20060828Idaho Power Company comments.pdf

~ -
An IDACORP Company
IDAHO POWER COMPANY
O. BOX 70
BOISE, IDAHO 83707
RECEIVED
200G AUG 25 PM~:
BARTON L KLINE
Senior Attorney
IDAHO PUBLIC
AuguJf~5!"~6afOMM'SS'ON
HAND DELIVERED
Jean D. Jewell , Secretary
Idaho Public Utilities Commission
472 West Washington Street
P. O. Box 83720
Boise, Idaho 83720-0074
Re:Case No. GNR-06-
Comments of Idaho Power
Dear Ms. Jewell:
Please find enclosed for filing an original and seven (7) copies of
Comments of Idaho Power Company in Case No. GNR-06-02.
I would appreciate it if you would return a stamped copy of this transmittal
letter for our files in the enclosed self-addressed stamped envelope.
rws
Barton L. Kline
BLK:sh
Enclosure
Telephone [phone] Fax [phone], E-mail BKline(gjidahopower.com
BARTON L. KLINE ISB #1526
LISA D. NORDSTROM ISB #5733
Idaho Power Company
O. Box 70
Boise, Idaho 83707
Phone: [phone]
FAX: [phone]
bkline ~ idahopower.com
Inordstrom ~ idahopower.com
RECEIVED
2006 AUG 25 PM 4: ,.,
IQAHO PUBLIC
UTlLlIIES COMMISSION
Attorneys for Idaho Power Company
Express Mail Address
1221 West Idaho Street
Boise , Idaho 83702
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE COMMISSION'
CONSIDERATION OF THE FIVE
AMENDMENTS TO SECTION 111 OF THE
PUBLIC UTILITY REGULATORY POLICIES
ACT OF 1978 (PURPA) CONTAINED IN
THE ENERGY POLICY ACT OF 2005
) CASE NO. GNR-06-
) COMMENTS OF IDAHO POWER
) COMPANY
COMES NOW , Idaho Power Company ("Idaho Power" or "Company ) and
hereby responds to the Notice of Inquiry of the Idaho Public Utilities Commission (the
Commission ) issued on July 28, 2006 in Order No. 30108.
BACKGROUND
In Order No. 30108 the Commission described the scope of the Commission
obligations under the Electricity Modernization Act of 2005 (the "Modernization Act") as
follows:
COMMENTS OF IDAHO POWER COMPANY - Page
Although the Modernization Act requires the Commission to
undertake a review of the new federal standards , the Act
does not compel the Commission to adopt the standards.
PURPA recognizes that nothing "prohibits any State
regulatory authority. . . from making any determination that
it is not appropriate to implement any such standard. . . .
16 U.C. 9 2621 (a) (emphasis added). The Modernization
Act also recognizes that a state regulatory commission may
have already implemented the new federal standards or
comparable standards in prior proceedings. 16 U.C. 9
2622(d)-(f). If a state has already reviewed a new standard
- by implementing the standard/comparable standard or has
considered the standard but declined implementation - then
no further action is necessary. Id; 16 U.C. 92621 (c)(1).
In Order No. 30108 the Commission summarized and discussed the five federal
standards set out in the Modernization Act and directed Idaho Power, Avista Utilities
and PacifiCorp dba Rocky Mountain Power to address in written comments the five
federal standards described in the Modernization Act.
For each of the five federal standards these Comments will provide (1) a
summary response to provide context , (2) responses to each of the specific questions
posed in Order No. 30108 regarding the individual standards and (3) Idaho Power
recommendation as to what action , if any, the Commission should take to comply with
the requirements for consideration of the five federal standards.
THE FIVE FEDERAL STANDARDS
Net Metering
Summary Response
As the Commission noted in Order No. 30108 the Commission approved the first
net metering tariff for Idaho Power (Schedule 84) in 1997. Since that time , to make
program improvements and to respond to the Commission s policy initiative regarding
net metering availability, Idaho Power has revised Schedule 84 several times.
COMMENTS OF IDAHO POWER COMPANY - Page 2
Most recently, on August 17, 2006 Idaho Power filed an application in Case No.
I PC-06-17 seeking authority to amend its net metering provisions to eliminate
potential financial barriers to non-residential customer participation in net metering and
to further refine and improve its net metering program.
In summary, Idaho Power believes its net metering program , including the
changes it has recently proposed in Case No. IPC-06-, fully complies with the
federal standard.
Responses to Specific Questions Regarding Net Metering
Question 1. Briefly describe your net metering program.
Response. The Company current net metering program credits
residential and small general service customers at the retail energy rate for all kilowatt-
hours (kWh) generated.
All other retail customer classes are credited at the retail energy rate for the kWh
generated up to the amount of kWh consumed.Generation amounts above the
consumption amounts, net excess generation , is credited at a rate per kWh equal to
85% of the weighted average of the daily on-peak and off-peak Dow Jones Mid-
Columbia Electricity Price Index (Dow Jones Mid-C Index).
Question 2. Are all customers eligible to participate in your net metering
program?If not , why not?Are there limitations on the number of participating
customers or the amount of net metering generation?
Response. Idaho Power offers a net metering option to all its retail
energy customers. Service is available on a first-come , first-served basis until the
1 The Company has proposed in its IPC-O6-17 filing to credit excess generation from residential and
small general service customers engaged in net metering in the same manner as other customer classes.
COMMENTS OF IDAHO POWER COMPANY - Page 3
cumulative generation nameplate capacity of net metering systems equals 2.9 MW
which represents one-tenth of one percent of the Company s retail peak demand during
2000. No single seller may connect more than 20 percent of the cumulative nameplate
capacity connected. Generation projects are limited to 25 kW for residential and small
commercial customers; generation projects are limited to 100 kW for all other retail
classes. The seller s generation facility must be fueled by solar, wind , biomass
hydropower, or represent fuel cell technology.
Question 3. State the number of net metering customers by customer
class.
Response. As of July 2006 , the number of Idaho net metering
customers is:
20 Residential
Small General Service
Large General Service
Question 4. State the amount of net metering generation by customer
class.
Response. Residential and small general service customers have all
energy received and delivered by the Company through a single watt-hour retail meter.
All generation directly offsets their usage. Therefore, only generation that exceeds a
seller s usage is separately identifiable. In 2005, the net excess generation for Idaho
residential and small general service customers was 397 255 kWh.
Retail customers other than residential and small general service have a
separate meter which records all customer-generation.In 2005, the total generation
from this group of net metering Idaho customers was 749 kWh. The net excess
2 In its application in IPC-O6-, the Company is proposing to offer a single meter alternative to retail
customers other than residential and small general service.
COMMENTS OF IDAHO POWER COMPANY - Page 4
generation that exceeded the Seller s usage from this group of Idaho customers was 0
kWh.
Residential customers have a total of 148.8 kW of nameplate generation; small
general service customers have a total of 88 kW; all other classes have a total of 101.
kW. The total nameplate generation for Idaho net metering customers is 337.9 kW.
Question 5. Does your current or proposed net metering tariff/schedule
meet the federal net metering standard set out above? If not , should the Commission
adopt this standard or a comparable standard?
Response. Idaho Power s current net metering Schedule 84 , including
the changes proposed in IPC-06-, meets the federal net metering standard.
Recommendation
Idaho Power believes that its current net metering program , including the
recently filed enhancements to its Schedule 84 net metering tariff, is in full compliance
with the net metering standard contained in the Modernization Act. All of Idaho Power
customers are eligible to receive net metering service and the net metering service
complies with the description contained in 16 U.S. C. 9 2621 (d)(11). Idaho Power
recommends that the Commission find that Idaho Power has already implemented
standards that are equal to or superior to the new federal standards and no further
action is necessary with respect to this standard.
Fuel Sources
Summary Response
In its discussion on page 4 of Order No. 30108 the Commission noted that this
standard may have already been implemented in Idaho. Idaho Power concurs that the
Integrated Resource Planning ("I RP") process that this Commission requires its
COMMENTS OF IDAHO POWER COMPANY - Page 5
jurisdictional electric utilities to follow includes plans to minimize dependence on a
single fuel source and provides the process to ensure that jurisdictional utilities utilize a
diverse range of fuels and technologies, including renewable technologies , to serve
loads.
Idaho Power s 2004 IRP identified acquisition targets for a diversified resource
portfolio with nearly equal amounts of renewable generation and traditional thermal
generation. The preferred portfolio for the 2004-2013 planning period contemplated the
addition of demand response and energy efficiency programs , combined heat and
power at customer facilities , and wind , geothermal, coal and natural gas generation. If
the projects identified in the 2004 I RP preferred portfolio are completed , in 2013 Idaho
Power s resource portfolio will contain approximately: 1 800 MW hydro, 1 520 MW
coal , 350 MW wind , 340 MW natural gas combustion , 100 MW geothermal , 48
combined heat and power, and 124 MW demand-side programs. Thus , Idaho Power
2004 IRP planned to continue increasing fuel source diversity and intended to add
approximately 450 MW of renewable energy to its generation portfolio.
Per the filing extension granted in Order No. 30092 , Idaho Power intends to file
its 2006 I RP explaining its potential generation acquisitions for the next twenty (20)
years on or before September 29 , 2006. The 2006 IRP preferred portfolio will continue
to include generation from multiple fuel sources including renewable energy.
In the 2006 IRP's comparison of levelized costs of energy from a number of
supply-side resource alternatives, Idaho Power includes an adder of $14/ton (2006$)
for CO2 emissions. By recognizing the potential of future costs for CO2 emissions
diversity of resource type (coal-fired, natural gas-fired, renewable , DSM) is indirectly
encouraged in the IRP process. In addition to considering the cost of future emissions
COMMENTS OF IDAHO POWER COMPANY - Page 6
the risk analysis utilized in the 2006 IRP considers expected, low and high case natural-
gas price forecasts. Consideration of uncertainty in natural gas costs, as well as
considering the possibility of future renewable portfolio standards also tends to
encourage fuel diversity in the preferred resource portfolio.
Recommendation
Idaho Power believes that through the Integrated Resource Planning process
this Commission has already implemented the standard outlined in 16 U.C. 9
1261 (d)(12). Idaho Power recommends that the Commission find that there is no need
for it to take further action with respect to this standard.
Fossil Fuel Generation Efficiencv
Summary Response
As was the case with the fuel diversity standard , the Integrated Resource
Planning process requires each electric utility to consider and implement cost-effective
efficiency upgrades of their fossil fuel generation as part of the IRP process. As a result
of upgrades identified in prior IRPs, Since 1995, Idaho Power has completed a total of
approximately 18 MW of thermal generation upgrades for the portions of the Bridger
and Boardman Plants it owns.Idaho Power continues to seek out cost-effective
efficiency upgrades as part of its ongoing Integrated Resource Planning process.
Incremental capacity upgrades at the Company existing generating facilities are
usually some of the most cost-effective supply-side upgrades available and they
typically will be implemented whenever they are available.
Recommendation
Idaho Power believes that through the Integrated Resource Planning process
this Commission has already implemented the standard outlined in 16 U.C. 9
COMMENTS OF IDAHO POWER COMPANY - Page 7
1261 (d)(13). Idaho Power recommends that the Commission find that there is no need
for it to take further action with respect to this standard.
Smart Metering
Summary Response
For purposes of this response, Idaho Power defines "Smart Metering" as an
automated meter reading system with two-way communication capability. Idaho Power
Company and this Commission have been engaged in analysis and development of
Smart Metering programs for more than seven (7) years. As a result Idaho Power
believes that Idaho regulated utilities are much farther along the Smart Metering
learning curve than are many other electric utilities in the United States. Based on that
experience, it is the Company belief that a rapid shift from the current on-going
smaller-scale smart metering applications to a system-wide mandatory smart metering
program described in the federal standard has the potential to impose substantial costs
on customers without any clear indication of commensurate benefits.
Response to Specific Questions Regarding Smart Metering
Question 1. Briefly describe your Smart Metering programs previously
implemented. For each program indicate the number of customers actually participating
in each program. What are the differences between your programs and the federal
standard, including costs and benefits?
Response.
(a)Automated Meter Readinq (AMR) Proqram
In 1998 Idaho Power conducted a small AMR pilot program of a power line
carrier system. This pilot was conducted in the Boise County area of its service
territory. The Company installed approximately 1 200 meters during this project. Idaho
COMMENTS OF IDAHO POWER COMPANY - Page 8
Power purchased used back-office equipment for this project and this system was only
capable of providing register reads , not hourly consumptive data. The Company used
this AMR system for approximately two years. After two years the system became
unsupported by the manufacturer and the system was no longer utilized. The primary
goal of this pilot was to test an AMR system in a rural area on a long feeder. The
system functioned well considering its capabilities.
Idaho Power currently has interval meters with telephone communications
installed for all primary service level customers, special contract customers , sale-for-
resale customers, and cogeneration customers over 10 MW capacity. Of the over 300
meter installations with telephone communications, 123 are served under Rate
Schedule 19 at the primary service level and 130 are served under Rate Schedule 9 at
the primary service level. The Rate Schedule 19 Industrial Customers are currently on
seasonal time-of-use rates. The Company s Schedule 19 time-of-use rate conforms to
the federal standard as defined in section (B), paragraph (i).Approximately 117
irrigation customers are on a time-of-use rate utilizing time-of-use meters that are read
on billing cycle by meter specialists not by an AMR system.
The Company filed its AMR Phase One Implementation Plan in December 2003.
This plan was the result of a collaborative effort with Commission Staff. In this plan the
Company identified the areas to be included in the Phase One AMR project and the
operational objectives that it planned to investigate. In the spring of 2004 Idaho Power
began executing the AMR Phase One Implementation Plan.Under this plan the
Company proposed installing approximately 23 000 AMR meters in the McCall and
Emmett area of its service territory. The Company also installed substation equipment
communication lines back-office hardware and software, and a meter data
COMMENTS OF IDAHO POWER COMPANY - Page 9
management system. By the fall of 2004 the AMR meter system was installed and by
January 2005 the basic AMR metering system was fully operational. The Meter Data
Management System (MDMS), however, was not operational and is still being refined
today. Currently there are 25 585 power line carrier AMR meters installed in the
Emmett and McCall areas that are providing monthly subtractive meter readings.
These readings are then passed through a computer interface to the Company
customer billing system. Approximately 21 096 of these meter installations are on
residential accounts , 3 961 are on commercial accounts and 528 are on irrigation
accounts. The AMR System is also delivering hourly interval data for each of the meter
points. The hourly data is used to bill energy consumption under the time-of-use and
critical peak pricing pilot programs and to provide usage graphs to most of the AMR
customers via the Internet.
(b)Time-of-Dav Pricinq Proqram
With the installation of "Smart Meters , Idaho Power has offered time-of-use and
critical peak pricing programs, on a pilot program basis , to approximately 4 000
customers in the Emmett area for two years. There are currently approximately 85
customers the Time-of-Day (TOD) Program and 68 customers on the Energy Watch
(EW) Program.
The TOD program conforms to the Federal standard as defined in section (B),
paragraph (i), with the exception that the TOD prices are not set at a level reflective of
the generating cost or market prices. Rather they are set to encourage customers to
change electricity usage behavior and reduce their bill. In the Time-of-Day and Energy
Watch Pilot Programs Final Report filed with the Commission on March 29 , 2006 , the
Company demonstrated that the TOD customers did not shift a statistically significant
COMMENTS OF IDAHO POWER COMPANY - Page 10
amount of load in 2005. The participants' bills did slightly decrease on average when
compared to a control group of customers with similar energy usage patterns.
The EW program is a critical peak pricing program , as defined in section (B),
paragraph (ii), however the EW program does not overlay critical peak prices over time-
of-use prices. EW customers pay a flat rate for energy for all hours outside the Energy
Watch hours. The EW analysis showed that the customers did shift a significant
amount of peak load and reduced their summer electricity expense by approximately
$22.26 when compared to a control group.
A costs and benefits of these Time-of-Day and Energy Watch Programs have
not been analyzed.
Idaho Power has investigated the costs and benefits of AMR in general for
several years. To date a positive business case for implementing AMR system-wide
has not emerged. In the Phase One AMR Implementation Status Report filed with the
Commission on December 30, 2005 the Company committed to continue testing AMR
related technology in 2006 and conduct an in depth financial analysis of AMR during
the second half of 2007 with updated costs and benefits associated with a system-wide
AMR integration.
Question 2. Should the Commission adopt the Smart Metering standard
by requiring each utility to offer by February 8, 2007, a time-based rate to each
customer class and the necessary time based metering to individual customer upon
request? Why, or why not?
Response. Idaho Power does not think that it is in the public interest to
adopt the federal standard in a way that requires implementation of a time-based rate
COMMENTS OF IDAHO POWER COMPANY - Page
for each customer class and implementation of time-based metering for individual
customers by February 8 , 2007 for the following reasons.
In the Phase One AMR Implementation Status Report filed with the Commission
on December 30 2005 the Company proposed a two-year plan to continue testing AMR
equipment and programs and to conduct an in depth financial analysis of AMR with
updated costs and benefits associated with a system-wide AMR integration. The
Company is working toward these goals.
The Company is still attempting to resolve many issues that have been exposed
by the Phase One AMR Implementation Plan. The Meter Data Management System is
still under development and needs further scalability testing before the Company is
confident of the capabilities of the system. The Company must develop a means to
automate the integration of time variant meter data into the Customer Information
System (CIS) if it is going to move forward on large-scale time variant pricing programs.
It also might be necessary to modify the CIS to be able to utilize more billing factors to
account for seasonal time-based rates seasonal changes and maintain the current
cycle billing operation. Enabling the Company s CIS system to maintain customer
information and billing for a large-scale time variant pricing scheme will be time
consuming, costly and necessitate major back office operational changes.
A February 2007 deadline is simply too short of a timeframe to install AMR
infrastructure file pricing programs with the Commission and solicit customers
participation.
Question 3. Should the Commission adopt the time-based metering and
communications standard by applying the same requirements to all utilities?
COMMENTS OF IDAHO POWER COMPANY - Page 12
Response. No. Idaho Power would like to be allowed to develop AMR
metering strategies that take into account the differences in service territories and goals
and objectives of each utility in Idaho. Allowing utilities to proceed utilizing normal
business methods would enable the utilities to have some leverage with suppliers when
letting RFP's and negotiating contracts with purveyors of AMR meters, substation
equipment , communications equipment and customer information systems.
The Company believes that each utility s business case is unique and that any
adoption of smart metering should be done on a case-by-case basis to fit the specifics
for each utility.
Question 4. Which , if any of the four listed types of time-based rate
schedules should the Commission require? Should the same types of rate schedules
be required of all utilities and for all customer classes?
Response. Idaho Power believes that the Commission should not
implement a blanket mandate for rapid implementation of any of the four listed types of
time-based rate schedules. The Commission should allow each utility to investigate the
use of time-based rates, offer pilot programs utilizing these rates , and develop cost
effectiveness models in order to decide which if any of these rates to offer to their
customers. Each utility s needs are different for reducing peak load , managing energy
usage or effectively pricing energy and demand for their customers.
Idaho Power believes that utilities should not be required to offer time-based
rates for all customer classes. As each utility is unique , each customer class is unique
in their energy use profiles , the prices that they pay for electricity, and the pricing
components required in order to recover the costs of serving each customer class. The
COMMENTS OF IDAHO POWER COMPANY - Page 13
utilities should be allowed to work with each customer class and Commission staff to
evaluate which rate schedules should be offered to which customer classes.
Question 5. Are there other issues the Commission should consider in
reviewing this standard?
Response. There are many issues the Commission should consider in
reviewing this standard. Purchasing, installing, utilizing and maintaining an AMR or
smart meter system is very costly and complex. The AMR systems are not essential for
offering some time-based rates and in some applications other forms of metering and
communications systems should be investigated in order to offer these rates. Each
utility should be allowed to analyze their unique requirements , costs and benefits in the
establishment of utility-specific AMR systems and pricing programs.
Recommendation
This is not a new issue for the Idaho Commission. Idaho Power recommends
that the Commission acknowledge the large body of information it has already gathered
concerning the application of Smart Metering on the system of Idaho Power and other
Idaho electric utilities. Idaho Power recommends that the Commission not adopt the
federal standard but instead confirm by order its ongoing commitment to further
analysis of Smart Metering standards and the continuing commitment to fully consider
the costs and benefits of smart metering.
Interconnection
Summary Response
Idaho Power believes that with one limited exception , Idaho Power currently has
in place Commission-approved tariffs and procedures establishing best practices for
interconnection that are in compliance with the federal standard. The one limited
COMMENTS OF IDAHO POWER COMPANY - Page 14
exception arises out of the reference in the federal standard to the adoption of IEEE
Standard 1547 as the basis for setting the standards for interconnections with
Consumer" generation facilities. While Idaho Power has not yet explicitly adopted
IEEE Standard 1547 in its tariffs, the standards and best practices included in the IEEE
1547 Standard are currently a part of Idaho Power s interconnection procedures and
therefore a Commission order formally adopting the IEEE 1547 Standard for application
to distributed resources would present no problem for Idaho Power. In fact, Idaho
Power intends to file an Application to update its Schedule 72 Interconnection of Non
Utility Generation later this month and adoption of the IEEE Standard 1547 is explicitly
included in that tariff fling.
Responses to Specific Questions Regarding Interconnection
Question 1. Should the Commission adopt this standard for
interconnection a customer s on-site generating facility to local distribution facilities?
Response. There is no need to adopt the federal interconnection
standard in total. Interconnections between "Consumer" on-site generation and Idaho
Power Company s system are currently covered by approved tariffs and best practices
and procedures that comply with the federal standard. It would be reasonable for the
Commission to specifically adopt IEEE Standard 1547 for application to appropriate
projects. The balance of the federal interconnection standard is already adequately
addressed in current Idaho Power tariffs and interconnection procedures.
Question 2. Do the utilities currently have tariffs agreements
procedures or schedules delineating interconnection standards of customer-owned
3 The primary reason for filing the revisions to Schedule 72 are to comply with FERC Standards of
Conduct.
COMMENTS OF IDAHO POWER COMPANY - Page 15
generating facilities? If yes , where are they located (e., tariffs, schedules, websites
etc.)? Are there limitations on the per-customer capacity or total system capacity of
customer-owned generation facilities? What are the limits?
Response. Idaho Power currently has Commission approved tariffs and
procedures delineating best practices for interconnection of customer-owned generating
facilities.Idaho Power s Schedule 72, Schedule 84 and the Company s published
Requirements for Generation Interconnection establish reasonable "best practices" for
interconnection of customer generating facilities.Copies of these tariffs and the
Requirements for Generation Interconnection are available on the Company s website
or by calling Rowena Bishop of Idaho Power s Delivery Business Unit at (208) 388-
2688. For the convenience of the Commission s review. copies of these tariffs and
standards are attached to this response as attachments 1 through 3.
There are no limits on per-customer capacity or system capacity available to
customer-owned generation facilities. There are limitations on the size and amount of
customer-owned generation facilities that qualify for payments for net metering facilities
as provided in Schedule 84. The response to Question 2 under net metering above
describes the size limitations on participation under Schedule 84 , the net metering tariff.
Idaho Power s Schedule 72 establishes standards under which qualifying
facilities (QFs) under PURPA would interconnect and deliver energy to Idaho Power
load centers. In the case of Schedule 72, the limitations on per customer capacity arise
out of the FERC established limitations on eligibility as a QF and not system capacity.
4 Of course, the Company s OA TT also plays a significant role in the total generation
integration process.
COMMENTS OF IDAHO POWER COMPANY - Page 16
Question 3. Should the Commission adopt or consider separate
interconnection standards for smaller and larger generating facilities (e.
g.
-:::25 kW up to
100 kW, -:::1 MW ~ 1 MW , or some other limitation)?
Response. Interconnection standards for smaller generating facilities
should be different than they are for large generating facilities. The relative impact on
the utility s system and the risks imposed by such interconnections are, to some
degree , proportionate to the size of the interconnecting generation. This is why the
Company has already established different interconnection standards for small
medium and large generating facilities.See attachment No., Requirements for
Generation Interconnection.
These separate standards are based on safety and reliability criteria. If the
Commission desires to adopt or consider standards that are different than the ones
currently used , Idaho Power urges the Commission to work with utility generation and
generation interconnection specialists to ensure that such revised standards do not
impose additional costs on the utility or compromise safety or reliability of the system.
Question 4. Should the Commission adopt IEEE Standard 1547?
Response. As previously noted , because the Company currently utilizes
the standards and best practices covered by IEEE Standard 1547 in its interconnection
procedures , Idaho Power would have no objection to the Commission explicitly
adopting IEEE Standard 1547 for use in appropriate situations. As the Commission
noted in its discussion of this standard in Order No. 30108 , IEEE Standard 1547 is
intended to apply to generating facilities with a capacity of 10 MV A or less. So long as
application of IEEE Standard 1547 is limited to appropriate situations, formal adoption
of IEEE Standard 1547 should present no problems.
COMMENTS OF IDAHO POWER COMPANY - Page 17
Question 5. Should the Commission adopt the NARUC Model
Interconnection Procedures Agreement?
Response. Efforts to develop standardized generation interconnection
procedures and pro-forma interconnection agreements have been occurring for some
time within multiple forums, including the FERC , beginning with its Advanced Notice of
Proposed Rulemaking in 2002. These various proceedings have engaged stakeholders
with wide and varying perspectives. Idaho Power followed both the FERC and NARUC
processes and has concluded that NARUC's process achieved the more balanced
outcome, recognizing, just as utilities which have successfully been interconnecting all
sizes and types of generation for decades do, that "one size does not fit aiL"
The NARUC process also acknowledged that there are many locational , policy
and technical issues best addressed through other entities such as IEEE, NERC
WECC and the individual state regulating bodies. To this end , the Company has
supported NARUC's efforts as being generally consistent with our own experience and
understanding of optimal interconnection requirements.
The Company recognizes that the adoption of any standardized interconnection
procedures and interconnection pro-forma agreements whether developed by NARUC
FERC or state regulators can serve a valuable function in that expectations for project
developers and the interconnecting utilities are discussed and more clearly defined.
The policy of cost-following-causation is important to maintain , tracking through both the
request for interconnection and the subsequent construction operation and
maintenance agreement.
The Company also understands the value and importance of allowing diversified
resources access to and use of the delivery system while maintaining safety and
COMMENTS OF IDAHO POWER COMPANY - Page 18
reliability to other customers.
With that background , and fully recognizing the State of Idaho s contribution
toward development of the NARUC models, Idaho Power does not believe it is
necessary for the Commission to adopt or require the use of the NARUC Model
Interconnection Procedures Agreement.
Over the past twenty (20) years , Idaho Power has entered into more than one
hundred (100) interconnection arrangements under Schedules 72 and 84 for both small
and large distributed generation projects.Idaho Power believes this track record
provides strong evidence that the current interconnection procedures and standards
developed over many years and continuously approved by the Commission , are
reasonable and are working well.
As noted previously in these comments, later this month Idaho Power intends to
file a revised Schedule 72 which will include a proposed Uniform Interconnection
Agreement which will work in tandem with the Company s Commission-approved
Schedule 72. As noted above , Schedule 72 addresses OF interconnection and parallel
operation issues as well as interconnection issues for net metering customers under
Schedule 84.
In preparing the proposed Schedule 72 Uniform Interconnection Agreement
Idaho Power reviewed the NARUC Model Interconnection Procedures Agreement as
well as the FERC's Large Generator Interconnection Agreement (LGIA) and Small
Generation Interconnection Agreement (SGIA). The Company also included contract
provisions that have been accepted by the Commission in dozens of firm energy sales
agreements over the years. As previously noted , Idaho Power is proposing these
COMMENTS OF IDAHO POWER COMPANY - Page 19
changes to Schedule 72 to respond to FERC's Standards of Conduct and not because
there are any defects in the interconnection process that require "fixing
Question 6. Are there other issues the Commission should consider
regarding this standard?
Response. While Idaho Power does not believe the Commission should
consider this issue in this docket, the location of proposed generation interconnections
on the grid is a rapidly emerging issue that will have a major impact on resource
interconnection. While traditionally regulators and others have attempted to define the
interconnection process and interconnection agreements in terms of resource size
location on the system is rapidly becoming a significant determinant of interconnection
impact. Therefore project size is becoming more of an arbitrary yardstick in defining
standardized processes and timelines when considering safe , economical and reliable
operation of the system for the benefit Idaho retail customers.
The concept of streamlining or expediting the interconnection of projects can
remove perceived barriers when warranted. However, the Company is concerned that
the various screening criteria contained both in the NARUC Model and the FERC rules
do not always produce the desired outcome.
Further, given the Company s inability to control the order, location, cumulative
impact and timing of generation interconnection requests and given the number of
experienced staff needed to process and respond to transmission requests, managing
the "que" can overwhelm the available resources and make compliance with extremely
short prescribed timelines very difficult. It is not only important to work quickly for the
customer, but the Company is also ultimately responsible for ensuring it is done
correctly.
COMMENTS OF IDAHO POWER COMPANY - Page 20
The Company received over 175 interconnection requests in the past several
years of all types, sizes and locations.Certainly not all of these requests have
culminated in completed projects.Some of these projects are network resources
seeking to sell their output to the Company.Some of these projects have been
merchant requests seeking access to wholesale markets, even from interconnection on
a 12.5 kV distribution circuit serving retail customers.
Issues flowing from the diversity of project requests are further compounded by
the intended disposition of energy, potentially dictating a different set of policies
procedures and agreement structure.Project developers often do not have a
purchase/sales agreement in place when they first apply for interconnection. Other
developers assume receipt of a purchase/sale agreement assures project validity.
Those development models need to be reassessed. In the future astute developers will
request interconnection early in their development process to identify as soon as
possible if there may be network capacity constraints or other transmission issues
resulting from their proposed location.Having multiple processes dependant upon
separate jurisdictional oversight (e.g. FERC and State) leads to additional confusion
and potential complications for customers.Especially those who are not full-time
generation developers.
It is the Company s belief that its customers and its interconnection customers
are best served by following a uniform interconnection process.Interconnection
standards and agreements with reasonable utility cost-recovery provisions which
conform to reliability standards are essential for both Idaho Power and the continued
development of desirable resources.
COMMENTS OF IDAHO POWER COMPANY - Page
DATED this 25th day of August, 2006, at Boise, Idaho.
BARTON L. KLINE
Attorney for Idaho Power Company
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on this 25th day of August, 2006, I served a true and
correct copy of the within and foregoing document upon the following named parties at
the electronic address given below:
Commission Staff Donald L. Howell , II
Deputy Attorney General
Idaho Public Utilities Commission
472 W. Washington (83702)
O. Box 83720
Boise, ID 83720-0074
Don. howell ~ puc. idaho.qov
Harry Hall, Staff Engineer
Idaho Public Utilities Commission
472 W. Washington (83702)
O. Box 83720
Boise , ID 83720-0074
Harry.hall ~ puc.idaho.qov
Avista Corporation Kelly Norwood
Vice President State Regulation
Bruce Folsom, Manager
Avista Utilities
O. Box 3727
Spokane , W A 99220-3727
Kellv. norwood ~ avistacorp.com
Bruce.folsom ~ avistacorp.com
David Meyer
P. & Chief Counsel
A vista Corporation
O. Box 3727
Spokane , VV A 9920-3727
David.mever~ avista.com
COMMENTS OF IDAHO POWER COMPANY - Page 22
PacifiCorp, dba Rocky Mountain Power
Sorenson Engineering
Pam Conley
Hunt Technologies
New Energy Coalition
R. Simplot Company
COMMENTS OF IDAHO POWER COMPANY - Page 23
Dean Brockbank, Attorney
PacifiCorp, dba Rocky Mountain Power
201 S. Main Street, Suite 2200
Salt Lake City, UT 84111
Dean.brockbank ~ pacificorp.com
Brian Dickman , Manager
PacifiCorp, dba Rocky Mountain Power
201 S. Main Street , Suite 2300
Salt Lake City, UT 84111
Brian.dickman ~ pacificorp.com
Ted S. Sorenson , P.
Sorenson Engineering
5203 South 11 th East
Idaho falls, ID 83404
ted ~ tsorenson. net
Pam Conley
O. Box 2526
Boise , Idaho 83701
pQconley ~ cableone. net
Scott H. DeBroff, Esq.
Smigel , Anderson & Sacks
4431 N. front Street
Harrisburg, PA 17110
sdebroff ~ sasllp.com
Ken Miller
Idaho Energy Advocate
NW Energy Coalition
5400 W. Franklin , Suite G
Boise , ID 83705
ken ~ nwenerQY .Qor
David Hawk
Director, Energy Natural Resources
R. Simplot Company
O. Box 27 (83707)
999 Main Street
Boise, Idaho 83702
dhawk ~ simplot.com
Itron, Inc.Ben Boyd
Director, Regulatory Affairs
Itron , Inc.
5430 Hickory Village Drive.
Kingwood, TX 77345
ben.bovd ~ itron.com
Industrial Customers of Idaho Power Peter Richardson
Richardson & O'Leary, PLLC
515 N. 2ih Street
Boise, Idaho 83702
peter~ richardsonandolearv.com
Bart
COMMENTS OF IDAHO POWER COMPANY - Page 24
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on this 25th day of August , 2006, I served a true and
correct copy of the within and foregoing document upon the following named parties by
S. Mail, postage prepaid as follows:
Commission Staff Donald L. Howell , II
Deputy Attorney General
Idaho Public Utilities Commission
472 W. Washington (83702)
O. Box 83720
Boise , ID 83720-0074
Don. howell ~ puc. idaho.Qov
Harry Hall , Staff Engineer
Idaho Public Utilities Commission
472 W. Washington (83702)
O. Box 83720
Boise, ID 83720-0074
Harry. hall ~ puc.idaho.Qov
Avista Corporation Kelly Norwood
Vice President State Regulation
Bruce Folsom , Manager
Avista Utilities
O. Box 3727
Spokane, WA 99220-3727
Kelly.norwood ~ avistacorp.com
Bruce.folsom ~ avistacorp.com
PacifiCorp, dba Rocky Mountain Power
David Meyer
P. & Chief Counsel
Avista Corporation
O. Box 3727
Spokane , WA 9920-3727
David. meyer ~ avista.com
Dean Brockbank, Attorney
PacifiCorp, dba Rocky Mountain Power
201 S. Main Street, Suite 2200
Salt Lake City, UT 84111
Dean.brockbank ~ pacificorp.com
Brian Dickman , Manager
PacifiCorp, dba Rocky Mountain Power
201 S. Main Street, Suite 2300
Salt Lake City, UT 84111
Brian.dickman ~ pacificorp.com
CERTIFICATE OF SERVICE
Sorenson Engineering
Pam Conley
Hunt Technologies
New Energy Coalition
R. Simplot Company
Itron , Inc.
Industrial Customers of Idaho Power
CERTIFICATE OF SERVICE
Ted S. Sorenson , P.
Sorenson Engineering
5203 South 11 th East
Idaho falls , ID 83404
ted ~tsorenson.net
Pam Conley
O. Box 2526
Boise , Idaho 83701
pqconley ~ cableone.net
Scott H. OeBroff, Esq.
Smigel, Anderson & Sacks
4431 N. front Street
Harrisburg, PA 17110
sdebroff~sasllp.com
Ken Miller
Idaho Energy Advocate
NW Energy Coalition
5400 W. Franklin, Suite G
Boise , 10 83705
ken~nwenerqy.qor
David Hawk
Director, Energy Natural Resources
R. Simplot Company
O. Box 27 (83707)
999 Main Street
Boise, Idaho 83702
dhawk ~ simplot.com
Ben Boyd
Director, Regulatory Affairs
Itron, Inc.
5430 Hickory Village Drive.
Kingwood , TX 77345
ben.boyd ~ itron.com
Peter Richardson
Richardson & O'Leary, PLLC
515 N. 2ih Street
Boise, Idaho 83702
eter~ richardsonandolea .com
Barton L. Kline
Case No. GNR-O6-
COMMENTS OF IDAHO POWER COMPANY
SCHEDULE 72
ATTACHMENT NO.
Idaho Power Company IDAHO PUBLIC UTILITIES COMMISSIONApproved EffectiveOriinal Sheet No. 72-May 31 2006 June 2006
Jean D. Jewell Secretary
I.P.C. No. 28. Tariff No. 101
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILITY GENERATION
AVAilABILITY
Service under this schedule is available throughout the Company s service area within the State
of Idaho to Sellers owning or operating Qualifying Facilities or that qualify for Schedule 84.
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 Seller 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 Interconnection Facilities which are subject to a Vested Interest.
Companv is the Idaho Power Company.
Connected load is the combined input rating of the Customer s motors and other energy
consuming devices.
Construction Cost is the cost, as determined by the Company, of Upgrades , Relocation or
construction of Company furnished Interconnection Facilities.
Disconnection Equipment 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 Enerqy Date is the date when the Seller begins delivering energy to the Company
system.
Generation Facility means equipment used to produce electric energy at a specific physical
location which meets the requirements to be a Qualifying Facility or that qualify for Schedule 84.
Interconnection Facilities are all facilities which are reasonably required by prudent electrical
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.
Interconnection Point is the point where the Seller s conductors connect to the facilities owned
by the Company.
IDAHO
Issued Per IPUC Order No. 30035
Effective - June 1 2006
Issued by IDAHO POWER COMPANY
John R. Gale, Vice President, Regulatory Affairs
1221 West Idaho Street, Boise, Idaho
Idaho Power Company IDAHO PUBLIC UTILITIES COMMISSIONApproved EffectiveOriinal Sheet No. 72-May 31, 2006 June 1 , 2006
Jean D. Jewell Secretary
I.P.C. No. 28. Tariff No. 101
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILITY GENERATION
(Continued)
DEFINITIONS (Continued)
Meterinq Equipment is the Company owned equipment required to measure, record or
telemeter power flows between the Seller s Generation Facility and the Company s system.
Protection Equipment is the circuit-interrupting device, protective relaying, and associated
instrument transformers.
PURPA means the Public Utility Regulatory Policies Act of 1978.
Qualifvinq Facility 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 I, 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.
Schedule 84 is the Company s service schedule which provides for sales of electric energy tothe Company by means of a net metering arrangement or its successor(s) as approved by the
Commission.
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
including net metering sales , as provided in Schedule 84.
Seller-Furnished Facilities are those portions of the Interconnection 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
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.
Upqrades are those improvements to the Company s existing system which are reasonably
required by prudent electrical 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.
IDAHO
Issued Per IPUC Order No. 30035
Effective - June 1 , 2006
Issued by IDAHO POWER COMPANY
John R. Gale, Vice President, Regulatory Affairs
1221 West Idaho Street, Boise , Idaho
Idaho Power Company IDAHO PUBLIC UTILITIES COMMISSIONApproved EffectiveOriinal Sheet No. 72-May 31, 2006 June 2006
Jean D. Jewell Secretary
I.P.C. No. 28. Tariff No.1 01
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILITY GENERATION
(Continued)
DEFINITIONS (Continued)
Vested Interest is the claim for refund that a Seller or Additional Applicant holds in a specific
portion of Company-owned Interconnection Facilities. The Vested Interest expires 5 years from the
date the Company completes construction of its portion of the Interconnection Facilities unless fully
refunded earlier. Vested Interests do not apply to Schedule 84 net metering projects.
COST OF INTERCONNECTION FACILITIES
All Interconnection Facilities provided under this schedule will be valued at the Company
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 otherwise by written agreement between the Seller and the
Company, the Seller will pay all costs of interconnecting a Generation Facility to the Company
system.
Unless specifically agreed otherwise in a written agreement between the Seller and the
Company, an initial cost estimate of Company-owned Interconnection Facilities will be provided to theSeller. Payment of the estimated cost will be required prior to the Company s ordering, installing,
modifying, upgrading, or performing in any other way work associated with the Interconnection
Facilities. Upon completion of the Company-owned Interconnection Facilities , the actual costs will be
reconciled against the estimated cost previously paid by the Seller and the appropriate billing or refund
will be processed. The Company reserves the right to collect additional costs from the Seller for any
additional Company equipment, modifications, or upgrades the Company deems necessary to operate
and maintain a safe, reliable electrical system as a result of the interconnection of the Seller
Generation Facility to the Company s system.
CONSTRUCTION AND OPERATION OF INTERCONNECTION FACILITIES
All Seller-Furnished Interconnection Facilities will be constructed and maintained in a manner to
be in full compliance with all prudent electrical practices, National 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 Interconnection Facilities
under this schedule have been obtained from applicable Federal, state, or local authorities.
IDAHO
Issued Per IPUC Order No. 30035
Effective - June 1 2006
Issued by IDAHO POWER COMPANY
John R. Gale, Vice President , Regulatory Affairs
1221 West Idaho Street, Boise , Idaho
Idaho Power Company IDAHO PUBLIC UTILITIES COMMISSIONApproved EffectiveOriinal Sheet No. 72-May 31, 2006 June 1 , 2006
Jean D. Jewell Secretary
I.P.C. No. 28. Tariff No. 101
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILITY GENERATION
(Continued)
CONSTRUCTION AND OPERATION OF INTERCONNECTION FACILITIES (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
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 notify 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 Generationand Interconnection Facilities from the Company s system. The Disconnection Equipment for a
Schedule 84 net metering facility will be installed at an electrical location on the Seller s side of the
Company retail metering point to allow complete isolation of the Seller Generation and
Interconnection Facilities from the Seller s other electrical load and service.
The Disconnection Equipment's operating device shall be:
Readily accessible by the Company at all times.
Clearly marked "Generation Disconnect Switch" with permanent 3/8 inch or larger letters.
IDAHO
Issued Per IPUC Order No. 30035
Effective - June 1 , 2006
Issued by IDAHO POWER COMPANY
John R. Gale , Vice President, Regulatory Affairs
1221 West Idaho Street, Boise, Idaho
Idaho Power Company
I.P.C. No. 28. Tariff No. 101
IDAHO PUBLIC UTILITIES COMMISSIONApproved EffectiveOriinal Sheet No. 72-May 31 , 2006 June 1 , 2006
Jean D. Jewell Secretary
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILITY GENERATION
(Continued)
DISCONNECTION EQUIPMENT (Continued)3. Physically installed at a location within 10 feet of the Interconnection Point or exact
permanent instructions posted at the Interconnection Point indicating the precise location of the
Disconnection Equipment's operating device.4. Of a design manually operated and lockable in the open position with a standard
Company padlock.
Operation of Disconnection Equipment., in the reasonable opinion of the Company, the
Seller s operation or maintenance of the Generation Facility or Interconnection 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 Interconnection Facilities by
operation of the disconnection device or by any other means the Company deems necessary to
adequately disconnect the Seller s Generation and Interconnection Facilities from the Company
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 Seller s Generation and Interconnection Facilities in the event
of any planned or unplanned maintenance or repair of the Company s system connected to the Seller
Generation and Interconnection Facilities. In the event of unplanned maintenance or repairs, no prior
notice will be provided. In 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 Interconnection 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.
All expenses of disconnection and reconnection incurred by the Company will be billed to the
Seller.
In the case of a net metering facility, 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.
The Company will establish the settings of Protection Equipment to disconnect the Seller
Generation Facility and Interconnection Facilities for the protection of the Company s system and
personnel consistent with prudent electrical practices. If the Seller attempts to modify, 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 Seller s Generation
and Interconnection Facilities to the Company s system.
IDAHO
Issued Per IPUC Order No. 30035
Effective - June 1 , 2006
Issued by IDAHO POWER COMPANY
John R. Gale , Vice President, Regulatory Affairs
1221 West Idaho Street, Boise , Idaho
Idaho Power Company IDAHO PUBLIC UTILITIES COMMISSIONApproved EffectiveOriinal Sheet No. 72-May 31 , 2006 June 1 , 2006
Jean D. Jewell Secretary
I.P.C. No. 28. Tariff No. 101
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILITY GENERATION
(Continued)
GENERAL REQUIREMENTS OF INTERCONNECTED PROJECTS1. The Company will construct, own , operate and maintain all equipment, Upgrades and
Relocations on the Company s electrical side of the Interconnection Point.2. The Company will clearly mark the Metering Equipment and any other Company
equipment associated with the Seller s Generation Facility and/or Interconnection Facilities designating
the existence of the Seller s Generation Facility as required by prudent electrical 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.
SPECIFIC PROJECT REQUIREMENTS
Generation Facilities Interconnectinq as a Schedule 84 (net meterinq) Proiect
Certification prior to interconnection:
Seller Generation Facilities that qualify for net metering under Schedule 84 will submit to
the Company a certification from an independent qualified party licensed in the State of Idaho
that the design and equipment in the Generation Facility and Seller-Furnished Facilities (1)
comply with the standards of this schedule and applicable electric and building codes and (2)
will operate to safely deliver Energy to the Interconnection Point. The Seller shall provide the
credentials and licenses of the certifying party to the Company for review and acceptance of the
certification.
Periodic re-certification:
i. Proiects laroer than 25 kW. The Seller will obtain an annual certification
from an independent qualified party licensed in the State of Idaho, certifying the
Generation Facility and Seller-Furnished Facilities and equipment are in compliance with
all current applicable electrical and safety codes and are able to safely and reliably
continue to operate. The Seller will provide the credentials and licenses of the certifying
party to the Company for review and acceptance of the certification. A copy of this
certification must be forwarded to the Company by May 1 st of each calendar year in
which the Seller s facility is interconnected to the Company s system. Within the first
calendar year of operation , the Seller will be required to supply only the certifications
required at the time of the initial interconnection. If the Company does not accept the
annual certification within sixty days of its receipt, the Generation Facility will be
disconnected from the Company s system until such time as the certification is
completed and accepted by the Company.
IDAHO
Issued Per IPUC Order No. 30035
Effective - June 1 , 2006
Issued by IDAHO POWER COMPANY
John R. Gale, Vice President , Regulatory Affairs
1221 West Idaho Street, Boise , Idaho
Idaho Power Company IDAHO PUBLIC UTILITIES COMMISSIONApproved EffectiveOriinal Sheet No. 72-May 31 , 2006 June 1 , 2006
Jean D. Jewell Secretary
I.P.C. No. 28. Tariff No. 101
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILITY GENERATION
(Continued)
(Continued)
Generation Facilities Interconnectinq as Schedule 84 (net meterinq) Project
ii. Proiects 25 kW and smaller.The above described certification will be
provided every three years.
iii. Re-certification followinq modifications Prior to making any material
modifications or additions to the Generation Facility or Interconnection Facilities Seller
will provide Company with a written description of the proposed change. The Company
will expeditiously review the proposal and authorize Seller to proceed subject to final
inspection and certification by a qualified party as described in paragraph 1 a above. Any
modifications made without notice will result in disconnection of the facility until such
time as certification of the modified facility is submitted to and accepted by the
Company.
Generation Facilities Less Than 1 MW Nameplate Ratinq
The following requirements are for Generation Facilities with nameplate ratings of less than
, not including net metering facilities utilizing Schedule 84.a. The Company shall procure, install , own and maintain Metering Equipment to
record energy deliveries to the Company. This metering will be separate from any other
metering of the Seller s load and may be located on either side of the Interconnection Point. All
acquisition, installation , maintenance, inspection and testing costs related to Meter Equipment
installed to measure the Seller s energy deliveries to the Company shall be born 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.c. 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 Idaho stating that the Seller s Generation Facility
and Interconnection Facilities are in compliance with all applicable electrical and safety codes to
enable safe and reliable operation.d. The Seller will obtain and provide to the Company an annual certification and
testing by a professional engineer licensed in the State of Idaho, certifying the ongoing
compliance with all applicable electrical and safety codes and that the Seller-Furnished
Facilities successfully meet applicable testing requirements and standards. In the event the
Company does not receive and accept the annual certification within 30 days of the annual
anniversary date of the agreement, the project will be disconnected from the Company s system
until such time as the certification is completed and accepted by the Company.
IDAHO
Issued Per IPUC Order No. 30035
Effective - June 1 , 2006
Issued by IDAHO POWER COMPANY
John R. Gale, Vice President, Regulatory Affairs
1221 West Idaho Street, Boise, Idaho
Idaho Power Company IDAHO PUBLIC UTILITIES COMMISSIONApproved EffectiveOriinal Sheet No. 72-May 31 , 2006 June 1 , 2006
Jean D. Jewell Secretary
I.P.C. No. 28 . Tariff No. 101
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILITY GENERATION
(Continued)
Generation Facilities Less Than 1 MW Nameplate Ratinq (Continued)e. In 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. If the Company owns the transformer interconnecting the Seller
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. If 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 Seller s expense.
iii. The Company will construct , own , operate and maintain all protective
relays and any associated equipment required to operate the protective relays.
Generation Facilities Greater Than 1 MW Nameplate Ratinq
The Company will own, maintain and operate all Interconnection Facilities and Disconnection
Equipment at the Seller s expense.
TRANSFER OF INTERCONNECTION FACILITIES
Transfer of Interconnection Facilities is available only for Generation Facilities with nameplate
ratings greater than 100 kW.
1. Transfer at First Enerqy Date. If the Seller desires to transfer and the Company desires
to accept any Seller-Furnished 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 Seller s contractor with construction and material
specifications and will have final approval of the design of the Seller-Furnished Facilities.
IDAHO
Issued Per IPUC Order No. 30035
Effective - June 1 , 2006
Issued by IDAHO POWER COMPANY
John R. Gale, Vice President, Regulatory Affairs
1221 West Idaho Street, Boise , Idaho
Idaho Power Company IDAHO PUBLIC UTILITIES COMMISSIONApproved EffectiveOriinal Sheet No. 72-May 31 2006 June 1 , 2006
Jean D. Jewell Secretary
I.P.C. No. 28 , Tariff No.1 01
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILITY GENERATION
(Continued)
Transfer at First Enerqy Date (Continued)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.d. If the Seller-Furnished 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 EnergyDate. In 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. Subsequent Transfer., after the First Energy Date, the Seller desires to transfer and
the Company desires to accept any Seller-Furnished 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.b. 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 equal to the depreciated
Construction Cost.c. 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 will 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.d. Effective as of the date of the transfer, the Company will operate and maintain
the transferred facilities.
IDAHO
Issued Per IPUC Order No. 30035
Effective - June 1 , 2006
Issued by IDAHO POWER COMPANY
John R. Gale, Vice President, Regulatory Affairs
1221 West Idaho Street, Boise, Idaho
Idaho Power Company IDAHO PUBLIC UTILITIES COMMISSIONApproved EffectiveOriinal Sheet No. 72-10 May 31 2006 June 1 2006
Jean D. Jewell Secretary
I.P.C. No. 28. Tariff No. 101
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILITY GENERATION
(Continued)
VESTED INTEREST
A Seller s eligibility for a Vested Interest refund will exist for 5 years after the date the Company
completes construction of its portion of the Interconnection Facilities.1. The Company will provide a refund payment to each Seller holding a Vested Interest in
Company-owned Interconnection Facilities when an Additional Applicant shares use of those
Interconnection Facilities.
The refund payment will be based on the following formula:
Refund =
Linear
Footage
Ratio
Connected
Load/Peak Generation
Ratio
Original
Interconnection
Costa. 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 all other Connected Loads and/or Peak Generation
on the Special Facilities.c. The Original Interconnection Cost is the sum of the Company s Construction Cost
and any Transfer Costs for the Interconnection 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 Interest
refund(s). Additional Applicants making Vested Interest payments are in turn eligible to receive refunds
within the 5 year limit described above.4. Vested Interest refunds will not exceed 100 percent of the refundable portion of any
party s cash payment to the Company.
Vested Interest refund payments may be waived by notifying the Company in writing.
IDAHO
Issued Per IPUC Order No. 30035
Effective - June 1 2006
Issued by IDAHO POWER COMPANY
John R. Gale , Vice President, Regulatory Affairs
1221 West Idaho Street, Boise, Idaho
Idaho Power Company IDAHO PUBLIC UTILITIES COMMISSIONApproved EffectiveOriinal Sheet No. 72-11 May 31 , 2006 June 2006
Jean D. Jewell Secretary
I.P.C. No. 28, Tariff No. 101
SCHEDULE 72
INTERCONNECTIONS TO
NON-UTILITY GENERATION
(Continued)
OPERATION AND MAINTENANCE OBLIGATIONS AND EXPENSES
The Company will operate and maintain Company furnished Interconnection 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 Company a monthly operation and maintenance 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:
Year
O&M Charge 26%27%28%29%30%32%33%035%36%38%0.40%0.41%
Year
O&M Charge 0.43%0.45%0.47%0.49%52%54%56%59%62%64%67%70%
Year
O&M Charge 73%77%80%84%87%91%96%00%04%09%14%
MONTHLY OPERATION AND MAINTENANCE CHARGES
138 kV and 161 kV
Year
O&M Charge 0.47%0.49%52%54%56%59%61%64%67%70%73%77%
Year
O&M Charge 80%84%87%91%95%00%04%09%14%19%24%30%
Year
O&M Charge 36%1.42%1.48%55%62%69%77%85%93%02%11%
MONTHLY OPERATING AND MAINTENANCE CHARGES
Below 138 kV
Where a Seller s interconnection will utilize Interconnection 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 Interest 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 Seller s sole risk and expense.
IDAHO
Issued Per IPUC Order No. 30035
Effective - June 1 , 2006
Issued by IDAHO POWER COMPANY
John R. Gale , Vice President, Regulatory Affairs
1221 West Idaho Street, Boise , Idaho
Case No.GNR-O6-
COMMENTS OF IDAHO POWER COMPANY
CHED ULE
ATTACHMENT NO.
Idaho Power Company IDAHO PUBLIC UTILITIES COMMISSIONApproved EffectiveOriinal Sheet No. 84-May 31 2006 June 1 2006
Jean D. Jewell Secretary
I.P.C. No. 28. Tariff No. 101
SCHEDULE 84
CUSTOMER ENERGY
PRODUCTION NET METERING
AVAILABILITY
Service under this schedule is available throughout the Company s service territory within the
State of Idaho for Customers intending to operate as Sellers under this schedule to generate electricity to
reduce all or part of their monthly energy usage.
Service under this schedule is available on a first-come , first-served basis until the cumulative
generation nameplate capacity of net metering systems equals 2.9 MW, which represents one-tenth of
one percent of the Company s retail peak demand during 2000. No single Seller may connect more
than 20 percent of the cumulative generation nameplate capacity connected under this schedule.
APPLICABILITY
Service under this schedule is applicable to any Seller that:1. Owns and/or operates a Generation Facility fueled by solar, wind , biomass, or
hydropower, or represents fuel cell technology; and2. Maintains its retail electric service account for the loads served at the Point of Delivery
adjacent to the Generation Interconnection Point as active and in good standing; and3. Meets all applicable requirements of the Company s Schedule 72 and Generation
Interconnection Process; and
Takes retail electric service under:
Schedule 1 or Schedule 7 ; and
Owns and/or operates a Generation Facility with a total nameplate capacity rating of 25
kW or smaller that is interconnected to the Seller s individual electric system on the Seller s side
of the Point of Delivery, thus all energy received and delivered by the Company is through the
existing watt-hour retail meter.
Schedules other than Schedule 1 or Schedule 7; and
Owns and/or operates a Generation Facility with a total nameplate capacity rating of 100
kW or smaller that is interconnected at a Generation Interconnection Point that is adjacent to the
Sellers Point of Delivery and is metered at the same voltage through a meter that is separate
from the retail load metering at the Sellers Point of Delivery.
IDAHO
Issued Per IPUC Order No. 30035
Effective - June 1 2006
Issued by IDAHO POWER COMPANY
John R. Gale , Vice President, Regulatory Affairs
1221 West Idaho Street, Boise, Idaho
Idaho Power Company IDAHO PUBLIC UTILITIES COMMISSIONApproved EffectiveOriinal Sheet No. 84-May 31 , 2006 June 1 , 2006
Jean D. Jewell Secretary
I.P.C. No. 28. Tariff No. 101
SCHEDULE 84
CUSTOMER ENERGY
PRODUCTION NET METERING
(Continued)
DEFINITIONS
Avoided Enerqy Cost is the monthly weighted average of the daily on-peak and off-peak Dow
Jones Mid-Columbia Electricity Price Index (Dow Jones Mid-C Index) prices for non-firm energy published
in the Wall Street Journal. This rate is calculated based upon the previous calendar month's data. If the
Dow Jones Mid-Index prices are not reported for a particular day or days, the average of the
immediately preceding and following reporting periods or days will be used.
Generation Facility 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
Interconnection Point, or is consumed by the Seller.
Generation Interconnection Process is the Company s generation interconnection application and
engineering review process developed to ensure a safe and reliable generation interconnection.
Interconnection 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 Interconnection Point.
Generation Interconnection Point is the point where the conductors installed to allow receipt of
Sellers generation connect to the Company s facilities adjacent to the Sellers Point of Delivery.
Point of Delivery is the retail metering point where the Company s and the Seller s electrical
facilities are interconnected to allow Seller 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.
Seller is any Customer that owns and/or operates a Generation Facility and desires to
interconnect the Generation Facility to the Company s system to potentially sell net surplus energy to the
Company.
MONTHLY BILLING
The Seller shall be billed in accordance with the Seller s applicable standard service schedule
including appropriate monthly charges.
IDAHO
Issued Per IPUC Order No. 30035
Effective - June 1 , 2006
Issued by IDAHO POWER COMPANY
John R. Gale, Vice President, Regulatory Affairs
1221 West Idaho Street, Boise, Idaho
Idaho Power Company IDAHO PUBLIC UTILITIES COMMISSIONApproved EffectiveOriinal Sheet No. 84-May 31, 2006 June 1 , 2006
Jean D. Jewell Secretary
I.P.C. No. 28, Tariff No. 101
SCHEDULE 84
CUSTOMER ENERGY
PRODUCTION NET METERING
(Continued)
CONDITIONS OF PURCHASE AND SALE
The conditions listed below shall apply to all transactions under this schedule.
Balances of generation and usage by the Seller:a. If electricity supplied by the Company during the Billing Period exceeds the
electricity generated by the Seller and delivered to the Company during the Billing Period , the
Seller shall be billed for the net electricity supplied by the Company at the Seller s standard
schedule retail rate , in accordance with normal metering practices.b. If electricity generated by the Seller during the Billing Period exceeds the electricity
supplied by the Company during the Billing Period, the Seller:i. Shall be billed for the applicable Demand and other non-energy charges for
the Billing Period under the Seller s standard service schedule, andii. Shall be financially credited for the net energy delivered to the Company
during the Billing Period at the Seller s standard service schedule retail rate for Schedule
or Schedule 7 service. Sellers taking service under schedules other than Schedule 1 or
Schedule 7 will be credited an amount per kWh equal to 85 percent of the most recently
calculated monthly per kWh Avoided Energy Cost for the kWh of net energy delivered to
the Company.
iii. Shall, if taking service under a schedule other than Schedule 1 or Schedule
, be billed the applicable retail rate for any net usage delivered by the Company and
recorded on the Seller s generation meter.
As a condition of interconnection with the Company, the Seller shall:a. Complete and maintain all requirements of interconnection in accordance with
the applicable portions of Schedule 72.b. Complete and maintain all requirements of the Company Generation
Interconnection Process.c. Obtain written confirmation from the Company that all conditions to
interconnection have been fulfilled prior to operation of the Generation Facility. Such
confirmation shall not be unreasonably withheld by the Company.3. The Seller shall never deliver or attempt to deliver energy to the Company s system
when the Company s system serving the Seller s Generation Facility is de-energized for any reason.
IDAHO
Issued Per IPUC Order No. 30035
Effective - June 1 , 2006
Issued by IDAHO POWER COMPANY
John R. Gale, Vice President, Regulatory Affairs
1221 West Idaho Street, Boise , Idaho
Idaho Power Company IDAHO PU~LlC UTILITIES COMMISSIONApproved EffectiveOriinal Sheet No. 84-May 31 , 2006 June 1 , 2006
Jean D. Jewell Secretary
I.P.C. No. 28. Tariff No. 101
SCHEDULE 84
CUSTOMER ENERGY
PRODUCTION NET METERING
(Continued)
CONDITIONS OF PURCHASE AND SALE (Continued)4. The Company shall not be liable directly or indirectly for permitting or continuing to allow
an attachment of a net metering facility to the Company s system , or for the acts or omissions of the
Seller that cause loss or injury, including death , to any third party.5. The Seller is responsible for all costs associated with the Generation Facility and
Interconnection Facilities. The Seller 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.6. The Company shall not be obligated to accept, and the Company may require the Seller
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.7. If the Company is required by the Commission to institute curtailment of deliveries of
electricity to its customers, the Company may require the Seller to curtail its consumption of electricity
in the same manner and to the same degree as other Customers within the same customer class who
do not own Generation Facilities.8. The Seller shall grant to the Company all access to all Company equipment and facilities
including adequate and continuing access rights to the property of the Seller 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
Seller s Interconnections Facilities.
IDAHO
Issued Per IPUC Order No. 30035
Effective - June 1 2006
Issued by IDAHO POWER COMPANY
John R. Gale, Vice President, Regulatory Affairs
1221 West Idaho Street, Boise, Idaho
Case No. GNR-O6-
COMMENTS OF IDAHO POWER COMPANY
REQUIREMENTS FOR
GENERA TION INTERCONNECTION
ATTACHMENT NO.
IDAHO
PO\NER
lIS", ILJ,\CORF (:omp",y.
Req uirements
For
Generation Interconnection
Idaho Power Company
1221 W. Idaho Street
Boise, Idaho 83702
[phone]
This document is to be used as only a general guideline of specific interconnection requirements.
In developing this document, Idaho Power Company has reviewed and incorporated various electrical
codes and regulations, safety codes and regulations, prudent electrical practices, utility codes and
regulations, Federal and state regulations, and the Idaho Power Company system impact. In the event any
statements or interpretations within this document are inconsistent with the various governing standards
and codes, the standards and codes will govern. Idaho Power Company reserves the right to update, correct
and/or modify these Interconnection Requirements without notice.
April 2002
IDAHO
POWER
1\,-, IL);\LU~~ (.:crnp.",..
THE IDAHO POWER COMW ANY
Requirements for
Generation Interconnection
TABLE OF CONTENTS
GENERAL.........................................................................................................................
Introduction...................................................................................................................
Responsibilities of the Generator................................................................................
Generation System Operation .....................................................................................
Separate System........................................................................................................ 7
Parallel System..........................................................................................................
DEFINITIONS ...
............ ..... ......
............................... ...... .................... ........................ ....... 7
DESIGN REQUIREMENTS FOR PARALLEL SYSTEM OPERATION .............. 11
General Requirements
................................................................................................
Electrical Specifications.. ....... ...................... ...... ......... ......... ............ .............. ............. 12
Generation ................................................................................................................... 13
Synchronous Generators..
...... ................... ............ ......... ........... ...... ...........
"""""" 13
Induction Generators .............................................................................................. 14
DC Inverters ............................................................................................................ 14
Interconnection Equipment .......................................................................................
Dedicated Transformer..........................................................................................
Revenue Metering ...................................................................................................
Disconnect Device....................................................................................................
Protection and Control Equipment....................................................................... 16
Telemetry ................................................................................................................ 18
Network Upgrades..................................................................................................
OPERATING REQUIREMENTS """""""""""""""""""'."""""""..........................
General.........................................................................................................................
TEST REQUIREMENTS ..............................................................................................
General.........................................................................................................................
Acceptance Testing .....................................................................................................
Maintenance Testing...................................................................................................
SPECIFIC REQUIREMENTS......................................................................................
April 2002
IbOHO
PONER
1m !IJ.\U)~I' ccmp3rr,.
Generation Classifications..........................................................................................
Total Generation Less Than lOO-kV A...................................................................... 22
Total Generation lOO-kV A to i-MY A....................................................................... 24
Total Generation More Than l-MV A....................................................................... 25
REFERENCES
........................................................
....................................................... 27
April 2002
PART 1
1.1.
,~
IDAHO
PO'NER
lOin IU.,(u~~ campsrr;
GENERAL
Introduction
This guideline describes the minimum requirements for safe and effective
operation of generation on The Idaho Power Company (!PC) system. The
generation owner (Generator) and IPC personnel will be guided by this document
when planning installations of generation interconnected with the IPC system.
is emphasized that these guidelines are general and may not cover all details
in specific cases. Additional requirements not found in the document may be
necessary as a result of the findings of a system impact study for a specific
project.
IPC will pennit any Generator to operate generating equipment in parallel with
IPC's electric system whenever this can be done without adverse effects to the
general public or to IPC equipment and personnel. Interconnections to the IPC
system may be made at the transmission or distribution level consistent with IPC'
Open Access Transmission Tariff (OATI) filed with the Federal Energy
Regulatory Commission (FERC).
Certain interconnection equipment (disconnects, relays, circuit breakers, meters
communications, etc.) must be installed where a Generator desires to operate
generation in parallel with the IPC system. In general, Figure 1.1 summarizes
these requirements. Specific requirements of the Generator s generation
equipment are specified herein.
Figure 1-
SUMMARY OF INTERCONNECTION REQUIREMENTS I
Interconnection Equipmene 25-25-kV A 100-kVA More
kVA than
or less 100-kVA MV A MV A
Dedicated Transformer
Revenue Metering
Disconnect Device XII
Circuit Interrupting Device XII
OverlUnder Voltage Protection
(59/27)
OverlUnder Frequency
Protection (810/81U)
Multifunction Relayl u, lZ
Telemetry 11
All reqUIrements are based on generator nameplate, unless otherwIse IndIcated.
April 2002
loin IU.\CCl~~ ccrnpal"l',
The equipment listed fulfills only the minimum requirements necessary to protect IPC and its
customers. Additional equipment may be required to ensure adequate protection based on the
factors discussed herein.
In general, generators less than 1 OO-kW generating at a secondary voltage level may not require a
dedicated transformer. However, this must be approved by IPC after review ofthe project details.
IPC will own the revenue meter. IfIPC owns the dedicated transformer, the meter will be located
on the low-voltage system (transformer secondary side). If the Generator owns the dedicated
transformer, the meter will be located on the high-voltage system (transformer primary side).
Generator may own, install, and maintain on the low-voltage system (transformer secondary side).
IfIPC owns the dedicated transformer, this device may be owned, installed, and maintained by the
Generator on the low-voltage system (transformer secondary side). Ifthe Generator owns the
dedicated transformer, this device shall be owned, installed, operated and maintained by IPC on
the high-voltage system (transformer primary side).
IPC owned, installed, operated, and maintained.
Generator may own, install, and maintain on the low-voltage system (transformer secondary side).
The device shall be capable of being remotely tripped by IPC.
Additional disconnect devices will be required for electrical isolation of interconnection facilities
for maintenance. The additional disconnect devices will be considered as network upgrades.
IPC owned relay(s) that performs multiple protection functions that include, but not limited to
over/under voltage, over/under frequency, ground fault protection, overcurrent with voltage
restraint or voltage restraint/voltage control overcurrent, phase directional overcurrent, out of step,
etc.
Requirement is based on deliveries to IPC , not necessarily generator nameplate rating.
Telemetering for net power output may be required based on interconnection agreement and
contractual arrangements for generation output.
12 An IPC owned dedicated DC power supply (battery or UPS) is required for all generation projects
larger than 300-kW.
Non-islanding DC inverters meeting the requirements of IEEE 929 and UL 1741 may have these
functions incorporated in, or integral, to the DC inverter package.
In general, commingling of load and generation downstream of an
interconnection point is not allowed unless the Generator qualifies under Net
Metering tariff, or other contractual arrangements (facilities charges, standby
power contracts, etc.) are established.
IPC shall have the right to review the design of a Generator s equipment and
interconnection facilities and to inspect the facilities prior to commencement of
parallel operation with IPC's electrical system. IPC may require a Generator to
make modifications as necessary to comply with the requirements of this
document. IPC's review and authorization for parallel operation shall not be
construed as confinning or endorsing the Generator s design or as waITanting the
generation and interconnection facilities' safety, durability, or reliability.
IPC's minimum requirements are designed and intended to protect IPC from
damage. IPC will not assume any responsibility for protection of the Generator
generator(s) or of any other portion of the Generator s equipment. The Generator
is fully responsible for protecting its equipment in such a manner that faults or
April 2002
1.2.
I DAHO
PO\NER
IJ..-, IU,KU~f' "-,cmparr,'
other disturbances on the IPC system do not cause damage to the Generator
equipment. In addition, the Generator is fully responsible for protecting the IPC
system and its customers from damage due to operation of the Generator
facilities. Use of these guidelines and specifications does not relieve the
Generator of any liability or obligations. In the event of any damage or injury as a
result of the operation of the Generator s generation either at the Generator
location or any location in the IPC system, the Generator will be liable for all such
damages or injury.
Throughout this document, generation size is addressed on the basis of volt-
amperes (VA) or kilovolt-amperes (kV A) rather than watts or kilowatts (kW).
However, for generation projects of 25- kV A or smaller, the rating of equipment is
often provided to IPC from the Generator in watts or kilowatts. Such ratings will
be considered equivalent of the same rating in volt-amperes or kilovolt-amperes
since the power factor of the generation equipment may be unknown (e.g. 25-kW ~
25-kV A)
Responsibilities of the Generator
The Generator is responsible for the following as part of the review, design, and
construction of the generation interconnection:
Design, installation, operation and maintenance of his own equipment in
accordance with all applicable federal, state, electrical, and safety codes as
well as prudent electrical utility practices.
Obtaining the necessary pennits and inspections requITed by the federal
state, and local authorities having jurisdiction over the generation project.
Submitting specifications for the generation equipment and
specifications/control schematics for the Generator-provided
interconnection protection and control devices to IPC for review and
written approval prior to parallel operation. Note: Written approval by IPC
does not indicate or ensure acceptance by local code authorities.
Providing access for IPC to Generator owned facilities for switching,
dispatching, inspection, and other requITed operations needs.
1.3.
Complying with the requITements as specified herein.
Reimbursing IPC for all expenses (labor, mileage, equipment, overheads
etc) incUITed to review, design, construct or any other function requITed to
enable the installation and interconnection of the Generator s generation
facility.
Generation System Operation
The Generator may elect to run its generator in parallel (interconnected) with IPC
or as a separate system with the capability of nonparallel load transfer between the
two independent systems. The two methods of operation are outlined below.
April 2002
DAHO
PC7NER
,~, ILJ,'::::JR~ (;cl11lpsrr.
A. Separate System
A separate system is one in which there is no possibility of delivering energy to the
IPC system ITom the Generator s equipment. For this operation to be practical the
Generator may want to maintain the capability of transfening load between the
two systems, but such transfer must be accomplished in an open transition or
nonparallel mode. This can be accomplished by either an electrically or
mechanically interlocked switching aITangement, which precludes operation of
both switches in the closed position simultaneously.
If the Generator has a separate system, IPC will require verification that the
transfer scheme meets the nonparallel requirements. This will be accomplished by
review and approval of drawings and equipment specifications by IPC, and if IPC
so elects, by field inspection of the transfer scheme. IPC will not be responsible
for approving the Generator s generation equipment and assumes no responsibility
for its design or operation.B. Parallel System
A parallel system is one in which the Generator s generation equipment can be
connected to IPC's system resulting in a transfer of power between the two
systems. A consequence of such parallel operation is that the parallel generator
becomes an electrical part of the IPC system, which must be considered in the
operation and protection of IPC's facilities.
The general and specific requirements for parallel generation installations are
discussed in the following sections.
PART 2 DEFINITIONS
Acceptance Test - A test perfonned or witnessed once for a specific protection
package or device to detennine whether specified requirements are met.
ANSI - American National Standards Institute
Automatic Disconnect Device - An electronic or mechanical device used to
isolate a circuit or piece of equipment ITom a source of power without the need for
human intervention.
Circuit - A conducting part through which an electric CUlTent is intended to flow.
Circuit Interrupting Device - A device designed to open and close a circuit by
non-automatic means and to open the circuit automatically as a result of a system
excursion without damage to itself when properly applied within its rating.
Cogeneration - The sequential production of electricity and heat, steam, or useful
work ITom the same fuel source.
Coordinated Interconnection Review - Any studies perfonned by utilities to
ensure that the safety and reliability of the electric grid with respect to the
interconnection of distributed generation as discussed in this document.
April 2002
IOOHO
. .
PCNVER
lOT. l(;h\lUR~ Ccmpsrr.
Dedicated Transformer - A transfonner that provides electrical service to only
one customer. The customer mayor may not have a generation facility. Note:
Dedicated" does not imply de facto ownership or exclusive use by the Generator.
Direct Transfer Trip - Remote operation of a circuit interrupting device by means
of a communication charmel.
Disconnect (verb) - To isolate a circuit or equipment from a source of power.
isolation is accomplished with a solid-state device
, "
Disconnect" shall mean to
cease the transfer of power.
Disconnect Device - A mechanical device used for isolating a circuit or equipment
from a source of power.
Dispatchability - The generating facility is operable and can be called upon at any
time to increase its deliveries of capacity to any level up to the contract capacity.
Disturbance - Trouble on the electrical system nonnally referring to fluctuation of
frequency or voltage values.
Electric Generator - A machine or device that transfonns energy (solar
mechanical, etc.) into electrical power.
Energy Conversion Device - A machine or solid state circuit for changing direct
CUITent to alternating CUITent or a machine that changes shaft horsepower to
electrical power.
Energize - To apply voltage to a circuit or piece of equipment.
Equipment - A general tenn including material, fittings, devices, appliances
fixtures, apparatus, and the like used as a part of, or in connection with, an
electrical installation.
Fault -An electrical short circuit between elements of potential difference.
Feeder -All circuit conductors between the utility distribution substation, or other
power supply source, and the final point of interconnection with a customer or
Generator.
Forced Outage - Any electrical outage resulting from a design defect, inadequate
construction, operator error or a breakdown of the mechanical or electrical
equipment that fully or partially curtails the electrical output of the generating
facility.
Frequency - The nrnnber of cycles occurring in a given interval of time (usually
on second) in an electric CUITent. Frequency is commonly expressed in Hertz.
Generating Facility - A plant wherein electrical energy is produced from some
other fonn of energy by means of suitable converting apparatus, including the
generation apparatus and all associated equipment owned, maintained, and
operated by the Generator.
April 2002
II1AHO
:-'
PO\NER
'm IIJ.,::::mf' compSFr.
Ground - A conducting connection, whether intentional or accidental, between an
electrical circuit or equipment and the earth (zero potential), or to some conducting
body that serves in place of the earth.
Hertz - The tenn denoting cycles per second or frequency.
IEEE - Institute of Electrical and Electronics Engineers, luc
Interconnection - The physical electrical connection that allows the transfer of
electrical energy between a generating facility and the utility.
Interconnection Equipment - The equipment required by prudent electrical utility
practice and applicable electrical and safety codes to interconnect, operate, and
safely deliver energy from the Generator to the utility system.
Islanding - A condition in which a portion of the IPC system that contains both
load and distributed generation is isolated from the remainder of the IPC system.
Kilovolt (kV) - An electrical unit of potential that equals 1 000 volts.
Kilovolt-Amperes (kV A) - The product of kilovolts and amperes that defines
equipment and/or circuit ratings.
Kilowatt (kW) - An electrical unit of power that equals 1 000 watts
Kilowatt-hour (kWh) - 1 000 watts of energy supplied for 1 hour.
Megawatt (MW) - An electrical unit of power that equals 1 000 000 watts.
Maintenance Test - A test perfonned upon initial installation and repeated
periodically to detennine that there is continued acceptable perfonnance.
Nameplate Rating - Output rating infonnation appearing on a generator
nameplate in accordance with applicable industry standards.
NEMA - National Electrical Manufacturers Association
NERC - North American Reliability Council
Network Upgrades - Those additions and modifications to the electrical system
that are integrated with and support the overall system for the general benefit of all
users of the electrical system, and are needed to accept delivery of energy from the
Generator. Network upgrades are generally owned and maintained by the utility at
the Generator s request and expense. Network upgrades are often refelTed to as
special facilities
OSHA - Occupational Safety & Health Administration
Outage - A condition existing when a circuit is de-energized.
Overload - A load in amperes greater than an electric device or circuit is designed
to caIT)' or operate.
Overvoltage - Voltage higher than that desired or for which equipment is
designed.
April 2002
IMHO
POVVER
"r, IU,\ClJRF CCmpsrri
Parallel - To electrically connect a generator or energized source, operating at an
acceptable fIequency and voltage, with an adjacent generator or energized system
after matching fIequency, voltage, and phase angle.
Parallel Operation - The operation of a non- utility generator while connected to
the utility's grid. Parallel operation may be solely for the Generator s operating
convenience or for the purpose of delivering power to the utilities grid.
Point of Interconnection - The point where the Generator s conductors meet the
utilities (point of ownership change).
Power - The time rate at which electrical energy is emitted, transfelTed, or
received; usually expressed in watts.
Power Factor - The ratio of actual power to apparent power.
Power System Stabilizer or PSS - A control system applied to a generator that
monitors generator variables such as cUlTent, voltage, and shaft speed and sends
the appropriate control signals to the voltage regulator to damp system oscillations.
Primary - Nonnally considered as the high voltage winding of a substation or
distribution transfonner.
Protection Equipment - Circuit intelTUpting device, protective relaying, and
associated instrument transfonners (if applicable).
Prudent Electrical Practices - Those practices, methods, and equipment, that are
commonly used in prudent electrical engineering and operations to design and
operate electrical equipment lawfully and with safety, dependability, efficiency,
and economy.
Radial Feeder - A distribution line that branches out fIom a substation and is
nonnally not connected to another substation or another circuit sharing a common
supply.
Relay - A device that is operative by a variation in the condition of one electric
circuit to affect the operation of another device in the same or in another electric
circuit.
Secondary - The winding of a transfonner that is nonnally operated at a lower
voltage than the primary winding.
Self-Excited - An electric machine in which the field CUlTent is secured fIom its
own annature CUlTent.
Synchronism - Expresses the condition across an open circuit wherein the voltage
sine wave on one side matches the voltage sine wave on the other side in fIequency
and without phase angle differences.
System - The entire generating, transmitting, and distributing facilities of an
electric company.
April 2002
PART 3
April 2002
I\n ILJ.\:::U~" ccmparf.
System Operator - A generic tenn used to describe the individuals responsible
for the integrity or the operational control of the Transmission Owner s System
and any successor thereto.
Transmission Owner s System - The integrated system of electrical generation
transmission, and distribution facilities, and all equipment and facilities ancillary
thereto, owned and/or operated by the Transmission Owner.
UL - UndeIWriters Laboratories
WSCC - Western States Coordinating Council
DESIGN REQUIREMENTS FOR PARALLEL SYSTEM OPERATION
General Requirements
IPC is required to follow certain safety procedures and maintain specified service
limits of voltage, ftequency, flicker, hannonic distortion, fault protection, and
surge capability of the IPC system. The introduction of a parallel generator
represents additional constraints that present several concems and additional
responsibilities for IPC that cannot be delegated to others:
1. Personnel Protection: IPC operating personnel need to be aware of the
exact location of all generation sources and appropriate action taken to
isolate them before beginning work on a circuit. IPC safety procedures (in
accordance with OSHA) require that a visible and lockable disconnect
device be provided at all electrical sources to ensure that a circuit is not
inadvertently energized. In addition, proper grounding is required to assure
the proper operation of circuit protective devices as well as assuring
operating personnel in the vicinity of the generation facilities are not
exposed to the danger of critical electric shock.
2. Relaying and Controls: IPC electric facilities are subject to a variety of
hazards. Among these are lightning, wind, animals, automobiles, malicious
mischief, human elTor, and equipment failures. The electric problems
which can result ftom these hazards, are principally either faulted or broken
circuits. These conditions require that the circuit be de- energized as soon
as possible because of the hazards they pose (both safety and equipment
damage). IPC installs equipment that is adequate, under expected
circmnstances, to detect and disconnect faulted equipment or circuits ftom
the IPC system. Since a parallel generator represents another source of
power, it alters the load flow and system protection characteristics of a
circuit, both during nonnal and faulted conditions, as well as affecting the
operation of automatic reclosing controls.
3. Power Quality: Power quality issues that must be considered for any
interconnected generation are voltage regulation, hannonics, flicker, and
phase unbalance because they affect both IPC and its customers. All
generators have an affect on power quality to some degree, and certain
measures may be required to mitigate these effects. When multiple
I DDaHO
PCNUER
1\'1", ID.'LU~~ Wmparr,
generators are connected to the same circuit, they may have a cumulative
affect on the power quality and additional measures may be required.
4. Islanding: Depending on its type and capacity and its relationship to the
IPC circuit load at any instant, a Generator may be able to maintain electric
supply to other customers on a circuit when that circuit is disconnected
from IPc. In this condition, the isolated system may continue to operate
independent of IPC causing a safety hazard, and likely with abnonnal
voltage or frequency causing problems for other IPC customers.
5. System Control: The loading of large generators is typically controlled by
a central computer that continuously monitors the system load from instant
to instant and adjusts the generator throttles accordingly (automatic
generation control) to match the system load. This type of control system
requires continuous and accurate telemetering of generators and utility ties
and requires communications circuits to link the various system generation
components to the central computer. Large Generators are required to be
incorporated into the automatic generation control scheme as well as
smaller Generators in physical locations where there is a large penetration
of distributed small generators.
6. Metering: The complexity and arrangement of the utility metering
equipment will depend on the size of the generator and the contractual
arrangements for the purchasing of the generation output. Generators that
intend to sell the generation output off system will be required to meter
their generation output continuously, and telemeter the real- time data to a
central location for comparison with an established transmission schedule.
The equipment and requirements described in the following sections are intended
to address the concerns and additional responsibilities noted above. These
requirements are few for small installations but increase as the size of the
generation increases.
Electrical Specifications
Parallel generation shall meet the following specifications:
Voltage: Matching the rated voltage of the IPC circuit at the point of
interconnection; 106 V to 132 V nus phase to ground (nominal 120 V nus
base) unless agreed upon otherwise.
Voltage Regulation: In accordance with ANSI C84., Range A.
Automatic voltage regulation is not allowed unless it is fully integrated
with the system operations, and the voltage is adjusted to meet an
operational schedule as contracted with IPc.
Frequency: 59.3 Hz to 60.5 Hz.
Limitation on DC injection: No greater than 0.5% of rated output current
and in accordance with the latest edition of IEEE 929.
April 2002
DAHO
PO\NER
1'II'i IU.\CLJRI' UJrnpafl','
Limitation of Voltage Flicker: In accordance with the latest edition of
IEEE 141 and must not exceed the limits defined by the maximum
pemrissible voltage fluctuations border line of visibility curve, Figure 10.
identified in IEEE 519.
Hannonics: Limit the maxlinum individual fTequency voltage hannonic to
3% of the fundamental fTequency, and the voltage Total Hannonic
Distortion (THD) to 5% at the point of interconnection ill accordance with
the latest edition of IEEE 519.
Surge Capability: In accordance with the latest edition of IEEE/ ANSI
C62.41 or IEEE C37.90.
Power Factor: 0.9 power factor (either leading or lagging). Operation
outside this range is acceptable provided the power factor is adjusted to
meet an operational schedule as contracted with IPc.
GrOlillding: Generation and interconnection facilities shall be grounded in
accordance with the latest edition of ANSI/IEEE 80, National Electrical
Safety Code, and National Electrical Code as applicable.
Gene rationA. Synchronous Generators
Synchronizing facilities: The Generator shall provide automatic synchronizing
equipment or manual synchronizing with relay supervision. The synchronizing
facilities shall have the following:
1. Slip fTequency matching 0.1 Hz, or less.
2. Voltage matching + 1 0%, or less.
3. Phase angle acceptance + 10 degrees, or less.
4. Breaker closure time compensation.
Automatic Voltage Regulation (A VR): Each synchronous interconnected unit
shall have A VR and such A VR shall be tuned in accordance with IEEE Standard
421 or its successor. Voltage regulator controls and limit functions (such
over/under excitation and volts/hertz limiters) shall coordinate with the
Generator s short-tenn duration capabilities and protective relays. A VRs must be
continuously acting and power factor regulation may be required. Unless agreed
upon by the Generator and IPC, synchronous generators shall automatically
regulate power factor, not voltage, while operating in parallel with IPC's
distribution system; however, system stabilization may be required for larger
generators connected to the transmission system.
Power System Stabilizer (PSS): Generators greater than 30- MW are required to
have a PSS. The PSS shall be installed and operated on generation units with a
suitable exciter in accordance with Western States Coordinating Council (WSCC)
policy statement on PSS and the Reliability Management System (RMS) Criteria.
April 2002
IDAHC
....,.
PO\NER
Iln ;L'\CO~~ (;ompsrY,'
Induction Generators
Induction generation may be connected and brought up to synchronous speed (as
an induction motor) if it can be demonstrated that the initial voltage drop measured
at the point of interconnection is acceptable based on current inrush limits. The
same requirements also apply to induction generation connected at or near
synchronous speed because a voltage dip is present due to inrush magnetizing
current. The Generator shall submit the expected number of starts per specific
time period and maximum starting kV A data to IPC to verify that the voltage dip
due to starting is within the visible flicker limits specified above.
Starting or rapid load fluctuations on induction generators can adversely impact
IPC's system voltage. Corrective techniques may be necessary.
The IPC system may provide reactive V AR capacity to the induction generators at
the Generator s expense. The installation of power factor correction capacitors by
the Generator on the Generator s side of the interconnection point must be
reviewed and approved by IPC prior to installation. The installation of capacitance
on circuits connected to induction generators increases the possibility of
ferroresonance or "self-excitation
In general, self-excitation can occur with induction machines when the isolated
capacitance is about 30 percent of rated kV A, and load that is less than 300 percent
of rated kV A. For smaller installations, sufficient capacitance may be present but
the load will usually be too large, even for small sections of feeder islands for self-
excitation. For large installations, sufficient load may be present but the
capacitance will usually be too small unless local power factor correcting
capacitors are present. Each installation, especially those where capacitors are
installed on the Generator s side of the point of interconnection, will require an
evaluation to detennine if self-excitation will be a problem and if additional
protection equipment is required.C. DC Inverters
Direct current generation can only be installed in parallel with IPC's system using
a synchronous inverter. The design shall be such that the synchronous inverter
disconnects from the system upon an IPC system interruption. Line-commutated
inverters do not require synchronizing equipment if the voltage drop is detennined
to be acceptable. Self-commutated inverters of the utility-interactive type shall be
capable of synchronizing to IPc. Stand-alone, self-commutated inverters shall not
be used for parallel operation with the IPc.
All inverters shall be "non-islanding" as defined by IEEE 929, and shall meet or
exceed the requirements of IEEE 929 and UL 1741. It should be noted that non-
islanding inverters rely on verifying that a perturbation introduced by the inverter
is not stabilized by other sources of generation on the system. If an island consists
of inverters and other, stable fonns of generation like a synchronous generator, the
inverter or other specified equipment might not be able to detect that an island
exists. Each installation will require an evaluation to detennine if other stable
April 2002
3.4.
,.., !u.\tu.!f- LampS1\','
fonns of generation are connected to the same circuit and whether additional
modifications may be required.
Interconnection Equipment
In general, interconnection equipment includes, but is not limited to
transfonnation, switching/disconnection, metering, system protection and control
communications/teleme1:1y, and network upgrades.
The interconnection point shall be as described in SPECIFIC REQUIREMENTS of
this document. All interconnection equipment electrically located on the generator
side of the interconnection point shall be owned and maintained by the Generator.
All interconnection equipment electrically located on the utility side of the
interconnection point shall be owned, operated, and maintained by IPC
Exceptions may be allowed, however, certain facility, operations, and maintenance
charges will apply.
All interconnection equipment shall meet applicable UL, ANSI and IEEE
standards, and shall be installed to meet all applicable local, state and federal
codes.
Dedicated Transformer
IPC may require a power producing facility to connect to the IPC system through a
dedicated transfonner.
The transfonner may be necessary to ensure confonnance with IPC safe work
practices, to enhance service restoration operations, to limit available fault cUITent
to prevent detrimental effects (such as voltage fluctuations or hannonics) to other
IPC customers, or to ensure that the generator cannot become isolated with a small
amount of other customer load. The dedicated transfonner that is part of the
nonnal electrical service connection of a Generator s facility may meet this
requirement if there are no other customers supplied nom it. A dedicated
transfonner is not required if the installation is designed to protect the IPC system
and its customers adequately nom potential detrimental net effects caused by the
operation of the generator.
The transfonner shall either be provided by IPC at the Generator s expense, or be
provided by the Generator confonning to ANSI C57, and to these requirements. If
the Generator chooses to provide the transfonner, the transfonner shall be multi-
tap where applicable, and the winding connections should be discussed with IPC
prior to purchasing the transfonner since they will affect the interconnection
protection requirements.
IfIPC provides the transfonner, a high side circuit-intenupting device will be
provided for transfonner protection. Fuses may be used for transfonners smaller
than 20- MY A if the fuses can be coordinated with existing IPC protection. A
circuit breaker (3- phase circuit intenupting device) will be used for transfonners
20-MY A and larger.
April 2002
DAHD
FONER
'In IIX\CURI-' t:cmp,fY,
Revenue Metering
Usually when a generator is installed with the intent of selling power to IPC or
other entities, electric service to the auxiliary load associated with the generator
plant is also needed. As such, power may flow into or out of the plant at different
times. Deliveries to and :ftom the plant must be separately recorded and treated as
separate entities under IPC's tariffs unless the generation facility qualifies under
the Net Metering tariff. Therefore, bi-directiona1 or separate metering will be
required. In the case of small tariff-defined Net Metered facilities (25- kV A and
smaller), only one kilowatt hour meter will be used to record power flow both into
and out of the power producing facility and other loads cormected downstream of
the meter.
All meters will be owned, operated, and maintained by IPC at the Generator
expense. The Generator will provide, install, own and maintain all mounting
structures, conduits, meter sockets, meter socket enclosures, metering transfonner
cabinets, and switchboard utility service sections of the size and type approved by
IPc.
Disconnect Device
Generating equipment shall be capable of being isolated :ftom the IPC system by
means of an accessible load-break disconnecting device.
The disconnect device shall be rated for the voltage and CUlTent requirements of
the installation. The basic insulation level (EIL) of the disconnect device shall be
such that it will coordinate with that ofIPC's system.
The location of the disconnect device shall be as specified herein or as detennined
by mutual agreement, and be readily accessible, operable, and lockable (where
applicable) by IPC at all times.
A disconnect device located on the low voltage side of the dedicated transfonner
that is owned and maintained by the Generator shall meet the following:
Be clearly marked
, "
Generator Disconnect Device , with pennanent 3/8
inch letters or larger.
Located within 10 feet of IPC' s external electric service meter or the
location and nature of the distributed power disconnection devices shall be
indicated in the immediate proximity of the electric service entrance.
The disconnect device shall either be provided by IPC at the Generator s expense
or be provided by the Generator confonning to these requirements.D. Protection and Control Equipment
With the exception of non-islanding inverters (meeting IEEE 929 and UL 1741),
appropriate protection and control equipment, including a circuit intelTUpting
device (e.g. circuit breaker), shall be required to disconnect the generation :ftom the
IPC system. The protection and control equipment shall be capable of
disconnecting the generation upon detection of an islanding condition, IPC system
April 2002
IDAHO
-.:!!
PONER
1..-; IlJ;'~URf' CCmparl',
fault, Generator system fault, and other abnonnal conditions on the circuit in
which the generation is connected.
The protection and control scheme shall be designed to allow the generation to
operate only within the limits specified herein or as required by the WSCC for
frequency and voltage. As a minimum, a circuit inteITUpting device(s) operated by
over and under voltage protection on each phase is required. The circuit
inteITUpting device(s) shall also be operated by over and under frequency
protection on at least one phase. All phases of a generator or inverter interface
shall disconnect for a voltage or frequency excursion on any phase.
The need for additional protection and control equipment shall be detennined by
IPC on a case-by-case basis. The specific design of the protection and control will
depend on the size and characteristics of the generation, the Generator s load level
transfonner connections, and the characteristics of the particular portion ofIPC's
system where the Generator jg interconnecting. IPC shall specify and provide
settings for those relays that IPC designates as being required to satisfy protection
practices. Any protective equipment or setting specified by IPC shall not be
changed or modified at any time by the Generator without written consent from
IPc.
Utilities, including IPC, often use high speed (30 cycle or less) reclosing of their
substation circuit breakers to rapidly restore service to customers after temporary
line faults (automatic load restoration). This could cause problems to a Generator
if they are reconnected out-of-phase with the system voltage. To avoid out-of-
phase reclosing, the design of the protection and control scheme shall take into
account the IPC practice of automatically reclosing circuit breakers without
synchronism check as quickly as 12 cycles after being tripped.
The Generator s protection equipment shall not share electrical equipment and
instrument transfonners associated with IPC revenue metering.
A failure of the interconnection protection equipment, including loss of control
power, shall open the circuit inteITUpting device, thus disconnecting the generation
from the IPC system. The protection equipment shall utilize a non- volatile
memory design such that a loss of intemal or external control power, including
batteries, will not cause a loss of interconnection protection functions or loss of
protection set points.
Protective relay requirements:
1. Meet IEEE/ANSI C37.90.
2. Maximum pickup accuracy of3% for overcurrent elements.
3. MaximlUll pickup accuracy of 5% for under-and overvoltage elements.
4. Maximum timer accuracy of3%.
5. Maximum pickup accuracy of 0.05 Hz for frequency elements.
April 2002
IDAHO
PONER
, IU.\CORf' (;CrBP3fYi
A dedicated DC power supply (battery or UPS) is required for all generation
projects larger than 300-kW.
The protection and control equipment will be either provided by IPC at the
Generator s expense, or be provided by the Generator confonning to IPC's
specifications depending upon the size of the generation as specified herein and
the system voltage at the point of interconnection.E. Telemetry
Depending upon the generator size and the contractual arrangements for the
generation output, the Generator may be required to maintain satisfactory
operating communications with IPC to transmit metering data from the point of
interconnection for IPC's system control and metering database. The Generator
will obtain and pay any associated monthly charges to the provider for a full
duplex data circuit (or circuits) operating at a minimrnn of 28800 baud, or at other
baud rates as reasonably specified by IPc.
Depending upon the generator size, a Remote Tenninal Unit ("RTU"), or
equivalent data collection and transfer equipment acceptable to both the Generator
and IPC, and communication to IPC may be required for IPC system operations.
The R TU will be used to gather accrnnulated and instantaneous data, breaker
position, transfer trip control, etc, to be telemetered to a location, or locations
designated by IPc. Generator will obtain, and pay any associated monthly charges
to the provider, a full duplex data circuit (in addition to that required for system
control and metering discussed above) operating at a minimrnn of 28800 baud, or
at other baud rates as reasonably specified by IPc.
The Generator may also be required to provide standard voice and facsimile
communications at its generation facilities through use of the public telephone
system.F. Network Upgrades
When Generators are connected to circuits that utilize high speed reclosing of the
substation circuit breakers to restore service after temporary line faults
modifications to the circuit control schemes are considered. One solution is for
IPC to disconnect their reclosing devices on lines serving a Generator, however
this results in a deterioration of service for other customers. A second alternative
is to continue high speed reclosing and assrnne that the Generator relaying will
cause disconnection before reclosing can occur; however, this could result in some
equipment damage if a Generator relaying misoperation occurs. A third alternative
is to have IPC send a transfer trip signal to the Generator before reclosing occurs;
however, this is quite expensive. Another, more practical, alternative is for IPC to
block reclosing until the Generator is disconnected and voltage-supervising relays
indicate the line is dead. Any of the required equipment and modifications
associated with the above-noted alternatives are considered network upgrades.
Other examples of network upgrades may include, but are not limited to such items
as line extensions, disconnect switches required for equipment isolation to perfonn
April 2002
IDAHO
PONER
N:, IU.\CO~~ ccmparl'"
routine maintenance, additional line tenninal relaying or modifications, additional
circuit inteffilpting devices, power factor colTection capacitor banks, additional
communications equipment or modifications, etc. The requirements for network
upgrades vary and will be detennined based on the physical and e1ectrica110cation
of the generation interconnection within the IPC system.
PART 4 OPERATING REQUIREMENTS
General
The Generator shall provide a 24-hour telephone contact(s) to IPc. This contact
will be used by IPC to arrange access for repairs, inspection or emergencies. IPC
will make such ammgements (except for emergencies) during nonna1 business
hours.
IPC will provide a name and telephone number so that the Generator can obtain
infonnation about any IPC activity impacting the Generator s generation (outages
disconnection, etc.
The Generator shall never supply power to IPC during an outage on the system
serving the Generator. The Generator s generation may be operated during such
outages only with an open tie to the IPC system.
The disconnect device may be opened by IPC at any time for any of the following
reasons:
To eliminate conditions that constitute a potential hazard to IPC personnel
or the general public;
Pre-emergency or emergency conditions on the IPC system;
A hazardous condition is revealed by a IPC inspection;
Protective device tampering.
The disconnect device may be opened by IPC for the following reasons, after
notice to the responsible party has been delivered and a reasonable time to COlTect
(consistent with the conditions) has elapsed:
A Generator has failed to make available records of maintenance tests and
maintenance of its protective devices;
A Generator s system interferes with IPC equipment or equipment
belonging to other IPC customers;
A Generator's system is found to affect quality of service of adjoining
customers.
IPC will disconnect the Generator in the event of any planned or unplanned
maintenance or repair of the system connected to the Generator. In the event
unplanned maintenance or repairs, no prior notice will be provided. In the event
planned repairs, IPC will attempt to notify the Generator of the time and duration
of the planned outage.
April 2002
DAHO
POVVER
/II", ID.\CO~~ com parr,
To the extent required by applicable rules and regulations, Generator shall (a)
request pennission 1iom IPC prior to opening or closing circuit breakers that affect
IPC's system, (b) carry out switching orders 1iom IPC in a timely manner and (c)
keep IPC advised of the Generator s operational capabilities as required for
reliable operation ofIPC's system.
IPC may require direct transfer trip (remote operation of a circuit breaker by means
of a communications channel) whenever:
The minimum load to generation ratio on a circuit is such that a
ferroresonance condition could occur
It is detennined that the Generator s protective relaying may not operate for
certain conditions or faults and/or
The installation could increase the length of outages on a circuit or
jeopardize the reliability of the circuit.
IPC will be required to demonstrate the need for direct transfer trip.
More detailed operating requirements are provided in the Generation
Interconnection Agreement or applicable IPC tariff.
PART 5 TEST REQUIREMENTS
1. General
When the Generator owns, operates, and maintains the interconnection protection
and control equipment, either as discrete components specified herein or as part of
a DC inverter package, the Generator shall confonn to these test requirements.
This section is divided into "acceptance testing" and "maintenance testing
Acceptance testing is perfonned on the interconnection equipment prior to the first
parallel operation to verifY that it meets the perfonnance requirements specified.
Maintenance testing is site-specific, periodic testing to assure continued acceptable
perfonnance of the interconnection protection equipment.
These test requirements apply only to interconnection disconnection devices and
the protection and control equipment (e.g. those equipment protecting IPC
personnel, the IPC system, and IPC's customers). Testing of equipment associated
specifically with protection or control of Generator s equipment is recommended
but not required unless they impact the interconnection protection.
The Generator, at his option, may either request IPC to perfonn, or have a
qualified testing finn perfonn, the required acceptance and maintenance tests. If a
qualified testing fmn perfonns the required tests, the test results shall be submitted
to IPc. In any case, IPC staff will evaluate the test results and provide approval
for interconnection or continued operation if the results are satisfactory.
If the Generator elects to retain a qualified testing finn, the testing finn shall have
the following minimum qualifications:
April 2002
IDAHO
....
~ PaNER
1...-, IU.\C:J~~ ccmpsrr;
Employer of engineers and technicians regularly engaged in testing and
inspecting of electrical equipment, installations, and systems.
Technicians certified by NICET (National Institute of Certification in
Engineering Technologies) or NET A (InterNational Electrical Testing
Association).
Corporately and financially independent organization functioning as an
unbiased testing authority.
Professionally independent of manufacturers, suppliers, and installers of
electrical equipment and systems being tested.
Test equipment shall have an operating accuracy equal to, or greater than
requirements established by NET A ATS (Acceptance Testing Specifications for
Electrical Power Distribution Equipment and Systems). Test instnnnent
calibration and documentation shall be in accordance with NET A ATS.
The testing finn shall perfonn inspection and testing in accordance with NET A
ATS and NET A MTS (Maintenance Testing Specifications for Electrical Power
Distribution Equipment and Systems) and as required herein.
IPC reserves the right to witness any testing.
Acceptance Testing
An acceptance test must be perfonned to verifY that the equipment meets the
requirements specified herein prior to initial parallel operation by a Generator, or
any time interface hardware or software is changed.
Prior to testing, all batteries shall be disconnected or removed for a minimum of
ten (10) minutes. This test is to verifY the system has a non- volatile memory and
that protection settings are not lost. A test shall also be perfonned to detennine
that failure of any battery not used to supply trip power will result in an automatic
shutdown.
All DC inverters shall be tested in accordance with the latest edition of IEEE 929
and UL 1741.
5.3.
These tests shall also verifY the Generator will not automatically reconnect to the
utility system until after five (5) minutes of continuous nonnal voltage and
frequency on the utility system. The DC inverter manufacturer may supply a
special production sample with the five minute reset timer disabled to eliminate
waiting time during acceptance testing. At least one test must be perfonned on a
sample with a five minute reset timer to verifY the function and accuracy of the
timer.
Maintenance Testing
A maintenance test is required to detennine if the equipment meets the
requirements specified herein; to verifY the interconnection protection and control
has not been tampered with; and to verifY the interconnection equipment meets
April 2002
IDAHC
.... .....
PO\NER
I'di ID.\::O,~F (:cn1Ipsrr..
safety codes and standards. In addition, all maintenance tests prescribed by the
manufacturer shall be perfonned.
Maintenance testing shall be perfonned annually, or as negotiated otherwise.
Any system that depends upon a battery for trip power shall be checked by the
Generator and logged once per month for proper voltage. Once every four (4)
years the battery must be either replaced or a discharge test perfonned.
PART 6 SPECIFIC REQUIREMENTS1. Generation Classifications
IPC has established three different classes for non-utility parallel generation, each
with distinctive requirements. These classes are as follows:
Less than 100-kV A.
100-kVA to I-MY A.
More than I-MY A.
Where multiple generators are connected to IPC's system through a single service
point, the class will be detennined by the sum of the ratings of the generators.
Multiple generators may be allowed to connect through an equal number of service
points in order to stay within a defined generation classification; however, the
Generator must submit separate generation interconnection applications for each
generation installation.
It should be understood that these classes have been established for convenience
and are based on nonnalload density and an assumed low density of parallel
generation on the serving circuit. The final decision as to the requirements for
each installation will be made depending on generation output, system voltage and
capacity at the Generator location, Generator load magnitude, the magnitude of
other load connected to that circuit/system, available short circuit contribution, etc.
As a general rule, generation that is less than 10- MY A is usually connected to the
distribution system (34.kV or less) or the sub-transmission system (69-kV or
less); generation fiom 10- MV A to 100- MY A is usually connected to the
transmission system (138- k V and less); and generation in excess of 100- MY A is
connected to the transmission system (500-kV and less).
Total Generation Less Than lOO-kV A
With the exception of the revenue metering equipment, the Generator, at his
option, may provide the interconnection equipment.
ill small single-phase applications, generation facilities applied on a center-tap
neutral 240- volt, single-phase service must be installed such that no more than 6-
k V A of imbalance in capacity exists between the two sides of the 240- volt service.
For dedicated transfonner services, the limit of a single-phase generator shall be
the transfonner nameplate rating.
April 2002
I DG.HD
PO\NER
I'in ILJ.\CORf' UJf11Iparr,
Interconnection Point: IfIPC owns the dedicated transfonner, the
interconnection point shall be the generator side of the utility revenue meter. If the
Generator owns the dedicated trans fonner, the interconnection point shall be the
generator side of the primary voltage disconnect device.
Dedicated transformer. In general, Generators less than 100- kW generating at a
secondary voltage level may not require a dedicated transfonner. However, this
must be approved by IPC after review of the project details, and it is detennined
that the facilities will adequately protect the IPC system and its customers fiom
potential detrimental effects caused by the operation of the generator.
Revenue Metering: Metering facilities will be detennined by the requirements of
the individual installation, contractual arrangements, and applicable tariff.
Disconnect device: The electrical location of the disconnect device depends upon
the ownership of the dedicated transfonner.
If the Generator owns the dedicated transfonner, the disconnect device will be
installed, owned, operated, and maintained by IPC, and located on the utility side
of the transfonner.
If IPC owns the dedicated transfonner, the disconnect device may be installed
owned, and maintained by the Generator, and installed on the Generator side of the
dedicated transfonner. If the disconnect device is installed on the Generator side
of the dedicated transfonner, the disconnect device shall be physically located at or
near the point of interconnection (metering location). In tariff defined Net
Metering applications, the disconnect device shall be electrically located between
the generation equipment and the facility load.
The disconnect device is to enable IPC to disconnect the generation fiom the IPC
system for safety while working on the lines, or to disconnect generation that does
not meet the requirements specified herein or other contractual arrangements.
Protection and Control equipment: The Generator may own, operate and
maintain the interconnection protection and control equipment. The provisions
discussed in TEST REQUIREMENTS of this document apply.
With the exception of non-islanding inverters (meeting IEEE 929 and UL 1741),
the interconnection package shall be equipped with a circuit-inteITUpting device
(line voltage relay or contactor) with associated voltage and fiequency relaying
that will prevent the generator fiom being connected to a de-energized or single-
phased (if nonnally three- phase) source. If it is possible an island can develop
with non- islanding inverters and other stable fonns of generation (lilee a
synchronous generator) on the same circuit, a non-islanding inverter will require a
circuit inteITUpting device with associated voltage and fiequency relaying.
The circuit-inteITUpting device shall automatically disconnect fiom the IPC system
as follows:
Within ten (10) cycles if the voltage falls below 60- V TIllS phase to ground
(nominal 120- V TIllS base) on any phase.
April 2002
IMHO
. .-..:!!
PO\NER
/I.n 11J,\LO~" CCmpSfYi
Within two (2) seconds if the voltage falls below 106 V nns phase to
ground (nominal120 V nns base) on any phase.
Within one (1) second if the voltage rises above 132 V nns phase to ground
(nominal120 V nns base) on any phase.
Within ten (10) cycles if the voltage rises above 144 V nns phase to ground
(nomina1120 V nns base) on any phase.
Within ten (10) cycles if the frequency rises above 60.5 Hz or falls below
59.3 Hz.
Following a generation facility disconnect as a result of a voltage or frequency
excursion, the generation facility shall remain disconnected until IPC's service
voltage and frequency are within the operating voltage range of 1O6V-132V, and
frequency range of59.3 Hz -60.5 Hz for a minimum of five (5) minutes.
The controls (typically consisting of control switches, lockout relays and other
discrete components) shall perfonn the following control fi.mctions:
The Generator can allow the circuit-inteITUpting device to close or force it
to trip. However, the Generator cannot force the circuit-inteITUpting device
to close or prevent it from tripping.
If the circuit-inteITUpting device closes into a fault it will trip and lockout
requiring a manual reset.
IPC will maintain a list of protective relays that have been acceptance tested and
approved for interconnection to the IPC system. The list will indicate specific
model numbers and finnware versions approved. The installed equipment must
have a nameplate that clearly shows the model number and finnware version (if
applicable).
Network Upgrades: Network upgrades shall be as required on a case-by-case
basis.
6.3.Total Generation lOO-kVA to I-MVA
With the exception of the revenue metering equipment and the protective relaying
and control equipment, the Generator, at his option, may provide the
interconnection equipment (including the interconnection circuit inteITUpting
device).
Interconnection Point: IfIPC owns the dedicated transfonner, the
interconnection point shall be the generator side of the utility revenue meter. If the
Generator owns the dedicated transfonner, the interconnection point shall be the
generator side of the primary voltage disconnect device.
Dedicated transformer. In general, the Generator shall be served through a
dedicated transfonner that serves no other customers.
Revenue Metering: Metering facilities will be detennined by the requirements of
the individual installation and contractual anangements.
April 2002
IDAHO
........
POVVER
i\,,-, ILJ.\CO~f' CCmporr..
Disconnect device: The electrical location of the disconnect device depends upon
the ownership of the dedicated transfonner.
If the Generator owns the dedicated trans fonner, the disconnect device will be
installed, owned, operated, and maintained by IPC, and located on the utility side
of the transfonner.
If IPC owns the dedicated transfonner, the disconnect device may be installed
owned, and maintained by the Generator, and installed on the Generator side of the
dedicated transfonner. If the disconnect device is installed on the Generator side
of the dedicated transfonner, the disconnect device shall be physically located at or
near the point of interconnection (metering location).
The disconnect device is to enable IPC to disconnect the generation ITom the IPC
system for safety while working on the lines, or to disconnect generation that does
not meet the requirements specified herein or other contractual auangements.
Protection and Control Equipment: The Generator, at his option, may provide
the circuit-intelTUpting device on the secondary side of the transfonner. The
circuit-intelTUpting device (circuit breaker or contactor) shall have remote "trip
capability and also meet the requirements of the National Electrical Code.
IPC will provide the protective relaying instrument transfonners (cUITent
transfonners and potential transfonners), protective relaying, dedicated DC power
supply, and associated controls to remotely operate the circuit-intelTUpting device.
Additional constraints may be required for the circuit-intelTUpting device based on
other system characteristics.
Telemetry: Depending upon the generator size and the contractual arrangements
for the generation output, the Generator may be required to maintain satisfactory
operating communications with IPC to transmit metering data ITom the point of
interconnection for IPC's system control and metering database. In addition, an
RTU may be required for transfer trip, etc.
If telemetry is required, the Generator will obtain (and pay any associated monthly
charges to the provider), a full duplex data circuit, or circuits operating at a
minimum of 28800 baud or at other baud rates as reasonably specified by IPc.
Network upgrades: Network upgrades shall be as required on a case-by-case
basis.
6.4.Total Generation More Than l-MV A
With the exception of the revenue metering equipment, protection and control
equipment, and disconnect device the Generator, at his option, may provide the
interconnection equipment.
Interconnection Point: Regardless of dedicated transfonner ownership, the
interconnection point shall be the generator side of the disconnect device.
Dedicated transformer. The Generator shall be served through a dedicated
transfonner that serves no other customers.
April 2002
IDAHO
PONER
11f", IlJ,\LD~~ (;(JmpSfJi
Revenue Metering: Metering facilities will be detennined by the requirements of
the individual installation and contractual aITangements.
Disconnect device: IPC will own, operate, and maintain the disconnect device.
The electrical location of the disconnect device depends upon the ownership of the
dedicated transfonner.
Protection and control equipment: IPC will own, operate, and maintain all
circuit interrupting devices, protective relaying and controls, instnnnent
transfonners, and associated AC and DC power supply. Multifunction protective
relays and redundant relaying (where applicable) are required. Synchronizing to
the system using IPC's circuit interrupting devices may be allowed provided
certain operating constraints are met.
Telemetry:
Communications : Data circuit(s) shall extend from the Generator s facility to a
location, or locations, specified by IPc. Operational communications shall be
activated and maintained under, but not be limited to, the following events: system
paralleling or separation, scheduled and unscheduled shutdowns, equipment
clearances, and hourly and daily load data exchange.
Remote Tenninal Unit:Generator shall install or facilitate installation ofRTU
equipment, and the installation shall be accomplished prior to the first parallel
operation. IPC will specify the communication protocol for the data circuits.
Instantaneous bi-directional analog real power and reactive power flow
infonnation, circuit breaker status infonnation, instantaneous analog voltage
infonnation, metering infonnation, and disturbance monitoring infonnation, as
detennined by IPC, must be telemetered directly to the location, or locations
specified by IPc.
The Generator may also be required to provide standard voice and facsimile
communications at its generation facilities through use of the public telephone
system.
Network Upgrades: IfIPC owns the dedicated transfonner, protection equipment
and relaying may be required on the transfonner secondary circuit. That
equipment as well as the need for additional elements (substation equipment
control facilities, disconnect devices, etc.) will be detennined, on a case-by-case
basis.
System Operation:
Obligation to Supply or Absorb Reactive Power:The Generator shall supply
reactive power to, and absorb reactive power from, the Transmission Owner
System during periods of time that its facility is connected to and operating in
parallel. The Generator shall respond to requests from the Transmission Owner to
increase or decrease the facility's reactive power output in a manner consistent
with the Generator s obligation to operate the facility (a) in a safe and reliable
manner in accordance with applicable operational and/or reliability criteria
protocols, and directives (which include those ofNERC and WSCC) and (b) in
April 2002
111QHO
....
'8t.."'!! PCMIER
IV... ILJ,\LU~~ LcmpSrr..
accordance with the provisions of the interconnection agreement. The facility
shall generate such reactive power in accordance with the voltage schedule
reactive schedule or power factor schedule, whichever is applicable, that is
prescribed by the Transmission Owner, but not in excess of the amount available
ITom the facility's equipment in operation at the time. Such limitation shall be in
accordance with results of the System hnpact Study and the Facilities Study
conducted by the Transmission Owner on behalf of the Generator.
Reactive Power Standards: The Generator shall operate the facility to maintain a
voltage schedule, reactive schedule or power factor schedule; whichever is
applicable, as prescribed by the System Operator within the facility's reactive
design limitations. The System Operator may request the Generator to change its
voltage schedule, reactive schedule or power factor schedule, whichever is
applicable, or request the Generator to supply its maximum available reactive
power output or absorb its maximum reactive power input (measured in MY AR)
within the reactive design limitations of the equipment in operation at the time in
order to maintain system security. In the event the facility is unable to consistently
maintain a reactive power capability sufficient to maintain a power factor at the
interconnection point within the facility's reactive design limitations, the
Generator shall take other appropriate steps to configure the facility to meet such
standards, including, as necessary, the installation of dynamic reactive power
compensating devices subject to prior review and approval by the Transmission
Owner.
System Security:In order to maintain security on the Transmission Owner
System, during an Emergency on the Transmission Owner s System or on a
transmission system connected to Transmission Owner s System, the System
Operator has the authority to direct the Generator to increase or decrease real
power production (measured in MW) and/or reactive power production (measured
in MY AR), within the design and operationa11imitations of the facility equipment
in operation at the time
PART 7 REFERENCES
ANSI/IEEE Standard 929-2000, IEEE Recommended Practice for Utility Interface
of Photovo1taic (PY) Systems.
UL 1741 May 1999, Standard for Static Inverters and Charge Controllers for use in
Photovoltaic Power Systems.
ANSI/IEEE Standard 519-1992, IEEE Recommended Practice and Requirements
for Hannonic Control in Electric Power Systems.
ANSI/IEEE Std. 1001-1988, IEEE Guide for Interfacing Dispersed Storage and
Generation Facilities with Electric Utility Systems.
ANSI/IEEE C3 7-1995, Guides and Standards for Circuit Breakers, Switchgear
Relays, Substations, and Fuses.
ANSI/IEEE Std. C37 .1996, IEEE Standard Electrical Power System Device
Function Numbers and Contact Designations.
April 2002
loin ILJ.\COR~ corrlparr.
ANSI/IEEE Std. C37.90-l989, IEEE Standard for Relays and Relay Systems
Associated with Electric Power Apparatus.
ANSI/NFPA 70-1999, National Electrical Code.
IEEE/ ANSI C2-l997, National Electrical Safety Code.
ANSI/IEEE C57-l995, Distribution, Power, and Regulating Transfonners.
NEMA MG 1-1993 , Motors and Generators.
IEEE/ANSI C62-l995 , Surge Protection.
ANSI/IEEE 80 - 1986, IEEE Guide for Safety in AC Substation Grounding.
IEEE 141-1993 , Recommended Practice for Electric Power Distribution for
fudustrial Plants - Red Book.
ANSI C84.l- Electric Power Systems and Equipment- Voltage Ratings.
IEEE P 1547 /D07 - 200 1 , Draft Standard for futerconnecting Distributed Resources
with Electric Power Systems.
April 2002