)
Seller is a non-utl
interconnect a Gen . or a
Customer takino service under the Companv's net meterinq tariffs. Schedule 6. Schedule 8. or
Schedule 84j .
Seller-furnisneO f
Seller
Soeciat facititie
transformers. inclu
Generation faciliV
Transfer Cost is the cost, as determined by the Company, for acceptance by the Company of
Seller-Fumished Facilities.
Uporades are those improvements to the Company's existing system which are reasonably
required by good practices and the National Electric Safety Code to safely interconnect the Selle/s
Generation Facility. Such improvements include, but are not limited to, additiona! or larger conductors,
transformers, poles, and related equipment.
Vested lnterest is the claim for refund that a Seller or Additional Applicant holds in a specific
portion of Company-owned lnterconnection Facilities. The Vested lnterest expires 5 years from the
date the Company completes construction of its portion of the lnterconnection Facilities unless fully
refunded earlier. Vested lnterests de net apply te Sehedule 8l net metering prejeets,
SECTION 1: GENERAL INTERGONNECTION REQUIREMENTS
The followinq provisions applv to all Sellers requestino interconnection to the Companv's
system.
CONSTRUCTION AND O
At Setter-f urnisn
Ue in tutt comolian
aopticanb feOer imes.
The Seller shall:
t. SuOmit oroot to t
necessarv tor tne co ies
unOer tnis scneOu ies.
IDAHO lssued by IDAHO POWER COMPANY
@, Vice President, Regulatory Affairslssued per IPUC Order No. 30571Effective-@ 2013 1221 West ldaho Street, Boise, ldaho
ldaho Power Company Fir€tsecond Revised Sheet No. 72-4
Cancels
LP.U.C. No. 29. Tariff No. 101 erieinalFirst Revised Sheet No. 72-4
Exhibit No. 4
Case No. IPC-E-12-27
M. Larkin, IPC
Page 38 of72
SCHEDULE 72
INTERCONNECTIONS TO
NON.UTILITY GENEMTION
(Continued)
consrnucloru nNo o
Z. Submit tne Oesl ion
facilitv anO Setter
not Ue construed as con
retiaOititv ot tne C
insoect this eouio ion
S. Demonstrate to t
Seller-Fumished Fa
Ceneration facill
Oetiveries ot ener
+. ProviOe anO maint
Generation Facili
witn attaoolicaU
S. ProviOe anO maint
etectricalanO safefu
0. ProviOe a Za-nou
arrange for repairs a
to arranoe reoairs a
ananoements in aOv
Seller can obtain in
DISCONNECTION EOU
f)isnnnncr-Jinn Fnrrinment is reouired for all Seller Gencration Faeiliiies Thc f)iseanncciion
Eouioment shall be
anO tnterconnection
Disconnection Equipment for Net Meterino Svstems will be installed at
an etectrical locat
isolation of tne Se
and-se-ryrce.
The f)isr:nnneelinn Fouinment's oneratino deviee shall he'
1 Readilv aeeessible bv the Comoanv at all times
2 Clearlv marked "Generation Disconnect Switch" with oermanent 3/8 inch or laroer letlers
3 Phvsinallv installed al a localion within 1O fect of the lnlernnnneclinn Pnini nr evacl
oermanent instrud
Oisconnection eoul
IDAHO lssued by IDAHO POWER COMPANYlssuedperlPUCorderNo.3057t@,VicePresident,RegulatoryAffairsEffective-@ 1221 West ldaho Street, Boise, ldaho
ldaho Power Company FiretsCggld Revised Sheet No. 72-5
Cancels
l.P.U.C. No. 29. Tariff No. 101 erieinelFirst Revised Sheet No. 72-5
SCHEDULE 72
!NTERCONNECT]ONS TO
NON-UTILITY GENEMTION
(Continued)
OISCONNECTON EOU
Exhibit No. 4
Case No. IPC-E-12-27
M. Larkin, IPC
Page39 ot72
4 Of a desion manuallv onerated and lockable in the ooen oosition with a slandard
Gompanv-padlocK
5. For Net Meterinq Svstems under Schedule 6. Schedule 8. or Schedule 84. equioped
with a visual disconnect that enables the Comoanv to visuallv confirm that the Custome/s and
Companv's conductors are phvsicallv disconnected. This requires the abilitv to visuallv inspect the
actual conductors. Circuit breakers and/or switches do not satisfu this requirement if the conductors
are not visible.
Ooeration of Oisco
Setbfs operation
mav otherwise adverc
Comoanv mav ohvsic
operation of the di
aOequatetv Oiscon
svstem. nt sucn tim
Comoanv is resolve
The Comnanv will disconneet lhe Seller's Generation and lntereonneelion Facilities in the eveni
of anv planned or un
Oeneration anA I irs--no_prior
notice witl Ue orovl
tne time anO Ouratl
fne Comoanv witl ies_in
tne event tnat anv t
interconnection ot
ddinsuent
All expenses of dis
Seller
tn tne case of a ne+ ruet
necessarv. The disc
Ceneration facitl
the.Sellel Disconnection provisions specific to Customers takinq service under Schedule 6. Schedule
8. or Schedule 84 are described further in Section 2 of this tariff.
IDAHO lssued by IDAHO POWER COMPANY|ssuedperlPUCorderNo.3e57t@,VicePresident,RegulatoryAffairsEffective-@ 1221 West ldaho Street, Boise, ldaho r
ldaho Power Company Sir@ Revised Sheet No. 72-6
Cancels
|.P.U.C. No. 29. Tariff No. 10'1 eiqinalFirst Revised Sheet No. 72-6
Exhibit No. 4
Case No. IPC-E-12-27
M. Larkin, IPC
Page 40 of72
SCHEDULE 72
INTERCONNECTIONS TO
NON.UT!LITY GENERATION
(Continued)
DISCONNECTION EQUIPMENT (Continued)
fne Comoanv witl e*
Oeneration facill
personnel consist
interfere witn tne or ion-mav
Ue grounds for the Com
tnterconneAion fac
GENERAL REOUIREME
t. fne Comoanv witl
nencations on tfie
Z. fne Companv witl
equipment associat inq
tne existence of t ices.
g. The Seller will b
test resutts ot tne Se
equipment specificat
contormance witn aoo
OPERATIONS AND MAINTENANCE OBLIGAIONS AND EXPENSES
The Companv will operate and maintain Companv furnished lnterconnection Facilities as well as
anv Seller-Furnished Facilities transferred to the Companv.
SECTION 2: INTERCONNECTION OF NET METERING GENERATION FACILITIES
The followino section is applicable to all Customers takinq Net Meterinq Service under Schedule
6. Schedule 8. or Schedule 84. lnterconnection of Net Meterinq Svstems is available on a first-come,
first-served basis until the cumulative qeneration nameolate capacitv of Net Meterinq Svstems equals
5.8 meoawatts (MW). This cap is aoplicable to all Net Meterino Svstems installed in all retail
iurisdictions in which the Company provides electrical service.
APPLICATION PROCESS
Customers requestinq Net Meterinq Service are required to complete the followino application
process prior to interconnection:
1. Customers must submit a comoleted apolication form and $100 apolication fee to the
Companv. Applications are available on the Companv's website.
IDAHO lssued by IDAHO POWER COMPANYlssuedperlPUCorderNo.3057,|@,VicePresident,RegulatoryAffairsEffective-@ 1221 West ldaho Street, Boise, ldaho
ldaho Power Company Firtt{jecong] Revised Sheet No. 72-7
Cancels
!.P.U.C. No. 29. Taffi No. 101 OdqinalFirst Revised Sheet No. 72-7
Exhibit No. 4
Case No. IPC-E-'12-27
M. Larkin, IPC
Page 41 of72
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILITY GENERATION
(Continued)
APPLICATION PROCESS (Continued)
2. Upon receipt of a comoleted application and $100 fee. the Companv will provide the
Customer with written or electronic mail notification that the apolication has been received and all
necessarv information has been provided. Companv verification of a completed application constitutes
a reservation of capacifu under the Companv's aqqreoate svstem net meterinq cap described above in
the amount listed on the application.
3. The Companv will oerform within a reasonable timeframe the Net Meterino Feasibilifu
Review based on proiect information orovided in the application. The Net Meterino Feasibilitv Review
for Net Meterino Svstems determines the caoabilitv of the Comoanv's electrical svstem to incorporate
the proposed Net Meterino Svstem and determines if Uoqrades are necessarv.
a. lf the results of the Net Meterino Feasibilitv Review indicate satisfactorv svstem
capabilitv, the Companv will orovide the Customer with an official "Approval to
Proceed" notification via written or electronic mail.
b. lf the results of the Net Meterino Feasibilitv Review indicate that Upqrades are
necessarv to accommodate the orooosed proiect. the Comoanv will notifu the
Customer throuqh written or electronic mail of such Upqrades. Fundinq,
construction. installation. and maintenance of required Upqrades will be subiect
to the Companv's standard Rule H reoardino New Service Attachments and
Distribution Line lnstallations or Alterations.
4. Followinq receipt of "Approval to Proceed" the Customer is resoonsible for comoletino
the installation of the Net Meterinq Svstem and fulfillino all applicable Federal. State. and local
insoection requirements. Upon completion the Customer must orovide all forms of documentation
outlined in Section 1-1 above verifuinq that all Federal. state, and local requirements have been met.
Customers must also provide the Comoanv with final invoices for all installed comoonents of the
completed Net Meterino Svstem.
5. Once all reouired documentation has been submitted. the Companv will complete an on-
site inspection within ten (10) business davs, subiect to work constraints. Companv on-site inspections
will not be performed until the svstem has passed all applicable Federal. State. and local inspection
requirements as described above. The Companv on-site inspection includes the followinq:
a. Verification that actual installed components correspond to information provided
on the initial applicationb. Verification that the disconnect is functional and reconnection time is no less than
five (5) minutesc. Verification of the proximitv and visibilitv of the disconnect or a sion indicatinq the
location of the disconnectd. Photoqraphic documentation of the installatione. Postino of aporooriate Companv siqnaqe
IDAHO lssued by IDAHO POWER COMPANYlssuedperlPUCorderNo.3€6;4@,VicePresident,RegulatoryAffairsEffective-@ 1221 West ldaho Street, Boise, ldaho
ldaho Power Company Fi€tSCCqtd Revised Sheet No. 72-8
Cancels
!.P.U.C. No. 29. Tariff No. 101 eiqinelFirst Revised Sheet No. 72-8
Exhibit No.4
Case No. IPC-E-12-27
M. Larkin, IPC
Page 42 of72
SCHEDULE 72
INTERCONNECTIONS TO
NON.UTILITY GENEMTION
(Continued)
APPLICATION PROCESS (Continued)
f. Documentation of the meter number and svstem confiqurationo. Evaluation of inverters:
i. Svstems utilizinq verifiable UL 1741 or IEEE 1547 inverters will not be
subiect to additional testinqii. Svstems utilizino all inverters other than UL 1741 or IEEE 1547 will be
subiect to third-oartv testinq oerformed at the Customer's exoense
6. Successful completion of the Companv on-site inspection constitutes the conclusion of
the aoolication process. The Customer will be moved to the appropriate Net Meterino Service rate
schedule within three (3) business davs. subiect to work constraints. Upon completion of this process.
the Customer will receive written or electronic mail confirmation that the apolication orocess has been
successfullv comoleted.
APPLICATION EXPIRATION AND FORFEITURE OF CAPACITY RESERVATION
1. Customers that fail to complete the aoplication process within one vear of receipt of the
initial Net Meterino Feasibilitv Review forfeit their capacitv reservation described in Section 2-2 above.
Customers reouestinq connection or approval of expired applications are reouired to resubmit a
completed application form and $100 application fee. and are subiect to the full application process
described above.
RECERTIFICATION
1. The Companv will perform full recertification inspections of al! Net Meterinq Svstems
once everv three vears. Recertification inspections will be performed in the same manner as new Net
Meterino Svstem inspections described above. The Comoanv reserves the rioht to insoect anv Net
Meterinq Svstem at anv time.
NET METERING SYSTEM EXPANSIONS
1. Anv modifications to Net Meterino Svstems that impact the qeneration caoacifu of the
svstem or modifu the svstem in anv wav that mav impact the safetv or reliabilitv of the Companv's
electrical svstem are considered svstem expansions for the ourposes of this tariff.
2. Customers wishino to install svstem expansions must submit a new application and
$100 application fee. and complete the application orocess accordinq to the procedures required of a
new installation.
3. Svstems that have been expanded in the manner described above without qaininq prior
Comoanv aoproval are considered unauthorized installations subiect to the provisions of this Schedule
described below.
IDAHO lssued by IDAHO POWER COMPANY|ssuedperlPUCorderNo.3e5z@,VicePresident,RegulatoryAffairsEffective-@ 122'l West ldaho Street, Boise, ldaho
ldaho Power Company Fi+stsecond Revised Sheet No. 72-9
Cancels
I.P.U.C. No. 29. Tariff No. 101 €risinalFirst Revised Sheet No. 72-9
Exhibit No.4
Case No. IPC-E-12-27
M. Larkin, IPC
Page 43 of72
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILITY GENERATION
(Continued)
UNAUTHORIZED INSTALLATIONS AND EXPANSIONS
1. Net Meterino Svstems that have been interconnected to the Companv's svstem without
Companv aoproval are considered unauthorized installations that ieooardize the reliabilitv of ldaho
Power's svstem and the safefu of its emplovees. This includes, but is not limited to. newlv installed
svstems. and unapproved expansions of approved svstems. The orocess described herein provides
the Companv the abilitv to offer net meterino service in an efficient, safe. and reliable manner.
2. Unauthorized installations are subiect to immediate Companv insoection without notice.
a. lf proper disconnection equioment is present. the Companv will ooen and lock
the disconnect and provide written notice that the Net Meterinq Svstem has been
disconnected from the Companv's svstem. The Comoanv will contact the
Customer either in oerson or via teleohone and make the Customer aware of
necessary steps to brinq the svstem into compliance accordinq to the provisions
of this Schedule. Uoon comoletion of the full apolication process the svstem will
be reinstated.
b. lf proper disconnection equioment is not oresent. the Comoanv will evaluate
installed inverters:
i. lf the svstem utilizes UL 1741 or IEEE 1547 inverters. the Companv will
contact the Customer either in person or via telephone in addition to
written communication reoardino the unauthorized installation. This
communication will include the necessarv steps to brino the svstem into
compliance accordino to the followinq procedures:
1. Within fifteen (15) davs of notification. the Customer must submit
a completed net meterino application and $100 fee.
2. Within thirtv (30) davs of completion of the Net Meterinq Feasibilitv
Review. the Customer must complete the remainder of the
inspection requi rements described above.
3. Customers that do not wish to brino their svstems into compliance
with this schedule mav choose to disable their svstems.
Customers wishinq to disconnect their svstems must notifo the
Companv within thirtv (30) davs of the date of notification that their
svstem is unauthorized and out of compliance with Companv
reoulation.
4. Customers that fail to complete the aoolication process within the
allotted timeframe and/or do not disable their svstems within thirtv
(30) davs will be subiect to termination of electric service.
IDAHO lssued by IDAHO POWER COMPANYlssuedperlPUCorderNo.3057,|@'VicePresident,ReguIatoryAffairsEffective-@ 1221 West ldaho Street, Boise, ldaho
ldaho Ponrer Company girstSeconO Revised Sheet No. 72-10
Cancels
!.P.U.C. No. 29. Tariff No. 1O10r-ieinalFirst Revised Sheet No. 72-10
Exhibit No. 4
Case No. IPC-E-12-27
M. Larkin, IPC
Page 44 oi 72
SCHEDULE 72
INTERCONNECTIONS TO
NON-UT!LITY GENERATION
(Continued)
UNAUTHORIZED INSTALLATIONS AND EXPANSIONS (Continued)
ii. lf the svstem utilizes inverters other than UL 1741 or IEEE 1547. or if the
presence of UL 1741 or IEEE 1547 inverters cannot be verifled. the
Customer will be subiect to immediate termination of service without
notice.
3. Customers subiect to termination of service under this Schedule are provided two
ootions for restoration of service. Under both options Customers are resoonsible for reconnection costs
per the Companv's standard fees contained in Schedule 66.
a. Customers mav choose to disconnect Net Meterinq Svstems from service.
Customers choosinq to do so must receive confirmation from a State electrical
inspector that the Net Meterino Svstem is no lonoer operational and
interconnected to the Companv's svstem. The results of this inspection must be
provided to the Companv prior to restoration of service.
b. Customers can brinq the svstem into compliance with the provisions of this
schedule bv completino the full application orocess described above.
SECTION 3: INTERCONNECTION OF NON-NET METERING GENERATION FACILITIES
The fotlowinq section is applicable to all Sellers requestino interconnection of non-utilitv
oeneration not takino service under the Companv's net meterino tariffs. Schedule 6, Schedule 8. or
Schedule 84.
SPECIFIC PROJECT REQUIREMENTS
1. Generation Facilities Less than 1 MW Nameplate Ratino
The followino requirements are for Generation Facilities with nameplate ratinos of less than 1
MW.
a. The Companv shall procure. install, own and maintain Meterino Eouipment to
record enerqv deliveries to the Companv. This meterinq will be separate from
anv other meterinq of the Seller's load and mav be located on either side of the
lnterconnection Point. All acquisition. installation, maintenance. inspection, and
testino costs related to Meter Equipment installed to measure the Seller's enerov
deliveries to the Comoanv shall be borne bv the Seller.
b. The Seller is responsible for all costs incurred bv the Companv for the review.
evaluation and testinq of Seller suoplied desions and equipment reqardless as to
the outcome of the review or test results.
IDAHO lssued by IDAHO POWER COMPANYlssuedperlPUCorderNo.3057,|@,VicePresident,RegulatoryAffairsEffective-@ 1221 West ldaho Street, Boise, ldaho
ldaho Power Company F+r€tsecond Revised Sheet No. 72-11
Cancels
!.P.U.C. No.29. Tariff No. 101e+ieinalFirst Revised Sheet No.72-11
SCHEDULE 72
!NTERCONNECTIONS TO
NON-UT!LITY GENERATION
(Continued)
SPECIFIC PROJECT REQUIREMENTS (Continued)
Exhibit No.4
Case No. IPC-E-12-27
M. Larkin,lPC
Page 45 ot72
c. The Seller. upon completion of installation and orior to interconnection of the
Generation Facilitv to the Comoanv's svstem. will orovide the Companv with
certification from a professional enoineer licensed in the State of ldaho statino
that the Seller's Generation Facilitv and lnterconnection Facilities are in
compliance with IEEE Standard 1547 and all applicable electrical and safefu
codes to enable safe and reliable operation.
d. The Seller will obtain and orovide to the Companv an annual certification and
testino bv a professional enqineer licensed in the State of ldaho. certifuinq the
onooinq comoliance with IEEE Standard 1547 and all applicable electrical and
safetv codes and that the Seller-Furnished Facilities successfullv meet aoolicable
testino requirements and standards. ln the event the Comoanv does not receive
and accept the annual certification within thirtv (30) davs of the annual
anniversarv date of the aqreement. the proiect will be disconnected from the
Companv's svstem until such time as the certification is completed and accepted
bv the Companv.
e. ln addition to the requirements specified in sections a throuoh d. Generation
Facilities that are qreater than 100 kW and less than 1 MW total nameplate ratinq
require the followinq:
i. lf the Companv owns the transformer interconnectino the Selleis
Generation Facilitv. then the Seller mav own and maintain a secondarv
voltaqe disconnection device that can be operated bv both the Seller and
the Companv.
ii. lf the Seller owns the transformer interconnectinq the Seller's Generation
Facilitv. then the Companv will own. ooerate. and maintain a primarv
voltaqe disconnection device at the Selle/s expense.
iii. The Companv will construct. own. operate. and maintain all protective
relays and anv associated equipment required to operate the orotective
relavs.
2. Generation Facilities Greater Than 1 MW Nameolate Ratinq
The Comoanv will own, maintain, and ooerate all lnterconnection Facilities and
Disconnection Equipment at the Seller's expense.
IDAHO lssued by IDAHO POWER COMPANYlssuedperlPUCorderNo.3057t@,VicePresident,RegulatoryAffairsEffeotive-@ | 1221West ldaho Street, Boise, ldaho
ldaho Power Company Fift*Semnd Revised Sheet No.72-12
Cancels
!.P.U.C. No. 29. Taffi No. 1O1€dqinalFirst Revised Sheet No. 72-12
Exhibit No. 4
Case No. IPC-E-12-27
M. Larkin,lPC
Page 46 of72
SCHEDULE 72
INTERCONNECTIONS TO
NON.UTILITY GENEMTION
(Continued)
GENERATOR INTERCONNECTION PROCESS
1. Seller shall pay the actual costs of all required interconnection studies. Any difference
between the deposit (if required) and the actual cost of the study shall be paid by or refunded to Seller,
as appropriate. lf, during the course of preparing a study, the Company incurs costs in excess of the
deposit amount, the Company may require that the deposit amount be replenished in an amount equa!
to the estimated costs for completion of the study. lf a deposit amount sufficient to pay for completion
of the study is not maintained, the Company may suspend work on the study.
2. Unless modified by the provisions of this schedule, the FERGapproved Large Generator
lnterconnection Procedures and Small Generator !nterconnection Procedures posted on the
Company's website will apply to the Generator lnterconnection Process.
3. The deposit amounts for Generation Facilities up to 30 MW are specified in this
schedule. Deposit amounts for Generation Facilities 30 MW and larger are oovered by the FERG
approved Large Generator lnterconnection Procedures posted on the Company's website.
4. Apolication. The Seller will submit a completed interconnection application in the form
posted on the Company's website. The application form includes a general description of the
Generation Facility and its location. The application includes payment of an application fee to be
applied against costs the Company incurs to perform the Feasibility Study described below. The
amount of the application fee is $1,000 for a Generation Facilig up to 30 MW.
5. Studv Aoreements. lf the Seller desires to proceed beyond the Application stage, the
Seller wi!! be offered a series of study agreements. The individual study agreements establish the time
to perform the study and the deposit the Seller is to provide prior to commencement of the study. The
deposit amount may be waived if a Seller meets the Company's credit worthiness standards for
unsecured credit specified in Attachment L to the Company's OATT. The studies e,onsist of:
a. The Feasibilitv Studv: The Feasibility Study includes a general review of project
impact, e.g. exceeding equipment capabilities and violation of electrical
performance requirements. The Feasibility Study Agreement states that no
deposit is required, since the deposit is covered by the application fee.
b. The Svstem lmoact Studv: The System lmpact Study provides a detailed
assessment of the distribution and/or transmission system adequacy to
accommodate the Generation Facility through the evaluation of equipment
capabilities and electrical performance requirements. This step may not be
necessary for some projects depending on the size and location of the project.
The System lmpact Study Agreement includes a deposit of $2,000 for a
distribution system impact study or a $'10,000 deposit for a transmission system
impact study.
IDAHO lssued by IDAHO POWER COMPANYlssuedperlPUCorderNo.30674@,VicePresident,RegulatoryAffairsEffective-@ 1221Wesl ldaho Street, Boise, ldaho
ldaho Power Company @] Revised Sheet No. 72-13
Cancels
!.P.U.C. No. 29. Tariff No. l0lerieinalFirst Revised Sheet No. 72-13
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILITY GENEMTION
(Continued)
GENERATOR INTERCONNECTION PROCESS (Continued)
c. The Facilitv Studv: The Facility Study includes the engineering to determine the
design specifications of the project. The Facility Study Agreement includes a
deposit of 5% of the total project costs that were determined in the System
lmpact Study Report ('SISR) or the Feasibility Study Report if a SISR is not
required, capped at $30,000.
At the end of each stage of the three.step study process, the Company wil! provide the Seller
with an increasingly more refined and detailed report that, among other things, will present a list of
required lnterconnection Facilities and a non-binding, good faith estimate of Selle/s cost responsibility
for the lnterconnection Facilities. !f long{ead time equipment items need to be ordered to meet Selleds
construction schedule, the Company will request advance funding by the Seller to cover these
equipment costs.
6. Generator lnterconnection Aoreement. The Generator lnterconnection Agreement
("GlA"), will be offered to Seller following completion of the Facility Study. The GIA will utilize the
Uniform lnterconnection Agreement template included in this schedule.
COST OF INTERCONNECTION FACILIT!ES
Al! lnterconnection Facilities provided under this schedule will be valued at the Company's
Construction Cost and/or the Transfer Cost for vesting purposes as well as for operation and
maintenance payment obligations.
PAYMENT FOR INTERCONNECTION FACILITIES
Unless specifically agreed othenrvise by written agreement between the Seller and the
Company, the Seller wil! pay al! costs of interconnecting a Generation Facility to the Company's
system. Costs of intereonnection include the costs of furnishing and constructing required
lnterconnection Facilities, including Upgrades.
pnvucur ren lrurcneo
Each request for interconnection will go through the Generator lnterconnection Process.
Throughout the Generator lnterconnection Process, the Company wil! periodically bill the Seller for
costs incuned or obligated. Failure to pay an invoice within the time specified in the invoice will result
in suspension of work on the interconnection and if the suspension of work extends beyond 30 calendar
days, the Generation Facility will be removed from the interconnection queue. Seller can end the
Generator lnterconnection Process at any time. lf Seller decides to end the Generator lnterconnection
Process prior to completion, the Company will either refund any monies held for security that have not
been spent or obligated, or issue an invoice to Seller for c,osts incurred prior to cancellation.
IDAHO lssued by IDAHO POWER COMPANYlssuedperlPUCorderNo.30574@,VicePresident,RegulatoryAffairs
Exhibit No. 4
Case No. IPC-E-12-27
M. Larkin, IPC
Page47 of72
Effective 1221 West ldaho Street, Boise, ldaho
ldaho Polrcr Company giretSeconU Revised Sheet No. 72-14
Cancels
I.P.U.C. No. 29. Tarifi No. 1O1e+iqinalFirst Revised Sheet No. 72-14
SCHEDULE 72
INTERCONNECTIONS TO
NON.UTILITY GENERATION
(Continued)
SECURITY FOR PAYMENT OF INTERCONNECTION COSTS
Sellers will provide adequate security for payment of the costs of the Generator lnterconnection
Process. Adequate security for Generation Facilities larger than 30 MW can be provided in accordance
with the Large Generator lnterconnection Procedures contained in Attiachment M to the Company's
OATT. Adequate security for Generation Facilities up to 30 MW can be provided in one of the following
ways
1. Sellers that meet the Company's credit worthiness standards for unsecured credit are
not required to provide additional security. The Company's minimum credit standards for unsecured
credit are described in Attachment L to the OATT.
2. Sellers that do not meet the credit worthiness standards for unsecured credit will be
notified of the reason for the determination and shall be given the option to provide altemative security
acceptable to ldaho Power. ln Iieu of providing a cash deposit, Seller may establish an escrow
ac@unt, provide a letter of credit or provide guarantee of payment by another person or entity which
meets the credit worthiness standards for unsecured credit. Anangements for alternative security must
be acceptable to ldaho Power.
AllSeller Fgmi€he
be in full eemplienee with all geeC utility preetiees; Natienel Eleetrie Safety €eCe; end ell ether
ime*
#i
iee
+en
a' Pemenetrete te the
IDAHO lssued by IDAHO POWER COMPANYlssuedperlPUCorderNo.3057,|@,VicePresident,RegulatoryAffairs
Exhibit No.4
Case No. IPC-E-12-27
M. Larkin,IPC
Page 48 of72
Effective-@ 1221 West ldaho Street, Boise, ;ldaho
Idaho Pouer Company g*4Seegd Revised Sheet No. 72-15
Cancels
I.P.U.C. No. 29. Taffi No. lOledqinelFirst Revised Sheet No. 72-15
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILITY GENERATION
(Continued)
te anange repairs anC inepeetiene dsring nermal bueinees hesrs anC te netiff the Seller ef sueh
ie*
badcndee*iee'
ime*
L ef a Cesign rnaneally eperateC enC leekable in the epen pesitien with a stanCerCeemPeffi
^-^-^*' - ^' h'^^ -- '' - --"'^- -'' ll in the rea€€neble epinien ef the Cempanyr the
SeUefs eperetien
Gernpany ma" physieally diseenneet the Seller'e Ceneratien FaeiLty er lntereenneeH€n Faeilitiee by
IDAHO lssued by IDAHO POWER COMPANYlssuedperlPUCorderNo.3057,|@,VicePresident,RegulatoryAffairs
Exhibit No.4
Case No. IPC-E-'12-27
M. Larkin, IPC
Page 49 ot72
Effective-@ 1221 West ldaho Street, Boise, ldaho
ldaho Porer Company firsfSeconcl Revised Sheet No. 72-16
Cancels
!.P.U.C. No. 29. Tariff No. l0leds.inalFirst Revised Sheet No. 72-16
Exhibit No. 4
Case No. IPC-E-12-27
M. Larkin, IPC
Page 5O of 72
SCHEDULE 72
INTERCONNECTIONS TO
NON.UTILIW GENEMTION
(Continued)
The €empeny will Ciseenneet the Selle/e Generetien enC lntereenneetien Feeilities in the event
The €empeny vuill Ciseenneet the Seller's Generetien Feeility enC lntereemeetien Faeilities in
d€lif,qt €rS
S€lbfr
The Cempeny will esteblieh the settinge ef Preteetien Equipmer* te Ciseemeet the Seller'e
tee
i
1, The eempany will censtrHetr ewnr eperate €nC maintain all equipmenti Upgradee anC
3, The Gempany will elearly marlr the Metering Equipmcnt anC any other €empany
e
ieee"
ien'
IDAHO lssued by IDAHO POWER COMPANYlssuedperlPUCorderNo.3057+@,VicePresident,RegulatoryAffairsEffective-@ 1221 West ldaho S,treet, Boise, ldaho
ldaho Porer Company gir@ Revised Sheet No.72-17
Cancels
I.P.U.C. No. 29. Tariff No. l0ledqinalFirst Revised Sheet No. 72-17
SCHEDULE 72
INTERCONNECTIONS TO
NON.UTILIW GENEMTION
(Continued)
Seller Generatien Faeilities that qualiff bpnet metering under Sehedule I I wi!! eubmit te
that the design and eguipment in the Generatien Faeility and Seller Furnished Faeilities (1)
eemply with the lnstitute ef Eleetrieal and Eleetrenie Engineers (IEEE) Standard 1517 and all
ether standards ef thie sehedule and anplieable eleetrie and building eedes and (2) will eperate
te safely deliver Energy te the lntereenneetien Peint, The Seller ehall previde the ereCentials
ee*if,eatie+
b, Periedie re eertifieatien:
ir o, i^^+6 r^' ^F rh^h ^E r'r^r; The seller will ebtain an annual oertifieatien
frem an independent qualified party lieensed in the State ef ldahe' eertiffing the
ee*ineatlen, n eepy ot t
enU tne eertineatio
ien
eertitleatienie eempl
ii: p" ia^+6 ^r r.r^, ^h.r -h^r^r: The abeve deseribed eeltafieatien will be
@
speetne pngueer n
will previde eempany with a written deseriptien ef the prepesed ehange, The Cempany
will expeditieusly review the prepesal and autherize Seller te preeeed subjeet te final
i
ime
The fellewing reqcirernente are fer Generatien Faeilities with nameplate ratings ef lees than 1
MW' net ineluding ne metering faeilities utilizing SeheCule 81,
IDAHO lssued by IDAHO POWER COMPANYlssuedperlPUCorderNo.305zt@,VicePresident,RegulatoryAffairs
Exhibit No. 4
Case No. IPC-E-12-27
M. Larkin, IPC
Page 51 of72
Effective-@ '1221 West ldaho Street, Boise, ldaho
Idaho Power Company
|.P.U.C. No. 29. Tarifi No. lOledqinalFirst Revised Sheet No. 72-18
SCHEDULE 72
INTERCONNECTIONS TO
NON-UT!LITY GENERATION
(Continued)
evaluatien anC testing ef Seller supplied Cesigns and equlpment regardless as te the euteeme
ef the review er test results,
e/s Generatien Faeility
ie*
C, The Seller will ebtain and previde te the Cempany an annual eertifieatien and
ing
eemplianee with IEEE Standard 15 17 and all applieable eledrioal and safety cedes and that the
Seller Furnished Faeilities sueeessfully meet aBplieable testing requirements and standarde, ln
the annual anniversary date ef the agreement; the prejeet will be dieeenneeted frem the
eempaqr
ien
Faeilities that are greater than 100 kW and lese than 1 MW tetal narneBlate rating require the
ruUeutin+
spcelfle pngueer n
i- ffi the eempany o intereenneeting t
dieeenneetien deviee that ean be eperated by beth the Seller and the Gempany,
ii, lf the Seller ewns the transfermer inter€enneeting the Seller's Generatien
iii, The Cempany will eenstruet; ewn; eBerate and maintain all preteetive
IDAHO lssued by IDAHO POWER COMPANYlssuedperlPUCorderNo.305Z1@,VicePresident,RegulatoryAffairs
Fi€tsecond Revised Sheet No.72-18
Cancels
Exhibit No. 4
Case No. IPC-E-12-27
M. Larkin, IPC
Page 52 ot72
Effective-@ 1221 West ldaho Street, Boise, ldaho
ldaho Porcr Company SirstSgcond Revised Sheet No. 72-19
Cancels
!.P.U.C. No. 29. Tariff No. lOledqinalFirst Revised Sheet No. 72-19
Exhibit No. 4
Case No. IPC-E-12-27
M. Larkin, IPC
Page 53 of 72
SCHEDULE 72
lNTERCONNECTIONS TO
NON.UTILITY GENEMTION
(Continued)
The Cempany will ewn' maintain and eperate al! lntereennectien Faeilities and Dieeenneetien
TMNSFER OF INTERCONNECTION FACILITIES
Transfer of Interconnection Facilities is available only for Generation Facilities with nameplate
ratings greaterthan 100 kW.
1. Transfer at First Enerov Date. lf the Seller desires to transfer and the Company desires
to accept any Seller-Fumished Facilities at the First Energy Date, the following will apply:
a. Prior to the beginning of construction, the Seller shall cause the contractor that is
constructing the Seller-Furnished Facilities to provide the Company with a
certificate naming the Company as an additional insured in the amount of not
less than $1,000,000 under the contractor's general liability policy.
b. The Company will provide the Selle/s contractor with construction and material
specifications and will have final approval of the design of the Seller-Furnished
Facilities.
During construction and upon completion, the Company wil! inspect the Seller-
Furnished Facilities to be transfened to the Company. The cost of such
inspection will be borne by the Seller.
rnnrusren ee trurenc
d. lf the Seller-Fumished Facilities meet the Company's design, material and
construction specifications, are free from defects in materials and workmanship,
and the Seller has provided the Company with acceptable easements, bills of
sale and assurance against labor or materials liens, the Company will accept
ownership effective as of the First Energy Date. ln the bill of sale, the Seller will
warrant to the Company that the Seller-Furnished Facilities are free of any Iiens
or encumbrances and will be free from any defects in materials and workmanship
for a period of one year from the First Energy Date.
2. Subseouent Transfer. ll after the First Energy Date, the Seller desires to transfer and
the Company desires to accept any Seller-Fumished Facilities, the following will apply:
a. The Company will inspect the facilities proposed for sale to determine if they
meet the Company's design, material and construction specifications.
IDAHO lssued by IDAHO POWER COMPANYlssuedperlPUcorderNo.30574@,VicePresident,RegulatoryAffairsEffective-@ 1221 West ldaho Street, Boise, ldaho
ldaho Power Company eir@ Revised Sheet No. 72-20
Cancels
l.P.U.C. No. 29. Tariff No. l0ledqinalFirst Revised Sheet No. 72-20
Exhibit No. 4
Case No. IPC-E-12-27
M. Larkin, IPC
Page 54 ol72
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILITY GENERATION
(Continued)
TRANSFER OF INTERCONNECTION FACILITIES (Continued)
The Company will determine the Transfer Cost of such facilities. The Transfer
Cost will be equal to the depreciated Construction Cost the Company would have
incurred if it had originally constructed the facilities plus the cost, if any, of
bringing the facilities into compliance with the Company's design, material and
construction specifications. Depreciation of the facilities proposed for transfer will
be determined on the same basis as the Company depreciates its own facilities
in accordance with the appropriate FERC account numbers for the type and size
of line or equipment involved. The time period used for the calculation of the
depreciated transfer cost will extend from the First Energy Date until the agreed
upon transfer date. The Transfer Cost will be paid to the Company in cash at the
time of transfer. At the same time, the Company will pay the Seller in cash an
amount equalto the depreciated Construction Cost.
As a condition of the Company's acceptance, the Seller will provide the Company
with acceptable easements, bills of sale and acceptrable assurance against labor
and material liens. The bill of sale will include a wananty that the transferred
facilities are free of al! liens and encumbrances and wil! be free from any defects
in materials and workmanship for a period of one year from the date of transfer.
Effective as of the date of the transfer, the Company will operate and maintain
the transfened facilities.
VESTED INTEREST
A Selle/s eligibility for a Vested lnterest refund wil! exist for 5 years afrer the date the Company
completes construction of its portion of the lnterconnection Facilities.
1. The Company will provide a refund payment to each Seller holding a Vested lnterest in
Company-owned lnterconnection Facilities when an Additional Applicant shares use of those
I ntercon nection Facilities.
2. The refund payment will be based on the following formula:
b.
c.
d.
Linear
Refund = Footage
Ratio
Connectedx Load/Peak Generation
Ratio
Originalx lnterconnection
Cost
a. The Linear Footage Ratio is the length of jointly used Special Facilities divided by
the length of the vested Special Facilities.
IDAHO lssued by IDAHO POWER COMPANYlssuedper!PUCorderNo.30€7+@,VicePresident,RegulatoryAffairsEffective-@ 1221 West ldaho Street, Boise, Idaho
ldaho Power Company Fir*Second Revised Sheet No.72-21
Cancels
!.P.U.C. No. 29. Tariff No. 101e+iqinalFirst Revised Sheet No. 72-21
Exhibit No. 4
Case No. IPC-E-12-27
M. Larkin, IPC
Page 55 of 72
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILITY GENEMTION
(Continued)
VESTED INTEREST (Continued)
b. The Connected Load/Peak Generation Ratio is the Connected Load or Peak
Generation of the Additiona! Applicant divided by the sum of the Connected Load
or Peak Generation of the Additional Applicant and all other Connected Loads
and/or Peak Generation on the Special Facilities.
c. The Original lnterconnec{ion Cost is the sum of the Company's Construction Cost
and any Transfer Costs for the lnterconnection Facilities to which the Additional
Applicant intends to connect and share usage.
3. The Additional Applicant will pay the Company the amount of the Vested lnterest
refund(s). AdditionalApplicants making Vested lnterest payments are in tum eligible to receive refunds
within the 5 year limit described above.
4. Vested lnterest refunds will not exceed 100 percent of the refundable portion of any
party's cash payment to the Company.
5. Vested Interest refund payments may be waived by notiffing the Company in writing.
OPERATION AND MAINTENANCE OBLIGATIONS AND EXPENSES
The Company wil! operate and maintain Company fumished lnterconnection Facilities as wellas
any Seller-Furnished Facilities transfened to the Company. For all projects not interconnecting as a
Schedule 84 customer, the Seller will pay the Company a monthly operation and maintenanoe charge
equal to a percentage of the Construction Cost and Transfer Cost paid by the Seller. The percentage
will change annually on the anniversary of the First Energy Date in accordance with the following table:
MONTHLY OPERATION AND MAINTENANCE CHARGES
IDAHO lssued by IDAHO POWER COMPANYlssuedperlPUCorderNo.3057,|@,VicePresident,RegulatoryAfiairs
138 kVand 161 kV
Year 1 2 3 4 5 6 7 I 9 10 11 12
O&M Charge 0.26%0.27o/o 0.28o/o 0.29o/o 0.30%0.320h 0.33%0.35%0.36%0.380/6 0.10o/o 0.41016
Year 13 14 15 16 17 18 19 20 21 22 23 24
O&M Charge O.13o/o o.150h 0.17o/o 0.,19%o.52%0.540/6 0.56%0.59%0.620/o o.6/.oa 0.6706 o.700h
Year 25 26 27 28 29 30 31 32 33 u 35
O&M Charge 0.73o/o 0.7704 0.80%O.81o/n o.870h 0.91%0.96%1.00%1.U%r.09%1.11o/o
Effective-@ 1221West ldaho Street, Boise, ldaho
Below 138 kV
Year 1 2 3 4 5 o 7 I I 10 11 12
O&M Charge 0.17%0.4906 o.52%0.54%0.56%0.590[0.61%0.640/6 o.a70a 0.70%0.73%0.770/o
Year 13 14 15 16 17 18 19 20 21 22 23 24
O&M Charge 0.E0%o.uoa o.87%0.91%0.9s%1.000r t.o4%1.090/6 1-11o/a 1.19%1.21%1.30%
Year 25 26 27 28 29 30 31 32 33 u 35
O&M Charoe 1.36%1.12%1.18%1.55%1.62%1.6S%1.77%1.85%1.S3%2.O2%2.',t1%
ldaho Power Company eimQeconO Revised Sheet No.72-22
Cancels
!.P.U.C. No. 29. Tarifi No. 1O1€dqinalFirst Revised Sheet No. 72-22
Exhibit No.4
Case No. IPC-E-12-27
M. Larkin, IPC
Page 56 of 72
SCHEDULE 72
INTERCONNECTIONS TO
NON.UTILIW GENERATION
(Continued)
OPERATION AND MAINTENANCE OBLIGATIONS AND EXPENSES (Continued)
MONTHLY OPERATING AND MAINTENANCE CHARGES
\Mtere a Selle/s interconnection will utilize lnterconnection Facilities provided under a prior
agreement(s), the term of wtrich was shorter than 35 years, the operation and maintenance charge for
the Selle/s interconnection will be computed to include the expired term of the prior agreement(s).
The cost upon which an individual Selle/s operation and maintenance charge is based will be
reduced by subsequent Vested lnterest refunds. Additional Applicants who are Sellers will pay the
monthly operation and maintenance charge on the amount they paid as an Additional Applicant.
Seller-Furnished Facilities not transferred to the Company will be operated and maintained by
the Seller at the Selle/s sole risk and expense.
IDAHO lssued by IDAHO POWER COMPANYlssuedperlPUCorderNo.3057,|@,VicePresident,RegulatoryAffairsEffective-@ 1221 West ldaho Street, Boise, ldaho i
ldaho Power Company gir@ Revised Sheet No.72-23
Cancels
!.P.U.C. No. 29. Taffi No. 10l€rieinalFirst Revised Sheet No. 72-23
Exhibit No.4
Case No. IPC-E-12-27
M. Larkin, IPC
Page 57 of72
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILITY GENERATION
(Continued)
IDAHO POWER COMPANY
UN IFORM INTERCONNECTION
AGREEMENT
(PURPA)
This lnterconnection Agreement ("Agreement") is effective as of the _ day of _,2O--, between hereinafrer called "Seller,' and ldaho Power
Company, hereinafier called'Company."
RECITALS
A. Seller will own or operate a Generation Facility that qualifies for service under ldaho
Power's Commission-approved Schedule 72 and any successor schedule.
B. The Generation Facility covered by this Agreement is more particularly described in
Attachment 1.
AGREEMENTS
1. Capitalized terms used herein shall have the same meanings as defined in Schedule 72
or in the body of this Agreement.
2. This Agreement and Schedule 72 provide the rates, charges, terms and conditions
under which the Selle/s Generation Facility will interconnect with, and operate in parallel with, the
Company's transmission/distribution system. Terms defined in Schedule 72will have the same defined
meaning in this Agreement. lf there is any conflict between the terms of this Agreement and Schedule
72, Schedule 72 shall prevail.
3. This Agreement is not an agreement to purchase Selle/s power. Purchase of Selle/s
power and other services that Seller may require will be covered under separate agreements. Nothing
in this Agreement is intended to affect any other agreement between the Company and Seller.
4. Attached to this Agreement and included by reference are the following:
Attachment 1 - Description and Costs of the Generation Facility, lnterconnection
Facilities, and Metering Equipment.
Attachment 2 - One.line Diagram Depicting the Generation Facility, lnterconnection
Facilities, Metering Equipment and Upgrades.
Attachment 3 - Milestones For lnterconnecting the Generation Facility.
IDAHO lssued by IDAHO POWER COMPANY!ssuedper!PUCorderNo.3057,|@,VicePresident,RegulatoryAffairsEffective-@ 1221 West ldaho Street, Boise, ldaho
ldaho Porer Company Fimtsecond Revised Sheet No.72-24
Cancels
|.P.U.C. No. 29. Tarifi No. 101edqi+alFirst Revised Sheet No. 72-24
Exhibit No. 4
Case No. IPC-E-12-27
M. Larkin, IPC
Page 58 of 72
SCHEDULE 72
!NTERCONNECTIONS TO
NON-UTILITY GENERATION
(Continued)
IDAHO POWER COMPANY
UNIFORM INTERCONNECTION
AGREEMENT
(PURPA)
(Continued)
AGREEMENTS (Continued)
Attachment 4 - Additional Operating Requirements for the Company's Transmission
System Needed to Support the Selle/s Generation Facility.
Attachment 5 - Reactive Power.
Attachment 6 - Description of Upgrades required to integrate the Generation Facility and
Best Estimate of Upgrade Costs.
5. Effective Date. Term. Termination and Disconnection.
5.1 Term of Aoreement. Unless terminated earlier in accordance with the provisions
of this Agreement, this Agreement shall become effective on the date specified above and
remain effective as long as Selle/s Generation Facility is eligible for service under Schedule 72.
5.2 Termination.
5.2.1 Seller may voluntarily terminate this Agreement upon expiration or
termination of an agreement to sell power to the Company.
5.2.2 After a Default, either Party may terminate this Agreement pursuant to
Section 6.5.
5.2.3 Upon termination or expiration of this Agreement, the Selle/s Generation
Facility will be disconnected from the Company's transmission/distribution system. The
termination or expiration of this Agreement shal! not relieve either Party of its liabilities
and obligations, owed or continuing at the time of the termination. The provisions of this
Section shall suruive termination or expiration of this Agreement.
IDAHO lssued by IDAHO POWER COMPANYlssuedper!PUCorderNo.3057,|@,VicePresident,RegulatoryAffairsEffective-@ 1221 West ldaho Street, Boise, ldaho
ldaho Power Company fireeSeconclRevised Sheet No. 72-25
Cancels
l.P.U.C. No. 29. Tariff No. 101€riqinalFirst Revised Sheet No. 72-25
Exhibit No.4
Case No. IPC-E-12-27
M. Larkin, IPC
Page 59 of 72
SCHEDULE 72
!NTERCONNECTIONS TO
NON.UT! LITY GENERATION
(Continued)
IDAHO POWER COMPANY
UNIFORM INTERCONNECTION
AGREEMENT
(PURPA)
(Continued)
AGREEM ENTS (Continued)
5.3 Temoorarv Disconnection. Temporary disconnection shall continue only for so
long as reasonably necessary under "Good Utility Practice." Good Utility Practice means any of
the practices, methods and acts engaged in or approved by a significant portion of the electric
industry during the relevant time period, or any of the practices, methods and acts which, in the
exercise of reasonable judgment in light of the facts known at the time the decision was made,
could have been expected to accomplish the desired result at a reasonable cost consistent with
good business practices, reliability, safety and expedition. Good Utility Practice is not intended
to be limited to the optimum practice, method, or act to the exclusion of al! others, but rather to
be acceptable practices, methods, or acts generally accepted in the region. Good Utility
Practice includes compliance with WECC or NERC requirements. Payment of lost revenue
resulting from temporary disconnection shall be governed by the power purchase agreement.
5.3.1 Emeroencv Conditions. "Emergency Condition" means a condition or
situation: (1) that in the judgment of the Pafi making the claim is imminently likely to
endanger life or property; or (2) that, in the case of the Company, is imminently likely (as
determined in a non-discriminatory manner) to cause a material adverse effect on the
security of, or damage to the Company's transmission/distribution system, the
Company's lnterconnection Facilities or the equipment of the Company's customers; or
(3) that, in the case of the Seller, is imminently likely (as determined in a non-
discriminatory manner) to cause a material adverse effect on the reliability and security
of, or damage to, the Generation Facility or the Selle/s lnterconnection Facilities. Under
Emergency Conditions, either the Company or the Seller may immediately suspend
interconnection service and temporarily disconnect the Generation Facility. The
Company shal! notiff the Seller promptly when it becomes aware of an Emergency
Condition that may reasonably be expected to affect the Selle/s operation of the
Generation Facility. The Seller shal! notiff the Company promptly when it becomes
aware of an Emergenry Condition that may reasonably be expected to affect the
Company's equipment or service to the Company's customers. To the extent
information is known, the notification shall describe the Emergency Condition, the extent
of the damage or deficiency, the expected effect on the operation of both Parties'
facilities and operations, its anticipated duration, and the necessary corrective action.
IDAHO lssued by IDAHO POWER COMPANYlssuedperlPUCorderNo.30571@,VicePresident,RegulatoryAffairsEffective-@ 1221 West ldaho Street, Boiso, ldaho
ldaho Porer Company firstSeconclRevised Sheet No. 72-26
Cancels
!.P.U.C. No. 29. Tariff No. lOlerisinalFirst Revised Sheet No. 72-26
SCHEDULE 72
INTERCONNECTIONS TO
NON.UTILIW GENEMTION
(Continued)
IDAHO POWER COMPANY
UNIFORM INTERCONNECTION
AGREEMENT
(PURPA)
(Continued)
AGREEMENTS (Continued)
Exhibit No.4
Case No. IPC-E-12-27
M. Larkin, IPC
Page60 of72
5.3.2 Routine Maintenance. Construction. and Reoair. The Company may
interrupt interconnection service or curtail the output of the Sellefs Generation Facilityand temporarily disconnect the Generation Facility from the Company's
transmission/distribution system when necessary for routine maintenance, construction,
and repairs on the Company's transmission/distribution system. The Company will
make a reasonable attempt to contact the Seller prior to exercising its rights to interupt
interconnection or curtai! deliveries from the Selle/s Facility. Seller understands that in
the case of emergency circumstances, rea! time operations of the electrical system,
and/or unplanned events, the Company may not be able to provide notice to the Seller
prior to intenuption, curtailment or reduction of electrical energy deliveries to the
Company. The Company shall use reasonable efforts to coordinate such reduction or
temporary disconneclion with the Seller.
5.3.3 Scheduled Maintenance. On or before January 31 of each calendar year,
Seller shall submit a written proposed maintenance schedule of significant Facility
maintenance for that calendar year and the Company and Seller shall mutually agree as
to the acceptability of the proposed schedule. The Parties determination as to the
acceptability of the Selle/s timetable for scheduled maintenance will take into
consideration Good Utility Practices, ldaho Power system requirements and the Selle/s
prefened schedule. Neither Party shall unreasonably withhold acceptance of the
proposed maintenance schedule.
5.3.4. Maintenance Coordination. The Seller and the Company shall, to the
extent practica!, coordinate their respective transmission/distribution system and
Generation Facility maintenance schedules such that they occur simultaneously. Seller
shall provide and maintain adequate protective equipment sufiicient to prevent damage
to the Generation Facility and Seller-furnished lnterconnection Facilities. ln some cases,
some of Seller's protective relays will provide back-up protection for ldaho Powefs
facilities. !n that event, ldaho Power will test such relays annually and Seller will pay the
actual cost of such annual testing.
IDAHO lssued by IDAHO POWER COMPANYlssuedperlPUCorderNo.306,74@,VicePresident,RegulatoryAffairsEffective-@ 1221 West ldaho Street, Boise, ldaho
ldaho Porer Company FirstsCcond Revised Sheet No.72-27
Cancels
l.P.U.C. No. 29. Tariff No. l0l9dsinalFirst Revised Sheet No. 72-27
Exhibit No. 4
Case No. IPC-E-12-27
M. Larkin, IPC
Page61 ot72
SCHEDULE 72
INTERCONNECTIONS TO
NON.UTILITY GENERATION
(Continued)
IDAHO POWER COMPANY
UNIFORM INTERCONNECTION
AGREEMENT
(PURPA)
(Continued)
AGREEMENTS (Continued)
5.3.5 Forced Outaoes. During any forced outage, the Company may suspend
interconnection service to effect immediate repairs on the Company's
transmission/distribution system. The Company shal! use reasonable efforts to provide
the Seller with prior notice. lf prior notice is not given, the Company shall, upon request,
provide the Seller written documentation after the fact explaining the circumstances of
the disconnection.
5.3.6 Adverse Operatino Effects. The Company shall notiff the Seller as soon
as practicable if, based on Good Utility Practice, operation of the Selle/s Generation
Facility may cause disruption or deterioration of service to other customers served from
the same electric system, or if operating the Generation Facility could cause damage to
the Company's transmission/distribution system or other affected systems. Supporting
documentation used to reach the decision to disconnect shall be provided to the Seller
upon request. !f, after notice, the Seller fails to remedy the adverse operating effect
within a reasonable time, the Company may disconnect the Generation Facility. The
Company shall provide the Seller with reasonable notice of such disconnection, unless
the provisions of Article 5.3.1 apply.
5.3.7 Modification of the Generation Facilitv. The Seller must receive written
authorization from the Company before making any change to the Generation Facility
that may have a material impact on the safety or reliability of the Company's
transmission/distribution system. Such authorization shal! not be unreasonably withheld.
Modifications shall be done in accordance with Good Utility Practice. lf the Seller makes
such modification without the Company's prior written authorization, the latter shall have
the right to temporarily disconnect the Generation Facility.
5.3.8 Reconnection. The Parties shall cooperate with each other to restore the
Generation Facility, lnterconnection Facilities, and the Company's
transmission/distribution system to their normal operating state as soon as reasonably
practicable followin g a temporary discon nection.
IDAHO lssued by IDAHO POWER COMPANYlssuedperlPUCorderNo.30574@,VicePresident,RegulatoryAffairsEffective-@ 1221 West ldaho.Street, Boise, ldaho
ldaho Porer Company First Revised Sheet No.72-28
Cancels
I.P.U.C. No. 29. Tarifi No. 101 OriqinalSheet No. 72-28
Exhibit No.4
Case No. IPC-E-12-27
M. Larkin, IPC
Page 62 of 72
SCHEDULE 72
INTERCONNECTIONS TO
NON.UILIry GENEMTION
(Continued)
IDAHO POWER COMPANY
UN IFORM INTERCONNECTION
AGREEMENT
(PURPA)
(Continued)
AGREEMENTS (Continued)
5.3.9 Voltaoe Levels. Seller, in accordance with Good Utility Practices, shall
minimize voltage fluctuations and maintain voltage levels acceptable to ldaho Power.
ldaho Power may, in accordance with Good Utility Practi@s, upon one hundred eighty
(180) days' notice to the Seller, change its nominal operating voltage level by more than
ten percent (10o/o) at the Point of Delivery, in which case Seller shall modiff, at ldaho
Power's expense, Selle/s equipment as neoessary to accommodate the modified
nominal operating voltage level.
5.4 Land Riohts.
5.4.1 Seller to Provide Access. Seller hereby grants to ldaho Power for the
term of this Agreement al! necessary rights.of-way and easements to install, operate,
maintain, replace, and remove Idaho Powe/s Metering Equipment, lnterconnection
Equipment, Disconnection Equipment, Protection Equipment and other Special Facilities
necessary or useful to this Agreement, including adequate and continuing access rights
on property of Seller. Seller warrants that it has procured sufficient easements and
rights-of-way from third parties so as to provide ldaho Power with the access described
above. A!! documents granting such easements or rights-of-way shall be subject to
ldaho Power's approval and in recordable form.
5.4.2 Use of Public Riqht+of-Wav. The Parties agree that it is necessary to
avoid the adverse environmental and operating impacts that would o@ur as a result of
duplicate electric lines being constructed in close proximity. Therefore, subject to ldaho
Powe/s compliance with Paragraph 5.4.4, Seller agrees that should Seller seek and
receive from any local, state or federal governmental body the right to erect, construct
and maintain Seller-furnished lnterconnection Facilities upon, along and over any and all
public roads, streets and highways, then the use by Seller of such public right-of-way
sha!! be subordinate to any future use by ldaho Power of such public right-of-way for
construction and/or maintenance of electric distribution and transmission facilities and
ldaho Power may claim use of such public right-of-way for such purposes at any time.
Except as required by Paragraph 5.4.4, ldaho Power shall not be required to
compensate Seller for exercising its rights under this Paragraph 5.4.2.
IDAHO lssued by IDAHO POWER COMPANYlssuedperlPUCorderNo.3057.|@,VicePresident,Regu!atoryAffairsEffective-@ 1221 West ldaho Street, Boise, ldaho
ldaho Power Company First Revised Sheet No. 72-29
Cancels
!.P.U.C. No. 29. Tariff No. 101 Oriqinal Sheet No. 72-29
Exhibit No. 4
Case No. IPC-E-12-27
M. Larkin, IPC
Page 63 of 72
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILITY GENERAT!ON
(Continued)
IDAHO POWER COMPANY
UNIFORM INTERCONNECTION
AGREEMENT
(PURPA)
(Continued)
AGREEMENTS (Continued)
5.4.3 Joint Use of Facilities. Subject to ldaho Powe/s compliance with
Paragraph 15.4.4,ldaho Power may use and attach its distribution and/or transmission
facilities to Selle/s lnterconnection Facilities, may recpnstruct Selle/s lnterconnection
Facilities to accommodate ldaho Power's usage or ldaho Power may construct its own
distribution or transmission facilities along, over and above any public right-of-way
acquired from Seller pursuant to Paragraph 5.4.2, attaching Selle/s lnterconnection
Facilities to such newly constructed facilities. Except as required by Paragraph 5.4.4,
ldaho Power shall not be required to compensate Seller for exercising its rights under
this Paragraph 5.4.3.
5.4.4 Conditions of Use. !t is the intention of the Parties that the Seller be lefi in
substantially the same condition, both financially and electrically, as Seller existed prior
to ldaho Powe/s exercising its rights under this Paragraph 5.4. Therefore, the Parties
agree that the exercise by ldaho Power of any of the rights enumerated in Paragraphs
5.4.2 and 5.4.3 shall: (1) comply with all applicable laws, codes and Good Utility
Practices, (2) equitably share the costs of installing, owning and operating jointly used
facilities and rights-of-way. lf the Parties are unable to agree on the method of
apportioning these costs, the dispute will be submitted to the Commission for resolution
and the decision of the Commission will be binding on the Parties, and (3) shall provide
Seller with an interconnection to ldaho Power's system of equa! capacity and durability
as existed prior to ldaho Power exercising its rights under this Paragraph 5.4.
6. Assiqnment. Liabilitv. lndemnitv. Force maieure. Conseouential Damaoes and Default.
6.1 Assiqnment. This Agreement may be assigned by either Party upon twenty-one
(21) calendar days prior written notice and opportunity to object by the other Pafi; provided
that:
6.1.1 Either Party may assign this Agreement without the consent of the other
Par$ to any affiliate of the assigning Party with an equal or greater credit rating and with
the legal authority and operational ability to satisff the obligations of the assigning Parg
under this Agreement.
!DAHO lssued by IDAHO POWER COMPANYlssuedperlPUCorderNo.30571@,McePresident,Regu!atoryAffairsEffective-@ 1221 West ldaho Street, Boise, ldaho
ldaho Power Company
!.P.U.C. No. 29. Tariff No. 101 Oriqina! Sheet No. 72-30
Exhibit No.4
Case No. IPC-E-12-27
M. Larkin, IPC
Page64 ot72
SCHEDULE 72
INTERCONNECTIONS TO
NON.UTILITY GENERATION
(Continued)
IDAHO POWER COMPANY
UNIFORM INTERCONNECTION
AGREEMENT
(PURPA)
(Continued)
AGREEM ENTS (Continued)
6.1.2 The Seller shall have the right to contingently assign this Agreement,
without the consent of the Company, for collatera! security purposes to aid in providing
financing for the Generation Facility, provided that the Seller will promptly notiff the
Company of any such contingent assignment.
6.1.3 Any attempted assignment that violates this article is void and ineffective.
Assignment shal! not relieve a Party of its obligations, nor shall a Party's obligations be
enlarged, in whole or in part, by reason thereof. An assignee is responsible for meeting
the same financial, credit, and insurance obligations as the Seller. Where required,
consent to assignment will not be unreasonably withheld, conditioned or delayed.
6.2 Limitation of Liabilitv. Each Party's liability to the other Pafi for any loss, cost,
claim, injury, liability, or expense, including reasonable attorney's fees, relating to or arising from
any act or omission in its performance of this Agreement, shall be limited to the amount of direct
damage actually incuned. !n no event shall either Pafi be liable to the other Pafi for any
indirect, special, consequential, or punitive damages, except as authorized by this Agreement.
6.3 lndemnitv.
6.3.1 This provision protects each Party from liability incurred to third parties as
a result of carrying out the provisions of this Agreement. Liability under this provision is
exempt from the genera! limitations on liability found in Article 6.2.
6.3.2 The Parties shall at alltimes indemniff, defend, and hold the other Pafi
harmless from, any and all damages, losses, claims, including claims and actions
relating to injury to or death of any person or damage to proper$, demand, suits,
recoveries, costs and expenses, court costs, attomey fees, and all other obligations by
or to third parties, arising out of or resulting from the other Party's action or failure to
meet its obligations under this Agreement on behalf of the indemniffing Party, except in
cases of gross negligence or intentional wrongdoing by the indemnified Par$.
IDAHO lssued by IDAHO POWER COMPANYlssuedperlPUCorderNo'3057,|@,VicePresident,Regu|atoryAffairsEffective-@ 1221 West ldaho Street, Boise, ldaho
ldaho Porer Company
|.P.U.C. No.29. Tariff No. 101 OriqinalSheet No.72-31
Exhibit No. 4
Case No. IPC-E-'12-27
M. Larkin, IPC
Page 65 of 72
SCHEDULE 72
!NTERCONNECTIONS TO
NON.UTILITY GENERATION
(Continued)
IDAHO POWER COMPANY
UNIFORM INTERCONNECTION
AGREEMENT
(PURPA)
(Continued)
AGREEMENTS (Continued)
6.3.3 lf an indemnified person is entitled to indemnification under this article as
a result of a claim by a third party, and the indemniffing Party fails, afrer notice and
reasonable opportunity to proceed under this article, to assume the defense of such
claim, such indemnified person may at the expense of the indemniffing Party contest,
settle or consent to the entry of any judgment with respect to, or pay in full, such claim.
Failure to defend is a Materia! Breach.
6.3.4 lf an indemniffing party is obligated to indemniff and hold any
indemnified person harmless under this article, the amount owing to the indemnified
person shall be the amount of such indemnified person's actual loss, net of any
insurance or other recovery.
6.3.5 Promptly after receipt by an indemnified person of any claim or notice of
the commencement of any action or administrative or !ega! proceeding or investigation
as to which the indemnity provided for in this article may apply, the indemnified person
shall notiff the indemniffing party of such fact. Any failure of or delay in such notification
shall be a Material Breach and shall not affect a Pafi's indemnification obligation unless
such failure or delay is materially prejudicialto the indemniffing party.
6.4 Force Maieure. As used in this Agreement, "Force Majeure" or "an event of
Force Majeure" means any cause beyond the control of the Seller or of the Company which,
despite the exercise of due diligence, such Pafi is unable to prevent or overcome. Force
Majeure includes, but is not limited to, acts of God, fire, flood, storms, wars, hostilities, civil
strife, strikes and other labor disturbances, earthquakes, fires, lightning, epidemics, sabotage, or
changes in law or regulation occurring afrer the Operation Date, which, by the exercise of
reasonable foresight such party could not reasonably have been expected to avoid and by the
exercise of due diligence, it shall be unable to overcome. lf either Party is rendered wholly or in
part unable to perform its obligations under this Agreement because of an event of Force
Majeure, both Parties shal! be excused from whatever performance is affected by the event of
Force Majeure, provided that:
(1) The non-performing Party shall, as soon as is reasonably possible after
the occurrence of the Force Majeure, give the other Pafi written notice describing the
particulars of the occurrence.
IDAHO lssued by IDAHO POWER COMPANYlssuedperlPUCorderNo.3057,|@,VicePresident,RegulatoryAffairsEffective-@ 1221 West ldaho Street, Boise, ldaho
ldaho Power Company
!.P.U.C. No.29. TariffNo. 101 OriqinalSheet No.72-32
Exhibit No. 4
Case No. IPC-E-12-27
M. Larkin, IPC
Page 66 of 72
SCHEDULE 72
INTERCONNECTIONS TO
NON.UTILIry GENEMTION
(Continued)
IDAHO PO\A'ER COMPANY
UNI FORM INTERCONNECTION
AGREEMENT
(PURPA)
(Continued)
AGREEMENTS (Continued)
(2) The suspension of performance shall be of no greater scope and of no
longer duration than is required by the event of Force Majeure.
(3) No obligations of either Pafi which arose before the occunence causing
the suspension of performance and which could and should have been fully performed
before such occunence shall be excused as a result of such o@urrence.
6.5 Default and Materia! Breaches.
a-
-
fails to perform any of the terms or conditions of
this Agreement (a "Default'or an "Event of Default"), the nondefaulting Party shallcause
notice in writing to be given to the defaulting Party, speciffing the manner in which such
default occuned. lf the defaulting Party shal! fail to cure such Default within the sixty
(60) days after service of such notice, or if the defaulting Pafi reasonably demonstrates
to the other Party that the Default can be cured within a commercially reasonable time
but not within such sixty (60) day period and then fails to diligently pursue such cure,
then, the nondefaulting Party may, at its option, terminate this Agreement and/or pursue
its lega! or equitable remedies.
6.5.2 Material Breaches. The notice and cure provisions in Paragraph 6.6.1 do
not apply to Defaults identified in this Agreement as Material Breaches. Material
Breaches must be cured as expeditiously as possible following occurrence of the
breach.
7. lnsurance. During the term of this Agreement, Seller shal! secure and continuously carry
the following insurance coverage:
7.1 Comprehensive Genera! Liability lnsurance for both bodily injury and property
damage with limits equal to $1,000,000, each occurrence, combined single limit. The deductible
for such insurance shall be consistent with cunent lnsurance lndustry Utility practices for similar
propefi.
7.2 The above insurance coverage shall be placed with an insurance company with
an A.M. Best Company rating of A- or better and shall include:
IDAHO lssued by IDAHO POWER COMPANYlssuedperlPUcorderNo.3057,|@,VicePresident,RegulatoryAffairsEffective-@ 1221 West ldaho Street, Boise, ldaho
ldaho Power Company
I.P.U.C. No. 29. Tariff No. 101 Oriqinal Sheet No. 72-33
Exhibit No. 4
Case No. IPC-E-'12-27
M. Larkin, IPC
Page67 of72
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILITY GENEMTION
(Continued)
IDAHO POWER COMPANY
UNIFORM INTERCONNECTION
AGREEMENT
(PURPA)
(Continued)
AGREEMENTS (Continued)
(a) An endorsement naming ldaho Porer as an additional insured and loss
payee as applicable; and
(b) A provision stating that such poliry shall not be canceled or the limits of
liability reduced without sixty (60) days' prior written notice to ldaho Power.
7.3 Seller to Provide Certificate of lnsurance. As required in Paragraph 7 herein and
annually thereafter, Seller shall fumish the Company a certificate of insurance, together with the
endorsements required therein, evidencing the coverage as set forth above.
7.4 Seller to Notifu ldaho Power of Loss of Coveraoe - lf the insurance coverage
required by Paragraph 7.1 shall lapse for any reason, Seller will immediately notiff ldaho Power
in writing. The notice will advise ldaho Power of the specific reason for the lapse and the steps
Seller is taking to reinstate the coverage. Failure to provide this notice and to expeditiously
reinstate or replace the coverage will constitute grounds for a temporary disconnection under
Section 5.3 and will be a Material Breach.
8. Miscellaneous.
8.1 Governino Law. The validity, interpretation and enforcement of this Agreement
and each of its provisions shall be governed by the laws of the state of ldaho without regard to
its conflicts of law principles.
8.2 Salvaoe. No later than sixty (60) days afier the termination or expiration of this
Agreement, ldaho Power will prepare and forward to Seller an estimate of the remaining value
of those ldaho Power furnished lnterconnection Facilities as required under Schedule 72 andlor
described in this Agreement, less the cost of removal and transfer to ldaho Powe/s nearest
warehouse, if the lnterconnection Facilities will be removed. lf Seller elects not to obtain
ownership of the lnterconnection Facilities but instead wishes that ldaho Power reimburse the
Seller for said Facilities the Seller may invoice ldaho Power for the net salvage value as
estimated by tdaho Power and ldaho Power shall pay such amount to Seller within thirty (30)
days after receipt of the invoice. Seller shall have the right to offset the invoice amount against
any present or future payments due ldaho Power.
IDAHO Issued by IDAHO POWER COMPANYlssuedperlPUCorderNo.30574@,VicePresident,RegulatoryAffairsEffective-@:1221 West ldaho Street, Boise, ldahd
ldaho Pover Company
!.P.U.C. No. 29. Tariff No. 101 Oriqinal Sheet No. 72-33
Exhibit No. 4
Case No. IPC-E-12-27
M. Larkin, IPC
Page 68 of 72
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILITY GENERATION
(Continued)
IDAHO POWER COMPANY
UNIFORM INTERCONNECTION
AGREEMENT
(PURPA)
(Continued)
AGREEMENTS (Continued)
9. Notices.
9.1 General. Unless othenrise provided in this Agreement, any written notice,
demand, or request required or authorized in connection with this Agreement ("Notice") shall be
deemed properly given if delivered in person, delivered by recognized nationa! currier service,
or sent by first class mail, postage prepaid, to the person specified below:
!f to the Seller:
Seller:
Attention:
City:Phone:_Fax:
lf to the Company:
State: Zip:
Company
Attention:
City:State: Zip:Phone:_Fax:
9.2 Billino and Pavment. Billings and payments shall be sent to the addresses set
out below:
Seller:
Attention:
Address:
City:
Phone:Fax:
Company:
Attention:
Address:
City:$tate: Zip:_Phone:_Fax:
IDAHO lssued by IDAHO POWER COMPANYlssuedper!PUCorderNo.3057,|@,VicePresident,RegulatoryAffairsEffective-@ 1221 West ldaho Street, Boise, ldaho
ldaho Porer Company
!.P.U.C. No.29. TaffiNo. 101 OriqinalSheet No.72-33
Exhibit No. 4
Case No. IPC-E-12-27
M. Larkin, IPC
Page 69 of 72
SCHEDULE 72
INTERCONNECTIONS TO
NON.UTILITY GENERATION
(Continued)
IDAHO POVVER COMPANY
UNIFORM INTERCONNECTION
AGREEMENT
(PURPA)
(Continued)
AGREEMENTS (Continued)
9.3 Desiqnated Ooeratino Reoresentiative. The Parties may also designate
operating representatives to conduct the communications which may be necessary or
convenient for the administration of this Agreement. This person will also serve as the point of
contact with respect to operations and maintenanoe of the Pafi's facilities.
Selleds Operating Representative:
Seller:
Attention:
City:State: Zip:Phone: Fax:
Company's Operating Representative:
Company:
State: Zip:Phone:_Fax:
9.5 Chanoes to the Notice lnformation. Either Party may change this information by
giving five Business Days written notice prior to the effective date of the change.
10. Sionatures.
lN WITNESS WHEREOF, the Parties have caused this Agreement to be executed by their
respective duly authorized representatives.
For the Comoanv
Name:
Title:
Date:
For the Seller
Name:
Title:
Date:
IDAHO lssued by IDAHO POWER COMPANYlssuedperlPUCorderNo.3057,|@,VicePresident,RegulatoryAffairsEffective-@ 1221 West ldaho Street; Boise, ldaho
ldaho Power Company
I.P.U.C. No. 29. Tariff No. 101 Oriqinal Sheet No. 72-33
Exhibit No. 4
Case No. IPC-E-12-27
M. Larkin, IPC
Page70 of72
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILIW GENEMTION
(Continued)
IDAHO POWER COMPANY
UNIFORM !NTERCONNECTION
AGREEMENT
(PURPA)
(Continued)
Attachment 1
Description and Costs of the Generation Facilitv. lnterconnection Facilities and Meterino
Eouipment
!n this attachment the Generation Facility and lnterconnection Facilities, including Specia!
Facilities and upgrades, are itemized and identified as being owned by the Seller or the Company. As
provided in Schedule 72, Pavment For lnterconnection Facilities, the Company will provide a best
estimate itemized cost of its lnterconnection Facilities, including Special Facilities, upgrades and
Metering Equipment.
Attachment 2
One-line Diaoram Depictino the Small Generation Facilitv. lnterconnection Facilities. Meterino
Eouipment and Uporades
IDAHO lssued by IDAHO POWER COMPANYlssuedperlPUCorderNo.30571@,VicePresident,RegulatoryAffairsEffective-@ 1221 West ldaho Street, Boise, ldaho
ldaho Power Company
I.P.U.C. No. 29. Tariff No. 101 Oriqinal Sheet No. 72-33
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILITY GENERATION
(Continued)
IDAHO POWER COMPANY
UNIFORM INTERCONNECTION
AGREEMENT
(PURPA)
(Continued)
Attachment 3
Milestones
ln-Service Date:
Critical milestones and responsibility as agreed to by the Parties:
Milestone/Date
Exhibit No.4
Case No. IPC-E-12-27
M. Larkin, IPC
PageT'l of 72
Responsible Party
(1)
(21
(3)
(4)
(5)
(6)
(7)
(8)
(e)
(10)
Agreed to by:
For the Company Date.
For the Seller
IDAHO
lssued per IPUC Order No.3e57t
lssued by IDAHO POWER COMPANY
@, Vice President, Regulatory Affairs
Effective 2013 1221 West ldaho Street, Boise, ldaho
ldaho Power Company
|.P.U.C. No.29. TaffiNo. 101 OrioinalSheet No.72-33
Exhibit No. 4
Case No. IPC-E-12-27
M. Larkin, IPC
Page72 of72
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILITY GENERATION
(Continued)
IDAHO POWER COMPANY
UNIFORM INTERCONNECTION
AGREEMENT
(PURPA)
(Continued)
Attachment 4
Additional Operatino Reouirements for the Comoanv's Transmission Svstem and Affected
Svstems Needed to Suoport the Selle/s Needs
The Company shall also provide requirements that must be met by the Seller prior to initiating
paralle! operation with the Company's Transmission System.
Attachment 5
Reactive Power Reouirements
ldaho Power will determine the reactive power required to be supplied by the Company to the
Seller, based upon information provided by the Seller. The Company will speciff the equipment
required on the Company's system to meet the Facility's reactive power requirements. These
specifications wil! include but not be limited to equipment specifications, equipment location, Company-
provided equipment, Seller provided equipment, and all costs associated with the equipment, design
and installation of the Gompany-provided equipment. The equipment specifications and requirements
will become an integra! part of this Agreement. The Company-owned equipment wil! be maintained by
the Company, with total cost of purchase, installation, operation, and maintenance, including
administrative cost to be reimbursed to the Company by the Seller. Payment of these costs will be in
accordance with ScheduleT2 and the total reactive power cost will be included in the calculation of the
Monthly Operation and Maintenance Charges specified in Schedule 72.
Attachment 6
Comoanv's Description of Uoqrades Required to lnteorate the Generation Facilitv and Best
Estimate of Uoorade Costs
As provided in Schedule 72 this Attachment describes Upgrades, including best work upgrades,
and provides an itemized best estimate of the cost of the Upgrades.
IDAHO lssued by IDAHO POWER COMPANYlssuedperlPUCorderNo.3057,t@,VicePresident,RegulatoryAffairsEffective-@ 1221 West ldaho Street, Boise, ldaho
CLEAN FORMAT I
ldaho Power Company Second Revised Sheet No. 84-1
Cancels
!.P.U.C. No. 29. Tariff No. 101 First Revised Sheet No. 84-'1
SCHEDULE 84
LARGE CUSTOMER
NET METERING SERVICE
AVAILABILIry
Service under this schedule is available throughout the Company's service territory within the
State of ldaho for Customers intending to operate Net Metering Systems under this schedule to generate
electricity to reduce all or part of their monthly energy usage.
APPLICABILITY
Service under this schedule is applicable to any Customer that:
1. Does not take service under Schedule 6 or Schedule 8; and
2. Owns and/or operates a Generation Facility fueled by solar, wind, biomass, geothermal
or hydropower, or represents fuel cell technology; and
3. Maintains its retail electric service account for the loads served at the Point of Delivery
adjacent to the Generation lnterconnection Point as active and in good standing; and
4. Meets all requirements applicable to Net Metering Systems detailed in the Company's
Schedule 72, lnterconnections to Non-Utility Generation; and
5. Owns and/or operates a Generation Facility with a total nameplate capacity rating of
100 kilowatts (kW) or smaller that is interconnected at a Generation lnterconnection Point that is
adjacent to the Customer's Point of Delivery and is metered at the same voltage through a meter that is
separate from the retail load metering at the Customer's Point of Delivery.
ONE METER EXCEPTION:
A separate meter from the existing retail load metering at the Customer's Point of Delivery is not
required if:
1. The Generation Facility has a total nameplate capacity rating of 25 kW or smaller; and
2. The Generation Facility has a total nameplate capacity rating no more than 2o/o of lhe
Customer's Basic Load Capacity (BLC) or comparable average maximum monthly Billing Demands.
DEFIN!TIONS
Basic Load Capacitv (BLC) is the average of the two greatest non-zero monthly Billing Demands
established during the 12-month period which includes and ends with the cunent Billing Period.
Excess Net Enerov means the positive difference between the kWh generated by a Customer
and the kWh supplied by the Company over the applicable Billing Period.
IDAHO
lssued per Order No.
Effective - October 1,2013
lssued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221 West ldaho Street, Boise, ldaho
Exhibit No. 5
Case No. IPC-E-12-27
M. Larkin, IPC
Page 1 of 11
ldaho Power Company First Revised Sheet No. 84-2
Cancels
|.P.U.C. No. 29. Tariff No. 101 Oriqinal Sheet No. 84-2
SCHEDULE 84
LARGE CUSTOMER
NET METERING SERVICE
(Continued)
DEFINITIONS (Continued)
Generation Facilitv means all equipment used to generate electric energy where the resulting
energy is either delivered to the Company via a single meter at the Point of Delivery or Generation
lnterconnection Point, or is consumed by the Customer.
Generation lnterconnection Point is the point where the conductors installed to allow receipt of
Customer's generation connect to the Company's facilities adjacent to the Customer's Point of Delivery.
lnterconnection Facilities are all facilities reasonably required by Prudent Electrical Practices and
the applicable electric and safety codes to interconnect and safely deliver energy from the Generation
Facility to the Point of Delivery or Generation lnterconnection Point.
Net Meterinq Service is the Company's service which provides for transfer of electric energy to
the Company by means of a net metering arrangement or its successor(s) as approved by the
Commission. This optional service provides for Customers to install Generation Facilities to
interconnect to the Company's system to offset all or a portion of their electrical usage. This service is
comprised of all customers taking service under Schedule 6, Schedule 8, or Schedule 84.
Net Meterinq Svstem is a Customer-owned Generation Facility interconnected to the
Company's system under the terms of Schedule 6, Schedule 8, or Schedule 84.
Point of Deliverv is the retail metering point where the Company's and the Custome/s electrical
facilities are interconnected to allow Customer to take retail electric service from the Company.
Prudent Electrical Practices are those practices, methods and equipment that are commonly used
in prudent electrical engineering and operations to operate electric equipment lawfully and with safety,
dependability, efficiency and economy.
Schedule 72 is the Company's service schedule which provides for interconnection to non-utility
generation or its successor schedule(s) as approved by the Commission.
CONDITIONS OF PURCHASE AND SALE
The conditions listed below shall apply to all transactions under this schedule.
1. Balances of generation and usage by the Customer:
a. lf electricity supplied by the Company during the Billing Period exceeds the
electricity generated by the Customer and delivered to the Company during the Billing Period,
the Customer shall be billed for the net electricity supplied by the Company at the Customer's
standard schedule retail rate, in accordance with norma! metering practices.
IDAHO
lssued per Order No.
Effective - October 1,2013
lssued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221 West ldaho Street, Boise, ldaho
Exhibit No. 5
Case No. IPC-E-12-27
M. Larkin, IPC
Page 2 of 11
ldaho Power Company First Revised Sheet No. 84-3
Cancels
!.P.U.C. No. 29. Tariff No. 101 Oriqinal Sheet No. 84-3
Exhibit No. 5
Case No. IPC-E-12-27
M. Larkin, IPC
Page3of11
2.
when the
SCHEDULE 84
LARGE CUSTOMER
NET METERING SERVICE
(Continued)
CONDITIONS OF PURCHASE AND SALE (Continued)
b. Effective as of the Customefs January 2014 Billing Period, if electricity generated
by the Customer during the Billing Period exceeds the electricity supplied by the Company during
the Billing Period, the Excess Net Energy shall be carried fonruard into the following Billing Period
as a kWh credit to be applied against future usage. Any Excess Net Energy credits remaining
after the Custome/s bill for the December Billing Period is prepared shall expire.
The Customer shall never deliver or attempt to deliver energy to the Company's system
Company's system serving the Customer's Generation Facility is de-energized for any
reason.
3. The Company shall not be liable directly or indirectly for permitting or continuing to allow
an attachment of a Net Metering System to the Company's system, or for the acts or omissions of the
Customer that cause loss or injury, including death, to any third party.
4. The Customer is responsible for all costs associated with the Generation Facility and
lnterconnection Facilities. The Customer is also responsible for all costs associated with any Company
additions, modifications, or upgrades to any Company facilities that the Company determines are
necessary as a result of the installation of the Generation Facility in order to maintain a safe, reliable
electrical system.
5. The Company shall not be obligated to accept, and the Company may require the
Customer to curtail, interrupt or reduce deliveries of energy if the Company, consistent with Prudent
Electrical Practices, determines that curtailment, interruption or reduction is necessary because of line
construction or maintenance requirements, emergencies, or other critical operating conditions on its
system.
6. lf the Company is required by the Commission to institute curtailment of deliveries of
electricity to its customers, the Company may require the Customer to curtail its consumption of
electricity in the same manner and to the same degree as other Customers on the Company's standard
service schedules.
7. The Customer shall grant to the Company all access to all Company equipment and
facilities including adequate and continuing access rights to the property of the Customer for the
purpose of installation, operation, maintenance, replacement or any other service required of said
equipment as wel! as all necessary access for inspection, switching and any other operational
requirements of the Customer's Interconnections Facilities.
8. The Customer shall notiff the Company immediately if a Net Metering System is
permanently removed or disabled. Permanent removal or disablement for the purposes of this
Schedule is any removal or disablement of a project lasting longer than six (6) months. Customers with
permanently removed systems will be removed from service under this schedule and placed on the
appropriate standard service schedule.
IDAHO
lssued per Order No.
Effective - October 1, 2013
lssued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221Wesl ldaho Street, Boise, ldaho
LEGISLATIVE FORMAT
ldaho Power Company Fhtsecond Revised Sheet No. &4-1
Cancels
!.P.U.C. No. 29. Tariff No. 101 OriqinalFirst Revised Sheet No. &4-1
Exhibit No. 5
Case No. IPC-E-12-27
M. Larkin, IPC
Page4of11
SCHEDULE 84
LARGE CUSTOMER EAIERCY
PREDUEHEN-NET METERING SERVICE
AVAILABILITY
Service under this schedule is available throughout the Company's service tenitory within theStateofldahoforCustomersintendingtooperateunderthisscheduleto
generate electricity to reduce all or part of their monthly energy usage.
Serviee unCer this sehedule is available en a first eeme; first eerved basis until the eumulative
generatien nameplate eap
ene pereent ef the Cempany's retail peak demand during 2000, Ne single Seller may eenneet mere
than 20 pereent ef the eumulative generatien nameplate eapaeity eenneeted under thie sehedule,
APPLICABILITY
Service under this schedule is applicable to any SellerCuslomel that:
1. Does not take service under Schedule Q4 or Schedule 59; and
2. Owns and/or operates a Generation Facility fueled by solar, wind, biomass, qeothermal
or hydropower, or represents fuel cell technology; and
3. Maintains its retail electric service account for the loads served at the Point of Delivery
adjacent to the Generation lnterconnection Point as active and in good standing; and
4. Meets all epplieable-requirements applicable to Net Meterinq Svstems detailed in-ef the
Company's Schedule 72. lnterconnections to Non-Utilitv Generationffiien
Preeees; and
5.;
elDelivery, thus all energy reeeived and delivered by the Cempany is threugh the existing watt heur
retailmeter,
O,urns and/or operates a Generation Facility with a total nameplate capacity rating of 100
kilowatts (kW) or smaller that is interconnected at a Generation lnterconnection Point that is
adjacent to the SercfsCuslomeft Point of Delivery and is metered at the same voltage through
ameterthatisseparatefromtheretailloadmeteringattheW]!omeGPointofDelivery.
ONE METER EXCEPTION:
IDAHO
lssued per Order No.30508
lssued by IDAHO POWER COMPANY
@, Vice President, Regulatory Affairs
Effective - AFrilJ.{e{2October 1. 2013 1221 West ldaho Street, Boise, lslgho
ldaho Power Company Fi{€tsecond Revised Sheet No. 84-1
Cancels
l.P.U.C. No. 29. Tariff No. 101 erkrinalFirst Revised Sheet No. 84-1
Exhibit No. 5
Case No. IPC-E-'12-27
M. Larkin, IPC
Page5of11
A separate meter from t
Deliverv is not reouired if:
t. fne Oeneration f
) The Generaiinn tranilitv haq a tnlal namcnlalc cananilv ratinn nn mnre lhan 2o/^ nf the
SefleCqeugtomer's Basic Load Caoaci ing
Demand.s.
DEFINITIONS
Basic Load Capacitv (BLC) is the averaqe of the two oreatest non-zero monthlv Billino Demands
established durino the 12-month period which includes and ends with the current Billinq Period.
Excess Net Enerov means the positive difference between the kWh qenerated bv a Seller
Customer and the kWh supplied bv the Companv over the applicable Billinq Period.
IDAHO lssued by IDAHO POWER COMPANY
@, vice President, Regulatory Affairslssued per Order No.30508Effective-@ 1221 West ldaho Street, Boise, lDdaho
ldaho Power Company First Revised Sheet No. 84-2
Cancels
!.P.U.C. No. 29. Tariff No. 101 Oriqinal Sheet No. &4-2
Exhibit No. 5
Case No. IPC-E-12-27
M. Larkin, IPC
Page6of11
SCHEDULE 84
LARGE CUSTOMER ENERGY
PREDU€+I€AI-NET M ETERI NG SERVI CE
(Continued)
W
^^^ ir^+^'^^+r^^: \ separate meter frem the existing retail lead metering at the Seller's
smalb+ene
a, fne generatien fae
n Seler wne uses tne
DEFINITIONS (Continued)
^"^tn^r tr^^"' ^^'r is the menthly weighted average ef the daily en peak and eff peak Dew
e
iees
inc
a^'i^ | ^^d ^^^^^in' /trr ^\ is the average ef the twe greatest nen zere menthly Billing Demands
the kWh supplied by the Cempany ever the applieable Billing Peried,
Generation Facilitv means all equipment used to generate electric energy where the resulting
energy is either delivered to the Company via a single meter at the Point of Delivery or Generation
lnterconnection Point, or is consumed by the SellerCustomet.
Generation tnterco
SeffefbCustomer's oeneration connect to the Comoanv's facilities adiacent to the SelledsCustomer's
Point of Deliverv.
^^-^"i^' r'+^' ^^'^*i^^ D' ^^" iE the eempany's generatien int€reenneetien applieation and
engineering review preeess develepeC te ensure a safe and reliable generatien intereonneetlen,
lnterconnection Facilities are allfacilities reasonably required by Prudent Electrical Practices and
the applicable electric and safety codes to interconnect and safely deliver energy from the Generation
Facility to the Point of Delivery or Generation lnterconnection Point.
IDAHO
lssued per Order No.€0508
lssued by IDAHO POWER COMPANY
@, Vice President, Regulatory Affairs
Effective 1221 West ldaho Street, Boise, lDglgho
ldaho Power Company First Revised Sheet No. 84-2
Cancels
Exhibit No. 5
Case No. IPC-E-12-27
M. Larkin, IPC
Page7of11|.P.U.C. No. 29. Tariff No. 101 Orioinal Sheet No. &4-2
Net Meterino Service is the Comoany's service which provides for transfer of electric enerov to
the Companv bv means of a net meterinq arranoement or its successor(s) as approved bv the
Commission. This optional service provides for Customers to install Generation Facilities to
interconnect to the Companv's svstem to offset all or a portion of their electrical usaqe. This service is
comprised of all customers takinq service under Schedule 6. Schedule 8. or Schedule 84.
Net Meterino Svstem is a Customer-owned Generation Facilitv interconnected to the
Companv's svstem under the terms of Schedule 6, Schedule 8. or Schedule 84.
Point of Deliverv is Customer's
electrical facilitl Customer to take retail electr
Company.
PruOent grcctrical
in oruOent etectric
Oeoendabititv. efilc
ScneOute ZZ is tne O
qeneration or its ion-
CONDITIONS OF PURCHASE AND SALE
The conditions listed below shall applv to all transactions under this schedule.
1. Balances of oeneration and usaoe bv the €ellerCustomer:
a. lf electricitv supolied bv the Companv durinq the Billino Period exceeds the
electricitv qenerated bv the SelleFCustomer and delivered to the Comoanv durinq the Billinq
Period. the Seller-Customer shall be billed for the net electricitv supplied bv the Companv at the
IDAHO lssued by IDAHO POWER COMPANYlssuedperorderNo.€0508@,VicePresident,RegulatoryAffairs
Effective 1221 West ldaho Street, Boise, lQlgho
ldaho Power Company First Revised Sheet No. 84-3
Cancels
I.P.U.C. No. 29. Tariff No. 101 OrioinalSheet No. &4-3
Exhibit No. 5
Case No. IPC-E-12-27
M. Larkin, IPC
Page8of11
SCHEDULE 84
LARGE CUSTOMER€SIER€Y
PRODU€:flEN-NET M ETERI NG SE RVIC E
(Continued)
W
^^^^-^''^^ t-* '^ ^- '' - '^'-* ie the peint where the eenCuetere instelleC te elleyv reeeipt ef
Setter's generati
Feint ef Beliverv io
D..,1^^- -l^*j^
i
o^r "..t -^ ie tne ee
iesie*
e^"^" ie any Cuetemer that ewns and/er eperatee a Generatien Faeility anC desires te
i
eempantr
T{EN+HIY€ITIIAIG
The Seller shall be billed irFaeeerdanee with the Se!!e/s aBBlieable standard serviee sehedule;
i
CENBITIONS EF PURG
The eenditiens listed belew shall apply te all transaetiene under this seheCule=
1, Balaneee ef generatien and usage by the Seller:
CONDITIONS OF PURCHASE AND SALE (Continued)
ieee'
b. Effective as of the Customer's Januarv 2014 Billino Period. lif electricity generated
by the SetterCuslomet during the Billing Period exceeds the electricity supplied by the Company during
the Billing Period,{he€elle*
the Billing Peried under the Sellede standarC serviee sehedule; andrhe Excess Net Enerqv shall
be carried forward into the followinq Billino Period as a kWh credit to be aoolied aoainst future
usaoe. Anv Excess Net Enerov credits remainino after the Customer's bill for the December
Billino Period is orepared shallexpire.
IDAHO
lssued per Order No.€0508
lssued by IDAHO POWER COMPANY
@, Vice President, Regulatory AffairsEffective-@ 1221 West ldaho Street, Boise, lslaho
ldaho Power Company First Revised Sheet No. 84-3
Cancels
I.P.U.C. No. 29 Tariff No. 101 OrioinalSheet No 84-3
32. The Selle+Customer shall never deliver or attemot to deliver enerov to the Comoanv's
svstem when the Com Customer's Generation Facilitv is de-eneroized
for anv reason.
_________:[3. The Comoanv shall not be liable directlv or indirectlv for oermittino or continuino to allow
an attachment of a $N terino System to the Comoanv's svstem. or for the acts
orgmissionsolthe€elHCustomer that cause loss or iniurv. includino death. to anv third oartv.
__________.j54-Ihe_.SefleflOustomer is resoonsible for all costs associated with the Generation Facilifu
and Interconnecti Customerjs also responsibl
Comoanv aOOition ines
are necessarv as a re
reliable electric
65. The Comoanv shall
SeilefCustomer to curtail. interru nergy_if the Comoanv. co
Prudent Electrical
because of line con
conOitions on its s
-16.
lf the Companv is r
electricitv to its c Customer to curtail its consumotion ofelectricitvinthes -withinthesameeu
ieson the Companv's standard service schedules.
---------------:97. The Selle+Customer shall orant to the Comoanv all access to all Comoanv eouioment
and facilities incl stomerlot
the ouroose of inst
equioment as well as a
reouirements of th Customer's Interconnections ies,
8. The Customer shall notifu the Companv immediatelv if a Net Meterinq Svstem is
permanentlv removed or disabled. Permanent removal or disablement for the purposes of this
Schedule is anv removal or disablement of a proiect lastinq lonqer than six (6) months. Customers with
permanentlv removed svstems will be removed from service under this schedule and placed on the
appropriate standard service schedule.
IDAHO lssued by IDAHO POWER COMPANYlssuedperorderNo.€o508@,VicePresident,RegulatoryAffairs
Exhibit No. 5
Case No. IPC-E-12-27
M. Larkin, IPC
Page9of11
Effective-@ 1221 West ldaho Street, Boise, lDdahg
Eahe PewerGempany CANCELLED
I;P:U:C, Ne. 29: Ta
S€HEDTJIFS4
GUSTOMER ENERCY
PRODUSTION NET METE
€entinued)
ii, SnaU ge nnanel
m, SnaU net ge nna
ie+
iv, Shallr if taking
7, be billed the applieable retail rate fer any net ueagedelivered by the Cempanrand
2, As a eenditien ef intereenneetien with the Cempany' the Seller shal!:
a. Gemplete and maintain all requirements ef intereenneetien in aeeerdanee with
b. Cemplete and maintain all requirements ef the Cempany's Generatien
lntereenneetien Preeess,
e, ebtain written eenfirmatien frem the Cempany that all eenditiens te
eenfirmatien shall net be unreasenably withheld by the eempany,
wnen tnegempany'e
I' The €empany ehell net be lieble direetly er indireetly fer permitting er eentinsing te allew
S, fne Setler is reo
€b€*r*ea+€y€*€*
Exhibit No. 5
Case No. IPC-E-12-27
M. Larkin, IPC
Page 10 of 1 1
irs
Effeetive Mareh 1' 2008 1221 West Idahe Street' Beise' lD
CANCELLED
!;P,U:C; Ne, 29: Tar
SCFIEDTIFSAW
PRODUGTION NET METE
€en*inuee)
ine
€y€tefr
7, lf the eempany is
eleetrieity te ite es
gE The Seller ehal ies
i
inetallatienl eperetien; meifitenaneer repleeement er eny ether eeffiee required ef eaid eqsipment es
Exhibit No. 5
Case No. IPC-E-12-27
M. Larkin, IPC
Page 11 of 1'l
IDAHO Ieeued by IDAHO POWER COMPANY
lssueC per Order Ne, 30508 Jehn R"Gale; Viee Preeident; Regulatery Affairs
PgErr
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Exhibit No.6
Case No. IPC-E-12-27 to
M. Larkin, IPC c!
Page 1 of 1
atroII*,ooIJ
!to.Ya
I{r,tro5crot-
IJ-
REQUEST NO. 1: On pages 18-19 of Matt Larkin's testimony, he says'utilizing
the results of the Company's most current class costof-service study that was reviewed
in Case No. IPC-E-11-08, Schedule 6 and Schedule I reflect three primary
modifications to the collection of revenue requirement from Residential and Small
General Service net metering customers." Please provide the cost-of-service study
used to develop the proposed modifications. As part of your response, please explain
how the results of this study were specifically used to design rates.
RESPONSE TO REQUEST NO. 1: The Excel files AS Model- SI/P IPC-E-I1-
08.x/s ('AS Model") and FC Model- SI/P IPC-E-I1-08.x/s ('FC Model") provided on the
enclosed CD represent the class cost-of-service study reflecting the stipulated results of
the Company's last general rate filing, Case No. IPC-E-11-08. The entire study is
summarized on the "Unit Cost by Schedule" worksheet of the FC Model, which was
utilized to design the Company's proposed rates. The "Unit Cost by Schedule"
worksheet contains the Company's overall revenue requirement by customer class,
subdivided into the various operating functions (production, transmission, distribution)
and classifications (demand-related, energy-related, customer-related ).
The utilization of the class cost-of-service study to design the Company's
proposed rates is demonstrated in the Excel file Nef Meter Rate Development.xlsx, also
provided on the enclosed CD. The first worksheet in this file, "!PC-E-11-08,' contains a
summary of the functionalized classified revenue requirement from the class cost-of-
service study contained in the 'Unit Cost by Schedule" worksheet of the FC Model.
Column 1 of the'IPC-E-11-08" worksheet indicates the corresponding row numbers
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REOUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 2 Exhibit No. 7
Case No. IPC-E-12-27
M. Larkin, IPC
Page 1 of 235
from the detailed "Unit Cost by Schedule' worksheet that were summed to arrive at the
revenue requirement amounts listed in column 2 of the 'lPC-E-11-08" worksheet.
Columns 3 and 4 of the'|PC-E-11-08" worksheet adjust the cost-of-service
results to reflect the final approved revenue requirement by rate class from the ldaho
Public Utilities Commission's Final Order No. 32426 in Case No. IPC-E-11-08. Because
the settlement stipulation in Case No. IPC-E-11-08 resulted in a uniform percentage
increase to all rate classes, final approved revenue requirement amounts did not sum to
the class cost-of-service totals contained in the FC Model. Therefore, to properly
calculate rates in a manner consistent with the Company's approved revenue
requirement, columns 3 and 4 uniformly adjust the functionalized classified components
of the cost-of-service revenue requirement to reflect the final approved revenue
requirement that was ultimately used to set rates. Through this calculation, the
Company was able to determine the level of customer-related and demand-related
revenue requirement associated with the distribution system that is embedded in energy
rates currently in effect.
The 'Rate Design" worksheet in the Net Meter Rate Development.xlsx Excel file
calculates the Company's proposed Schedule 6 and Schedule I rates based on the
values contained in column 4 of the'!PC-E-11-08" worksheet. Column 1 of this
worksheet reflects billing units used to set the Company's currently-approved base rates
established in Case No. IPC-E-12-14. Column 2 contains current residential and small
general service rates, while column 3 calculates the Company's currently approved
revenue requirement by applying current rates to the billing units contained in column 1.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 3 Exhibit No. 7
Case No. IPC-E-12-27
M. Larkin, IPC
Page 2 of 235
Column 4 details the adjustments made to the current revenue requirement to
calculate rates for the proposed Schedules 6 and 8 by shifting customer-related and
demand-related revenue requirement associated with the distribution system from the
per kilowatt-hour ('kwh") energy charges into the proposed service charge and basic
load capacity ('BLC') charge, respectively. As detailed in column 4, revenue
requirement associated with the Service Charge and Basic Load Capacity charge was
adjusted upward, while revenue requirement associated with the per kWh energy
charges was adjusted downward, resulting in (1) a service charge that reflects the full
customer-related cost-of-service, (2) a BLC charge that reflects the full demand-related
cost-of-service associated with the distribution system, and (3) energy charges that
reflect the remaining components of revenue requirement. As detailed on lines 17 and
38 of column 4, this adjustment resulted in zero net impact to the overall revenue
requirement associated with each rate class.
Column 5 contains the final revenue requirement reflecting the adjustments
described above, while column 6 contains the Company's final proposed rates.
The response to this Request was prepared by Matthew T. Larkin, Regulatory
Analyst ll, ldaho Power Company, in consultation with Lisa D. Nordstrom, Lead
Counsel, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 4 Exhibit No. 7
Case No. IPC-E-12-27
M. Larkin, IPC
Page 3 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 4 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 5 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 6 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 7 of 235
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Page 8 of 235
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Page 14 of235
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Page 20 of 235
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Page 22 ol 235
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Case No. IPC-E-12-27
M. Lartin, IPC
Page 23 of 235
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Case No. IPC-E-12-27
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Page 33 of235
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Page 34 of 235
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Page 35 of 235
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Page 36 of 235
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M. Larkin, IPC
Page 37 of 235
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M. Larkin, IPC
Page 38 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 45 of235
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Page 46 of 235
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M. Larkin, IPC
Page 48 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 49 of 235
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Case No. IPC-E:12-27
M. Larkin, IPC
Page 50 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 51 of235
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Case No. IPC-E-12-27
M. Lartin, IPC
Page 52 of 235
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M. Larkin, IPC
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 85 of 235
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Page 87 of 235
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M. Larkin, IPC
Page 88 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 93 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 95 of 235
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M. Larkin, IPC
Page 96 of 235
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M. Larkin, IPC
Page 97 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 98 of235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 99 of235
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M. Larkin, IPC
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Case No. IPC-E:12-27
M. Larkin, IPC
Page 101 of235
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M. Larkin, IPC
Page 109 of235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 111 of235
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Page 112 ot 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 1 14 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 115 of235
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M. Larkin, IPC
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 117of235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 1 23 of 235
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M. Larkin, IPC
Page 125 of 235
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M. Larkin, IPC
Page 130 of 235
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Case No. IPC-E]12-27
M. Larkin, IPC
Page 131 of235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 1 32 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 1 33 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 134 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page '135 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 1 36 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 1 37 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 1 38 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 1 39 of 235
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Exhibit No. 7
Case No. IPC-E-12-27
M. Larkin, IPC
Page 140 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 141 of235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page'142 ot 235
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Exhibit No. 7
Case No. IPC-E-12-27
M. Larkin, IPC
Page 143 of235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 144 ol 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 145 of 235
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Exhibit No. 7
Case No. IPC-E-12-27
M. Larkin, IPC
Page 146 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 147 ot 235
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Exhibit No. 7
Case No. IPC-E-12-27
M. Larkin, IPC
Page 148 of235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 149 of 235
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M. Larkin, IPC
Page 150 of 235
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Case No. IPC-E:12-27
M. Larkin, IPC
Page 1 51 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 1 52 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 1 53 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 1 54 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page t 55 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 156 of 235
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Exhibit No. 7
Case No. IPC-E-12-27
M. Larkin, IPC
Page 157 of235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 1 58 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page '159 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 160 of235
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Case No. IPC-E-'12-27
M. Larkin, IPC
Page 16'l of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 163 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 164 of235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 165 of 235
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Case No. IPC-E:12-27
M. Larkin, IPC
Page 166 of235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 167 of235
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M. Larkin, IPC
Page 173 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 174 ol 235
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M. Larkin, IPC
Page 1 75 of 235
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Exhibit No. 7
Case No. IPC-E-12-27
M. Larkin, IPC
Page 1 76 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 177 ot 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 1 87 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 188 of235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 1 89 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 1 90 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 191 of235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 192 of235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 193 of235
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Case No. IPC-E-12-27
M. Lartin, IPC
Page 194 of235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 1 95 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 't 97 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 198 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 1 99 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 200 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 201 of235
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M. Larkin, IPC
Page 202 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 206 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page207 of235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 208 of 235
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Case No. IPC-Ej12-27
M. Larkin, IPC
Page 209 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 216 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
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Case No. IPC-E-12-27
M. Laftin, IPC
Page 220 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page221 ot235
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M. Larkin, IPC
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M. Larkin, IPC
Page 223 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 224 of 235
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Exhibit No. 7
Case No. IPC-E-12-27
M. Larkin, IPC
Page225 o1235
Exhibit No. 7
Case No. IPC-E-12-27
M. Larkin, IPC
Page 226 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 228 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 229 oI 235
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Exhibit No. 7
Case No. IPC-E-12-27
M. Larkin, IPC
Page 230 of 235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page 231 of235
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Case No. IPC-E-12-27
M. Larkin, IPC
Page232 ol 235
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Exhibit No. 7
Case No. IPC-E-12-27
M. Larkin, IPC
Page 233 of 235
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ldaho Power Company
Dewlopment of Pricing Proposal
Residential and Small General Net Metering Service
COS Rerrenue Requirement
(21
"Unit Gost by Schedule' Class COS Results Cap and Spread
Row Numbers per Stipulation Uniform
from FC Model Case No. !PC-E-ll-08 Adiustment
(3)(1)
Line
No.
Residential Service
Production
Demand
Energy
Transmission
Demand
Distribution
Demand
Customer
Other
Customer
Energy
Total
Small General Service
Production
Demand
Energy
Transmission
Demand
Distribution
Demand
Customer
Other
Customer
Energy
Total
9-1 1
13-14
18
23,25,28,31,33
26,29,32,34-36,38
41-43,47,56-58
54
69-71
73-74
78
83,85,88,91,e3
86,89,92,94-96,98
101-103,107,1 16-1 18
114
$88,687,817
$107,046,094
$39,491,942
$48,916,636
$65,207,031
$31,384,630
$720,999
$381 ,455,1 50
$2,079,774
$3,237,974
$956,095
$1,332,639
$5,701,529
$2,175,483
$21,432
$15,504,927
3.77o/o
3.77o/o
3.77o/o
3.77o/o
3.77o/o
3.77%
3-77o/o
395,848,470
(4)
Cap and Spread
Adjusted
Revenue Requirement
$92,034,245
$111,085,229
$40,982,079
$50,762,391
$67,667,466
$32,568,856
$748,20s
$3S5.848,470
$2,006,983
$3,124,ill
$922,632
$1,285,998
$5,s01,979
$2,099,343
$20,682
$14,962,264
1
2
3
4
5
6
7I
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
-3.50%
-3.50%
-3.50%
-3.50%
-3.50o/o
-3.50%
-3.s0%
14,962,264
Exhibit No. 7
Case No. IPC-E-12-27
M. Larkin, IPC
Page234 ot 235
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Exhibit No. 7
Case No. IPC-E-12-27
M. Larkin, IPC
Page 235 of 235
ldaho Power Gompany
Case No.[PCf-12-27
Resolution of Net Metering lnterconnection lssues
PART I.
ISSUES IDEilNHED BY IDA}IO GLEAN Ei{ERGYASSOCIANON
Schedule 72-7. Scction 2. APPLICATION PROCESS. Paraoraoh 4
As Fibd:
Upon completlon the Customer must provide all forms of documentation outlined in Section 1-1
above verifying that all Federal, state, and local requirements have been met. Customers must also
provide the C.ompany with final invoices for all lnstalled components of the completed Net Metering
System.
Resolution:
Upon completion the Customer must provide all forms of documentation oudined in Section 1-1
above verirying that all Federal, state, and local requirements have been met. Customers must also
prodde the Company with.a comoleteq Svstem Verification I dgtailing the specifications of all
installed components of the completed Net Metering System. Svstem Verification forms can be
found on the Compant's w€bsite or will be orovided uoon reouest.
Schedule 72-7. Ssction 2. APPLIGATIOI{ PROCESS. Paraoraoh 5b
As Filed:
Verification that the disconnect is functional and reconnection time is no less than five (5) minutes
Rosolution:
Verification that the disconnect is functional and reconnectlon time
L547
Scheduh 72€. Sec.tlon 2. RECERTIFIGATION. Paraoraoh t
Ar Fihd:
The Company will perform full recertification inspections of all Net Metering Systems once errery
three years. Recertification inspectlons will be performed in the same manner as neu Net Metering
si.s:+."fi.#€#gdL#w s
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. . :Elixrie8r.*+S
.,,+,--t+u r*r*.*i*Wp,*r,4u,l,{Xt, $
Exhibit No. 8
Case No.\PC-E-12-27
M. Larkin,lPC
Page 1 of7
l'! :'l--; ilt*iiq.4r 1,", :.j;ii:lrsi+iif 5;
System inspections described above. The Company reserves the right to inspect any Net Metering
System at any time.
ffiffili'
The Company will perform full recertification inspections of all Net Metering Systems once every
three years. Recertification inspections will be performed in the same manner as new Net Metering
System inspections described above. Custcnrers mav.n3ose tc rEii. inr.isLit, )i!:,il_!i]Ll3iiyj
inspection throueh an-independent insoection oerformed by a certified third-oartv at the
Custcrner's exoense. The Company reserves the right to inspect any Net Metering System at any
time.
Schedule 72-8. Section 2. NET METERING SYSTEM EXPANSIONS. Paraqraph 2
As Filed:
2. Customers wishing to install system expansions must submit a new application and S10O
application fee, and complete the application process according to the procedures required of a new
installation.
Resolution:
2. Customers wishing to install system expansions must submit a4application fcrn: and a S10O
Jeilsibilitv review and inslection fee, and complete the application process according to the
procedures required of a new installation.
Schedule 72-10. Section 2. UNAUTHORIZED INSTALLATIONS AND EXPANSIONS.
Paraqraph 3a
As Filed:
a. Customers may choose to disconnect Net Metering Systems from service. Customers choosing
to do so must receive confirmation from a State electrical inspector that the Net Metering System is
no longer operational and interconnected to the Company's system. The results ofthis inspection
must be provided to the Company prior to restoration of service.
Resolution:
a. *ISSUE PENDING FOLLOW-UP WITH THE STATE OF IDAHO.
Ddtf: i": .: Delettd: application
Exhibit No. 8
Case No. IPC-E-12-27
M. Larkin, IPC
Page 2 of 7
D Schedule 72-5. Sec{ion 1. first oaraoraph followinq "Ooeration of Disconnect
Equioment"
As Filed:
lf, in the reasonable opinion of the Company, the Seller's operation or maintenance of the
Generation Facility or lnterconnection Facilities is unsafe or may otherwise adversely affect the
Company's equipment, personnel, or service to its Customers, the Company may physically
disconnect the Seller's Generation Facility or lnterconnection Facilities by operation of the
disconnection device or by any other means the Company deems necessary to adequately
disconnect the Selle/s Generation and lnterconnection Facilities from the Company's system. At
such time as the unsafe condition is remedied or other condition adversely affecting the Company is
resolved to the Company's satisfaction, the interconnection will be restored.
Company Position:
While it was suggested that a requirement be added to the end of this paragraph indicating a
specific timeframe for restoration of interconnection, the Company does not believe such an
addition is appropriate. Restoration of service and/or interconnection has not been an issue with
the current tariff, and the Company is concerned that including a specific timeframe for restoration
would implement a service standard that is not present in any other service tariff. The Company
feels that the value added is less than the risk of setting an undesired precedent of committing to
specific time requirements for restoration of service.
PART II.
ISSUES IDENTIFIED BY IDAHO PUBLIC UTILITIES COMMISSION STAFF
Schedule 72-5. Section l. DISCONNECTION EQUIPMENT. Ooeration of Disconnection
Equioment. Paraqraoh 4
As Filed:
All expenses of disconnection and reconnection incurred by the Company will be billed to the Seller.
Staff Proposal:
AII expenses of disconnection and reconnection incurred by the Company as a resuit of a Ci:stom.lr' j
Net Metering Svstem and/or the Custorrer's failure tc acrde bv tlre prcvisrcns contained in Scheduie
72 will be billed to the Seller.
Exhibit No. 8
Case No. IPC-E-12-27
M. Larkin, IPC
Page 3 of 7
Gompany Position:
All expenses of disconnection and reconnection incurred by the Company will be billed to the Seller.
Net Meterins Customers will onlv be subiect to disconnection and reconnectlon charges if the
exoenses occurred as the result of a Cirstcmer's Net Metering Svstem and/or a Custocler's failure tJ
abide bv the orovisions of Schedule 72.
> Schedule 72-6. Section 2. APPLIGATION PROGESS. Paraoraph 1
As Filed:
1. Customers must submit a completed applicatlon form and 5100 application fee to the Company.
Applications are available on the Company's website.
Staff Proposal / Company Position: :
1. Customers must submit a completed application form and 5100 application fee to the Company.
Applications are available on the Company's website or will be provided to the Customer upon
request.
F Schedule 72-7. Section 2. APPLICATION PROCESS. Paraqraph 3
As Filed:
3. The Company will perform within a reasonable timeframe the Net Metering Feasibility Review
based on proiect information provided in the application.
Staff Proposal:
3. TheCompanywill performwithlnfive{5) br,sinessdaystheNetMeteringFeasibilityReview E;"d,",*-,-"ol"ti--.ro*----
based on project information provided in the application.
Gompany Position:
The Company is not opposed to a specific timeframe for performing the Net Metering Feasibility
Review. However, further internal discussion is needed to ensure that the timeframe is achievable
on a consistent basis.
>
As Filed:
5. Once all required documentation has been submitted, the Company will complete an on-site
inspection within ten (10) business days, subject to work constraints.
Exhibit No. 8
Case No. IPC-E-12-27
M. Larkin, IPC
Page 4 ot7
5. Once all required documentation has been submitted, the Company will complete an on-site
inspection within ten (10) business dayq
Company Position:
5. Once all required documentation has been submitted and the Comoaoy has verified that all
apol:cable Federal, state, and local requirements have been met, the Company will complete an on-
site inspection within ten (10) business dayq.
Schedule 72-8. Section 2. APPLICATION PROCESS. Paraqraph 6
6. Successful completion ofthe Company on-site inspection constitutes the conclusion ofthe
application process. The Customer will be moved to the appropriate Net Metering Service rate
schedule within three (3) business days, subject to work constraints.
Staff Proposal:
6. Successful completion of the Company on-site inspection constitutes the conclusion of the
application process. The Customer will be moved to the appropriate Net Metering Service rate
schedule within three (3) business day5r
Company Position:
The Company is not opposed to a set timeframe for the transfer of rate schedules, but needs more
time to discuss internallythe appropriate timeframe forthis portlon ofthe interconnection process.
Schedule 72-8. Section 2. APPLICATION PROCESS. lnspection Failure Process. Add
New Paraqraph 7
Staff Proposal I Company Position:
7- ln the event that a Net Metering System fails inspection, the system will be locked and a tag
providing Company contact information will be placed on the device. A Company representative will
then follow up via telephone with the Customer regarding the reason(s) for failure, and assist the
Customer in steps needed to bring the system into compliance with inspection requirements. Once
all issues have been addressed and the Customer indicates that the system has passed all applicable
Federal, state, and local requirements, ldaho Power will re-inspect the system.
I DeleEd:subjed to work constrainb
Deleted: , subjed to work coniraints
Exhibit No. 8
Case No. IPC-E-12-27
M. Larkin, IPC
Page 5 of 7
D Schedule 72-8. Section 2. RECERTIFICATION. Paraoraoh I
As Filed:
The Company will perform full recertification inspections of all Net Metering Systems once every
three years. Recertification inspections will be performed in the same manner as new Net Metering
System inspections described above. The Company reservesthe rightto inspect any Net Metering
System at any time.
Staff Proposal I Gompany Position:
The Company will perform full recertification inspections of all Net Metering Systems once every
three years aLne chxrgggqlhC.lcustgllel. The Comoanv will orovlde the Customer with written
notice at least fourteen (8) calendar davs prior to oerforming a recertification insoection.
Recertification inspections will be performed in the same manner as new Net Metering System
inspections described above. The Company reserves the right to inspect any Net Metering System
at anytime if cond:tions are unsafe or rnav otherwise adverselv afiect the Companv's eouioment,
personnel, or service to its ffi,
Schedule 72-9. Section 2. UNAUTHORIZED INSTALLATIONS AND EXPANSIONS.
Paraqraoh 2a
As Filed:
a. lf proper disconnection equipment is present, the Company will open and lock the disconnect
and provide written notice that the Net Metering System has been disconnected from the
Company's system. The Company will contact the Customer either in person or via telephone and
make the Customer aware of necessary steps to bring the system into compliance according to the
provisions of this Schedule. Upon completion of the full application process the system will be
reinstated.
Staff Proposal / Company Position:
a. lf proper disconnection equipment is present, the Company will open and lock the disconnecq
When the svstem is disconnected. the Companv will leave a tag on the svstem orovidinq the reason
for disconnection and Comoany contact information. A door hanser or card will also be left at the
front door at the time of disconnection. Within twentv-four {24) hours of the disconnection. the
Customer will be called and written notification will be sent via U.S. Mail. Upon completion of the
full application process the system will be reinstated.
Dd"Ed:-" J;.rd. t",ri.*,"*iiit'" ni
Meterint sysem h6 ben disonnected from the
CompanYs system
Del€bd: The company will contact the
Cu$omer either in persn or viatelephone and
make the Customer aware ofn*esrary steps to
brinS the sy5tem into compliance according to the
provisions of this Schedule,
Exhibit No. 8
Case No. IPC-E-12-27
M. Larkin,lPC
Page 6 of 7
SYSTEM VERIFICATION FORM FIELDS
Project lnfo
Account Holder
Project Name
Account Number
Project Address
Phone Number
Electrical Permit Number
Technology Type: PV, Wind, etc.
Total S)rstem Size/Name Plate Rating: (Should match the watts/modules etc. below)
lf Solar:
Number of Modules
Size of Modules (watts)
Tracker? (Y/N)
Battery Backup? (Y/N)
Panel Orientation
Degrees from Horizontal
lf Othen
Wind: Number of Turbines; Turbine Capacity (watts)
Hydro: Number of Generators; Capacity (watts)
I nverter Type/Brand/Model
ls inverter VL1741 or |EEE1547 listed?
lf not, what protection type.
Certification Requirements: Form must be completed by a licensed electrician, solar
company/installer, NABCEP certified individual or an engineer or other qualified persons as
accepted by ldaho Power. ln lieu of professional certification, documentation must be
provided including cut sheets and/or invoices for installed components. lf invoices are
provided, financial information (e.9. purchase price) is not required and can be redacted if
desired.
Exhibit No. 8
Case No. IPC-E-12-27
M. Larkin, IPC
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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE
APPLICATION OF IDAHO POWER
COMPANY FOR AUTHORITY TO
MODIFT ITS NET METER]NG
SERVICE AND TO INCREASE THE
GENERATION CAPACITY LIMIT.
CASE NO. IPC.E.I2-27
Idaho Conservation League
Direct Testimony of R. Thomas Beach
May 10,2013
EXHIBIT 201
CURICI,'LUM VITA FOR R. THOMAS BEACH
R. THOMAS Br.IcrT
Principal Consultant Page 1
Mr. Beach is principal consultant with the consulting firm Crossborder Energy. Crossborder
Energy provides economic consulting services and strategic advice on market and regulatory
issues concerning the natural gas and electric industries. The firm is based in Berkeley,
California, and its practice focuses on the energy markets in California, the western U.S.,
Canada, and Mexico.
Since 1989, Mr. Beach has participated actively in most of the major energy policy debates in
California, including renewable energy development, the restructuring of the state's gas and
electric industries, the addition of new natural gas pipeline and storage capacity, and a wide
range of issues concerning California's large independent power community. From 1981
through 1989 he served at the California Public Utilities Commission, including five years as an
advisor to three CPUC commissioners. While at the CPUC, he was a key advisor on the
CPUC's restructuring of the natural gas industry in California, and worked extensively on the
state's implementation of PURPA.
Annls oF EXPERTTSE
Califomia's Renewable Portfolio Standard program, including the calculation of the
state's Market Price Referent for new renewable generation. He has also worked for the
solar industry on the creation of the Califomia Solar Initiative (the Million Solar Roofs),
as well as on a wide range of solar issues in other states.
on numerous issues involving the restructuring of the electric industry, including the
2000 - 2001 Western energy crisis.
markets, including the impacts of new pipeline capacity on natural gas prices and of
electric restructuring on wholesale electric prices.
involving independent power facilities in the Western U.S. He is one of the leading
experts in Califomia on the calculation of avoided cost prices. Other QF issues on
which he has worked include complex QF contract restructurings, electric transmission
and interconnection issues, property tax matters, standby rates, QF effrciency standards,
and natural gas rates for cogenerators. Crossborder Energy's QF clients include the full
range of QF technologies, both fossil-fueled and renewable.
pipeline rates and on marginal cost-based rates for natural gas and electric utilities.
Crossborder Energ,t
R. THOMAS Br.ICrT
Principal Consultant Page 2
Eoucarrox
Mr. Beach holds a B.A. in English and physics from Dartmouth College, and an M.E. in
mechanical engineering from the University of California at Berkeley.
Aclnrurc HoNoRS
Graduated from Dartmouth with high honors in physics and honors in English.
Chewon Fellowship, U.C. Berkeley, 1978-79
PRornssroNAL Accnrormuox
Registered professional engineer in the state of Califomia.
Expnnr Wrrxrss Trsrrnnoxy BEFoRE THE CPUC
1.Prepared Direct Testimony on Behalf of Pacific Gas & Electric Company/PaciIic Gas
Transmission (I. 88-12-027 - July 15, 1989)
. Competitive and environmental beneJits of new natural gas pipeline capacity to
Califurnia.
a. Prepared Direct Testimony on Behalf of the Canadian Producer Group (A.
89-08-024 - November 10, 1989)b. Prepared Rebuttal Testimony on Behalf of the Canadian Producer Group (A.
89-08-024 - November 30, 1989)
. Natural gas procurement policy; gas costforecasting.
Prepared Direct Testimony on Behalf of the Canadian Producer Group (R. 88-08-018
- December 7, 1989)
. Brokering of interstate pipeline capacity.
Prepared Direct Testimony on Behalf of the Canadian Producer Group (A. 90-08-029
-November l, 1990)
. Natural gas procurement policy; gas costforecasting; brokerage fees.
Prepared Direct Testimony on Behalf of the Alberta Petroleum Marketing
Commission and the Canadian Producer Group (I. 86-06-005 - December 21,1990)
. Firm and interruptible rates for noncore natural gas users
2.
J.
4.
5.
Crossborder Energt
R. TnouAS Bnlcr
Principal Consultant
6.
7.
8.
9.
10.
11.
12.
13.
a. Prepared Direct Testimony on Behalf of the Alberta Petroleum Marketing
Commission (R. 88-08-018 - January 25,1991)b. Prepared Responsive Testimony on Behalf of the Alberta Petroleum Marketing
Commission (R. 88-08-018 - March 29,l99l)
. Brokering of interstate pipeline capacity; intrastate transportation policies.
Prepared Direct Testimony on Behalf of the Canadian Producer Group (A.
90-08-029lPhase II - April 17, I99l)
. Natural gas brokerage and transportfees.
Prepared Direct Testimony on Behalf of LVZ Partnership Management (A.91-01-027
-July 15, 1991)
. Natural gas parity rates for cogenerators and solar powerplants.
Prepared Joint Testimony of R. Thomas Beach and Dr. Robert B. Weisenmiller on Behalf
of the California Cogeneration Council (I. 89-07-004 - July 15, l99l)
Avoided cost pricing; use of published natural gas price indices to set avoided
c o s t pr ic e s for qual ifying fac il iti e s.
a. Prepared Direct Testimony on Behalf of the Indicated Expansion Shippers (A.
89-04-033 - October 28,1991)b. Prepared Rebuttal Testimony on Behalf of the Indicated Expansion Shippers
(A. 89-04-0033 - November 26,1991)
o Natural gas pipeline rate design; cost/benefit analysis of rolled-in rates.
Prepared Direct Testimony on Behalf of the Independent Petroleum Association of
Canada (A. 91-04-003 - January 17,1992)
. Natural gas procurement policy; prudence ofpast gas purchases.
a. Prepared Direct Testimony on Behalf of the California Cogeneration Council
(I.86-06-005/Phase II - June 18,1992)b. Prepared Rebuttal Testimony on Behalf of the California Cogeneration Council
(I. 86-06-005/Phase II - July 2,1992)
. Long-Run Marginal Cost (LRMC) rate designfor natural gas utilities.
Prepared Direct Testimony on Behalf of the California Cogeneration Council (A.
92-10-017 -February 19, 1993)
. Performance-basedratemaking.forelectricutilities.
Crossborder Energ,t
15
16.
17.
18.
t9.
20.
2t.
R. TrroM,q.s Bp.lcn
Principal Consultant Page 4
14. Prepared Direct Testimony on Behalf of the SEGS Projects (C. 93-02-0141A.93-03-053
-May 21,1993)
. Natural gas transporiation service for wholesale customers.
a. Prepared Direct Testimony on Behalf of the Canadian Association of Petroleum
Producers (A. 92-12-043 I A. 93-03-03 8 - June 28, 1993)b. Prepared Rebuttal Testimony of Behalf of the Canadian Association of
Petroleum Producers (A. 92-12-043 I A. 93-03-03 8 - July 8, 1 993)
. Natural gas pipeline rate design issues.
a. Prepared Direct Testimony on Behalf of the SEGS Projects (C. 93-05-023 -November 10, 1993)b. Prepared Rebuttal Testimony on Behalf of the SEGS Projects (C. 93-05-023 -January 10,1994)
. Utility overcharges for natural gas service; cogeneration parity issues.
Prepared Direct Testimony on Behalf of the City of Vernon (A. 93-09-0061A.
93-08-0221 A. 93-09-048 - June I 7, 1994)
. Natural gas rate designfor wholesale customers; retail competition issues.
Prepared Direct Testimony of R. Thomas Beach on Behalf of the SEGS Projects (A.
94-01-021 - August 5, 1994)
. Natural gas rate design issues; rate parityfor solar power plants.
Prepared Direct Testimony on Transition Cost Issues on Behalf of Watson Cogeneration
Company (R. 94-04-031/1.94-04-032 - December 5,1994)
. Policy issues concerning the calculation, allocation, and recovery of transition
costs associated with electric industry restructuring.
Prepared Direct Testimony on Nuclear Cost Recovery Issues on Behalf of the California
Cogeneration Council (A. 93-12-025/1.94-02-002 - February 14,1995)
. Recovery of above-market nuclear plant costs under electric restructuring.
Prepared Direct Testimony on Behalf of the Sacramento Municipal Utility District (A.
94-l l-015 - June 16, 1995)
. Natural gas rate design; unbundled mainline transportation rates.
Crossborder Energt
R. TnouAs Br.lcr
Principal Consultant Page 5
22. Prepared Direct Testimony on Behalf of Watson Cogeneration Company (A. 95-05-049
- September 11, 1995)
. Incremental Energt Rates; air quality compliance costs.
23. a. Prepared Direct Testimony on Behalf of the Canadian Association of Petroleum
Producers (A. 92-12-043 I A. 93 -03 -03 8/A. 94-05-03 5 I A. 94-06-0341 A.
94-09 -056 I A. 94-06-044 - January 30, 1996)b. Prepared Rebuttal Testimony on Behalf of the CanadianAssociation of
Petroleum Producers (A. 92-12-043 I A. 93-03-03 8/A . 94-05 -03 5 I A.
94-06-0341A. 94-09-0561A.94-06-044 - February 28, 1996)
. Natural gas market dynamics; gas pipeline rate design.
24. Prepared Direct Testimony on Behalf of the California Cogeneration Council and
Watson Cogeneration Company (A. 96-03-031 - July 12,1996)
. Natural gas rate design: parity rates for cogenerators.
25. Prepared Direct Testimony on Behalf of the City of Vernon (A. 96-10-038 -August 6,
teeT)
Impacts of a major utility merger on competition in natural gas and electric
markets.
Prepared Direct Testimony on Behalf of the Electricity Generation Coalition
(A.97-03-002 - December 18,1997)
Prepared Rebuttal Testimony on Behalf of the Electricity Generation Coalition
(A. 97-03-002 - January 9, 1998)
Natural gas rate designfor gas-fired electric generators.
Prepared Direct Testimony on Behalf of the City of Vernon (A. 97-03-015 - January
16, 1998)
. Natural gas service to Baja, California, Mexico.
26. a.
b.
27.
Crossborder Energt
R. THOMAS BnlcH
Principal Consultant Page 6
28. a. Prepared Direct Testimony on Behalf of the California Cogeneration Council
and Watson Cogeneration Company (A. 98-10-0121 A. 98-10-03 l/A. 98-07-005
- March 4,1999).b. PreparedDirect Testimony on Behalf of the California Cogeneration Council
(A. 98-10-0121 A. 98-01-03 1/A. 98-07-005 - March 15, 1999).c. Prepared Direct Testimony on Behalf of the California Cogeneration Council
(A. 98-10-0121A.98-01-031/A. 98-07-005 - June 25,1999).
. Natural gas cost allocation and rate designfor gas-fired electric generators.
PreparedDirect Testimony on Behalf of the California Cogeneration Council
and Watson Cogeneration Company (R. 99-l l-022 - February 11,2000).
Prepared Rebuttal Testimony on Behalf of the California Cogeneration Council
and Watson Cogeneration Company (R. 99-11-022 - March 6,2000).
Prepared Direct Testimony on Line Loss Issues of behalf of the California
Cogeneration Council (R. 99-11-022 - April 28,2000).
Supplemental Direct Testimony in Response to ALJ Cooke's Request on behalf
ofthe California Cogeneration Council and Watson Cogeneration Company
(R. 99-11-022 - April 28,2000).
Prepared Rebuttal Testimony on Line Loss Issues on behalf of the California
Cogeneration Council (R. 99-11-022 - May 8,2000).
Market-based, avoided cost pricingfor the electric output of gas-fired
cogenerationfacilities in the California market; electric line losses.
Direct Testimony on behalf of the Indicated Electric Generators in Support of
the Comprehensive Gas OII Settlement Agreement for Southern California Gas
Company and San Diego Gas & Electric Company (I. 99-07-003 - May 5,
2000).
Rebuttal Testimony in Suppon of the Comprehensive Settlement Agreement on
behalf of the Indicated Electric Generators (I. 99-07-003 - May 19, 2000).
Testimony in support of a comprehensive restructuring of natural gas rates and
services on the Southern Califurnia Gas Company system. Natural gas cost
allocation and rate designfor gas-fired electric generators.
Prepared Direct Testimony on the Cogeneration Gas Allowance on behalf of the
California Cogeneration Council (A. 00-04-002 - September 1, 2000).
Prepared Direct Testimony on behalf of Southern Energr California (A.
00-04-002 - September 1, 2000).
Natural gas cost allocation and rate designfor gas-fired electric generators.
29. a.
b.
c.
d.
31. a.
b.
e.
30.
b.
Crossborder Energt
R. THoMAS Brlcs
Principal Consultant PaseT O
32. a. Prepared Direct Testimony on behalf of Watson Cogeneration Company (A.
00-06-032 - September 1 8, 2000).b. Prepared Rebuttal Testimony on behalf of Watson Cogeneration Company (A.
00-06-032 - October 6,2000).
. Rate designfor o natural gas "peaking service."
33. a. Prepared Direct Testimony on behalf of PG&E National Enerry Group &
Calpine Corporation (I. 00- 1 1 -002-April 25, 2001).b. Prepared Rebuttal Testimony on behalf of PG&E National Enerry Group &
Calpine Corporation (I. 00-11-002-May 15, 2001).
. Terms and conditions of natural gas service to electric generators; gas
curtailment policies.
34. a. Prepared Direct Testimony on behalf of the California Cogeneration Council
(R. 99-l l-022-May 7,2001).b. Prepared Rebuttal Testimony on behalf of the California Cogeneration Council
(R. 99-l l-022-I|if.ay 30, 2001).
. Avoided cost pricingfor alternative energl producers in California.
35. a. Prepared Direct Testimony of R. Thomas Beach in Support of the Application of
WiId Goose Storage Inc. (A. 0l-06-029-June 18,2001).b. Prepared Rebuttal Testimony of R. Thomas Beach on behalf of Wild Goose
Storage (A. 0 I -06-029-Novemb er 2, 2001)
. Consumer benefits from expanded natural gas storage capacity in Califurnia.
36. Prepared Direct Testimony of R. Thomas Beach on behalf of the County of San
Bernardino (I. 0l-06-047-December 14, 2001)
. Reasonableness review of a natural gas utility's procurement practices and
storage operations.
37. a. Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Cogeneration Council (R. 0 I - 1 0 -024-May 3 l, 2002)b. Prepared Supplemental Testimony of R. Thomas Beach on behalf of the
California Cogeneration Council (R. 0 1 - I 0 -024-May 3 l, 2002)
. Electric procurement policies for Califurnia's electric utilities in the aftermath of
the California energ,t crisis.
Crossborder Energ,t
R. TnourAS BsA,cH
Principal Consultant Page 8
38. Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Manufacturers & Technolory Association (R. 02-01-01l-June 6,2002)
. "Exitfees" for direct occess customers in California.
39. Prepared Direct Testimony of R. Thomas Beach on behalf of the County of San
Bernardino (A. 02-02-012 - August 5,2002)
. General rate case issues "for a natural gas utility; reasonableness review of a
natural gas utility's procurement practices.
40. Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Manufacturers and Technolory Association (A. 98-07-003 - February 7,2003)
o Recoyery of past utility procurement costs from direct access customers.
41. a. Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Cogeneration Council, the California Manufacturers & Technolory
Association, Calpine Corporation, and Mirant Americas,Inc. (A 01-10-011
-February 28,2003)b. Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the California
Cogeneration Council, the California Manufacturers & Technology
Association, Calpine Corporation, and Mirant Americasr lnc. (A 01-10-011
-March 24,2003)
. Rate design issues for PaciJic Gas & Electric's gos transmission system (Gas
Accord II).
a. Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Manufacturers & Technologr Association; Calpine Corporation; Duke
Enerry North America; Mirant Americasr lnc.; Watson Cogeneration
Company; and West Coast Power,Inc. (R. 02-06-041- March 21,2003)b. Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the California
Manufacturers & Technolory Association; Calpine Corporation; Duke
Enerry North America; Mirant Americasr lnc.; Watson Cogeneration
Company; and West Coast Power,Inc. (R. 02-06-041- April 4,2003)
. Cost allocation of above-market interstate pipeline costs for the Califurnia
natural gas utilities.
Prepared Direct Testimony of R. Thomas Beach and Nancy Rader on behalf of the
California Wind Energy Association (R. 01-10-024 - April 1, 2003)
. Design and implementation of a Renewable Portftlio Standard in Califurnia.
42.
43.
Crossborder Energt
44. a.
b.
R. THOMAS Boacn
Principal Consultant Page 9
PreparedDirect Testimony of R. Thomas Beach on behalf of the California
Cogeneration Council (R. 01-10-024 - h:rlre 23,2003)
Prepared Supplemental Testimony of R. Thomas Beach on behalf of the
California Cogeneration Council (R. 01-10-024 - June29,2003)
Power procurement policies for electric utilities in California.
Prepared Direct Testimony of R. Thomas Beach on behalf of the Indicated Commercial
Parties (02-05-004 - August 29,2003)
Electric revenue allocation and rate designfor commercial customers in southern
Califurnia.
Prepared Direct Testimony of R. Thomas Beach on behalf of Calpine
Corporation and the California Cogeneration Council (A. 04-03-021 - July
t6,2004)
Prepared Rebuttal Testimony of R. Thomas Beach on behalf of Calpine
Corporation and the California Cogeneration Council (A. 04-03-021 - July
26,2004)
Policy and rate design issues for Pacific Gas & Electric's gos transmission
system (Gas Accord IID.
Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Cogeneration Council (A. 04-04-003 - August 6,2004)
. Policy and controct issues concerning cogeneration QFs in Califurnia.
a. Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Cogeneration Council and the California Manufacturers and Technolory
Association (A. 04-07-044 - January 11, 2005)b. Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the California
Cogeneration Council and the California Manufacturers and Technolory
Association (A. 04-07-044 - January 28,2005)
c Natural gas cost allocation and rate designfor large transportation customers in
northern Califtrnia.
a. Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Manufacturers and Technolory Association and the Indicated Commercial
Parties (A. 04-06-024 - March 7, 2005)b. Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the California
Manufacturers and Technologr Association and the Indicated Commercial
Parties (A. 04-06-024 - April26,2005)
. Electric marginal costs, reyenue allocation, and rate designfor commercial and
industrial electric customers in northern California.
45.
46.
47.
48.
a.
49.
Crossborder Energt
R. THOMAS BnICTT
Principal Consultant Page 10
52. a.
b.
50.
51.
54.
55.
56.
Prepared Direct Testimony of R. Thomas Beach on behalf of the California Solar
Enerry Industries Association (R. 04-03-017 - April28, 2005)
. Cost-effectiveness of the Million Solar Roofs Program.
Prepared Direct Testimony of R. Thomas Beach on behalf of Watson Cogeneration
Company, the Indicated Producers, and the California Manufacturing and
Technolory Association (A. 04-12-004 - July 29,2005)
Natural gas rate design policy; integration of gas utility systems.
Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Cogeneration Council (R. 04-04-003/R. 04-04-025 - August 31, 2005)
Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the California
Cogeneration Council (R. 04-04-003/R. 04-04-025 - October 28,2005)
Avoided cost rates and contracting policies for QFs in Califurnia
Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Manufacturers and Technolory Association and the Indicated Commercial
Parties (A. 05-05-023 - January 20,2006)b. Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the California
Manufacturers and Technolory Association and the Indicated Commercial
Parties (A. 05-05-023 - February 24,2006)
. Electric marginal costs, revenue allocation, and rate designfor commercial and
industrial electric customers in southern Califurnia.
a. Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Producers ( R. 04-08-018 -January 30,2006)b. Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the California
Producers ( R. 04-08-018 - February 21"2006)
. Transportation and balancing issues concerning Califurnia gas production.
Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Manufacturers and Technolory Association and the Indicated Commercial Parties
(A. 06-03-005 - October 27,2006)
. Electric marginal costs, revenue allocation, and rate designfor commercial and
industrial electric customers in northern Califurnia.
Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Cogeneration Council (A. 05-12-030 - March 29,2006)
. Review and approval of a new contract with a gas-fired cogeneration project.
a.53.
Crossborder Energt
R. THOMAS BrIcu
Principal Consultant Page 11
57.Prepared Direct Testimony of R. Thomas Beach on behalf of Watson
Cogeneration, Indicated Producers, the California Cogeneration Council,
and the California Manufacturers and Technolory Association (A. 04-12-004
-July 14,2006)
Prepared Rebuttal Testimony of R. Thomas Beach on behalf of Watson
Cogeneration, Indicated Producers, the California Cogeneration Council,
and the California Manufacturers and Technolory Association (A. 04-12-004
-July 31,2006)
Restructuring of the natural gas system in southern California to include firm
capacity rights; unbundling of natural gas services; risk/reward issues for
natural gas utilities.
Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Cogeneration Council (R. 06-02-013 - March 2,2007)
' Utility procurement policies concerning gas-fired cogenerationfacilities.
a. Prepared Direct Testimony of R. Thomas Beach on behalf of the Solar Alliance
(A.07-01-047 - August 10,2007)
Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the Solar
Alliance (A. 07-01-047 - September 24,2007)
Electric rate design issues that impact customers installing solar photovoltaic
systems.
Prepared Direct Testimony of R,. Thomas Beach on Behalf of Gas Transmission
Northwest Corporation (A. 07-12-021- May 15, 2008)
Prepared Rebuttal Testimony of R,. Thomas Beach on Behalf of Gas
Transmission Northwest Corporation (A. 07-12-021- June 13, 2008)
Utility subscription to new natural gas pipeline capacity sertting Califtrnia.
a. Prepared Direct Testimony of R. Thomas Beach on behalf of the Solar Alliance
(A.08-03-015 - September 12,2008)b. Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the Solar
Alliance (A. 08-03-015 - October 3, 2008)
' Issues concerning the design of a utility-sponsored program to install 500 MW of
utility- and independently-owned solar photovoltaic systems.
Prepared Direct Testimony of R. Thomas Beach on behalf of the Solar Alliance (A.
08-03-002 - October 31, 2008)
58.
59.
61.
62.
b.
60. a.
b.
Crossborder Energ,t
R. THOMAS BN,ICH
Principal Consultanl Page ]!
a.
b.
63.
Electric rate design issues that impact customers installing solar photovoltaic
systems.
Phase II Direct Testimony of R. Thomas Beach on behalf of Indicated
Producers, the California Cogeneration Council, California Manufacturers
and Technolory Association, and Watson Cogeneration Company (A.
08-02-001 - December 23,2008)
Phase II Rebuttal Testimony of R. Thomas Beach on behalf of Indicated
Producers, the California Cogeneration Council, California Manufacturers
and Technolory Association, and Watson Cogeneration Company (A.
08-02-001 - January 27,2009)
Natural gas cost allocation and rate design issues for large customers.
Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Cogeneration Council (A. 09-05-026 - November 4,2009)
Natural gas cost allocation and rate design issues for large customers.
Prepared Direct Testimony of R. Thomas Beach on behalf of Indicated
Producers and Watson Cogeneration Company (A. 10-03-028 - October 5,
2010)b. Prepared Rebuttal Testimony of R. Thomas Beach on behalf of Indicated
Producers and Watson Cogeneration Company (A. 10-03-028 - October 26,
2010)
o Revisions to a program offirm backbone capacity rights on natural gas pipelines.
Prepared Direct Testimony of R. Thomas Beach on behalf of the Solar Alliance (A.
10-03-014 - October 6,2010)
. Electric rate design issues that impact customers installing solar photovoltaic
systems.
Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the Indicated Settling
Parties (A. 09-09-013 - October 11, 2010)
. Testimony on proposed modifications to a broad-based settlement of rate-related
issues on the Pacific Gas & Electric natural gas pipeline system.
64.
65.
66.
67.
Crossborder Energ,t
R. THOMAS Bnlctr
Principal Consultant Page 13
68. a.
b.
Supplemental Prepared Direct Testimony of R. Thomas Beach on behalf of
Sacramento Natural Gas Storage, LLC (A. 07-04-013 - December 6,2010)
Supplemental Prepared Rebuttal Testimony of R. Thomas Beach on behalf of
Sacramento Natural Gas Storage, LLC (A. 07-04-013 - December 13, 2010)
Supplemental Prepared Reply Testimony of R. Thomas Beach on behalf of
Sacramento Natural Gas Storage, LLC (A. 07-04-013 - December 20,2010)
Local reliability benefits of a new natural gas storage fucility.
ExpBRr WIrNrss TBsrruoNy BEFoRE rnB ColoRADo Puruc Urrr,rrrns Covrvussrolr
l.Direct Testimony and Exhibits of R. Thomas Beach on behalf of the Colorado Solar
Energy Industries Association and the Solar Alliance, (Docket No. 09AL-2998 - October
2,2009).
. Electric rate design policies to encourage the use of distributed solar generation.
Direct Testimony and Exhibits of R. Thomas Beach on behalf of the Vote Solar Initiative
and the Interstate Renewable Energy Council, (Docket No. 1 1A-418E - September 21,
20tr).
. Development of a community solar programfor Xcel Energt.
ExprRr WtrNBss Tnsrrvroxy BEFoRE THE PuBLrc SERvrcE CovtvrlsstoN oF Npv.q.oa
1.Pre-filed Direct Testimony on Behalf of the Nevada Geothermal Industry Council
(Docket No. 97-200 l-May 28, 1997)
. Avoided cost pricingfor the electric output of geothermal generationfacilities in
Nevada.
Pre-filed Direct Testimony on Behalf of Nevada Sun-Peak Limited Partnership
(Docket No. 97-6008-September 5, 1997)
Pre-filed Direct Testimony on Behalf of the Nevada Geothermal Industry Council
(Docket No. 98-2002 - June 1 8, 1998)
. Market-based, avoided cost pricingfor the electric output of geothermal
gener ati on fac il iti e s in N ev ada.
c.
2.
2.
3.
Crossborder Energt
R. THOMAS BnIcrr
Principal Consultant Page 14
Expsnr Wrrxnss TpsuuoxvBpronr rnB Nnw MBxrco Pusl,rc Rpcur,.lrtoN CopruISSIoN
l.Direct Testimony of R. Thomas Beach on Behalf of the Interstate Renewable Enerry
Council (Case No. I 0-00086-UT-February 28, 201 l)
. Testimony on proposed standby rates for new distributed generation projects;
cost-ffictiveness of DG in New Mexico.
Direct Testimony and Exhibits of R. Thomas Beach on behalf of the New Mexico
Independent Power Producers, (Case No. I l-00265-UT, October 3,2011)
. Cost capfor the Renewable Portfolio Standard progrom in New Mexico
ExpBRr WrrxBss TrsrrvroNv Brronr rnrc Punlrc UrrLrrIES CoMMISSIoN oF Onrcon
1.DirectTestimony of Behalf of Weyerhaeuser Company (UM 1129 -August 3,
2004)
Surrebuttal Testimony of Behalf of Weyerhaeuser Company (UM I129 -October 14,2004)
Direct Testimony of Behalf of Weyerhaeuser Company and the Industrial
Customers of Northwest Utilities (UM ll29 lPhase II - February 27,2006)
Rebuttal Testimony of Behalf of Weyerhaeuser Company and the Industrial
Customers of Northwest Utilities (UM ll29 lPhase II - April 7,2006)
Policies to promote the development of cogeneration and other qualifying
facilrties in Oregon.
ExpnRr WrrxBss Trsrrvroxv Bpponr rHr VrRcrxr.l ConpoRATroN Coutvrrssrou
1. Direct Testimony and Exhibits of R. Thomas Beach on Behalf of the Maryland - District
of Columbia - Virginia Solar Energy Industries Association, (Case No.
PUE-201 l-00088, October I l, 201l)
. Standby rates for net-metered solar customers, and the cost-effectiyeness of net
metering.
a.
b.
a.
b.
Crossborder Energt
R. THOMAS BslcH
PrincipalConsultant Page 15
Lrrrcarrox ExpnRrpxcs
Mr. Beach has been retained as an expert in a variety of civil litigation matters. His work
has included the preparation of reports on the following topics:
. The calculation of damages in disputes over the pricing terms of natural gas sales
contracts (2 separate cases).
. The valuation of a contract for the purchase of power produced from wind generators.
. The compliance of cogeneration facilities with the policies and regulations applicable to
Qualifuing Facilities (QFs) under PURPA in California.
. Audit reports on the obligations of buyers and sellers under direct access electric
contracts in the California market (2 separate cases).
. The valuation of interstate pipeline capacity contracts (3 separate cases).
In several of these matters, Mr. Beach was deposed by opposing counsel. IvIr. Beach has also
testified at trial in the bankruptcy of a major U.S. energy company, and has been retained as a
consultant in anti-trust litigation conceming the Califomia natural gas market in the period prior
to and during the 2000-2001 California energy crisis.
Crossborder Energ,,
BEFORE THE IDAHO PUBLIC UTITITIES COMMISSION
IN THE MATTER OF THE
APPLICATION OF IDAHO POWER
COMPANY FOR AUTHORJTY TO
MODIFT ITS NET METERING
SERVICE AND TO INCREASE THE
GENERATION CAPACITY LIMIT.
CASE NO. IPC-E-I2-27
Idaho Conservation League
Direct Testimony of R. Thomas Beach
May 10,2013
EXHIBIT 202
EVALUATION OF NET METERING IN VERMONT CONDUCTED PURSUANT TO ACT I25
oF 2012
VERMONT PUBLIC SERVICE DEPARTMENT
JANUARY t5,20t3
Evaluation of Net Metering in Vermont
Conducted Pursuant to Act L 25 of 20Lz
Public Service Department
January t5,2OL3
o
I Introduction
Act 125 of the 2012 Vermont legislative session directed the Public Service Department (Department) to
complete an evaluation of net metering in Vermont:
No loter than January L5, 2013, the deportment of public service (the deportment) sholl perform
a general evaluotion of Vermont's net metering stotute, rules, and procedures ond shall submit
the evaluation ond any occompanying recommendations to the generol ossembly. Among ony
other issues reloted to net metering that the department mqy deem relevont, the report shall
include an analysis of whether ond to what extent customers using net metering systems under
30 V.S.A. 5 279a ore subsidized by other retail electric customers who do not employ net
metering. The analysis also shall include an examination of ony benefits or costs of net metering
systems to Vermont's electric distribution ond transmission systems ond the extent to which
customers owning net metering systems do or do not contribute to the fixed costs of Vermont's
retoil electric utilities. Prior to completing the evaluation ond submitting the report, the
deportment shall offer on opportunity for interested persons such os the retoil electric utilities
ond renewable energy developers ond advocotes to submit informotion and comment.
The Department undertook several steps to address the legislative request and evaluate Vermont's net
metering statute, rules, and procedures. Background and current statistics regarding net metering in
Vermont are presented in Section 2 of this report. Section 3 describes the analysis the Department
conducted to evaluate whether, and to what extent, customers employing net metering are subsidized
by other customers. Section 4 concludes the report with a general assessment of the state's net
metering statute, rules, and procedures.
The Department issued a Request for lnformation, focused on the cross-subsidization analysis but
welcoming comments on all aspects of the study, on September t7 ,2OL2. The results and analysis
reported here were informed by comments submitted by eleven interested persons, organizations, and
businesses (including utilities and renewable energy advocates). The Department also held several
meetings with commenters to better understand their comments and solicit further information. The
Department also received stakeholder comments on both the draft report document and draft
spreadsheettool, both of which were released on December21-,2O!2.
2 Background
2.L A Brief History of Net Metering in Vermont
The 1998 legislative session enacted a net metering law (30 V.S.A. 5219a), requiring electric utilities to
permit customers to generate their own power using small-scale renewable energy systems of 1.5 kW or
Iess (including fuel cells using a renewable fuel). Farm systems were allowed to be larger, with a cap of
100 kW. Any power generated by these systems could be fed back to the utility, running the electric
meter backwards, if generation exceeded load at any given time.
Amendments in 1999, 2002 and 2008 permitted the installation of more net metered capacity,
increased the allowable size of systems, and added the use of non-renewably fueled combined heat and
power units of 20 kW or less. Beginning in 2OO2 "group net metering" was allowed, but was restricted
to farmers. The 2008 amendments lifted this restriction, increased the permissible size per installation
to 250 kW, simplified the permitting process for systems under 150 kW, and raised the ceiling on the
total installed capacity from one percent to two percent of peak load. ln 201L, the Vermont General
Assembly expanded the permissible size limit per installation to 500 kW, simplified the administration
for net metering groups, allowed a registration process for photovoltaic (PV) systems 5 kW and under,
increased the overall net metering capacity cap per utility to 4 percent of the 1996 utility system peak or
previous year's peak (whichever is higher), and created a solar credit payment for all customers who
have installed PV net metered systems. The solar credit payment has the effect of increasing the value
of generation to net metered customers up to 20 cents per kWh in the year the system is installed.
During the 2012 session the registration process was expanded to PV projects 10 kW and under, and the
process for group net metering billing and monetization of credits was clarified.
2.2 Status of Net Metering in Vermont
Net metering has experienced rapid growth over the last four years as the demand for local renewable
energy has grown, costs have come down, and access to renewables has broadened. As can be seen in Figure
1, solar PV has had the most substantial growth of all the renewable technologies. The number of PV
systems applying for net metering permits annually has grown by a factor of more than four since 2008.
Net Metering Applications Per Year
Figure t. Number of net metering opplicotions & registrations onnuolly. (2072 dato os of 72/5/72.)
With the recent rise in number of PV installations, solar now accounts for almost 88% of all net metering
systems. Wind turbines represent under 8% of the systems and hydro just 3% (see figure 2.)
Net Metered Capacity
by Type
Irr
0
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2
100
II I
I
-rIIIIIIIII
1999 2000 200t 2002 2003 2004 200s 2006 2007 2008 2009 20LO 2017 20L2
I Methane 0 0 0 0 0 I 0 0 0 L 2 2 0 2
IWind 5 L 5 4 11 11 18 18 29 2t L7 L2 4 8
I Solar 9 18 17 L2 19 39 57 50 90 140 226 425 358 603
Figure 2. Net metering dpplications & registrations by technology type.
To date, there have been no net metered fuel cells or combined heat and power systems in Vermont.
The exponential increase in the number of PV system installations has driven not only the overall
number of net metered systems but also the total growth of net metered system capacityl to over 20
MW (see figure 3).
Net Metering Applications - kW Capacity by Year and Type
25,000 i -
I
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Figure 3. Copacity of net metering applications by type. (2072 data as of 12/5/72.)
The capacity histogram (figure 4) shows that 59% of net metering systems permitted to date are less
than 5 kW,260/o are between 5-10 kW and fewer than two percent are larger than 100kW.
I The capacity ofa generator is the maximum output that the generator is capable ofproducing. It is an instantaneous
measure, and measured in Watts, kilowatts (kW), megawatts (MW), etc. Energy production is measured over time -
a I kW generator operating at that level for an hour produces one kilowatt-hour (kWh) of energy. Vermont's
summer peak load is near 1000 MW, and the state uses about 5.5 terawatt-hours each year.
5
74.
PV Net Meteri lications
kW Capacity Histogram of
350
250
100
,> tu L% ru b Lb A L$ e ao f &o &o Ao &op$trop$tro
Capacity kW AC
Figure 4. Copocity (in kW AC) of oll net metered PV system applicotions
While the growth has been rapid and 20MW of small net metered systems represents a level of success
that some didn't think would be achieved, it represents a very small fraction of Vermont's overall
electrical portfolio. Only one utility (Washington Electric Cooperative) has more than L% of their
customers participating in net metering. There are some smaller utilities that are approaching the 4%
capacity cap, but it is important to remember that the cap is based on capacity and not power
production. Net metering systems produce less than 1% of the power Vermont uses each year or about
35 GWh per year'.
3 Cross-SubsidizationAnalysis
This section describes the quantitative analysis conducted by the Department to examine the question
raised explicitly in Act L25: "... the report shall include an onalysis of whether and to whot extent
customers using net metering systems under 30 V.S.A. I 2L9o are subsidized by other retoil electric
customers who do not employ net metering." ln conducting this analysis, the Department was greatly
aided by information and suggestions received from numerous stakeholders through written comments,
data submittals, and meetings.
3.1 Literature review
ln order to frame the analysis for determining whether net metering represents a "cost-shift" from non-
participating ratepayers to net metering customers, the Department conducted a broad-based literature
review of relevant papers and studies. This review included over two dozen publications from a wide
variety of sources, including the National Renewable Energy Laboratory (NREL), the Solar America Board
150
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for Codes and Standards (Solar ABCs), and a number of states and utilities on either the subject of net
metering benefits generally, or specifically on the rate impacts of net metering. Few of the publications
reviewed were directly comparable with each other, or with the specific net metering rules and
regulations in Vermont. However, information gleaned from these publications provided context that
informed assumptions made in the Department model.
One of the challenges facing Vermont is that the only one other state - California - has conducted a full
analysis of the cost-shift question (i.e., a full cost-benefit analysis)from a utility and ratepayer
perspective. The California study3 (and its subsequent updateso's), along with two prior values-only
studies performed for specific utilities (Arizona Public Service6 and Austin EnergyT'8) form the basis for a
generalized methodology for analyzing the costs and benefits of net metering proposed by the Solar
America Board for Codes and Standardse. This methodology, however, only looks at exported (rather
than gross) generation from net-metered solar photovoltaic systems, For reasons explained below,
Vermont has chosen to look at gross generation, and at generation from a number of allowed types of
net metering technologies - not only solar. Therefore, the methodology serves as a good guidepost and
checkpoint for our work, but not an exact template.
Three other relevant statewide studies have been performed: two in New York and one in
Pennsylvania/New Jersey. One of the New York studies is a broad review of the benefits and costs to
ratepayers of increasing in-state solar capacity to 5,OOO MW by 2125ro; while the other looks at the
overall costs and benefits of distributed solar to ratepayers and taxpayers in the New York City area11.
The PA/NJ study is similar to the latterl'. The assumptions and methodologies used in these studies
were also helpful in framing our analysis.
Table L below summarizes the results of relevant publications. Each study is unigue, with distinct
definitions for the costs and benefits analyzed. ln many cases, costs and benefits not included in this
' Energy and Environmental Economics, lnc. (2010). Net energy metering (NEM) cost effectiveness evoluation (E3
study/. Available at http://www.cpuc.ca.govlPUC/energy/DistGen/nem_eval.htm.
a Beach, Thomas R. and Patrick G. McGuire (2012]. Re-evoluating the Cost-Effectiveness of Net Energy Metering in
Co I ifo rnio. Berkeley, CA: Crossborder Energy.
s Beach, Thomas R. and Patrick G. McGuire (2072). Evaluating the Benefits and Costs of Net Energy Metering for
Residential Customers in Colifornio. Berkeley, CA: Crossborder Energy.
' Distributed Renewoble Energy Operating lmpocts ond Voluotion Study (2OO9l. Seattle, WA: R.W. Beck.
'Braun, Jerry, Thomas E. Hoff, Michael Kuhn, Benjamin Norris, and Richard Perez (2006). The Value of
Distributed Photovoltaics to Austin Energt and the City of Austin Napa, CA: Clean Power Research, LLC.t Ha*ey, Tim, Thomas E. Hof[ Leslie Libby, Benjamin L. Norris, and Karl R. Rabago (2012): Designing Austin
Energt's Solar Tariff Using a Distributed PV Value Calculafor. Austin, TX and Napa, CA: Austin Energy and
Clean Power Research.
'Keyes, Jason B. and Joseph F. Wiedman (20721. A Generolized Approoch to Assessing the Rote tmpocts of Net
Energy Metering. Solar America Board for Codes and Standards,
http://www.solarabcs.orslabout/publications/reoorts/rateimoact/pdfs/rateimpact full.pdf.
10 New York Solor Study: An Anolysis of the Benefits and Costs of tncreosing Generotion from Photovoltoic Devices in
New York (2lt2l. Albany, NY: New York State Energy Research and Development Authority.
" Hoff, Thomas E., Richard Perez, and Ken Zweibel (2011). Solar Power Generotion in the US: Too Expensive, or o
Borgoin? Albany, NY: Clean Power Research, LLC.
" Hoff, Thomas E., Benjamin L. Norris, and Richard Perez (2OL2l. The Volue of Distributed Solor Electric Generation
to NewJersey ond Pennsylvonio. Albany, NY: Clean Power Research, LLC.
7
table are discussed. Additional details of select studies are provided in a more extensive literature
review document, posted at http://oublicservice.vermont.eovltopics/renewable enersv/net meterine.
Details of this Public Service Department study are included in Table 1 for comparison purposes.
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3.2 Cross-subsidization analysis decisions
Based upon the landscape of methodologies revealed in the broad literature review, the Department
made three threshold decisions regarding its cross-subsidization analysis framework, each described in
greater detail below:
o To examine the cost-benefit from a statewide ratepayer perspective, with consideration of two
scenarios which include and do not include monetary value for reductions in greenhouse gas
emissions;
o To include a clear, defined set of assumptions of the costs and benefits of net metering; and
o To include costs and benefits associated with all generation by net metering systems, rather
than only that generation that is exported to the electric grid.
The following subsections describe the conclusions the Department reached on each of these points.
The Department modeled the costs and benefits of net metered generation from three technologies:
fixed solar photovoltaic (PV), 2-axis tracking solar PV, and wind power. While there are a handful of net-
metered generators in Vermont that use agricultural methane or hydropower, over 95% of net-metered
generation uses either solar or wind power. ln addition, the Legislature has made special allowance for
agricultural methane in the Standard Offer program. The Department expects that the vast majority of
new net metering generation will continue to be powered by solar and wind energy.
3.2.L Ratepayer perspective
There are a number of different cost-benefit tests that an analysis could pursue to determine the impact
of net metering, each reflecting the different perspective.13 The Department concluded that Act 125
requires a statewide ratepayer perspective. This is the appropriate analysis to evaluate any potential
subsidization of net metering participants by other Vermont retail electric customers. For simplicity and
clarity, the Department decided to consider the weighted average costs and benefits across all of the
state's utilities rather than model the costs and benefits for each utility separately.
ln addition, the Department supplements the state utility ratepayer perspective by the avoided costs of
greenhouse gas emissions that are currently externalized due to market failures. This calculation
attempts to quantify what the ratepayer costs and benefits would be if these costs were internalized in
t'One perspective is that of the participant (net metered customer), who receives lower electric bills in exchange
for expending the capital for the project. A ratepayer cost-benefit test captures costs and benefits to a utility's
ratepayers (including both those who install net metered systems and those who do not). This perspective
depends on the regulatory structure where utility recovers the costs from, and shares the benefits with, its
customers. Moving to a larger universe of impacted people, a study can examine the impact on all the ratepayers
in the state of Vermont. The largest scale is society as a whole.
Depending on the perspective considered for a cost-benefit analysis, a particular flow of value could be considered
a cost, a benefit, or a transfer. For example, the utility's cost from lost bill revenue is the participant's benefit from
reduced electric bills. Reduced Vermont contribution to regional transmission costs (for transmission already built)
is a benefit if the boundary is drawn at the utility or state level, but is simply a transfer of burden to other New
England ratepayers if society as a whole is considered. Under current policies, costs due to many environmental
impacts, such as greenhouse gas emissions, are borne by society as a whole, not just by Vermont or any single
utility's ratepayers.
10
the electricity market. The Department finds this addition appropriate given the State's emphasis on
greenhouse gas emission reductions, exemplified in statutory priorities (see, for example, 10 V.S.A. $
578 and 30 V.S.A. S 8001), and especially the statutory guidance in 30 V.S.A. 5 218c to consider "the
value of the financial risks associated with greenhouse gas emissions from various power sources."
3,2.2 Costs and benefits
The Department examined the relevant literature, as well as the structure of New England and Vermont
electricity markets and regulation to identify the following costs:
o Lost revenue (due to participants paying smaller electric bills)
o The Vermont solar credit, for solar PV systems
o Net metering-related administrative costs (engineering, billing, etc.)
The Department identified the following benefits:
o Avoided energy costs, including avoided costs of line losses and avoided internalized
greenhouse gas emission costs
o Avoided capacity costs, including avoided costs of line losses
o Avoided regional transmission costs (costs for built or un-built pooled transmission facilities, or
PTF, embodied in the ISO-NE Regional Network Service charge and other regional changes
allocated in a similar fashion)
o Avoided in-state transmission and distribution costs (avoiding the construction of new non-PTF
facilities)
o Market price suppression
o Value associated with SPEED generation
Net costs and benefits were calculated both including and excluding the value of avoided greenhouse
gas emissions that are currently not internalized in the cost of energy. Ratepayers face a risk that more
greenhouse gas costs will be internalized in the future, potentially leading to stranded assets.
Costs and benefits are determined from a Vermont ratepayer perspective; transfers from entities which
are not Vermont ratepayers to Vermont ratepayers are included; any potential transfers between
Vermont ratepayers are not included.
The assumptions used for each of these costs and benefits are described in more detail in Section 3.3
below.
3.2,3 Generation to include
The literature review conducted for this study revealed one particular analytic choice made by the
Department that is different from some similar studies undertaken elsewhere: other analyses consider
the costs and benefits of only the generation that is exported to the grid from the site of the net
metering generator. That is, they do not consider the costs and benefits to the consumer, utility, or
society of generation that offsets load on-site. The Department considered the analytical option used by
others, but determined that this choice is not appropriate for Vermont because it would have been
unresponsive to the charge from Act 125 which asks for an evaluation and analysis of 30 V.S.A. 5 219a as
a whole. lnstead, the Department's analysis considers all generation from net metering systems. Other
reasons for this choice include:
o The net metering solar credit is based on all generation;
o Simplified permitting is allowed for small net metering generators whether they produce
enough to spin their host's meter backwards or not;
o Generation from a net metering system can offset not only a customer's load but also service
and other charges;
o Group net metering and virtual group net metering options are available in Vermont. ln these
instances, generators are likely to be connected directly to the grid, and balancing of production
with load is only accounted for on paper each billing period rather than physically in net electric
energy flow through a meter.
3.3 Modelingassumptions
The spreadsheet modella estimates the costs and benefits incurred as a result of any single net metering
installation installed in 2013 ora lateryear. lt projects costs and benefits overthe 20-year period
following installation, allowing examination of the potential changing costs and benefits over that period
as well as calculation of a levelized net benefit or cost per kWh over 20 years.
3.3.1 What the model does not do
While model calculations are precise, and reflect the Department's best point estimate, they do not
estimate the width of the range of uncertainty surrounding each estimate due to the compounding
effect of multiple assumptions, each of which has its own uncertainty. ln addition, the model does not:
Capture economic impacts outside of the utility-ratepayer context, such as job or economic
impacts from the renewable electricity industry or changes to the economics of energy
consumption among net metering participants or non-participants.
ldentify impacts on energy prices, load shapes, or other inputs to the analysis that may have
already occurred due to deployment of net metering systems in Vermont. For systems modeled
as installed in years after 2013, the model does not account for potential changes in Vermont's
load shape or other inputs that may occur prior to installation.
Capture potential changes in rate structures or regional costs, including those due to net
metering. lt models only the marginal impact of net metering under a "current policy'' baseline
scenario. That is, it does not model a situation in which rate structures change over time (such
as adoption of time-of-use rates), or the impact that increasing net metering may have on future
rates or rate structures.
Capture nonlinear or feedback effects in which additional deployment of net metering in
subsequent years may change marginal costs or benefits attributable to systems installed in
earlier years (such as through changes in load shape and resulting peak coincidence). For
example, it does not capture changes in the costs or benefits (such as avoided infrastructure
costs) attributed to systems deployed in 2013 that might occur if future net metering, or other
ta Available for download from http://publicservicedept.vermont.sovltooics/renewable enersv/net meterins.
L2
generation or efficiency deployment, changes the state's load shape and therefore the need for
or cost of infrastructure.
o lnclude impact from advanced metering infrastructure or other grid modernization
technologies, and the resulting potential changes to rate structures.
o Account for integration costs (incremental costs due to the need to change the output of other
resources to account for intermittency). These costs are expected to be very small for systems of
the size eligible for net metering in Vermont.
o lnclude monetary values for environmental impacts other than avoided greenhouse gas
emissions or value as SPEED resources.
o Capture differences between utilities. All numbers used are weighted statewide or region-wide
averages.
. Capture potential cross-subsidization between utilities. This should be very small as the costs
and benefits studied are utility-specific. Second-order effects of net metering are possible if net
metering penetration or the distribution of net metering technologies is very different between
utility service territories.
3,3,2 Economic assumptions
3,3.2.1 Inflation
The baseline expected long-term inflation estimate is2.45o/o. This is based on the market expectations
for inflation, measured by the difference between the return on inflation-protected and non-inflation-
protected long-term (>10 year) U.S. Treasury bonds (as measured in late November,2OL2).
3.3,2,2 Discount rate
The Department's analysis uses two discount rates. One, referred to as the "ratepayer" discount rate, is
based on the cost of capital to individual ratepayers. The other, referred to as the "statewide" discount
rate, is based on a societal perspective on time preference in which the state as a whole has less strong
time preference than do individual ratepayers.
The ratepayer discount rate assumed in the Department's analysis is 8.03%. This rate was derived based
on analysis conducted by the U.S. Department of Energy for use in analysis of the cost-effectiveness of
appliance energy conservation standards.ls The analysis that U.S. DOE conducts for these standards
includes examination of the cost of capital faced by U.S. residential, commercial, and industrial energy
consumers. The Department weighted the three average values used in recent U.S. DOE rulemaking
proceedings by the three sectors' share of Vermont load, then adjusted for inflation.
The statewide discount rate assumed in the Department's analysis is5.52%. The Department assumes
that the state as a whole has a time preference similar to that of society at large. The Public Service
" See, for example, analysis conducted for the standards of furnace fans
(https://wwwl.eere.energv.govlbuildinss/appliance standards/residential/furnace fans.html) and electric motors
(https://wwwl.eere.energv.gov/buildings/appliance standards/commercial/electric motors.html).
13
Board has adopted a value of 3% in real terms for societal screening of energy efficiency measures; this
value is 3% adjusted for inflation.ls
3.3.3 Costs and Benefits
ln the context ofthis study, "costs" and "benefits" are measured from the ratepayer standpoint. The
utility regulatory structure in Vermont (including GMP's alternative regulation plan, the co-op structure
of VEC and WEC, and the municipal structure of the state's other utilities) results in the relevant set of
costs and benefits faced bythe state's utilities being passed to the state's ratepayers. For example,
utility costs include lost revenue, the solar credit, and administrative costs. Benefits include avoided
energy, capacity, transmission, and distribution costs. As a result, the proposed analytical framework
treats utility costs as ratepayer costs, and utility benefits as ratepayer benefits.lT
3.3,3.1 Costs
3.3,3.1.1 Reduction in utility revenue
Net metering reduces utility revenue by enabling a participating customer to provide some of their own
electricity (including, at times, spinning their meter backward while exporting energy), which reduces
their monthly bill. ln order to calculate the size of this reduction due to a modeled net metering
installation, the model requires the energy produced per year, along with the expected average
customer rate, and any solar credit. The current average electric rate applicable to most net metering
installations is L4.7 cents/kWh. This is the average residential electric rate; after the passage of Act 125
in the 2012 legislative session the vast majority of net metering installations in the state should be
credited at the residential rate. This is because these installations are in fact residential, or because they
are commercial accounts billed under a demand or time-of-use tariff - Act 125 established that such
commercial customers receive credit for net metered generation at the residential rate.
Generally speaking, electric rates are composed of energy, capacity, transmission, and other costs.
(Other costs include personnel/O&M and the carrying costs of the utility's investments in poles and
wires.) ln order to project costs and benefits into the future, the Department has built a simple tool to
build a self-consistent projection of rates based on forecast market costs of energy and capacity,
forecast transmission costs, and an assumption that other utility costs will rise at some rate, for which
the Department chose to use the rate of inflation.
The analysis assumes that energy costs in rates are composed of a mixture of the market energy costs
seen in New England over the preceding 10 years: 20%based on market energy prices in the year in
question, 40% based on the average ofthe previous 5 years, and 40% based on the average ofthe
previous 10 years. Vermont's utilities enter into contracts of varying lengths, and the prices they are
willing to pay are based on the energy prices at the time, as well as projected energy prices. See the
discussion of "avoided energy costs" below for detail regarding the market energy price forecast.
" The discount rate is 5.52o/o rather than 5.45% because the two rates are most appropriately multiplied rather
than added. !.O245x1.03 = 1.0552.
17 Externalities, such as the externalized portion of the value of greenhouse gas emission reductions, no not follow
this pattern.
L4
The analysis assumes that market capacity costs equivalent to 50% of Vermont's peak are included in
rates; the remainder of capacity is self-supplied and therefore not subject to market fluctuations. (These
self-supplied capacity costs are included in the "othe/'categoryfor utility infrastructure, O&M, etc.) See
the discussion of "avoided capacity costs" below for detail regarding the market capacity price forecast.
Regional transmission costs, embodied in the ISO-NE administered Regional Network Service charge,
account for the independent transmission portion of electric rates. The analysis assumes that these
costs are distributed in an even fashion across all of Vermont's kWh. See the discussion of "avoided
regional transmission costs" below for detail regarding the RNS forecast.
Once 2012 energy, capacity, and transmission costs are removed from2072 rates, the remainder must
reflect other costs,18 The Department assumed that these costs rise at the rate of general inflation. The
analysis makes one adjustment to account for known current circumstances: the guaranteed merger
savings resulting from the merger of GMP and CVPS. These savings come out of the "other" category,
and are assumed to total 5144 million in nominal dollars in 2072to 202L, then to continue at the same
annual nominal level in 2022 and later that they achieve in 202'J.
The rate forecast resulting from this analysis is shown in Table 2, located in Section 3.3.3.2.1.
Solar photovoltaic net metering systems are eligible for a "solar credit" in addition to the value of their
rates. This credit is calculated by subtracting the residential rate from 20 cents/kWh. Therefore, the
state average solar credit in 2013 should be 5.3 cents per kWh generated. The value of this credit is fixed
for ten years for each installation at the value it had at the time the system was commissioned. As a
result, by the end of ten years the cost of each kWh provided by the solar net metering system could
significantly exceed 20 cents. The solar credit is guaranteed to each system for ten years. For systems
installed in later years, when rates are expected to be higher in nominal terms, the solar credit is
assumed to be correspondingly smaller.
3.3.3.1.2 Administrative costs
The Department did not receive quantitative data from any commenter regarding appropriate
administrative costs. The Department developed a set of assumed costs based on qualitative comments
that the current administrative burden on distribution utilities is split between two main tasks:
evaluating systems as they are submitted (a one-time cost related to engineering assessment and other
setup costs) and billing (which is predominantly a cost for group net metered systems, as billing
individual net metering is already or very easily automated). Based on qualitative comments, the
Department assumed that the total cost for these two tasks is approximately 5200,000 dollars per year
forthe current pace and scale of net metering in Vermont, split roughly in half between initial costs and
on-going costs. To a rough approximation, this corresponds to a setup cost of approximately S20 per kW
of net metering system capacity, ongoing costs of about S20 per kW per year for billing group net
metered systems, and no on-going billing cost for individual net metered systems. The Department also
assumed that efficiencies in billing systems (aided by the standardization resulting from the Board's
" These other costs are also reflected in the monthly customer charge, which does not play a significant role in the
determination of net metering costs and benefits.
15
order regarding billing standards and procedures) would result in billing costs per kW falling at a rate of
20% per year.
3,3,3.2 Benefits
3.3.3.2.1 Avoided enerry cost
From the perspective of the regional electric grid ora utility purchasing powerto meet its load, net
metering looks like a load reduction. A utility therefore purchases somewhat less power to meet the
needs of their customers. While Vermont utilities purchase much of their energy through long-term
contracts, this kind of moment-by-moment change in load is reflected in changes in purchases or sales
on the ISO-NE day-ahead or spot markets. As a result, the Department assumes that the energy source
displaced or avoided by the use of net metering is energy purchased on these ISO-NE markets (the
difference between day-ahead and spot markets over the course of the year is minor).
Variable generators, like many of the types of generators deployed in Vermont for net metering, may
exhibit some correlation with the weather and therefore with market prices. For example, the season
and time of most solar irradiance is correlated (although imperfectly) with the peak summer loads, and
therefore somewhat higher regional electricity prices. ln order to capture this real correlation, the
Department calculated a hypothetical 2011 avoided energy cost on an hourly basis by multiplying the
production of real Vermont generators by the hourly price set in the ISO-NE market. This 2011 annual
total value was then updated to 2013 and beyond by scaling the annual total price according to a market
price forecast. The Department used hourly generation data from the Standard Offer program and net
metering systems deployed around Vermont.ls Significant deployment of such systems has continued
this year, but relatively few systems operated for all of 2011. These calculations indicate that fixed solar
PV has a weighted average avoided energy price LOo/o higher than the annual ISO-NE average spot
market price, 2-axis tracking solar PV is 73% higher, and small wind is 5% lower.
The Department assumed that the capacity factor for each solar technology is projected capacity factor
using the NREL PVWatts tool for a location in Montpelier, using all PVWatts default settings. The
assumed capacity factor for wind is the 2011 capacity factor of the real Vermont generator used to
calculate the correlation. Separating the capacity factor from the price-performance correlation allows
the analysis to correct for differences between the typical capacity factors expected over many years for
a generic facility and the capacity factors exhibited for a limited number of generators in only one year.
Output from net-metered generators is expected to decay at a low rate as the generator ages. The
Department has assumed a rate of 05% per year; this is based on typical degradation rates for solar PV
systems.
The Department's market energy price forecast is based on known forward market energy prices for the
first five years, then known forward natural gas prices for years 5 to 1.0. Natural gas prices are an
le lncluding a fixed solar array in Ferrisburgh, a two-axis solar tracker array in Shelburne, and a 100 kW wind
turbine near the Burlington airport.
16
appropriate proxy for scaling electricity prices because the marginal generator in New England, which
sets the price, is almost always a natural gas generator. Prices beyond L0 years are based on
extrapolation of the electricity and natural gas price trends seen in the market-derived forecast for years
1-10. Using forward market prices implicitly includes the value of net metering as a known-price hedge
against a volatile price of energy or natural gas. This is because the prices used in developing the
Department's fit are the known prices to lock in supply years into the future; these prices already have a
market-determined price risk adjustment included. The resulting energy price forecast (in nominal
dollars) is shown in Table 2. The values used in this analysis are averages of the market price forecast
conducted on three separate dates in October and November,2Ot2.
Energy generated by net metering systems on distribution circuits in Vermont is used locally, often on
the same property or within a few miles. Therefore, line losses from this energy are insignificant. The
energy being displaced, however, would be purchased on the bulk system and then transported to load,
with resulting line losses. Analysis conducted by utilities and the Department for the development of the
Vermont energy efficiency screening tool concluded that typical marginal line losses are about 9%. A
very similar line loss factor applies to capacity; the Department has assumed it to be the same factor of
9%.
L7
Table 2: Deportment assumptions ond forecasts of avoided energy, copocity, regional tronsmission, and
in-state transmission ond distribution costs, along with ossumed self-consistent residentiol rate forecast,
developed for this study. Values ore in nominal dollors.
Re$demtr*
,ktes
Isrkwhl ,,
Energy
(s/MWh)
Capacity
(s/kw-
month)
Regional
transmission
{PrF) (s/kw-
month)
Vermont
T&D (non-
PTF)
(s/kw-
monthl
2012
2013
20t4
2015
2016
2017
201,8
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
50.L47
50.147
s0.1so
so.1s1-
so.1s0
So.rs+
So.1s7
s0.162
So.roa
s0.170
5o.rzs
So.rae
s0.1e3
s0.201
so.2o8
s0.216
so.22s
s0.234
50.244
so.2s4
so.26s
50.276
So.zss
s0.301
S0.314
s0.328
So.z+z
So.:sz
So.gz:
S3s.28
547.22
546.Bo
s46.83
547.12
$47.7s
S48.s6
sso.60
Ssz.go
Sss.a+
ss8.1s
Sso.gz
Sss.as
567.62
571.72
576.L6
Sso.gs
Sss.oz
Sgt.qq
597.18
s103.2s
s109.69
Srre.s+
$L23.82
s131.s4
s139.7s
5L48.48
5$t.tq
s167.s9
Sz.eg
52.84
s2.84
5z.aq
Sr.re
St.tt
s2.39
s2.68
s3.76
Ss.es
Ss.zs
56.s2
57.s7
s7.85
$8.03
58.20
58.38
Se.so
Ss.zs
Ss.s+
se.13
Ss.::
5g.sa
$s.t+
Sg.gs
s10.16
s10.38
S10.61
S10.83
5o.zt
s7.08
Sz.ss
Sa.zr
Sg.ss
Sro.os
s10.s6
S11.09
Srr.e+
572.23
512.84
s13.48
s14.1s
S14.80
s1s.60
s16.38
s17.19
s18.os
s18.9s
Srs.ag
$20.88
521..e2
s23.01
s24.L6
s2s.36
526.62
s27.9s
s29.34
s30.80
5L3.L7
S13.43
s13.71
s13.88
5L4.14
5L4.48
S14.s8
S14.ss
Srs.:s
s1s,64
S1s.es
Sro.rg
s16.s0
s16.86
s17.18
S17.so
5L7.82
518.14
s18.46
S18.78
s19.10
iLs.42
5L9.74
s2O.O7
S20.39
52O.7L
s21.02
52L.34
s21.5s
3.3.3.2.2 Avoided capacity cost
Capacity costs are charged by ISO-NE to each of the region's utilities in order to offset the region's
payments to generators through the Forward Capacity Market. (This market assures that enough
capacity is available in the region to meet load during extreme weather or grid emergencies.) These
18
costs are allocated to each utility based on its share of the ISO-NE regionalpeak load. The value
provided by net metering systems is based on average performance (power output) during the time of
peak system demand. For the bulk grid perspective, net metering systems look like a reduction in
demand, and therefore reduce the utility's cost for capacity.
There are multiple potential methodsto measure the effective capacity of generators with respectto
different purposes. ln determining the peak coincidence factors described in this or following
subsections, the Department used the average performance of real in-state generators during particular
times of day and particular months, as it determined were appropriate for the purpose at hand based on
known cost allocation mechanisms or parallels with the treatment of energy efficiency. For example, the
Department estimated economic peak coincidence for each generation technology by examining 2010,
2011 and 2012 performance of examples of each technology during afternoons in the month of July;
ISO-NE peaks typically occur during July afternoons. These values were calculated based on the output
of ten 2-axis tracking solar PV generators, four fixed solar PV generators, and two small wind generators.
The resulting capacity peak coincidence values are shown in Table 3.
The capacity price forecast assumed by the Department, and used by default in the model, is based on
recent electric utility regulatory filings including lntegrated Resource Plans and purchase power
acquisitions. The resulting capacity price forecast (in nominal dollars) is shown in Table 2.
Table 3: Department assumptions of net-metered generotors' performonce during peok times used to
calculate volues of avoided capocity, avoided regional RA/S cosf, and ovoided in-state transmission and
distribution infrostructure. Eoch value shows the fraction of the system's roted copocity thot is assumed
in the calculation of the value of the three ovoided costs. For example, in calculoting the volue of ovoided
copacity costs due to a fixed solar PV system with a nameplate capacity of 100 kW, the system is
assumed to reduce capacity costs by the same omount as a system thot can output 49.5 kW and is
always running or perfectly dispatchable. These vslues were calculated based on the output of ten 2-axis
tracking solor PV generators, four fixed solor PV generators, ond two smoll wind generotors.
&495
0.595
0.045
RNS
o.2151
0.263
&069
o376,, ' ,
0.562
0.oso
ln-state T&D
Fired8\l '
Tracking PV
Wind
3.3.3.2.3 Avoided regional transmission costs
Regional Network Service (RNS) costs are charged by ISO-NE to each of the region's utilities to pay for
the cost of upgrades to the region's bulk transmission infrastructure. These are costs that have already
been incurred, or are required to meet reliability standards, and thus cannot be entirely avoided - only
their allocation among New England ratepayers can be changed. Avoiding these costs through net
metering shifts the costs to ratepayers in other states. These costs are allocated to each utility based on
its share of the monthly peak load within Vermont. The model uses values calculated by examining
performance of Vermont generators during hour ranges when monthly peaks have occurred in Vermont
over the last 5 years. The resulting average monthly peak coincidence values are shown in Table 3.
L9
The values assigned to this cost are based on the ISO-NE forecast of the next 5 years' worth of RNS
costs, and escalated based on historical increases in the Handy-Whitman lndex of public utility
construction costs. ISO-NE forecast RNS costs increase att}o/o or more per yearfrom 2012to20L7,but
the Department assumes that flattening regional peak loads, including dernand response and distributed
generation, will reduce this growth rate. The resulting regional transmission price forecast (in nominal
dollars) is shown in Table 2.
3.3.3.2.4 Avoided in-state transmission and distribution costs
ln-state transmission and distribution costs are those costs incurred by the state's distribution utilities or
VELCO and which are not subject to regional cost allocation. The values used in this model are derived
from those in the recently completed avoided transmission and distribution cost working group for the
update to the electric energy efficiency cost-effectiveness screening tool. This working group consisted
of representatives from the state's distribution, transmission, and efficiency utilities, and the
Department. The values used in the model have been converted to nominal dollars using the assumed
rate of inflation.
The in-state transmission and distribution upgrades deferred due to load reduction or on-site generation
(such as net metering) are driven by reliability concerns. Therefore, rather than average peak
coincidence for a net metering technology, the critical value is how much generation the grid can rely on
seeing at peak times. Therefore, the Department calculated a "reliability" peak coincidence value,
separate from the "economic" peak coincidence used in avoided capacity and regional transmission cost
calculations. The Department calculated a reliability peak coincidence by calculating the average
generator performance of several Vermont generators during June, July, and August afternoons. This
corresponds to the methodology that ISO-NE uses to value energy efficiency in the Forward Capacity
Market, results of which are used fortransmission planning purposes. The resulting reliability peak
coincidence values are shown in Table 3.
3.3.3.2.5 Market price suppression
Reductions in load shift the relationship between the supply curve and demand curve for both energy
and capacity, resulting in changes in market price.20 Because net metering looks like load reduction, the
Department has approximated the market price suppression effect using analysis based on the 201L
Avoided Energy Supply Cost (AESC)study's calculation of the demand reduction induced price effect
("DRlPE") for Vermont. Energy DRIPE is a fraction of the value of avoided energy supply (starting at 9%
and decaying over time), while capacity DRIPE has varying values over time, averaging to between 52
and 53 per kW-year. The assumptions regarding load, prices, and other factors used in the AESC study
do not correspond directly to the assumptions used in this study, and load reduction with the particular
load shapes corresponding to solar PV or wind generation are likely dissimilar from those from energy
efficiency. As a result, the value attributed to net metering generation from this mechanism is very
much approximate.
20 This kind of market price suppression is a transfer between generators and ratepayers, so it is a benefit from a
ratepayer perspective but would not be included in a societal cost-benefit analysis.
20
3.3.3.2.6 Value associated with meeting SPEED goals
The model allows for assignment of a value that ratepayers see that is attributable to the type of
generation used by net metering systems installed by other customers. The analysis does not include, or
attempt to quantify, the value of renewable attributes (such as RECs) to the participating customer, who
is assumed to retain ownership of those attributes. Ratepayers see monetary value associated with the
type of net metering technology and resource used by other customers' net metering through the fact
that net-metered generation would help the state's utilities meet their SPEED goals. (The state has goals
of 2Oo/o new SPEED resources by 2Ot7 and75% renewable electricity by 2032.1lf a utility were to acquire
SPEED resources elsewhere, there would likely be a small premium cost compared to market costs. This
avoided premium is a benefit to all utility ratepayers from net-metered generation. Based on
conversations with commenters the Department assumes this value is S5/MWh (fixed in nominal dollar
terms).
3.3.3.2.7 Climate change
The Department's analysis calculates the costs and benefits of net metering to the state's non-
participating ratepayers both with and without the estimated externalized cost of greenhouse gas
emissions. lt should be noted that these benefits from a marginal net metering installation in Vermont
do not flow to Vermonter ratepayers in direct monetary terms. lnstead, they reflect both a societal cost
that is avoided and the size of potential risk that Vermont ratepayers avoid by reducing greenhouse gas
emissions. lf these environmental costs were fully internalized, for example into the cost of energy,
ratepayers would bear those costs. The Department is assuming a value of S80 per metric ton of COz
emissions reduced (in 52011); this is the societal value adopted by the Public Service Board for use in
energy efficiency screening, and is intended to reflect the marginal cost of abatement. About 52 of the
S80 is internalized in utility costs through the Regional Greenhouse Gas lnitiative, so the analysis
incorporates an additional cost of about S78 (in S2011) for cases in which costs of environmental
externalities are included.
CO2 emission reductions are calculated by using the 2010 ISO-New England marginal emission rate of
943 lbs/MWh.21 ISO-NE grid operations and markets almost always result in a gas generator dispatched
as the marginal plant, so this value is comparable to the emissions from a natural gas generator. The
Department's analysis does not track or account for emission or abatement of other greenhouse gasses.
3.4 Results of Cross-Subsidization Analysis
3.4.1 Systems Examined
This report presents the results of the cross-subsidization analysis for 5 systems, representing typical
cases in Vermont:
o A 4 kW fixed solar PV system, net metered by a single residence
o A 4 kW 2-axis tracking solar PV system, net metered by a single residence
o A 4 kW wind generator, net metered by a single residenceo A 100 kW fixed solar PV system, net metered by a group
2l http://www.iso-ne.com/genrtion_resrcs/reports/emission/final_2010_emissions-report-v2.pdf
2L
!l}
. A 100 kW 2-axis tracking solar PV system, net metered by a group
o A 100 kW wind generator, net metered by a group
3.4.2 Results for Systems Installed in 2013
The methodology described in section 3.3 allows the model to calculate costs incurred and benefits
received from each typical net-metered generator on an annual basis. These values may also be
combined into a 2O-year levelized value. A levelized value is the constant value per kWh generated that
has the same present value as the projected string of costs and/or benefits over the 2O-year study
period. This section presents graphs of the annual costs and benefits along with levelized costs, benefits,
and net costs (costs minus benefits). Benefits are presented both with and without externalized carbon
emission costs; levelized values are also presented from both an individual ratepayer and statewide
perspective (corresponding to different discount rates).
22
o3,4,2,7 4 kW fixed solar PV system, net metered by a single residence
A 4 kW fixed solar PV system would generate about 4500 kWh annually with a capacity factor of t3.O%.
Figure 5. Annuolcosts ond benefits dssociated with a 4 kW fixed solor PV residential system installed in
2013.
Table 4. Levelized cost, benefit, ond net benefit of o 4 kW fixed solor PV residentiol system installed in
2073 to other rotepdyers individuolly ("rotepayef) or statewide.
0.400
0.350
</t
E o.r*
EoEo 0.250)?
f; o.zmgo!
o 0.150
6oI
E o.rmc
0.050
0.000
-
f,65t5 psy ft\illfi
--- Benefits per kwh
r oggnsftsperkwhW/GHG
"#"d}"S"*""$"e""d9"&""S"S"d$"d"etr"od,*r.f ".8"o'r"dP
GHG value included
23
3.4.2.2 4 kW tracking solar PV system, net metered by a single residence
A 4 kW 2-axis tracking solar PV system would generate about 6,000 kwh annually with a capacity factor
of L7.7%.
Figure 5. Annual costs and benefits ossocioted with a 4 kW tracking solar PV residential system instolled
in 2073.
0.lmo
0.350
<rt
E o.r*
Eogg 0.2s0
i!
S o.zmIolt
o 0.150
o
E o.rm
c,c
0.050
0.000
"d9"d9"d9"e""$""t".".,f "^e""S"S"S",$"..r"e"".drd,"rd"d,"""'i".fl
Table 5. Levelized cost, benefit, and net benefit of a 4 kW trocking solar PV residentiol system installed in
2073 to other ratepoyers individually ("ratepoyer") or statewide.
-
costs per kwh
- - Benefits per kWh
24
3,4.2,3 4 kW wind generator, net metered by a single residence
A 4 kW wind generator generates approximately 2,600 kWh per year, with a capacity factor of 7.4%.lf
such a generator were sited optimally, it could have a significantly higher capacity factor and generate
more electricity. However, the per-kWh costs and benefits described here would be unlikely to change
significantly.
Figure 7. Annual costs and benefits associated with o 4 kW residentiol wind generator instolled in 2073.
Table 6. Levelized cost, benefit, and net benefit of a 4 kW residential wind generator instolled in 2073 to
other rotepoyers individually ("ratepayer") or stotewide.
0.400
0.350
{,}
E o.*
Eoco 0.2505ii
E o.2oog
0,!
o 0.150
o
E o.rmcE
0.050
r (sst5 psl k\ivtl
- -- Benefits per kwh
-
. Benefits per kwh w/ GHG
,d9"d}"S"-f ,$.,-s"t"-f "-dF"SrSS"$"Sr-tr"dtr,*.,.tr"dP"d}"$
25
3,4,2,4 700 kW fixed solar PV system, group net metered
A L00 kW fixed solar PV system would generate about 114000 kWh annually with a capacity factor of
L3.A%.
Figure 8. Annuol costs ond benefits ossociated with a 700 kW fixed solar PV group net-metered system
instdlled in 2073.
Table 7. Levelized cost, benefit, ond net benefit of o 100 kW fixed solor PV group net-metered system
instolled in 2073 to other rotepoyers individually ("rotepoye/') or statewide.
Units: $ per kWh GHG value included
Ratepayer 0.228
0.400
0.350
arl.
-E o.am
EoEo 0.250
-=o
E o.2oocolt
o 0.150
o(,
E o.rmc
0.050
0.000
t""tt'
---"--"'-'o'
-
costs per kwh
rr r Ssnsfit5 p61 kll/h
-
. Benefits per kWh w/ GHG
.,.sf ..,tr..,f "e""S""t""d"&t"$"SnS"S.^d.".g""d"e".,.tr"o8"d1'"P
26
3,4,2,5 100 kW tracking solar PV system, group net metered
A 100 kW 2-axis tracking solar PV system would generate about 150,000 kWh annually with a capacity
factor of L7.L%.
Figure 9. Annuol costs and benefits associoted with o 700 kW trocking solar PV group net-metered
system installed in 2073.
Table 8. Levelized cost, benefit, and net benefit of o 700 kW tracking solar PV group net-metered system
installed in 2073 to other ratepayers individually ("rotepoye/') or stotewide.
0.tt00
0.350
<r|
E o.am
Eo
o 0.25O
=i
E o.2ooEoa
o 0.150
60I
E o.rmet
0.050
0.(m
-
Costs per k\ /h
- - - Benefits per kwh
-
. Benefits per kwh w/ GHG
,.d9"d}.,-f "e""$"e""d"&""d'"S"""?"dP""tr"+"r-S"*""d".f "dr".+
27
3,4.2.6 700 kW wind generator, group net metered
A 100 kW wind generator generates approximately 55,000 kWh per year, with a capacity faclor of 7.4%.
lf such a generator were sited optimally, it could have a significantly higher capacity factor and generate
more electricity. However, the per-kWh costs and benefits described here would be unlikely to change
significantly.
Figure 1,.O. Annuol costs and benefits associated with a 100 kW group net-metered wind generator
instolled in 201-3.
0.400
:
0.350
0.300 - -
0.250 "
0.200
-
Costs per kwh
- - - Benefits per kwh
-
. Benefits per kwh w/ GHG
0.050 ----
Table 9. Levelized cost, benefit, and net benefit of o 100 kW group net-metered wind generotor installed
in 2013 to other rotepayers individually ("ratepayer") or statewide.
Units: S per kWh generated GHG value included
€ost
o.L97
0.199
Ben€fit: . NetBanefit
3.4"3 Systems Installed in Corning Years
Costs of energy, capacity, and transmission which contribute to electric rates may also be avoided by a
net metered generator. These costs are projected to change overtime. ln addition, as electric rates rise
the solar credit that applies to a newly installed net metered solar generator is expected to fall. This
leads to the question of how the analysis of cross-subsidization presented in the previous section is
likely to change for systems installed in future years.
a/l
(u
.s
Eo
o
E
oco-o
o
oIE
=trtr
Ratepayer
Statewide
So.r+z
s0.151
-- --.
Bendit ' ilet Eenefito.1os (so.oe2)
28
While the analysis described in this section is necessarily more uncertain than the analysis presented in
the previous section, it does provide some directional information and insights regarding future costs
and benefits. The limitations of the model the Department developed for the cross-subsidization
analysis also limit this analysis. ln particular, the avoided transmission and distribution costs attributable
to net metered generation depend on the State's and utilities' load shapes (particularly including the
timing of monthly and seasonal demand peaks). Load shapes will change as net metering is deployed,
saturation of appliances changes, and electric energy efficiency measures are implemented. Projections
of costs and benefits are necessarily more uncertain as they reach further into the future.
ln order to undertake this secondary analysis, the Department modeled the costs and benefits, as in
Section 3.3, but for systems installed in years after 2013. The following figures illustrate the changes in
net costs and benefits for residential-scale systems installed in subsequent years. (The results of large-
scale systems are similar, as illustrated in the previous section, and are omitted here for brevity.)
Qualitatively, the benefits of solar PV net metered generation increase more quickly than the costs (due
in large part to the decreasing solar credit), so that solar PV systems installed in later years have greater
net benefit than systems installed in 2013. The same is not true for wind generation.
Figure 71. Levelized net benefit of o 4 kW individual net metered fixed solor PV system installed in each
yeor 207j to 2018. Four lines show the net benefits from the perspective of a typical Vermont ratepayer,
from the stotewide perspective of all ratepayers, ond both including and excluding the value of GHG
emission reductions due to system operation.
.+Ratepayer-- no GHG
+Ratepayer- GHG
inte.nalizpd
.ryStatewide'- noGHG
-,Lstatewide - GHG
internalized
Year of System lnstallation
3v
E.s
Eoc
GoEo!0
ozEoEo
oJ
0.05
0.04
0.03
0.02
0.01
-0.01
-0.02
29
Figure 12. Levelized net benefit of a 4 kW individuol net metered Z-oxis tocking solar PV system instolled
in each year 2013 to 2018. Four lines show the net benefits from the perspective of o typical Vermont
rdtepoyer, from the statewide perspective of all ratepoyers, dnd both including and excluding the value
of GHG emission reductions due to system operation.
3J
G
Ec
EoE
IEruc(,!o
(,gz!o4(,
o
0.04
Figure 13. Levelized net benefit of a 4 kW individuol net metered wind generotor system instolled in eoch
year 2013 to 2078. Four lines show the net benefits from the perspective of o typicol Vermont rotepoyer,
from the stotewide perspective of all ratepayers, ond both including ond excluding the value of GHG
emission reductions due to system operotion.
263
+Ratepayer- noGHG
.a-Ratepayer- GHG
internalized
+Statewide - noGHG
+t-Statewide -GHG
internalized
=3 -0.02
I
5 -0.03c
E -o.o+g
t -o.ost(,.0
E -0.06
cz
E -0.07
sI -o.oaoJ
L
zo1+ 2015 2016 20L7 2018
Year of sy:tem lns:allation
t-RatePayer-- noGHG
*-Ratepayer-GHG
internalized
: *Statewide * noGHG
, ..r-Statewide-GHc
int€malized
-0.09
-0.10
30
s
3.4.4 Concluding Remarks on Cross-Subsidization
The analysis presented in the preceding sections indicates that net metered systems do not impose a
significant net cost to ratepayers who are not net metering participants. Net benefits from solar
photovoltaic systems, which represent nearly 88% of net metering systems, are either positive or
negative depending on the discount rate chosen and whether the value of non-internalized greenhouse
gas emissions are included or not included respectively. There would be real long-term riskto ratepayers
if decisions were made that assume no increase in the internalization of these costs over the 2O-year
analysis period for this study. lmpacts on transmission and distribution infrastructure costs are a
significant component of the value of net-metered systems. Solar PV has much greater coincidence of
generation with times of peak demand than does wind power; this results in more net benefits for solar
PV than for wind. Wind power has net costs whether greenhouse gas emissions costs are included or
not. Given the relatively small scale of wind system net metering in Vermont, the Department does not
consider this to be a significant cost to ratepayers.
4 General assessment of Vermont's net metering statute, rules, and
procedures
The Department has reviewed the relevant statutes, rules, and general policy in Vermont, and the
results of the cross-subsidization analysis described in Section 3. The Department's general assessment
is that Vermont's current net metering policy is a successful aspect of State's overall energy strategy
that is cost-effectively advancing the state's renewable energy goals. Net metering in Vermont has
undergone a significant growth, enabled in part by changes in state policy and statutes, as well as by
changes in technology costs and business models. ln addition to the costs and benefits discussed in the
preceding sections, net metering has enabled the growth of numerous small businesses, which employ
hundreds of Vermonters and form an important part of the foundation of Vermont's clean energy
economy. Based on this success and the analysis presented in this report, the Department has
concluded that there is no need for statutory changes at this time.
The Department highlights the process, led by the Public Service Board (PSB), to clarify and make more
uniform the billing standards and practices associated with net metering. The PSB issued an order with
billing standards and procedures on November L4,2OL2, and has the authority to revise these standards
as may be warranted. While additional changes may be required as utilities and regulators understand
billing cases and configurations not yet covered in the standards, utilities should expeditiously update
their tariffs and procedures to match the Board's order. These efforts should provide clarity and
uniformity; lack of clarity and uniformity had been an area of concern to the Department. Stability in
utility procedures and state policies would provide an opportunity to better understand the impacts of
current policies and allow regulatory processes to come up to date. For example, such stability should
allow the PSB to update their net metering rule (5.100) to reflect statutory changes and updated
interconnection standards since the rule was last updated. The PSB has the authority to raise the 4%
capacity cap for each utility, reducing any future need to raise that cap through statutory change.
31
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE
APPLICATION OF IDAHO POWER
COMPANY FOR AUTHORITY TO
MODIFY ITS NET METERING
SERVICE AND TO INCREASE THE
GENERATION CAPACITY LIMIT.
CASE NO. IPC-E-12-27
Idaho Conservation League
Direct Testimony of R. Thomas Beach
May 10,2013
CONFIDENTIAI
EXHIBIT 203
ANALYSIS OF CUSTOMER BILTS BEFORI, AND AFTER SOLAR NEM SYSTEM USING
IDAHO PO\MER CONFTDENTIAL RESPONSE TO rCL PRODUCTION REQUEST NO. 13.
9
*oozud
Jrr3
LOL
Exhibit 203
BEACH, Di
Idaho Conservation League
IPC-E-12-27
BEFORE THE IDAHO PI,JBLIC UTILITIES COMMISSION
IN THE MATTER OF THE
APPLICATION OF IDAHO POWER
COMPANY FOR AUTHORITY TO
MODIFY ITS NET METERING
SERYICE AND TO INCREASE THE
GENERATION CAPACITY LIMIT.
CASE NO. IPC-E-I2-27
Idaho Conservation League
DirectTestimonyof R. Thomas Beach
May 10,2013
EXHIBIT 204
IDAHO POWER RESPONSE TO rCL PRODUCTION REQUETS NO I
o a
REQUEST NO. 1: Please provide the most recently used altemate costs for
analyzing demand side resources. Please provide these costs for each hour of the year
and for the future 20 years. Please provide these costs in excel spreadsheet or other
digitalformat.
RESPONSE TO REQUEST NO. 1: The most recent costs for analyzing
demand-side resources were produced in the 2011 lntegrated Resource Planning
(.lRP') process. ln addition, Attachment 1 (attached hereto) contains hourly avoided
costs from January 1,2011, to December 31 ,2029. Attachment 2 (aftached hereto)
contains copies of the 2011 IRP Appendix C, pages 66 to 71 . This section of Appendix
C explains the derivation of the Demand-Side Management ("DSM") altemative costs.
These costs are averaged in time-of-use type pricing categories for analysis of DSM
resources. Please note, the Summer On-Peak prices are calculated using tdaho
Powe/s 3O-year levelized capacity, variable energy, and operating costs of a 17O
rnegawatt ('MW") Simple Cycle Combustion Turbine.
The response to this Request was prepared by Pete Pengilly, Customer
Research and Analysis Leader, ldaho Power Company, in consultation with Lisa D.
Nordstrom, Lead Counsel, ldaho Power Company.
IOAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE IDAHO CONSERVATION LEAGUE TO IDAHO POWER COMPANY.2
BEFORE THE IDAHO PUBTIC UTILITIES COMMISSION
IN THE MATTER OF THE
APPLICATION OF IDAHO POWER
COMPANY FOR AUTHORITY TO
MODIFY ITS NET METERING
SERVICE AND TO INCREASE THE
GENERATION CAPACITY LIMIT.
cAsE NO. IPC-E-12-27
Idaho Conservation kague
Direct Testimony of R. Thomas Beach
May 10,2013
EXHIBIT 205
IDAHO POWER 2OI3 IRP DSM STATI.NS UPDATE
ocToBER tt,20t3
2013IRP DSM Status Update, slide 4
2013 IRP DSM Status Update -
2011vs. 2013 IRP Cost
Comparison
Average Annual DSM Ahernative
Costs (nominal S/Mwh)
S18o
s160
S14o
s120
5100
$80
S6o
S4o
52o
$o
-2013
IRP Summer Mid Peak Hou6
12011 tRP Summer Mk' Peak Hours
Comparison of Summer Mid-Peak Hours (7am-1pm and 9-11pm)
between 2011 and 2013 IRP Alternative
"dp ,srt dF ,$," d dl" ,o" ,"r" "d,l "s& rf d,F sr9 ,"r" rf ,sf
"d'P
962 N. Glen Asp€n Way
Star, ldaho 83669
Phone' f2081 761-8858
h^nlvlabCdnd
Experierrce
July 2008 - present
1978-20n/,
Pi:neer Porer, LLC - Oryhee Cannty, ldaho. lnitial phnning, produdion of documentstion and submifials for Conditirnal Use
Permit applirztion for 40kW wind facility.. Pennifiing and projai management of consfructbn phase hru cornmbskrning.. l\Ianagement of applitatbn ard subrni$als fur Federal '1603 Gnant in lieu of
Ta<Credil'prog]am.
\A/b#m Dessert Energy - Orrryhee County, ldaho. lnilial planning and coordinalion of documents0cn br Conditional Use Permit
appliztion for 5 [n /whd hility.
Tunblevyeed Wrrclfam - Elnore Coun$, ldaho. lnitial planning and coordindion of doomentstion for Condfional Use Permit
application for 10 - 15 iJn rwind hcrltty.. Cost edim#s ard Financial Projedions br 20 year Porer Purchase
Agreernent. Researcfi for Federal"l@3 Gnant in lieu of Tax Credif prognam.. Research, support for Estinnrry for ldaho legislative reneuable energy issues.
TIE Bladfiafi Proie4 LLC - Bcise, ldafiro. Pqiai nnnagernent ard coordinatbn.
' Computer layouts br CNC machining of prototype parb.. Prototype materials procurement and manufiacturing scheduling.. Coordirstion of institutirnd collabonationswih ldaho National l€b (lNL) and he
Center br Advanced Eryergy StJdi€)s (CAES), Bcise Sffi University and
Synacuse Unilersity.. Research on projed development br manufacfuring design engineering,
certiftcation prooesses, marketing and distribution.. ldaho Departnent of Commerce granb application.. Application to he Departnent of Energy mllaboration with TBP, LLC,
CAES and Syracuse University.. Participation in reneuable energy confurences, forums and working
groups.
Archibctunalgxperiene
lndudes participalion in a full nange of servfries, forn des(;n dwebpment
stages b he impkrnenhtion of oonfract docurnents, br prciecb nanging fronr
single fanily duellings tc insfr'Utirnal facililies. The bllonting is a paltial llst
ananged by type, tc prwkle an overviart of my experience and capabilities.
E Dawn Marie Cardwell [phone] EXHIBlT40l
tPc-E-12-27
. Recreational/Commercial, AnchorageClarion Hotel. Kirlarcod ResortClarion Hotel ---
Anchorage, AK
Kirlaivood, CA.
Education
Rebrences
Summaryof
Qualifications
' Del Webb Hotels, Marinas, Convention Centers and
Support facilities on Lake Powell
Wahweap, Bullfrog, and Dangling Rope, AZ. and UT.. lnstihrtionalFacilities. Adminisfation Offces, Minimum Security,ldaho State
Conedional Institntion Boise,lD
' Pendyne Remodel and Renovation, Medium Security,
ldaho State Conectionallnstitution Boise, lD.. Correctional lndustries Facility, Medium Security, ldaho
State Conectional I nstitution Boise.lD. ldaho Army National Guard Tank School and Training
Facili$ at Gowen Field Boise,lD.. Nampa Care Center Renovation Nampa, lD.. The Peregrine Fund Research, Support Facilities and
lnterpretive Center Boise,lD
Financiial/ Retail / Spre Planning. Mountain Home Federal Credit Union - Mt. Home, lD.. ldaho Mountain Touring Towne square Mall __-
Boise, lD. Albertsons Food Centers
Boise, lD., Las Vegas, NV., Wenatchee, WA
. My education has been ongoing in nature. Years of higher
education, with emphasis on design, engineering and architecture.
Extensive informaleducation and work experience. This education
and experiences have enabled me to gain a well-rounded knowledge
in all areas of the construction industry and also qualify for the
Professional Arch itectura I Regishation Exam ination, administered
under the guidelines set forth by the National Council on Architectural
Accreditation Board, and more recently, my work experience in the
Renewable Energy lndustry has greatly expanded my knowledge.
References available upon request.
. My experience began with entry level design and drafting and has
expanded to include organizing project design teams, training and
working with others, coordinating and communicating with building
officials and governmental agencies, engineers, contractors, clients
and their representatives, code reviews, specifications, bidding,
estimating and job supervision as they relate to the building and
renewable energy industries.
-
Dawn Marie Cardwell [phone] EXHIBIT 401
tPc-E-12-27
Thank you for taking the time to review this document. Please, feel free to contact me for any
additional information you may require.
Sincerely,
Dawn Marie Cardwell
208-761 -8658
[e-mail]
Dawn Marie Cardwell [phone] EXHIBIT 401
tPc-E-12-27
$ ilt{-'iEl-
E$ ryoat-EOo
D isru ptive Cha[[enges:
Financiat lmplications and Strategic
Responses to a Changing Retait
Electric Business
O CEil Edison EtectricEl-U rnstrtute
Prepared by:
Peter Kind
Energy lnfrastructure Advocates
Prepared for:
Edison Electric lnstitute
Disru ptive Challenges.
Financial lmplications and Strategic
Responses to a Changing Retail
Electric Business
o
January 2013
@ 2013 by the Edison Electric lnstitute (EEl).
All rights reserved. Published 2013.
Printed in the United States of America.
No part of this publication may be reproduced or transmitted in any form or by any means, electronic or mechanical, including
photocopying, recording, or any information storage or retrieval system or method, now known or hereinafter invented or
adopted, without the express prior written permission of the Edison Electric lnstitute.
Attribution Notice and Disclaimer
This work was prepared by Peter Kind, Energy lnfrastructure Advocates for the Edison Electric lnstitute (EEl). When used as
a reference, attribution to EEI is requested. EEl, any member of EEl, and any person acting on its behalf (a) does not make
any wananty, express or implied, with respect to the accuracy, completeness or usefulness of the information, advice or
recommendations contained in this work, and (b) does not assume and expressly disclaims any liability with respect to the use
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The views and opinions expressed in this work do not necessarily reflect those of EEI or any member of EEl. This material
and its production, reproduction and distribution by EEI does not imply endorsement of the material.
Published by:
Edison Electric lnstitute
701 Pennsylvania Avenue, N.W.
Washington, D,C. 20004-2696
Phone: [phone]
Web site:www.eei,org
Disruptive Challenges: Financial lmplications and Stnategic Responses b a Changing Retail Electric Business
O Table of Contents
Executive Summary ................. I
Disruptive Threats-Strategic Considerations............ ........................6
Finance 101 - Innoduction to Corporate Finance...... ........7
Finance 201 - Financial Market Realities.... .....................8
Finance 501 - Financial Implications of Disruptive Forces ..............1I
Telephone lndustry Parallels .......14
Strategic Implications of Distribution 2020 Disruptive Forces....... .....................17
Edison Elechic lnstitute iii
Disruptive Challenges: Financial lmplications and Strategic Responses to a Changing Retail Electric Business
Executive Summary
Recent technological and economic changes are expected to challenge and transform the electric utility
industry. These changes (or "disruptive challenges") arise due to a convergence of factors, including: falling
costs of distributed generation and other distributed energy resources (DER); an enhanced focus on
development of new DER technologies; increasing customer, regulatory, and political interest in demand-
side management technologies (DSM); government programs to incentivize selected technologies; the
declining price of natural gas; slowing economic growth trends; and rising electricity prices in certain areas
of the country. Taken together, these factors are potential "game changers" to the U.S. electric utility
industry, and are likely to dramatically impact customers, employees, investors, and the availability of capital
to fund future investment. The timing of such transformative changes is unclear, but with the potential for
technological innovation (e.g., solar photovoltaic or PV) becoming economically viable due to this
confluence of forces, the industry and its stakeholders must proactively assess the impacts and alternatives
available to address disruptive challenges in a timely manner.
This paper considers the financial risks and investor implications related to disruptive challenges, the
potential strategic responses to these challenges, and the likely investor expectations to utility plans going
forward. There are valuable lessons to be learned from other industries, as well as prior utility sector
paradigm shifts, that can assist us in exploring risks and potential strategic responses.
The financial risks created by disruptive challenges include declining utility revenues, increasing costs, and
lower profitability potential, particularly over the long-term. As DER and DSM programs continue to capture
"market share," for example, utility revenues will be reduced. Adding the higher costs to integrate DER,
increasing subsidies for DSM and direct metering of DER will result in the potential for a squeeze on
profitability and, thus, credit metrics. While the regulatory process is expected to allow for recovery of lost
revenues in future rate cases, tariff structures in most states call for non-DER customers to pay for (or
absorb) lost revenues. As DER penetration increases, this is a cost-recovery structure that will lead to
political pressure to undo these cross subsidies and may result in utility stranded cost exposure.
While the various disruptive challenges facing the electric utility industry may have different implications,
they all create adverse impacts on revenues, as well as on investor returns, and require individual solutions as
part of a comprehensive program to address these disruptive trends. Left unaddressed, these financial
pressures could have a major impact on realized equity returns, required investor returns, and credit quality.
As a result, the future cost and availability of capital for the electric utility industry would be adversely
impacted. This would lead to increasing customer rate pressures.
The regulatory paradigm that has supported recovery of utility investment has been in place since the electric
utility industry reached a mature state in the first half of the 20th century. Until there is a significant, clear,
and present threat to this recovery paradigm, it is likely that the financial markets will not focus on these
disruptive challenges, despite the fact that electric utility capital investment is recovered over a period of 30
or more years (i.e., which exposes the industry to stranded cost risks). However, with the current level of lost
load nationwide from DER being less than I percent, investors are not taking notice of this phenomenon,
despite the fact that the pace of change is increasing and will likely increase further as costs of disruptive
technologies benefit further from scale efficiencies.
Investors, particularly equify investors, have developed confidence throughout time in a durable industry
financial recovery model and, thus, tend to focus on earnings growth potential over a 12- to 24-month period.
Edison Electric lnstitute 1
Disruptive Challenges: Financial lmplications and Strategic Responses to a Changing Retail Electric Business
So, despite the risks that a rapidly growing level of DER penetration and other disruptive challenges may
impose, they are not cunently being discussed by the investment community and factored into the valuation
calculus reflected in the capital markets. In fact, electric utility valuations and access to capital today are as
strong as we have seen in decades, reflecting the relative safety of utilities in this uncertain economic
environment.
In the late 1970s, deregulation started to take hold in two industries that share similar characteristics with the
electric utility industry-the airline industry and the telecommunications industry (or "the telephone utility
business"). Both industries were price- and franchise-regulated, with large barriers to entry due to regulation
and the capital-intensive nature of these businesses. Airline industry changes were driven by regulatory
actions (a move to competition), and the telecommunications industry experienced technology changes that
encouraged regulators to allow competition. Both industries have experienced significant shifts in the
landscape of industry players as a result.
In the airline sector, each of the major U.S. carriers that were in existence prior to deregulation in 1978 faced
bankruptcy. The telecommunication businesses of 1978, meanwhile, are not recognizable today, nor are the
names of many of the players and the service they once provided ("the plain old telephone service"). Both
industries experienced poor financial market results by many of the former incumbent players for their
investors (equity and fixed-income) and have sought mergers of necessity to achieve scale economies to
respond to competitive dynamics.
The combination of new technologies, increasing costs, and changing customer-usage trends allow us to
consider alternative scenarios for how the future of the electric sector may develop. Without fundamental
changes to regulatory rules and recovery paradigms, one can speculate as to the adverse impact of disruptive
challenges on electric utilities, investors, and access to capital, as well as the resulting impact on customers
from a price and service perspective. We have the benefit of lessons learned from other industries to shift the
story and move the industry in a direction that will allow for customers, investors, and the U.S. economy to
benefit and prosper.
Revising utility tariff structures, particularly in states with potential for high DER adoption, to mitigate (or
eliminate) cross subsidies and provide proper customer price signals will support economic implementation
of DER while limiting stress on non-DER participants and utility finances. This is a near-term, must-consider
action by all policy setting industry stakeholders.
The electric utility sector witl benefit from proactive assessment and planning to address disruptive
challenges. Thirty year investments need to be made on the basis that they will be recoverable in the fuhrre in
a timely manner. To the extent that increased risk is incurred, capital deployment and recovery mechanisms
need to be adapted accordingly. The paper addresses possible strategic responses to competitive threats in
order to protect investors and capital availability. While the paper does not propose new business models for
the industry to pursue to address disruptive challenges in order to protect investors and retain access to
capital, it does highlight several of the expectations and objectives of investors, which may lead to business
model transformation alternatives.
2 Edison Eleckic lnstitute
Disruptive Challenges: Financial lmplications and Shategic Responses to a Changing Retail Electric Business
Background
As a result of a confluence of factors (i.e., technological innovation, public policy support for sustainability
and efficiency, declining trends in electricity demand growth, rising price pressures to maintain and upgrade
the U.S. distribution grid, and enhancement of the generation fleet), the threat of disruptive forces (i.e., new
products/markets that replace existing products/markets) impacting the utility industry is increasing and is
adding to the effects of other types of disruptive forces like declining sales and end-use efficiency. While we
cannot lay out an exact roadmap or timeline for the impact of potential disruptive forces, given the current
shift in competitive dynamics, the utility industry and its stakeholders must be prepared to address these
challenges in a way that will benefit customers, long-term economic growth, and investors. Recent business
history has provided many examples of companies and whole industries that either failed or were slow to
respond to disruptive forces and suffered as a result.
Today, a variety of disruptive technologies are emerging that may compete with utility-provided services.
Such technologies include solar photovoltaics (PV), battery storage, fuel cells, geothermal energy systems,
wind, micro turbines, and electric vehicle (EV) enhanced storage. As the cost curve for these technologies
improves, they could directly threaten the centralized utility model. To promote the growth of these
technologies in the near-term, policymakers have sought to encourage disruptive competing energy sources
through various subsidy programs, such as tax incentives, renewable portfolio standards, and net metering
where the pricing structure of utility services allows customers to engage in the use of new technologies,
while shifting costs/lost revenues to remaining non-participating customers.
In addition, energy efficiency and DSM programs also promote reduced utility revenues while causing the
utility to incur implementation costs. While decoupling recovery mechanisms, for example, may support
recovery oflost revenues and costs, under/over recovery charges are typically imposed based on energy
usage and, therefore, adversely impact non-participants of these programs. While the financial community is
generally quite supportive of decoupling to capture lost revenues, investors have not delved into the long-
term business and financial impact of cross subsidization on future customer rates inherent in most
decoupling models and the effective recovery thereof. In other words, will non-DER participants continue to
subsidize participants or will there be political pressure to not allow cost pass thru over time?
The threat to the centralized utility service model is likely to come from new technologies or customer
behavioral changes that reduce load. Any recovery paradigms that force cost of service to be spread over
fewer units of sales (i.e., kilowatt-hours or kWh) enhance the ongoing competitive threat of disruptive
altematives. While the cost--recovery challenges of lost load can be partially addressed by revising tariff
structures (such as a fixed charge or demand charge service component), there is often significant opposition
to these recovery structures in order to encourage the utilization of new technologies and to promote
customer behavior change.
But, even if cross-subsidies are removed from rate structures, customers are not precluded from leaving the
system entirely if a more cost-competitive alternative is available (e.g., a scenario where efficient energy
storage combined with distributed generation could create the ultimate risk to grid viability). While tariff
restructuring can be used to mitigate lost revenues, the longer-term threat of fully exiting from the grid (or
customers solely using the electric grid for backup purposes) raises the potential for irreparable damages to
revenues and growth prospects. This suggests that an old-line industry with 30-year cost recovery of
investment is vulnerable to cost-recovery threats from disruptive forces.
Edison Elechic lnstitute 3
Disruptive Challenges: Financial lmplications and Strategic Responses to a Changing Retail Electric Business
Generators in organized, competitive markets are more directly exposed to threats from new technologies
and enhanced efficiency programs, both of which reduce electricity use and demand. Reduced energy use
and demand translate into lower prices for wholesale power and reduced profitability. With reduced
profitability comes less cash flow to invest and to support the needs of generation customers. While every
market-driven business is subject to competitive forces, public policy programs that provide for subsidized
growth of competing technologies and/or participant economic incentives do not provide a level playing field
upon which generators can compete fairly against new entrants. As an example, subsidized demand response
programs or state contracted generation additions create threats to the generation owner (who competes
based upon free market supply and demand forces).
According to the Solar Electric Power Association (SEPA), there were 200,000 distributed solar customers
(aggregating 2,400 megawatts or MW) in the United States as of 201 [. Thus, the largest near-term threat to
the utility model represents less than I percent of the U.S. retail electricity market. Therefore, the current
level of activity can be "covered over" without noticeable impact on utilities or their customers. However, at
the present time, 70 percent of the distributed activity is concentrated within 10 utilities, which obviously
speaks to the increased risk allocated to a small set of companies. As previously stated, due to a confluence
of recent factors, the threat to the utility model from disruptive forces is now increasingly viable. One
prominent example is in the area of distributed solar PV, where the threats to the centralized utility business
model have accelerated due to:
r The decline in the price of PV panels from $3.80/watt in 2008 to $0.86/watt in mid-2012'. Whil"
some will question the sustainability of cost-curve trends experienced, it is expected that PV panel
costs will not increase (or not increase meaningfully) even as the current supply glut is resolved. As a
result, the all-in cost of PV solar installation approximates $5/watt, with expectations of the cost
declining further as scale is realized;
An increase in utility rates such that the competitive price opportunity for PV solar is now "in the
market" for^approximately l6 percent of the U.S. retail electricity market where rates are at or above
$0.1s/kwhz. In addition, projections by PV industry participants suggest that the "in the money"
market size will double the share of contestable revenue by 2017 (to 33 percent, or $170 billion of
annual utility revenue);
Tax incentives that promote specific renewable resources, including the 30-percent Investment Tax
Credit (ITC) that is effective through 2016 and five-year accelerated depreciation recovery of net
asset costs;
Public policies to encourage renewable resource development through Renewable Portfolio
Standards (RPS), which are in place in 29 states and the District of Columbia and which call for
renewable generation goals within a state's energy mix;
Public policies to encourage net metering, which are in effect in 43 states and the District of
Columbia (3 additional states have utilities with voluntary net metering programs) and which
typically allow customers to sell excess energy generated back to the utility at a price greater than
the avoided variable cost3;
Time-of-use rates, structured for higher electric rates during daylight hours, that create incentives for
installing distributed solar PV, thereby taking advantage of solar benefit (vs. time-of-use peak rates)
and net metering subsidies; and
Source: Bloomberg New Energy Finance, Solar Module Price Index
Source: Energy Information Agency, Electricity Data Overview
Source: Database for State lncentives for Renewables and Efficiency, www.dsireusa.org
4 Edison Electric lnstitute
Disruptive Challenges: Financial lmplications and Strategic Responses to a Changing Retail Electric Business
I The evolution of capital markets' access to businesses that leverage the dynamics outlined above to
support a for-profit business model. Examples include tax equity financing, project finance lending,
residential PV leasing models (i.e., "no money down" for customers), and public equity markets for
pure play renewable resource providers and owners. As an illustration, U.S. tax equity investment is
running at $7.5 billion annualized for 2012.4 Add other sources of capital, including traditional
equity, and this suggests the potential to fund a large and growing industry.
Bloomberg New Energy Finance (BNEF) projects that distributed solar capacity will grow rapidly as a result
of the competitive dynamics highlighted. BNEF projects 22-percent compound annual growth in PV
installations through 2020, resulting in 30 gigawatts (GW) of capacity overall (and approximately 4.5 GW
coming from distributed PV). This would account for l0 percent of capacity in key markets coming from
distributed resources and even a larger share ofyear-round energy generated.
Assuming a decline in load, and possibly customers served, of l0 percent due to DER with full subsidization
of DER participants, the average impact on base elechicity prices for non-DER participants will be a 20
percent or more increase in rates, and the ongoing rate of growth in electricity prices will double for non-
DER participants (before accounting for the impact of the increased cost of serving distributed resources).
The fundamental drivers previously highlighted could suggest even further erosion of utility market share if
public policy is not addressed to normalize this competitive threat.
While the immediate threat from solar PV is location dependent, if the cost curve of PV continues to bend
and electricity rates continue to increase, it will open up the opportunity for PV to viably expand into more
regions of the country. According to ThinkEquity, a boutique investment bank, as the installed cost of PV
declines from $S/watt to $3.5/watt (a 3O-percent decline), the targeted addressable market increases by 500
percent, including 18 states and 20 million homes, and customer demand for PV increases by 14 times. If
PV system costs decline even further, the market opportunity grows exponentially. In addition, other DER
technologies being developed may also pose additional viable alternatives to the centralized utility model.
Due to the variable nature of renewable DER, there is a perception that customers will always need to remain
on the grid. While we would expect customers to remain on the grid until a fully viable and economic
distributed non-variable resource is available, one can imagine a day when battery storage technology or
micro turbines could allow customers to be electric grid independent. To put this into perspective, who
would have believed l0 years ago that traditional wire line telephone customers could economically "cut the
cord?"
The cost of providing interconnection and back-up supply for variable resources will add to the utility cost
burden. [f not properly addressed in the tariff structure, the provision of these services will create additional
lost revenues and will further challenge non-DER participants in terms of being allocated costs incurred to
serve others.
Another outcome of the trend of rising electricity prices is the potential growth in the market for energy
efficiency solutions. Combining electricity price trends, customer sustainability objectives, and ratemaking
incentives via cross-subsidies, it is estimated that spending on energy efficiency programs will increase by as
much as 300 percent from 2010 to2025, within a projected range of $6 to $16 billion per yeart. This level of
o Source: Bloomberg New Energy Finance, Renewable Energt-Research Note,July 18,2012
' Source: Lawrence Berkeley National Laboratory, The Future of Utility Funded Energy Efficiency Programs in the United
States: Projected Spending and Savings 2010 to 2025, January 2013
Edison Electric lnstitute 5
Disruptive Challenges: Financial lmplications and Strategic Responses to a Changing Retail Electric Business
spending on energy efficiency services will have a meaningful impact on utility load and, thus, will create
significant additional lost revenue exposure.
The financial implications of these tlreats are fairly evident. Start with the increased cost of supporting a
network capable of managing and integrating distributed generation sources. Next, under most rate
structures, add the decline in revenues attributed to revenues lost from sales foregone. These forces lead to
increased revenues required from remaining customers (unless fixed costs are recovered through a service
charge tariffstructure) and sought through rate increases. The result ofhigher electricity prices and
competitive threats will encourage a higher rate of DER additions, or will promote greater use of efficiency
or demand-side solutions.
Increased uncertainty and risk will not be welcomed by investors, who will seek a higher retum on
investment and force defensive-minded investors to reduce exposure to the sector. These competitive and
financial risks would likely erode credit quality. The decline in credit quality will lead to a higher cost of
capital, putting further pressure on customer rates. Ultimately, capital availability will be reduced, and this
will affect future investment plans. The cycle of decline has been previously witnessed in technology-
disrupted sectors (such as telecommunications) and other deregulated industries (airlines).
D isru ptive Th reats-Strateg ic Con siderations
A disruptive innovation is defined as "an innovation that helps create a new market and value network, and
eventually goes on to disrupt an existing market and value network (over a few years or decades), displacing
an earlier technology. The term is used in business and technology literature to describe innovations that
improve a product or service in ways that the market does not expect, typically first by designing for a
different set of consumers in the new market and later by lowering prices in the existing market."
Disruptive forces, if not actively addressed, threaten the viability of old-line exposed industries. Examples of
once-dominant, blue chip companies/entities being threatened or succumbing to new entrants due to
innovation include Kodak and the U.S. Postal Service (USPS). For years, Kodak owned the film and related
supplies market. The company watched as the photo business was transformed by digital technology and
finally filed for bankruptcy in2012.
Meanwhile, the USPS is a monopoly, government-run agency with a mission of delivering mail and
providing an essential service to keep the economy moving. The USPS has been threatened for decades by
private package delivery services (e.g., UPS and FedEx) that compete to offer more efficient and flexible
service. Today, the primary threat to USPS' viability is the delivery of information by email, including
commercial correspondence such as bills and bill payments, bank and brokerage statements, etc. Many
experts believe that the USPS must dramatically restructure its operations and costs to have a chance to
protect its viability as an independent agency.
Participants in all industries must prepare for and develop plans to address disruptive threats, including plans
to replace their own technology with more innovative, more valuable customer services offered at
competitive prices. The traditionalwire line telephone players, including AT&T and Verizon, for example,
became leaders in U.S. wireless telephone services, which over time could make the old line telephone
product extinct. But these innovative, former old-line telephone providers had the vision to get in front of the
trend to wireless and lead the development of non-regulated infrastructure networks and consumer marketing
skills. As a result, they now hold large domestic market shares. In fact, they have now further leveraged
technology innovation to create new products that expand their customer offerings.
6 Edison Electric lnstitute
Disruptive Challenges: Financial lmplications and Strategic Responses to a Changing Retail Electric Business
The electric utility sector has not previously experienced a viable disruptive threat to its service offering due
customer reliance and the solid economic value of its product. However, a combination of technological
innovation, public/regulatory policy, and changes in consumer objectives and preferences has resulted in
distributed generation and other DER being on a path to becoming a viable alternative to the electric utility
model. While investors are eager to support innovation and economic progress, they do not support the use
of subsidies to attack the financial viability of their invested capital. Utility investors may not be opposed to
DER technologies, but, in order for utilities to maintain their access to capital, it is essential that the financial
implications of DER technologies be addressed so that non-DER participants and investors are not left to pay
for revenues lost (and costs unrecovered) from DER participants.
Finance 101 - lntroduction to Corporate Finance
Investors allocate investment capital to achieve their financial objectives consistent with their tolerance for
risk and time horizon. Fixed-income (i.e., bond) investors seek certainty as to (investment) returns through a
guarantee by the debt issuer of timely payment of principal and interest. Equity investors seek a higher
expected refurn than debt investors and, accordingly, must accept increased risk. "Expected" return refers to
the distinction that equity investor returns are not guaranteed; therefore, equity investors bear a higher level
of risk than bondholders. The expected return on equity investment is realized through a combination of
dividends received and expected growth in value per share (which is achieved through a combination of
growth in earnings and dividends and/or a rerating of retum expectations as a result of investment market
forces).
Corporate financial objectives focus on enhancing shareholder value through achieving long-term growth
consistent with the preservation of the corporate entity. Corporations develop financial policies to support the
access to capital to achieve their business plans. For utilities, these financial policies are consistent with
investment-grade credit ratings. Since practically all utilities have an ongoing need for capital to fund their
capital expenditure programs, the industry has developed financial policies intended to support the access to
relatively low-cost capital in (practically) all mirket environments. Under traditional cost-of-service
ratemaking, customers benefit through lower cost of service and, therefore, lower rates.
In order to retain the financial flexibility required to maintain investment-grade credit ratings, the rating
agencies prefer policies that promote the retention of corporate cash flow and provide a liquidity cushion to
support fixed obligations. Prudent corporate financial management disdains significant fixed commitments to
investors-since such commitments limit management flexibility and increase capital-access dependency
and risk. While paying dividends to equity investors is not a legal obligation, the rating agencies and
investors view dividends as a moral (or intended) obligation that management will not reduce unless it has no
viable alternative to preserve long-term corporate value. The corporate financial objective ofretaining cash
from operations to support credit quality limits the potential to pay dividends to investors. Thus, growth of
investment value is required by equity investors (as discussed above) to achieve retum expectations
warranted by the increased risk taken and investment retum expectations relative to fixed income investors.
It is important to highlight that the rating agencies' rating criteria and associated target corporate credit
metrics reflect the credit risk of the industry environment of the corporation being rated. Thus, due to the
benefits of a stable regulatory environment, utilities are able to maintain (for a given rating category)
significantly more debt relative to cash flow than competitive industries. However, if business risks were to
increase for utilities in the future, as we will discuss in the next sections, it would be likely that utility debt
leverage (i.e., debt relative to cash flow) would need to be reduced in order to retain credit ratings.
Edison Electric lnstitute 7
Disruptive Challenges: Financial lmplications and Strategic Responses to a Changing Retail Electric Business
Stable, mature industries-those that have a proven product, stable product demand, and low volatility
related to their revenues and cash flow (the "defensive industries"Fare attractive to investors as they offer
more certainty and fewer business and financial risks. As a result, investors in these stable, defensive
industries (such as utilities) will require a lower expected retum compared to investors in less mature and
more volatile industries. We describe this lower expected return requirement as a lower cost of capital. This
lower cost of capital associated with defensive industries is manifested in lower borrowing costs and higher
relative share values. In addition, in difficult financial market environments (such as we experienced in
October 2008 through March 2009\, these stable businesses typically experience less adverse stock price
impact due to investors fleeing in order to reduce risk. Thus, in difficult markets, mature companies have
demonstrated ongoing financial market access (investor demand) when those in other industries have not.
This is the benefit (or the "insurance policy") of an investment-grade credit rating-lower capital costs and
more stable access to capital despite market conditions.
The benefit to customers of cost-of-service rate-regulated utilities is that a lower cost of capital contributes to
lower utility rates. Also of importance, but often taken for granted, is the comfort that comes with knowing
that utilities will have capital access to support the reliability and growth needs of their service territories
and, thus, will not adversely expose customer service needs, including customer growth plans.
Finance 201 - Financial Market Realities
With the exception of a very few periods over the past century, utilities have experienced unfettered access to
relatively low-cost capital. Even during challenging financial market environments when many industries
have been effectively frozen from capital access, utilities have been able to raise capital to support their
business plans. The primary reason for the markets' willingness to provide capital to the utility sector is the
confidence that investors place in the regulatory model, particularly the premise that utilities will be awarded
the opportunity to earn a fair return on investor capital investment.
However, at times of regulatory model uncertainty, we have seen the financial markets punish utility
securities. Examples of periods of investor uncertainty would include the timeframe post the 1973 oil
embargo, which was prior to the enactment of fuel adjustment clauses for purchased power; the nuclear
power plant abandonments and cost disallowances of the 1980s that led to multiple bankruptcies and
financial dishess for quite a few utilities; the PURPA cost fallout of the 1990s; and the post-Enron
bankruptcy collapse of the merchant power sector in the early 2000s, which challenged merchant energy
providers and heavily exposed utility counterparties. These events led to bankruptcies, longstanding financial
distress for impacted utilities, and ongoing erosion in credit quality and investor confidence. These examples
highlight that regulated businesses are vulnerable to risks related to business model changes, economic
trends and regulatory policy changes. When investors focus on these issues as being material risks, the
impact on investors and capital formation can be significant.
I Edison Electric lnstitute
Disruptive Challenges: Financial lmplications and Stnategic Responses to a Changing Retail Electric Business
Exhibit 1
Dow Jones Utility lndex: 1965-2012
Great
Recession
Prudency
Disallowances
ConEd Dividend Reduction
Merchant Crisis
Jan'65 Jan'70 Jan'75 Jan'80 Jan'85 Jan'90 Jan'95 Jan'00 Jan'05 Jan'10
(11 hdexed to U2lt97o price
Source: Bloomberg
Prior to the 1980s, the utility sector was dominated by "AA" credit ratings. Power supply-side cost
pressures, declining economic and customer growth trends, inflation in cost-of-service provision, and an
evolving industry and regulatory model have resulted in steady erosion in credit quality over each of the last
five decades. (See Exhibit 2 for a credit-rating history of the electric utility sector.) lnvestors responded to
these periods of significant industry challenge with a rethink of their "blind" faith in the regulatory model
and became more focused on company selection as they approached investment strategy. But, for the most
part, as utilities and regulation adjusted to political, regulatory, and economic challenges, investor faith in the
regulatory model has been restored.
After five decades of decline in industry credit quality, a potential significant concern now is that new
competitive forces, which have not been a concern of investors to date, will lead to further credit erosion.
The industry cannot afford to endure significant credit quality erosion from current ratings levels without
threatening the BBB ratings that are held by the majority of the industry today. Non-investment grade ratings
would lead to a significant rerating of capital costs, credit availability, and investor receptivity to the sector.
The impact on customers would be dramatic in terms of increased revenue requirements (i.e., the level of
revenues required for a utility to cover its operating costs and eam its allowed cost of capital), customer
rates, and reduction in the availability of low-cost capital to enhance the system.
300
;.: 2so
a.
g
-E zooIAto{ rsos
100
Edison Electric lnstitute I
Disruptive Challenges: Financial lmplications and Strategic Responses to a Changing Retail Electric Business
Exhibit 2
Electric utility industry credit ratings distribution evolution
(S&P Credit Ratings Distribution, U.S. Shareholder-Owned Electric Utilities)
100Yo
80o/o
il%
fiolo
20Yo
0o/o
1970 1980 1990
I ml ! eA+, AA, elA-
! aaa*,eaa I aea-
Source: Standard & Poor's, Macquarie Capital
2000
! A+, A, A-
lI BB*, BB, BB-, B+, B, B-, ccc+
2011
As we look at the electric utility sector today, investors, for the most part, remain confident that the
regulatory model will be applied fairly to provide them with the opportunity to earn a reasonable and fair
return on their investment. Those states that have experienced prior upheavals in their regulatory model (e.g.,
California) have had to tighten their approach to regulatory cost recovery to convince investors that past
problems have been addressed. If a state has not been as receptive to addressing its approach to past
problems, then investors will be highly reticent to deploy capital in those jurisdictions.
ln reviewing recent sector research reports, the majority of security analysts continue to project future
earnings levels based on assumed capital-investment levels and projected costs of capital (a bottoms-up
approach). While analysts acknowledge that each rate case carries some degree of uncertainty, there appears
to be limited focus in their analysis on service area quality, competitiveness of customer pricing, and the
drivers for future service territory growth. No other significant industry is analyzed by Wall Street on a
bottoms-up basis; the basis for analysis of non-utility industries is competitive position, sales prospects, and
sales margins. [n addition, the threat of disruptive forces is given no (or almost no) printed lines in utility
sector research. This approach to investment analysis is based upon confidence in utilities' ability to earn a
fair return on prudent investment. But, it may expose investors to the future economic risks posed by rapid
growth in DER. What will happen as technological advancement in the utility sector provides customers with
viable competitive alternatives?
'10 Edison Electric lnstitute
Disruptive Challenges: Financial lmplications and Strategic Responses to a Changing Retail Electric Business
Finance 501 - Financial lmplications of Disruptive Forces
As discussed previously, equity investors expect and will value an equity security based upon growth
attributes as a major component of the expected total return investors require. Growth in utility earnings has
historically been realized by a combination of increased electricity sales (volume), increased price per unit of
sales (higher rates), and/or expanded profit margins on incremental revenues achieved between rate cases
reflecting the realization of operational/overhead efficiencies. Earnings levels and growth are also impacted
by changing costs of capital due to market forces-this is currently a depressant on utility earnings per share
(EPS) levels due to the sector-wide decline in authorized returns on equity (ROE) realized over the last
several years.
First, let's review the current climate for the utility sector. While valuations are near all-time highs, the
headwinds facing the sector are significant. Concerns start with the anemic electricity demand, which has
been primarily impacted by the overall economic climate but also impacted by demand-side efficiency
programs and the emergence of DER. Next, there is the need to deploy capital investment at almost twice the
rate of depreciation to enhance the grid and address various regulatory mandates. Soft electricity demand
plus increasing capital investment lead to rate increase needs and the investment uncertainty created by a
future active rate case calendar. While sell side analysts are expecting EPS growth of 4 percent to7 percent
overall for the regulated sector, this is likely to be quite challenging. If investor expectations are not realized
a wholesale reevaluation of the sector is likely to occur.
So, what will happen when electricity sales growth declines and that decline is not cyclical but driven by
disruptive forces, including new technology and/or the further implementation of public policy focused on
DSM and DER initiatives? In a cost-of-service rate-regulated model, revenues are not directly correlated to
customer levels or sales but to the cost of providing service. However, in most jurisdictions, customer rates
are a function of usage/unit sales. In such a model, customer rate levels must increase via rate increase
requests when usage declines, which from a financial perspective is intended to keep the company whole
(i.e., earn its cost of capital). However, this may lead to a challenging cycle since an increase in customer
rates over time to support investment spending in a declining sales environment (due to disruptive forces)
will further enhance the competitive dynamics of competing technologies and supply/demand efficiency
programs. This set of dynamics can become a vicious cycle (See Exhibit 3) that, in the worst-case scenario,
would leave few(er) customers remaining to support the costs of a large embedded infrastructure system,
some of which may be stranded investment but most of the costs will continue to be incurred in order to
manage the flows between supply and customers.
Edison Electric lnstitute 11
Disruptive Challenges: Financial lmplications and Strategic Responses to a Changing Retail Electic Business
Exhibit 3
Vicious Cycle from Disruptive Forces
When investors realize that a business model has been stung by systemic disruptive forces, they likely will
reheat. When is the typical tipping point when investors realize that the merits of the investnent they are
evaluating or monitoring has been forever changed? Despite all the talk about investors assessing the future
in their investment evaluations, it is often not until revenue declines are reported that investors realize that
the viability of the business is in question.
An interesting example is the story of RlM, the manufacturer of the Blackberry handheld information
management tool. From its public start in the 1990s thru 2008, RIM was a Wall Street darling. Its share price
was less than $3 in 1999 and peaked at $ I 50 in 2008. The company started to show a stall in sales in 20 I I ,
and, now, despite a large cash position and 90 million subscribers, the market is questioning RIM's ability to
survive and RIM's stock has plummeted from its high.
What happened to this powerful growth company that had dominant market shares in a growth market? The
answer is the evolution of the iPhone, which ffansformed the handheld from an email machine to a dynamic
lnternet tool with seemingly unlimited applications/functionality. When the iPhone was first released in
2007, it was viewed as a threat to RIM, but RIM continued to grow its position until the introduction of the
iPhone 4 in June 2010. The iPhone 4, which offered significant improvements from prior versions, led to a
retreat in RIM's business and caused a significant drop in its stock price.
It seems that investors have proven to be reasonably optimistic on selected industries even though the
competitive threat is staring them head-on. However, if we can identiff actionable disruptive forces to a
business or industry, then history tells us that management and investors need to take these threats seriously
12 Edison Electric lnstitute
Disruptive Challenges: Financial lmplications and Strategic Responses to a Changing Retail Electric Business
and not wait until the decline in sales and revenues has commenced to develop a new strategy or, in the case
of investors , realize their loss.
As discussed above, investors in the utility sector seek increased certainty (or less risk) than in other
industries and have confidence in the consistent application of ratemaking recovery models to provide a
lower degree of investment risk. As a result of this confidence, when instances have occurred in the past that
have not provided consistent application ofexpected cost recovery models, investors have responded and
have caused significant adverse impact on entities' ability to raise incremental capital. But, with the
exception of the Califomia energy crisis in the early 2000s, these events reflected embedded cost issues that
had defined exposures and time frames. Disruptive changes are a new type of threat to the electric utility
industry. Disruptive changes lead to declining customer and usage per customer levels that cannot be easily
quantified as to the potential threat posed to corporate profitability. This type of problem has not been faced
before by the electric industry and, thus, must be understood as to the strategic issues and altematives that are
raised.
The new potential risk to utility investors from disruptive forces is the impact on ftlture earnings growth
expectations. Lost revenues within a net metering paradigm, for instance, are able to be recovered in future
rate cases. However, without a shift in tariff structures, there is only so much of an increase that can be
placed on remaining non-DER customers before political pressure is brought to bear on recovery
mechanisms. Once the sustainability of the utility earnings model is questioned, investors will look at the
industry through a new lens, and the view from this lens will be adverse to all stakeholders, including
investors and customers. While we do not know the degree to which customer participation in DER and
behavior change will impact utility earnings growth, the potential impact, based upon DER trends, is
considerable (as stated earlier, industry projections propose that 33 percent of the market will be in the
money for DER by 2017, assuming current tax and regulatory policies). Today, regulated utilities have seen
allowed returns on equity decline to around 10 percent, a multi-decade low point, as a result of declining
interest rates (See Exhibit 4). The cost of equity has also been growing. However, the risks in the business
have never been higher, due to increasing customer rate pressures from capital expenditures required to
upgrade the grid and address environmental mandates, inflation, low/negative demand growth from active
customers, and the threat of load lost due to the rapid development of DER and disruptive forces. The impact
of declining allowed returns and increasing business risk will place pressure on the quality and value of
utility investments. How large of an impact on investment value will be a function of the impact of disruptive
forces described herein. But, lower stock prices will likely translate into lower levels of capital spend, lower
domestic economic growth, and fewer grid enhancements.
Edison Electric lnstitute
Disruptive Challenges: Financial lmplications and Strategic Responses to a Changing Retail Electric Business
Exhibit 4
History of Allowed ROE's (U.S. Shareholder-Owned Electric Utilities)
(Based on regulatory cases settled each quarter)
14
8r,
LrJou
QI
1990
Q1
1994
Ql Ql Q1 Ql Ql Ql Ql
1996 1998 2000 2002 2004 2006 2008
Q1
1992
Ql Ql
2010 2012
Source: SNL Financial/Regulatory Research Associates (RRA), EEI Rate Department
Telephone lndustry Parallels
There are other examples in other industries that can provide lessons as to the risks of disruptive change
confronting the U.S. electric utility industry. The once fully regulated, monopoly telephone industry provides
one clear example. The telephone industry experienced significant technological changes that led to
deregulation-initially in the long-distance sector and then followed by the local exchange market.
Beginning in the 1970s, the impact of an array of new technologies (e.9., satellite, microwave, and fiber optic
technologies) led to increased telephone system capacity and a reduction in the cost of providing telephone
service. These technological changes provided the opportunity for competition by new entrants using newer
technologies, while the monopoly service provided by AT&T used older analog technology. ln 1974, MCI, a
new entrant, filed an anti-trust case challenging AT&T's monopoly powers in long-distance telephone
service. The U.S. government ruled against AT&T in 1982, which led to a negotiated plan to break up the
Bell system, which was completed in 1984. As a result, long-distance telephone service and the Bell Labs'
research anns were housed in AT&T. The local provision of phone service (i.e., intrastate regional calls) was
to remain regulated and was to be provided by seven Bell Operating Companies ("the Baby Bells"). By
1996, the Telecommunications Act opened the local telephone market to competition and allowed for
Internet providers to acquire spectrum services.
Dramatic technological change has evolved over the past 35 years, which has led to the development of a
new infrastructure system; new services that are providing abundant transfer of information; and the
convergence of voice, data, and entertainment into one combined service from what had previously been
14 Edison Electric lnstitute
Disruptive Challenges: Financial lmplications and Strategic Responses to a Changing Retail Electric Business
viewed as separate and distinct services and industries. Today, the number of customers who utilize the
previously exclusive "copper wire "telephone system represents a rapidly declining percentage of the market
for telephone services. (Verizon Communications, for example, has lost approximately 45 percent of its wire
line customers over the past five years.) Today, many customers access voice services exclusively through
mobile cellular (wireless) phones, a technology that became commercially viable in the mid- to late-1980s.
In addition, the advent ofcable-based phone service has sped the decline in copper-based services.
This transformation in the telephone sector of pre- 1982 to today has not been smooth or easy. Significant
capital investment has been made to develop new technologies and related infrastructure-it is estimated of
that more than $300 billion has been deployed to build out new telephone infrastructure. New entrants have
experienced booms and busts as the supply of capacity outstripped demand, leading to bankruptcies and
mergers. The original AT&T, the seven Baby Bells, and several large independent monopolies (e.g., GTE,
Citizens, United Telephone and Alltel) have merged into four independent companies. The sector today is
dominated by wireless and cable-based technologies.
Exhibit 5
Verizon Stock Price vs. S&P500 from 2000 to2012
- Verizon loses -45% of wireless customers
Verizon experienced leading Us wireless share
Verizon experiences rapid growth in fiber "tie" bundle
'99 Dec '01 Dec '03 Dec'05 Oec '07 Dec '09 Dec'l1
(1) lndexed to 7213117999 ptice
Source: Factset
s&P s00
There are important lessons to be learned from the history of the telephone industry. First, at the onset of the
restructuring of the Bell System, there was no vision that the changes to come would be so radical in terms of
the services to be provided and the technologies to be deployed. Second, the telephone players acted boldly
to consolidate to gain scale and then take action to utilize their market position to expand into new services
on a national scale. Finally, and most important, if telephone providers had not pursued new technologies
and the transformation of their business model, they would not have been able to survive as viable businesses
today. So, while the sector has underperformed the overall market since 2000, and as shown in Exhibit 5,
even a leading industry participant like Verizon Communications has not been able to perform in-line with
t I ir,,l'l
l;80o
Lo
-E eoo!oxo!5 ,10
0.r
Dec
Edison Electric lnstitute 15
Disruptive Challenges: Financial lmplications and Strategic Responses to a Changing Retail Electric Business
the overall market despite its growth, market share and solid profitability outlook due to the competitive
uncertainties inherent in the business. However, those telecom providers that have embraced new
technologies and addressed the competitive threats they faced have managed to survive and to protect
investors from a "Kodak moment."
Exhibit 6
Credit Capaci$ of Regulated vs. Competitive lndustries
*"rrr","a ,iir,i*,
Southern Company
ConEd
Xcel Energy
A
A.
A-
S53
27
24
Baal
Baal
Baal
25%
25%
239l
?'-b_'{:"1'"ol
3.5x
3.3x
3.8x
,rOr,O ri,tnL,
Exelon Corp
-ls-E9!gi9_u.rcs:
Telephone
AT&T
Verizon
48
. 21... _
266
222
Baa2
.s:11 _ _ .
A2
A3
BBB
._ ?ql
A-
A.
3.lx
- -?.3I
2.lx
1.9x
s5%
38%
54%
63%
Regulated Entity LO% 3.5
Competitive Telco L2% 2
Competitive Sector Cost
Premium
% ihanse-in wAcj
(l) "00f, COE ' ls divldend di*ount model coat of oqulty
From being led by a "AAA'rated company with monopoly powerc (AT&T), the telecommunications
industry looks very different today. Services today are often comprised of a bundle of telephone, Intemet,
and entertainment options provided on an unlimited basis by a monthly fee (relative to usage-based pricing
prior to 1982). The market has seen significant new entrants, capital investment, and boom and bust periods
leading to bankruptcies and/or mergers to enhance scale. Due to the increased competitive business risk, the
credit-rating agencies have downgraded the credit rating of AT&T from "AAA" in 1981 to "A "today. [n
addition, due to competitive business dynamics, the credit rating agencies expect to see significantly lower
debt leverage (thereby, raising the overall cost of capital) in order to support the credit ratings assigned. To
compare with the electric sector, a comparable rating in telecom would bear approximately 50 percent of the
leverage level of a regulated electric utility-resulting in an approximately 35 percent higher pre-tax
weighted cost of capital for the telephone sector based on credit-ratings metrics (See Exhibit 6).
While customers have benefitted from a proliferation of new services provided at a lower cost, investors
have not done as well in financing a transition to a competitive industry. These lessons should be fully
16 Edison Electric lnstitute
Disruptive Challenges: Financial lmplications and Strategic Responses to a Changing Retail Electric Business
considered as stakeholders shape the approach electric utilities pursue in participating in an environment
where disruptive technologies may transform the provision of services and the providers of these new
services.
One significant difference between the electric sector and the telecom restructuring example is the value of
the respective infrastructure following the disruptive threat. In the telecom situation, the original copper wire
phone network is of no/low value in a wireless, Internet protocol, landline world. However, the value of the
electric grid to the customer is retained in a distributed generation environment as the grid provides the
highway to sell power generated by the DER and the back-up resource infiastructure to deliver power
required when the DER is not meeting the load obligation of its provider. In essence, while a wireless user
does not need a landline, an electric consumer-generator will not be able to and will not necessarily want to
achieve full independence from the "wired" utility grid. So, while the telecom example is a tale of
responding to the threat of obsolescence, the near-term challenge to the electric sector is providing the proper
tariffdesign to allow for equitable recovery of revenue requirements to address the pace of non-economic
sector disruption.
Strategic lmplications of Distribution 2020 Disruptive Forces
The threats posed to the electric utility industry from disruptive forces, particularly distributed resources,
have serious long-term implications for the traditional electric utility business model and investor
opportunities. While the potential for significant immediate business impact is currently low (due to low
DER participation to date), the industry and its stakeholders must begin to seriously address these challenges
in order to mitigate the potential impact of disruptive forces, given the prospects for significant DER
participation in the future.
One example of a significant potential adverse impact to utility investors stems from net metering. Utilities
have witnessed the implementation of net metering rules in all but a handful of states. Lost revenues from
DER are being recovered from non-DER customers in order to encourage distributed generation
implementation. This type of lost revenue recovery drives up the prices of those non-participating customers
and creates the environment for ongoing loss of additional customers as the system cost is transferred to a
smaller and smaller base of remaining customers.
Utility investors are not being compensated for the risks associated with customer losses resulting from
increasing DER. It is difficult to identify a rate case in which the cost-of-capital implications of net metering
were considered. At the point when utility investors become focused on these new risks and start to witness
significant customer and earnings erosion trends, they will respond to these challenges. But, by then, it may
be too late to repair the utility business model.
DER is not the only disruptive risk the industry faces. Energy efficiency and DSM programs that promote
lower electricity sales pressure earnings required to support capital investment. Without a tariff structure that
properly allocates fixed vs. variable costs, any structure for lost revenues would come at a cost to non-
participating customers, who will then be more motivated to find altematives to reduce their consumption.
While it is not the objective of this paper to outline new business model alternatives to address disruptive
challenges, there are a number of actions that utilities and stakeholders should consider on a timely basis to
align the interests of all stakeholders, while avoiding additional subsidies for non-participating customers.
Edison Electric lnstitute 17
Disruptive Challenges: Financial lmplications and Strategic Responses to a Changing Retail Electric Business
These actions include:
lmmediate Actions:
r lnstitute a monthly customer service charge to all tariffs in all states in order to recover fixed costs
and eliminate the cross-subsidy biases that are created by distributed resources and net metering,
energy efficiency, and demand-side resources;
. Develop a tariff structure to reflect the cost of service and value provided to DER customers, being
off-peak service, back-up interruptible service, and the pathway to sell DER resources to the utility or
other energy supply providers; and
r Analyze revision of net metering programs in all states so that self-generated DER sales to utilities
are treated as supply-side purchases at a market-derived price. From a load provider's perspective,
this would support the adoption of distributed resources on economically driven bases, as opposed to
being incentivized by cross subsidies.
Longer-term Actions:
r Assess appropriateness of depreciation recovery lives based on the economic useful life of the
investment, factoring the potential for disruptive loss of customers;
. Consider a stranded cost charge in all states to be paid by DER and fully departing customers to
recognize the portion of investment deemed stranded as customers depart;
. Consider a customer advance in aid of construction in all states to recover upfront the cost of adding
new customers and, thus, mitigate future stranded cost risk;
. Apply more stringent capital expenditure evaluation tools to factor-in potential investment that may
be subject to stranded cost risk, including the potential to recover such investment through a
customer hook-up charge or over a shorter depreciable life;
. Identify new business models and services that can be provided by electric utilities in all states to
customers in order to recover lost margin while providing a valuable customer service-this was a
key factor in the survival of the incumbent telephone players post deregulation; and
r Factor the threat of disruptive forces in the requested cost of capital being sought.
Investors have no desire to sit by and watch as disruptive forces slice away at the value and financial
prospects of their investment. While the utility sector provides an important public good for customers,
utilities and financial managers of investments have a fiduciary responsibility to protect the value of invested
capital. Prompt action to mitigate lost revenue, while protecting customers from cross-subsidization better
aligns the interests of customers and investors.
As growth in earnings and value is a major component of equity investment returns, what will investors
expect to see as a strategic response from the industry to disruptive forces? The way to realize growth in
earnings is to develop profit streams to counterbalance the impact of disruptive forces. Examples of new
profit sources would include ownership of distributed resources with the receipt of an ongoing service fee or
rate basing the investment and financial incentives for utilities to encourage demand sideienergy effrciency
benefits for customers. From an investor perspective, this may be easier said than done because the history of
the electric utility industry in achieving non-regulated profits/value creation streams has not been a pleasant
experience. So, investors will want to see very clear cut programs to capture value that are consistent with
the core strengths of utilities: ability to execute construction projects, to provide dependable service with
high reliability, and to access relatively low-cost capital.
18 Edison Electric lnstitute
Disruptive Challenges: Financial lmplications and Strategic Responses to a Changing Retail Electric Business
O Summary
While the threat of disruptive forces on the utility industry has been limited to date, economic fundamentals
and public policies in place are likely to encourage significant future disruption to the utility business model.
Technology innovation and rate structures that encourage cross subsidization of DER and/or behavioral
modification by customers must be addressed quickly to mitigate further damage to the utility franchise and
to better align interests ofall stakeholders.
Utility investors seek a return on investment that depends on the increase in the value of their investrnent
through growth in earnings and dividends. When customers have the opportunity to reduce their use of a
product or find another provider of such service, utility earnings growth is threatened. As this threat to
growth becomes more evident, investors will become less attracted to investments in the utility sector. This
will be manifested via a higher cost of capital and less capital available to be allocated to the sector.
Investors today appear confident in the utility regulatory model since the threat of disruptive forces has been
modest to date. However, the competitive economics of distributed energy resources, such as PV solar, have
improved significantly based on technology innovation and government incentives and subsidies, including
tax and tariff-shifting incentives. But with policies in place that encourage cross subsidization of proactive
customers, those not able or willing to respond to change will not be able to bear the responsibility left
behind by proactive DER participating customers. It should not be left to the utility investor to bear the cost
of these subsidies and the threat to their investment value.
This paper encourages an immediate focus on revising state and federal policies that do not align the interests
of customers and investors, particularly revising utility tariff structures in order to eliminate cross subsidies
(by non-DER participants) and utility investor cost-recovery uncertainties. In addition, utilities and
stakeholders must develop policies and strategies to reduce the risk of ongoing customer disruption,
including assessing business models where utilities can add value to customers and investors by providing
new services.
While the pace of disruption cannot be predicted, the mere fact that we are seeing the beginning of customer
disruption and that there is a large universe of companies pursuing this opportunity highlight the importance
of proactive and timely planning to address these challenges early on so that uneconomic disruption does not
proceed further. Ultimately, all stakeholders must embrace change in technology and business models in
order to maintain a viable utility industry.
Edison Electric lnstitute 19
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BEFORE THE
IDAHO PTJBLIC UTILITIES COMMISSION
CASE NO. IPC.E-I2.27
IDAHO CLEAI{ EI\'ERGY ASSOCIATION
wHrTE C., DI TESTIMONY
EXHIBIT NO. 701
Source: Response Staff's Request No. 9 (@101890)
lncludes Corrections provided by IPC in Supplemental Response to Request No.9, Entered by C. White
BILL COMPARISON BY CUSTOMER, Sorted from Highest to Lowest Difference
CURRENT RATES VS. PROPOSED RATE$ Historical Data Year January 2012 through December 2012
Line
No. Rate Schedule
Biil -
Current Rates
Bi[ -
Proposed Rates Difference
15
26
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$571.53
$351.28
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$363.75
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$721.74
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$384.24
$327.80
$391.81
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$198.15
$659.62
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$18,125.41
$13,628.79
$9,282.37
$3,947.08
$2,569.23
$1,770.15
$1,394.15
$1,361.88
sL,292.53
$1,088.45
$1,051.70
s949.44
$764.79
$730.s6
$698.16
$660.90
$655.49
$s95.26
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$570.61
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$490.75
$487.09
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$467.47
$459.08
$423.53
$421.90
$418.65
$413.06
$405.02
$392.65
$390.31
$384.77
$37s.01
$3s3.08
$351.34
$340.71
Exhibit No. 701
Case No.IPC-E-12-27
White, C Di Testimony.
Clean Energy Association
Page I of7
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$867.13
$98.24
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$687.67
$s23.s9
$507.4s
$39t.22
$415.28
$643.78
$915.47
$184.77
$6s1.99
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$395.08
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$799.22
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$575.88
$58.25
$167.37
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$23.98
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$1,312.03
$601.37
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$748.35
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$34s.51
$319.07
s306.32
$376.70
9282.28
$453.21
$s61.28
$374.69
$392.32
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s994.95
$371.13
$617.6s
$1,233.50
$826.89
$122.73
$1,182.56
$408.98
$319.86
$991.5s
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$790.80
$670.40
$693.48
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$1,188.68
$4s7.68
$923.23
$s19.41
$663.8s
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$1,066.34
$28',1.s2
$836.68
$317.0s
$42s.86
$613.17
$274.06
$493.09
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$119.40
s487.08
$703.21
$541.90
$707.88
$1,543.37
$827.13
$640.95
$7s3.67
$970.08
$781.81
$566.78
ss40.18
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$s87.70
$491.01
$656.7s
$764.73
$577.47
$589.29
$1,292.83
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$814.67
$546.31
$1,185.92
$337.36
8328.72
8328.23
$318.59
$316.85
$315.43
$310.74
$307.47
$303.88
$786.76
$283.35
$279.18
$278.20
$273.9s
$273.22
9272.91
$271.24
$271.05
$268.76
$267.91
$267.12
$265.41
$260.80
$2s8.80
$258.49
$2s 1.90
$250.08
$244.2s
$241.67
$236.32
$233.96
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$233.50
s231.40
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92t6.43
s2l r.00
$208.73
$203.5s
$203.45
$202.78
$196.97
$195.54
$193.64
$192.1s
s191.37
s190.98
Exhibit No. 701
Case No. IPC-E-12-27
White, C Di Testimony
Clean Energy Association
Page2 of7
81
38
230
6t
177
158
25s
53
198
195
29
261
162
257
194
92
74
91
157
219
r91
55
27
183a
187
95
167
209
23s
t42
90
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116
174
144
2s3
r36
106
59
239
75
148ztt
2
126
200
18
r68
154
248
233
260
246
I84R
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I84R
184R
184R
I84R
184R
I84R
I84R
I84R
I84R
I84R
I84R
I84R
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I84R
I84R
I84R
I84R
I84R
I84R
I84R
I84R
I84R
I84R
I84R
I84R
I84R
I84R
I84R
I84R
I84R
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I84R
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I84R
I84R
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184R
I84R
I84R
I84R
I84R
184C
I84R
184R
I84C
I84R
I84R
I84R
I84R
I84R
It4R
$232.32
$4s2.43
$893.31
$373.33
$408.68
9832.92
$l l.5l
$64s.99
$674.94
$812.29
$6s1.77
($25. l 5)
$663.30
$26t.91
$299.40
$594.38
$7r2.00
$604.73
$847.47
$794.41
$718.53
$r03.35
$592.76
$1,070.08
$797.71
$86s.89
$7s8.95
$308.33
$771.05
s283.44
$s40.70
$767.07
$716.76
$296.05
$971.60
$599.09
$86.09
$170.78
$666.56
$1,067J4
$231.00
s2,855.96
$680.30
9768.79
$510.91
s699.6s
$620.32
($6.e7)
s335.35
s969.93
$274.94
$544.42
$10.73
92t4.34
$419.86
8638.47
$t,076.72
$550.31
$582.50
$1,000.14
$178.40
$812.64
$840.94
$977.42
$8r6.s2
$136.96
9824.2s
9422.s8
s457.82
$751.40
s865.78
$7s8.34
$1,001.01
$947.68
s870.62
s2s3.39
$74t.44
$1,218.64
s94l.0l
$1,004.48
$896.35
$444.71
$90s.38
$416.61
$671.02
$893.83
8E42.34
$4r8.57
$1,093.12
$719.04
$201.89
$286.42
$782.04
$1,182.40
s34s.19
$2,969.24
s79t.2s
$877.22
$616.53
$804.23
$724.40
$96.24
$435.6s
$1,065.36
$364.68
$633.03
$98.38
s30r.85
$187.53
$186.04
$183.41
$176.98
9173.82
$167.22
$166.89
$166.66
$166.00
$165.14
$164.75
$162.1I
$160.95
$160.61
$1s8.41
$157.03
$153.79
$r53.62
$153.54
sts3.27
$1s2.09
s150.04
$r48.68
$148.56
$143.30
$138.59
$137.40
sr36.38
$134.33
$133.17
$130.3 r
$126.76
$125.58
$122.52
$121.52
$119.95
$11s.80
$11s.64
$l15.48
$114.66
$r 14.19
$113.27
$l10.9s
s108.43
$10s.62
$104.s7
s104.08
$103.21
$100.30
$9s.43
$89.74
$88.61
sE7.65
s87.sl
Exhibit No.701
Case No.IPC-E-12-27
White, C Di Testimony
Clean Energy Association
Page 3 of7
o
50
268z't
269
138
197
256
254
242tl4
78
28
252
258
118
169
241
24
212
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276
134
238
266
262
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244
243
182
19
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267
229
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228
274
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88
62
175
263
120
272
181
203
264
277
216
44
50
26s
271
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184R
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184R
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184R
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I84R
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IE4R
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$r92.00
s183.57
$195.45
s10.37
91,319.77
$799.86
$250.69
$398.s 1
$2s7.78
$1,162.96
$t,192.82
91,247.53
$476.92
$119.22
$686.3s
$1,119.04
$328.38
$747.57
$571.63
$449.26
($ 17.e4)
$1,071.68
$731.57
$59.06
$204.36
$1,203.67
s305.23
$333.s3
$888.85
$49.14
$2,243.33
$978.07
$1s0.81
$1s3.99
8122.25
$763.28
$7.18
$378.81
s64.05
s1,981.69
ss6.02
6620.46
$204.90
s1,467.24
$143.38
$2,231.95
s1,398.58
s4.93
$27.94
s54.42
$1,171.53
$1,338.33
$329.86
s253.39
9276.89
s266.80
s278.08
$91.62
$1,400.94
s880.29
$329.92
$477.13
$335.96
$1,239.18
$1,268.08
$1,322.52
s551.90
$193.67
s7s9.79
$1,191.97
$401.05
$818.s9
$640.91
$517.62
$49.04
$1,133.58
$789.s9
$116.72
$260.57
$1,257.59
$358.89
$386.7s
$939.96
$100.08
$2,292.09
$1,026.42
$198.22
$198.13
$165.75
$803.06
$44.80
$415.82
$92.88
s2,010.11
$77.r3
$641.28
$225.60
$1,487.59
$160.87
$2,248.94
$1,414.91
820.92
$41.30
$65.89
sl,l82.l7
$1,347.88
s338.24
$259.79
$84.89
$83.23
$82.63
s81.2s
s81.17
s80.43
$79.23
$78.62
$78.18
$76.22
$7s.26
974.99
974.98
s74.45
$73.M
$'12.93
$72.67
$71.03
$69.28
s68.36
$66.98
s61.90
$s8.02
$s7.66
$56.21
$53.93
$53.66
$s3.22
s5l.l l
$50.94
$48.76
$48.3s
$47.41
fi44.14
$43.50
$39.79
$37.62
$37.01
$28.83
$28.42
$2r.12
s20.83
$20.70
$20.3s
$17.49
$16.99
s16.33
s15.99
$13.36
$l1.48
$l1.23
$9.s5
$8.38
$6.39
Exhibit No. 701
Case No. IPC-E-12-27
White, C Di Testimony
Clean Energy Association
Prge 4 oI7
280
205
204
201
281
279
240
275
150
170
190
70
193
273
220
221
278
99
97
r55
52
I
186
222
ts2
196
87
109
11
247
69
223
131
107
160
159
25
139
214
202
208
96
151
234
199
143
166
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I84R
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I84R
I84R
I84R
I84R
I84R
I84R
184R
I84R
I84R
I84R
I84R
I84R
I84R
I84R
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s86.80
$1,088.58
s866.38
$1,478.00
$256.13
$l 11.r I
$6.49
$99.28
$1,675.68
$1,448.90
$1,530.39
$2,262.01
$1,147.76
9322.80
$1,182.03
$1,554.33
9209.s2
$1,3M.16
$1,595.68
$2,139.24
$1,574.49
$832.28
$1,666.58
$863.4s
$2,495.37
$2,119.03
$1,458.52
$1,600.35
$882.88
s906.19
92,419.69
s2,347.05
$2,514.52
$2,4M.55
$1,114.46
$1,684.53
$2,454.70
$1,739.28
$1,935.00
$2,085.63
$1,842.95
$2,223.94
$2,t&.89
$1,421.57
$2,634.66
92,t67.78
$2,693.|s
$90.76
$1,091.31
$868.s2
$1,477.04
$2s2.74
$106.07
$0.00
$91.13
$1,662.86
$1,430.89
$1,512.17
$2,242.45
$1,122.43
$29r.53
$1,148.56
91,520.27
$169.0s
$1,343.09
$1,538.18
$2,080.22
$1,515.10
$769.86
$1,576.84
s772.16
$2,398.91
$2,022.27
$1,357.42
$1,496.91
$769.35
$791.6t
$2,303.77
s2,230.84
$2,393.99
$2,320.44
$990.25
$1,5M.47
s2,309.48
$1,590.06
$1,783.45
$1,928.84
$1,677.33
$2,039.33
$1,964.22
$1,215.95
82,412.38
$1,939.51
92,460.48
$3.97
92.73
$2.r4
($0.e6)
(s3.3e)
($5.05)
($6.4e)
(s8. I s)
(s12.82)
($ 18.01)
($ 18.22)
(s 1e.56)
(s2s.33)
(s31.28)
(s33.47)
(s34.06)
(s40.48)
(s4 r.08)
(ss7.s0)
(s5e.o2)
($5e.3e)
($62.42)
($8e.74)
(sel.2e)
($e6.46)
($e6.76)
(sr0l.r0)
($ 103.44)
($l13,54)
($r r4.58)
($r 15.e2)
($r 16.2r)
($ 120.53)
($124.1l)
($ 124.21)
($140.06)
($ 145.21)
($14e.22)
(slsl.56)
($ 1s6.79)
(s16s.62)
(s184.61)
(s200.67)
($20s.62)
($222.28)
($228.26)
($232.67)
Exhibit No. 701
Case No. IPC-E-12-27
White, C Di Testimony.
Clean Energy Association
Page 5 of7
184
117
140
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153
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226
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s2,156.50
91,997.33
$2,320.12
$1,314.30
$2,116.35
$2,470.61
$2,909.29
s2,079.13
$1,413.03
$2,785.86
$3,028.00
$2,653.45
s3,096.00
$3,303.64
$3,046.53
$3,622.48
$3,006.46
93,673.60
$3,078.95
$3,639.40
$2,598.87
84,936.79
$5,603.42
$5,558.42
$9,364.90
s19,718.02
$1,923.07
$1,763.07
$2,050.53
$1,040.94
$1,842.87
$2,178.07
52,614.27
$1,773.52
$1,087.93
$2,433.84
92,646.70
$2,229.62
$2,632.89
82,798.94
$2,528.69
$3,101.32
92,457.42
$3,1 17.84
$2,501.78
$3,032.75
$1,822.69
$4,026.92
$4,402.83
s4,354.90
$7,235.57
($233.43)
(9234.26)
($26e.58)
($273.36)
($273.48)
($2e2.54)
($2es.02)
($3os.6l)
($325. I o)
($352.02)
($381.30)
($423.83)
($463. I 1)
($s04.70)
($517.84)
($521.16)
(s54e.04)
($s55.76)
($s77.17)
($606.66)
($776. I 8)
($eoe.87)
(s1,200.59)
(s1,203.52)
($2,129.33)
963.84
Exhibit No. 701
Case No.IPC-E-(],A7
White, C Di Testimony
Clean Enerry Association
Page 6 of7
Correlation of Change in Bill with Usage
lncludes 281 Net Metering Customers
$20,000
lo
($20,000.00) ($1s,000.00) ($10,000.00)
Customers with high usage
would see decreases in their
bills.
lncrease in bill
resulting ftom
proposed changes
Customers with substantial excess generation
Note: lncludes customers with less than 12 months of billing activity
$1o,ooo.oo
-iiSooo,og- $20,ooo.oo $25,ooo.oo
$15,000
$10,000
$5,000
a
a
a
($5,Ooo.0o)
($s,000)
Customers eaming
under 2012 rate schedule
(negative bills)
Zoom in on correlation between Usage and the Ghange in Bill
lncludes Resldents Only
Y A(l3 scaled betureen $25fl) lncreaae or decrcaso to better Yiew ralortty of
custorttr
hcrease in bill reulting
ftom proposed changes
atlooo Note: lncludes customers with less than 12 months ofbilling acthiity
,'
(s2,000) ($1,ooo)t
"t.
Grcsover point Cu$oners nith usage of
approxirnably 1500 kwt/nnnh or npre uould
see decreases in bih.
$.l,mo $5,m0 g6,(xlo t7,0m $8,0m $,000 01o,0oo
t
s3,000
Exhibit No. 701
ease No. IPC-E-12-27
White, C Di Testimony
Clean Energy Association
PageT ofl
2012 BiI at Cunent Rates (Flglpr = Ffdet tlsroe)
BEFORE THE
IDAHO PT]BLIC UTILITIES COMMISSION
CASE NO.IPC.E-DA7
IDAHO CLEAI\I EI\IERGY ASSOCIATION
WI{ITE C., I)I TESTIMONY
EXHIBIT NO. 702
The growth trend provided below reflects a linear continuation of
the2010-12 growth in net meteflng capacity, kW.9;
"the installed capacity of net metering systems steadily increased from 39 kW to just under 1000
kWh between2002 and 2010. Since 2010, growth increased sharply, rising by nearly 1,500 kW
over approximately two years." (Page 12 of Direct Testimony, Matthew Larkin, Idaho Power)
"If current growth trends continue or increase, it is important to maintain a capacity limit to
allow the Company and other stakeholders to evaluate this service as it expands." (Page 13 of
Direct Testimony, Matthew Larkin, Idaho Power)
Exhibit No. 702
Case No. IPC-E-1247
White, C Di Testimony
Clean Energy Association
Page I ofl
BEX'ORE TIIE
IDAHO PTIBLIC UTILITIES COMMISSION
CASE NO.IPC.E-I247
IDAHO CLEAI\ EI\TERGY ASSOCIATION
WHITE C., DI TESTIMONY
EXHIBIT NO. 703
The value of the potential inequity claimed by the Company relates to annual excess generation,
not to customers who use net metering to offset their power bills. A separate rate structure is
unnecessary.
Of the total value of the potential inequity claimed by the
Company, 7o/o is linked to customers who use net
metering only to reduce their annual power bills
100o/o = $73,929
This is the total value of the inequity
claimed by the company for current
net metering customers in2012
For customers who offset their power
bills, the total value of the claimed
inequity represents 7o/o of lhe total for
all net metering customers tor 2012.
< The remaining portion of the claimed
inequity is represented by customers
who offset more than the total value of
their power bills in 2012.
860/o of customers use net metering to offset their
Exhibit No. 703
Case No.IPC-E-12-27
White, C Di Testimony.
Clean Energy Association
Page I of I
930h
annual bills; they represent7o/o of the claimed
inequity".. less than $6,000.
100%=281 customers
Customers with a net credit in
2012.
Customers who used net
metering in2012 only to offset
their power bills
10%
0o/"
Potential inequtty # ofcustomers
Source: Data provided by IPC in response to staff request #9; includes impact of corrections
submitted by the Company in its Supplemental Response to stafi request #9.
100%=$73.929
BEFORE TIIE
IDAHO PUBLIC UTILITIES COMIVIISSION
CASE NO.IPC.E.I2-27
IDAHO CLEAI\I EIYERGY ASSOCIATION
WIIITE C., DI TESTIMONY
EXHIBIT NO. 704
Below is one example of how high monthly fees prevent net metering customers from lowering
their bills in the same manner standard customers are allowed.
Using the empirical data provided by the Company in response to StaffRequest #9 (00101890),
the following graph shows the monthly bills in20l2 as restated by the Company for an example
net metering customer under the proposed rate structure. These are compared to the monthly
bills for a hypothetical standard customer with the same energy usage and demand.
Standard customers can lower their bills in a
manner denied to Net Meterers
180
160
1fi
120
1m
80
60
/o
m
0
Jan Feb Mar Apr lvlay Jun Jul Atg Sep Oct
Source: Customer data provided by ldaho Power in response # 9
There are many cases which would demonstrate this issue further but for which empirical data is
not available. For example, a net metering customer who is absent from their home for months
would not have the same freedom as a standard customer to lower their power bills due to the
high monthly fees. A customer with aprimary home poorly suited for customer-owned
generation and a vacation home well-suited for customer-owned generation would be
unnecessarily discouraged from offsetting their total power bills through net metering at the
vacation home due to high monthly fees. A net metering customer considering the rental of
power tools for a Saturday afternoon project must consider the risk of creating a high billing
demand that would drive up the customer's montlly BLC charges for a year. Evidence has not
been provided that justifies why a net metering customer's choices should be more constrained
than a standard service customer.
Exhibit No. 704
Case No. IPC-E-12-27
White, C Di Testimony
Clean Energy Association
Page I of I
Due to $48 monthly fees, this example net metering
customer would be denied the opportunity to lower
hislher bill in the same manner allowed to a standard
customer with equivalent usage and demand.
Net illeterer
,t $48
Monthly fee =
Service + BLC
-st"nd"rd cusfomer,
(same kwh & kW
BEFORE TIIE
IDAHO PI]BLIC UTILITIES COMNIISSION
CASE NO. IPC.E.I2.27
IDAIIO CLEA}I ENI"ERGY ASSOCIATION
WHITE C., DI TESTIMOI\-Y
EXHIBIT NO. 705
Manv net metering customers would be better offturning off their generation systems
This exhibit describes an analysis which was done in order to consider the choice net metering
customers would face of whether to pay the higher fees resulting from the proposed new rate
schedule or to turn off their generation systems, generate no electricity, and avoid paying the
unfavorable new terms proposed for net metering.
Sources: Data was combined from the following:
(8) CONFIDENTIAL Attachment - Supplemental Response to Staffs Request No. 8 (00101622)
(9) CONFIDENTIAL Attachment - Response Staffs RequestNo. 9 (00101890)
Attachment 3 - Response to Staffs Request No. l_Net Meter Rate Development (00101l7l)
Premise Numbers were referenced on documents (8) and (9) to merge the "Operation Date",
"Resource", "Total Watts", and Bill "Difference".
Customers: With regard to the customers referenced in this analysis, please note the following:. Within document (9), a total of 281 customers with billing info are referenced.r Within document (8), a total of 331 customers with system info are referenced.. Nine of the customers with billing info had no corresponding "Premise No." on the system
info document.. Fifty-two customers were not included in the analysis because there was not twelve months
of active billing data.. This leaves 220 customers with 12 months of billing data. Of these, 158 utilized solar PV as
the "Resource". To most accurately estimate production levels, only the solar customers were
evaluated.
Production estimate: The "Total Watts" for each solar system is estimated to generate 1.4
times this value in kWh per year in Southern Idaho. This estimate is based on National
Renewable Energy Lab System Advisor Model simulations using Typical Meteorological Year
weather data for the Boise area.
Production value: The total annual value of solar generation is then calculated using the
average 2012value of 0.0792 $lkwh = ($385,511,114 + $13,764,710) I (4,896,272,827kWh
+ 144,888,296kwh) from the rate design on Attachment 3. For each customer, the increase in
bills the customer would incur as a standard service customer result from turning off the
generation system was compared to the change in bills the customers would incur due to the
proposed rate structure for net metering.
Finding: Based on the empirical data and methodology above, 37 out of the 158 solar net
metering customers with active billing data throughout2Dl2 would be better offshutting off
their systems in order to avoid the unfavorable new rate structure. The increase in their bills
would be more than the value of the energy they would generate.
Exhibit No. 705
Case No. IPC-E-12-27
White, C Di Testimony
Clean Energy Association
Page 1 of 1
I
BEFORE TIIE
IDAHO PT]BLIC UTILITIES COMNISSION
CASE NO.IPC.E-I247
IDAHO CLEAN EI\IERGY ASSOCIATION
WHITE C". DI TESTIMONY
EXHIBIT NO. 706
The premium paid by standard customers relative to net metering customers at high usage levels
demonstates discrimination.
Guctonrera With tho_ sarne
wbuld,be charupo
This empirical example provided by the Company shows, for a customer
averaging -5100 kWh/ month, a {2-month totalbill based on the proposed
net metering rates. A standard customer with the same consumption would
be charged $1,203 more.
ls the premium paid by
the standard customer
lustified because it
costs $1203 less to
serYe the net metering
customer?
Or is the rate structure
designed such that
differences in bills are
not justified by
differences in costs?
Net Metering Customer Standard Customer
Source: Response to staffs request No. 9 (001 01 890)
Exhibit No. 706
Case No. IPC-B-12-27
White, C Di Testimony.
Clean Energy Association
Page 1 of I
$ 5,558
BEFORE THE
IDAHO PUBLIC UTILITIES COMIVIISSION
CASE NO.IPC-E-IIA7
IDAHO CLDAI\I EI\IERGY ASSOCIATION
WHITE C., DI TESTIMONY
EXHIBIT NO. 707
The filing changes the economics of investing in customer-owned generation to discriminate
against low usage customers
Currently, the financial benefit of generating one's own
electricity is similar across residential customers
Below is the $ benefit of offsetting 200 kwh per month for three hypothetical
customers. The value is slightly higher for customers with higher usage given
the tiered rate structure $ I yeaf
500 kwh/mo
Customer
Typical
(1050kwh/mo)
5000 kWl/mo
Customer
s1,500
Note: For simplicity, both the production level (200 kWh/mo) and kWh consumption levels were
assumed to be equal on a monthly basis.
ffi
produce.
ffi
ffi
n*#.effius -$500 $0 $500 $1,000 $1,500
Note: The above is provided as an exemplary comparison; these are not statistically representative. The kW
demand figures used for calculating the Basic Load Charge included: 7.16kW for the "Typical' customer, and
empirical examples of the monthly kW demand for customers with annual kWh consumption approximating 500
kWh/month and 5000 kWh/month above provided in IPC response to staff request (9).
I eayotf under proposedrafes
,436
Exhibit No. 707
Case No. [PC-E-12-27
White, C Di Testimony.
Clean Energy Association
Page I of I
TTry
The proposed rate structure will cause the financial
benefit of generating one's own electricity to vary
dramatically across residential customers
For the 3 hypothetical customers previously evaluated, the net benefit of investing in a
system that produces 20OkWh/month varies greatly. For the low usage customer, it is a
loss. For the high usage customer, the benefit is driven by the value of getting onto the
net metering rate schedule more so than the value of the kWh's the customer would
I Payott under current rates
500 kWh/mo
Gustomer
Typical
(1O50lorvh/mo)
5000 kWh/mo
Gustomer
($110)
o BEFORE TIIE
IDAHO PUBLIC UTILITTES COMMISSION
CASE NO.IPC.E.TTA1
IDAHO CLEAI\I EI\TERGY ASSOCIATION
WHITE C., DI TESTIMONY
BXHIBIT NO. 708
Empirical example of how high usage customers can lower their bills
For this empirical
example provided the
Company of a very high
usage customer, the
customer would pay $5k
less per year if on the
net metering rate
schedule rather than
standard service rate
schedule.
$Ofi)/rrear
tt\
Service-
Usage
Decrease =
$ 5(year
2o12Blil= Standad Serulce
Source: Response to Staff Request No. 9 (00101890)
Prcpoced = Netlbbrhg
ExhibitNo. TOt
CaseNo IPC-E-12-27
White, C Di Testimony
Clean Energy Association
Page I ofl
BEFORE TIIE
IDAHO PUBLIC UTILITIES COMNIISSION
CASE NO.IPC-E-NA7
IDAHO CLEA}I EII"ERGY ASSOCIATION
WHITE C., DI TESTIMONY
EXHIBIT NO. 709
Rates at which
IPG collects
revenue for
customer-
produced
energy
Gustomer
producing that
energy might
benefit months
later at 40% less
Note - Customer forfeits any balance of credits on Dec 31.
Summer rates for stanrdard customers
Proposed Non-summer rates ior Net tetering
ErhibitNo. T(D
Case No.IPC-E-12-27
White, C Di Testimony
Clean Energr Association
Pege2ol2
The kWh Usage Pattern of a sampling of 5 residential solar customers
kwh Net Usage Pattern
Sampling of 5 residential net metering customers
3500
3000
2500
2000
1500
1000
500
0
600
-1000
-1500
lncrease in bills resulting from proposal to
give no $ value to excess generation
- Sampling of 5 residential net metering customerc -
Each customer's 2012 monthly bills
under the proposed terms were re-
calculated to reflect one change:
monthly excess generation was given a
financial value rather than a kWh credit.
The increase in bills shown here does
not reflect the negative impact on
customers of disallowing them from
using credits past December.
fr/,
lelo
11o/o
Exhibit No. 709
Case No. IPC-E-12-27
White, C Di Testimony
Clean Energy Association
Page I of2
Source: Customer data provided by ldaho Power in response # 9
BEFORE TIIE
IDAHO PT]BLIC UTILITIES COMMISSION
CASE NO. IPC.E.IIA1
IDAHO CLEAIT EI\-ERGY ASSOCIATION
WIIITE C., DI TESTIMONY
EXHIBIT NO. 710
Estimation of the potential revenue reduction which high usage customers on Schedule 1
could achieve by shifting to the proposed net metering schedule:
Energy Usage
Range
kWh /year
18,000 - 21,000
21,001 -24,000
24,001-27,000
27,001- 30,000
30,001 - 33,000
33,001 - 36,000
36,001 - 39,000
39,00 -42,000 est.
42,001-45,000 est.
Over 45,000 est.
#of
Customers
in Usage
Rangel
26,058
16,679
10,322
6,500
3,948
2,433
1,553
1,205
1,205
1,205
Peak BLCkw'? Charge3
Change
in service
feesa
$191
s191
$191
$191
$191
$191
$191
$191
$191
s191
Change in
Enerry
Usage feess
-ss06
-$s84
-s662
-$739
-$817
-$895
-$973
-$1,051
-$1,129
-$1,207
Aggregate
change in
revenue
(reduction)6
-$3,052,353
-$2,744,640
-$2,187,938
-$1,685,972
-91,271,215
-$E61,778
-$623,709
-$541,078
-$598,209
-s655,341
Average per-customer calculations
11
13
15
t6
18
20
2t
23
25
27
$198
$228
$2s9
$289
$3 19
$350
s380
$41 I
$441
s472
Net
change
in bill
-$117
-s16s
-$212
-$2s9
-$307
-$354
-$402
-$449
-s496
-$544
Total 71,108 $14,162234
The purpose ofthis analysis is to scope the range ofrevenue reduction represented by residential
customer who could lower their bills by becoming net metering customers due to the savings resulting
from lower per-kWh rates net of the increase in service and BLC charges. The calculations presented
above indicate this potential for revenue reduction among residential customers with usage over
18,000 kWh/year is in the $14 million range. Due to limited empirical data, this is not a projection
exercise but a scoping of the size of this potential revenue reduction opportunity which can be
compared to the $74,000 increase in revenue collection estimated for 2012 and provided in response
to Staffs Request No. 9. This analysis indicates that the potential for revenue reduction is a multi
million dollar issue.
Please note:r This analysis does not project the percentage of the 70,000+ customers eligible to lower their
power bills who would act on the opportunity.r In order to isolate the impact of shifting rate schedules, the potential costs and benefits of
customer-owned generation are not included above.. This analysis involves several assumptions, as described below, which result in a range of
uncertainty. Results are presented above without rounding, but the significant digits presented in
the results are not an indicator of precision.
Methodolow and Assumntions
1. The distribution of residential customers on Schedule 1 in 2012 was provided by the
Company in IPCO Response to ICEA First Production Request (0014128) for the ranges of
kWh/ year listed above with the exception of usage over 39,000 kWh/year. The IPCE
Exhibit No. 710
Case No. IPC-E-12-27
White, C Di Testimony
Clean Energy Association
Page 1 of2
response disclosed that there are3,615 customers with usage over 39,000 kwh / year; for
purposes of the estimations above, this distribution was assumed to be evenly distibuted
across the ranges 39,001 - 42,000; 42,00145,000, and over 45,000.
2. To estimate Peak kW, the frst step was to estimate a Load Factor. From Attachment -
Supplemental Response to Staffs RequestNo.2 (00101621): Sum the Residential Service
kWh for the 12 rnonths of 2011 and divide by 8,760 hours/year = 571,185kW. The average of
the Largest and Second Largest Estimated Billing kW for Residential Service :2,857,948
kW. The Load Factor: 571,185kW I 2,857,948kW:0.1999. This is the Average
Residential Load Factor forthe Billing kW in 201l.
For the average kWh/year in each of the above usage ranges, divide by 8760 hours in ayear
to get average kW. Divide this by the average Load Factor of .1999 to get the average peak
kW forbilling.
Note this method assumes the load factor is consistent across usage ranges.
3. The BLC charge = $1.48 x (Peak kW) x 12
4. The increase in service charge : ($20.92 - $5) x 12
5. The savings due to lower kWh rate is estimated to equal $.025946 times the average kWh per
year. From Attachment 3 - Response to Staffs RequestNo. l_Net Meter Rate Development
(00101171), Rate Design, on Line No. l5:
Residential Service Net Metering Revenue Requirement Adjustment /
IPC-E-12-24 Test Year Usage Total Enerry:
F27lC27 : $127,038,981 I 4,896,272,827 kWh : S0.025946 / kWh rate discount
This is a conservative estimate given customers with higher usage see savings at the higher
end ofthe tiered rate structure.
6. Aggregate change in revenue : Net change in bill per customer x Number of customers in
kWh/year Usage Range
Exhibit No.710
Case No. IPC-E-12-27
White, C Di Testimony
Clean Energy Association
Page2 of2
BEFORE THE
IDAIIO PUBLIC UTILITIES COMMISSION
CASE NO.IPC-E.I2-27
IDAHO CLEAI\I EIYERGY ASSOCIATION
ELGETHUN, L., DI TESTIMONY
EXHIBIT NO. 711
Cumulative lnstalled Net Metering Capaclty
3,OO0
2,5O0
2,000
kw 1,500
1,000
to:
*.%"i."I"n"1*i..1"..1"o_1$"
ir
Exhibit No. 7'11
Case No. IPC-E;12-27
Elgethun, L Di Testimony
Clean Energy Association
Page 1 of 1
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