20150225IPC to Staff 1-33.pdf

S!ffi*.
An IDACORP Company
JULIA A. HILTON
Gorporate Gounsel
ihi [e-mail]
February 25,2015
?frti rill 25 Pl'l h: 28
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VIA HAND DELIVERY
Jean D. Jewel!, Secretary
ldaho Public Utilities Commission
472 West Washington Street
Boise, ldaho 83702
Re: Case Nos. IPC-E-14-41and PAC-E-14-11
Exchange of Certain Transmission Assets - ldaho Power Company's
Response to the First Production Request of the Commission Staff to
ldaho Power Company
Dear Ms. Jewell:
Enclosed for filing in the above matters please find an original and three (3)
copies of ldaho Power Company's Response to the First Production Request of the
Commission Staffto ldaho Power Company.
Also enclosed are four (4) copies of a confidential disk containing information
responsive to the Staff's production requests.
Very truly yours,
Jt'$U--
Julia A. Hilton
JAH:csb
Enclosures
1221 W ldaho St. (83702)
P.O. Box 70
Boise, lD 83707
JULIA A. HILTON (lSB No. 7740)
ldaho Power Company
1221 West ldaho Street (83702)
P.O. Box 70
Boise, ldaho 83707
Telephone: [phone]
Facsimile: [phone]
ih ilton@ida hopower. com
Attorney for ldaho Power Company
DANIEL E. SOLANDER (lSB No. 8931)
Rocky Mountain Power
201 South Main Street, Suite 2300
Salt Lake City, Utah 84111
Telephone: (801 ) 220-4014
Facsimile: (801 ) 220-3299
dan iel. solander@pacificorp. com
Attorney for PacifiCorp
IN THE MATTER OF THE APPLICATION
OF PACIFICORP DBA ROCKY
MOUNTAIN POWER AND IDAHO POWER
COMPANY FOR AN ORDER
AUTHORIZING THE EXCHANGE OF
CERTA! N TRANSMISSION ASSETS
COMES NOW, ldaho Power Company
?r1F Ft'l 2:r L: 28
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
CASE NOS. IPC.E.14-41
PAC-E-14-1 1
IDAHO POWER COMPANY'S
RESPONSE TO THE FIRST
PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO
POWER COMPANY
("ldaho Powe/' or "Company"), and in
the Commission Staff to ldaho Powerresponse to the
Company dated
First Production Request of
February 4,2015, herewith submits the following information:
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 1
REQUEST NO. 1: What are the average monthly operation and maintenance
expenses currently associated with the plant in service that is proposed to be
transferred to PacifiCorp from ldaho Power Company?
RESPONSE TO REQUEST NO. 1: ldaho Power does not directly assign or
allocate all operations and maintenance ("O&M") costs to specific plant in service for
which those costs are applicable. Of the tracked expenses, the average monthly
maintenance expenses directly related to the lines to be transferred is $10,300. The
average tracked monthly maintenance expenses directly related to the stations to be
transfened is $67,000.
The response to this Request is sponsored by Paula Penza, Finance Team
Leader, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 2
REQUEST NO. 2: What are the average monthly operation and maintenance
expenses estimated to be associated with the plant in service that is proposed to be
transfened to ldaho Power Company from PacifiCorp?
RESPONSE TO REQUEST NO. 2: The monthly O&M expenses associated with
the transfer of plant in service from PacifiCorp, dlbla Rocky Mountain Power
("PacifiCorp") to ldaho Power are estimated as follows:
Estimated Monthlv Billine IDAHO
Lines-O&M
Stations-O&M
s
$
67,zfi
lLilTs
Tota! Btamated Monthly Lines and
Stations O&M Billing s 78,395
The response to this Request is sponsored by Paula Penza, Finance Team
Leader, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 3
REQUEST NO. 3: Will there be any financial gain or loss associated with the
transfer of assets? lf so, please provide the specific details and associated assets.
RESPONSE TO REQUEST NO. 3: Please refer to PacifiCorp's response to the
ldaho Public Utilities Commission Staffs Request No. 3 to PacifiCorp.
The response to this Request is sponsored by Paula Penza, Finance Team
Leader, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 4
REQUEST NO. 4: Please provide the proposed joumal entries associated with
the transfer of assets.
RESPONSE TO REQUEST NO. 4: Idaho Powe/s and PacifiCorp's respective
proposed journa! entries were included within the joint Federal Energy Regulatory
Commission ("FERC') 203 filing in Docket No. EC15-54-000. Specifically, Attachment 1
on page 329, which can be accessed at:
http://elibrarv.ferc.oov/idmws/common/OpenNat.asp?filel D=1 371 7306.
The response to this Request is sponsored by Courtney Waites, Senior
Regulatory Analyst, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REOUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 5
REQUEST NO. 5: Please quantify the financia! benefits to ldaho Power
customers for the transparency, flexibility, and reliability accomplished by this asset
transfer.
RESPONSE TO REQUEST NO. 5: While ldaho Power and PacifiCorp have not
quantified the total amount of time and cost dedicated to resolving differences in
interpretation of the Legacy Agreements, the companies have dedicated significant
executive, legal, operational, technical, and regulatory resources toward managing both
the ongoing administration of the Legacy Agreements and associated interpretation
questions. For example, from an operational perspective, daily administration (i.e.,
scheduling/tagging) of the Legacy Agreements can take up to four hours and after-the-
fact reconciliation can take up to 10 hours per month, which is significantly more time
and labor than required to perform similar tasks for modern contracts. These examples
exclude time spent by other departments, as well as operations, in trying to manage and
resolve differences in interpretation, which have occasionally required up to 30 hours or
more in one week to address. The companies have also incuned significant Iegal
expenses over the years related to interpretation of the Legacy Agreements. The
elimination of these activities will result in avoided administrative costs; however, the
specific amount of costs avoided has not been estimated.
The response to this Request was prepared by Kathy Anderson, Transmission
Energy Scheduling Leader, ldaho Power Company, under the direction of Lisa Grow,
Senior Vice President of Power Supply, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 6
REQUEST NO. 6: What future anticipated projects, including capital,
maintenance, and operational, will no Ionger be needed as a result of this transfer of
assets? Please list each project that will not be undertaken or revised as a result of this
asset transfer.
RESPONSE TO REQUEST NO. 6: As stated in David Angell's direct testimony,
this transfer of assets will eliminate the need for the tap of the Brady - Antelope 230
kilovolt ("kV") transmission line, the Iine from that tap to the Haven substation, and the
upgrade of the distribution feeder, Portneuf 042, lhat presently serves the Arbon Valley
customers.
The response to this Request is sponsored by David Angell, Customer
Operations Planning Manager, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCT]ON
REOUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 7
REQUEST NO. 7: Please provide a schedule showing the plant in service by
specific plant account, original cost, cunent book value, current depreciation expense
and accumulated depreciation for the assets to be transferred to PacifiCorp.
RESPONSE TO REQUEST NO. 7: Please see the attached asset sheet.
The response to this Request is sponsored by Larry Tuckness, Finance Team
Leader, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 8
REQUEST NO. 8: The Joint Purchase and Sale Agreement (JPSA) requires
ldaho Power to be responsible for the 230 kV Upgrades necessary to provide
PacifiCorp with 510 MW of long{erm firm point-to-point transmission service on ldaho
Power's transmission system. (Application, JPSA, pg. 27, Section 2.g(bXxiv).) Please
specify the specific equipment purchased or upgraded, and the location of these
required investments along with an explanation of whether there will be any impacts to
path ratings, the flexibility of transmission transfers, or transmission capacity.
RESPONSE TO REQUEST NO. 8: The 230 kV upgrades are identified in
Schedule 1.1(k) of the JPSA and repeated here: (1) install a2301138 kV, 300 megavolt
ampere transformer at the Bowmont substation and (2) replace two 230 kV series
capacitor banks at the Midpoint substation. These upgrades wil! increase the capacity
of the ldaho Power Midpoint West transmission path rating from 1027 megawatts
("MW") to 1300 MW.
The response to this Request is sponsored by David Angell, Customer
Operations Planning Manager, ldaho Power Company.
]DAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 9
REQUEST NO. 9: Lisa Grow's testimony says that the manual transmission
scheduling process will be replaced by a more efficient automatic process through the
execution of the Joint Ownership and Operations Agreement (JOOA). (Application,
Grow Dl, pg. 12, lines 12-14.') Please provide a detailed description of the automatic
scheduling process, including the implementation timing and details regarding any
capabilities for inter-hour dispatch or dynamic transfers of energy. Further, please
explain if the automated transmission scheduling functionality will increase with future
automation outside of ldaho Powe/s Balancing Authority Area.
RESPONSE TO REQUEST NO. 9: ldaho Power follows the scheduling time
lines outlined in its Open Access Transmission Tariff ('OATT') for all service sold under
the OATT. This allows all schedules to be presented to ldaho Power for processing no
later than 20 minutes before the start time of the schedule. This includes any inter-hour
schedules that begin at xx:15, xx:30, or xx:45. All automatic validations for schedules in
ldaho Powe/s scheduling systems are set to accept this timing. The services provided
under the Legacy Agreements currently in place with PacifiCorp have different timing
requirements. They require schedule changes to be done no later than 30 minutes
before the top of the next hour. lt does not allow for any intra-hour changes to these
schedules, except for forced generation or transmission outages that affect the
schedule. This requires manual monitoring and intervention of schedules to ensure
these schedules are handled according to the contract. Under the proposed JOOA,
these schedules become OATT schedules and are processed like all other OATT
schedules with regard to timing. This allows for all the automatic validations in the
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 1O
systems to be applied to all schedules and eliminates the manual intervention and
monitoring.
With regard to dynamic transfer capability, the generatlon that is allowed to use
the dynamic transfer capacity is limited to a specific generator in the current Legacy
Agreements. In addition, the contracts further restrict how much that scheduled
generation transfer can vary from the before the hour schedule to the final after the hour
adjusted schedule. This creates a manual process after the hour to ensure the
adjustments made to the schedules are within the terms of the contract. lt does not
allow for intra-hour dispatching of the resource. Under the OATT service, the restriction
on what resources can utilize that dynamic capacity is eliminated and current North
American Electric Reliability Corporation ("NERC"), North American Energy Standards
Board, and Western Electricity Coordinating Council (.WECC') standards regarding
schedule changes would apply to these schedules rather than specific contract
limitations.
As the industry continues to implement and utilize intra-hour scheduling and
develops energy imbalance markets, it becomes more important to standardize and
automate the processing of schedules. By eliminating the non-standard schedules and
restrictions of use in the current Legacy Agreements, it better aligns ldaho Power to
automate the processing of schedules.
The response to this Request was prepared by Kathy Anderson, Transmission
Energy Scheduling Leader, ldaho Power Company, under the direction of Lisa Grow,
Senior Vice President of Power Supply, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY . 11
REQUEST NO. 10: Lisa Grow's testimony says that the Parties are to create a
method to determine and allocate losses for the use of the transmission system within
the other Party's Balancing Authority Area. (Application, DI Grow, pg. 13, lines 8-12.)
Please provide a description of the previous method, the new method, and the
associated implementation time line.
RESPONSE TO REQUEST NO. 10: Section 6 of the Restated Transmission
Service Agreement ("RTSA") outlines how losses are repaid for the services provided
under the contract. Under Section 6, the Iosses PacifiCorp is required to repay to ldaho
Power for use of its system under the RTSA is determined by:
2.8 percent of the hourly incremental amount of the total net
scheduled transfers (for RTSA allowed services) that are
less than or greater than 1,000 megawatt-hours per hour,
except to the extent that such transfers are below 1,000
megawatts for at least two (2) hours due to a forced outage,
mechanical restriction, or scheduled maintenance outage at
the Jim Bridger Project, on the Bridger Transmission
System, on the ldaho Power transmission system or on
PacifiCorp's Midpoint-Summer Lake 500 kV transmission
line, any of which directly force a Party to reduce the East to
West Transfer Services in order to maintain system
reliability.
The RTSA also defines loss repayment for transmission and generator main
step-up transformer Iosses. Section 6.3 of the RTSA discusses how these losses are
distributed between ldaho Power and PacifiCorp.
ldaho Power and PacifiCorp are currently reviewing options for the loss
calculations and repayment options but have not yet determined a common
methodology. !t is anticipated a common methodology will be completed by the closing
date of the transaction.
The response to this Request was prepared by Kathy Anderson, Transmission
Energy Scheduling Leader, ldaho Power Company, under the direction of Lisa Grow,
Senior Vice President of Power Supply, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REOUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 12
REQUEST NO. 11: Please provide copies of the Phase 1, and if available the
Phase ll, Environmental Site Assessments for the properties proposed to be transferred
to PacifiCorp underthe JPSA.
RESPONSE TO REQUEST NO. 11: ldaho Power proposes to transfer only
equipment, not land, to PacifiCorp under the JPSA. Because no land is being
transferred under the JPSA, there are no Phase I and Phase ll Environmental Site
Assessments that pertain to the JPSA transaction.
The response to this Request is sponsored by Lisa Grow, Senior Vice President
of Power Supply, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 13
REQUEST NO. 12: Please provide a list of the FERC accounts used in the
calculations presented in Exhibit No. 1 of Lisa Grow's testimony.
RESPONSE TO REQUEST NO. 12: The following FERC accounts were used in
the calculations presented in Exhibit No. 1 of Lisa Grow's testimony:
Electric Plant
ln Service
(101)
350
352
3s3
354
355
356
3s9
362
394
397
398
Accumulated
Provision for
Depreciation (108)
350
3s2
353
354
355
356
3s9
352
394
397
398
Accumulated
Deferred Operating
Taxes Revenues
282.L 454
456
o&M
Depreciation
Expense
(403)
Deferred lncome
lncome Tax Tax
569
570
924
350
352
3s3
354
355
355
359
362
394
397
398
4LO.L/41L.1 4O9.L
The response to this Request is sponsored by Lisa Grow, Senior Vice President
of Power Supply, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 14
REQUEST NO. 13: How will the asset exchange impact the current Power Cost
Adjustment (PCA) and/or Fixed Cost Adjustment (FCA) mechanisms?
RESPONSE TO REQUEST NO. 13: Based on current known information, ldaho
Power anticipates a slight reduction in FERC Account 565, Third Party Transmission,
expenses upon execution of the JOOA with PacifiCorp. Because Account 565
expenses are tracked through the PCA mechanism, any benefits associated with the
reduction in expenses will flow through to customers annually through the PCA. The
asset exchange will have no immediate impact on the FCA mechanism. However, any
changes in the Company's fixed costs that are a result of the asset exchange would be
reflected in ldaho Powe/s FCA mechanism following the next general rate case.
The response to this Request was prepared by Courtney Waites, Senior
Regulatory Analyst, ldaho Power Company, under the direction of Lisa Grow, Senior
Vice President of Power Supply, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 15
REQUEST NO. 14: Please explain how the transmission expenses and
revenues are expected to change as a result of the asset exchange, by FERC account
or other tracking method.
RESPONSE TO REQUEST NO. 14: While overall transmission O&M expenses
are expected to remain the same, the transmission O&M expenses that will be charged
pursuant to the JOOA (FERC Accounts 567,570, and 571) are expected to be lower as
a result of the proposed transaction because current "use of facilities" expenses (FERC
Account 454) will be replaced by ownership on certain transmission paths. Please refer
to the confidential Excel spreadsheet provided in the Company's response to the
lndustrial Customers of ldaho Powe/s ('lClP") Request for Production No. 21(a) which
details the change in transmission O&M expenses as a result of the asset exchange.
The analysis presented as Exhibit No. 1 to Lisa Grow's direct testimony
demonstrates that there is a net increase in third-party transmission revenue (FERC
Account 456) if the asset exchange is approved. As described on page 17 of Lisa
Grow's direct testimony, "upon termination of the MTFA, RTSA, and ITSA, the
associated contract demands used in the calculation of ldaho Powe/s OATT formula
rate will become zero." This change will result in an increase to ldaho Powe/s third-
party transmission rate, which is projected to translate into higher third-party
transmission revenues.
The response to this Request was prepared by Kelley Noe, Financial Analyst,
ldaho Power Company, under the direction of Lisa Grow, Senior Vice President of
Power Supply, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 16
REQUEST NO. 15: Please clarify the facilities, the load locations, and potential
customers that may use the 100 MW of the Jim Bridger Transmission System
eastbound rights. (Application, Angels Dl, pg. 11, lines 3-6.) Further, please clarify if
these eastbound rights will primarily add redundancy, or serve future land growth.
RESPONSE TO REQUEST NO. 15: The above-referenced section of David
Angell's direct testimony pertains to off-system sale of firm Jim Bridger energy. The 100
MW of eastbound rights are within the Jim Bridger transmission system, which includes
the following facilities: Borah; Kinport; Populus; Goshen; Three Mile Noll; and Jim
Bridger substations, Borah - Populus #1, Kinport - Populus, Populus - Jim Bridger #1,
Populus - Jim Bridger #2, Kinport - Goshen, and Goshen - Jim Bridger. The potential
customers of the Jim Bridger energy are electric utilities, including any power marketing
function, federal power marketing agencies, or any entity purchasing energy for resale.
Assuming a firm energy sale, the load locations would be specific to the customer
acquiring the Jim Bridger energy. ln addition to the Jim Bridger energy sales, the
capacity will be managed through the OATT and any of the potential customers
identified above could request and contract transmission service, when available, that
may use this path to deliver any energy resource to any load. The eastbound rights do
not add redundancy or support future ldaho Power retail Ioad growth.
The response to this Request is sponsored by David Angell, Customer
Operations Planning Manager, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REOUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 17
REQUEST NO. 16: Please provide supporting cost estimates associated with
Dave Angel's testimony regarding elimination of the need for the Brady - Antelope 230
kV line. (Application, Angels Dl, pg. 12, lines 13-17.)
RESPONSE TO REQUEST NO. 16: Lines 16 and 17 of Dave Angell's direct
testimony incorrectly stated that "eliminating the need for the Brady - Antelope 230 kV
line at half the cost of the present plan." It should have stated "eliminating the need for
the tap of the Brady - Antelope 230 kV line at half the cost of the present plan."
The cost estimates for the Brady - Antelope 230 kV line tap, Atomic City
substation, and the line from the Atomic City substation to the Haven substation Goshen
- Antelope 161 kV tap, tap substation, and transmission line to Haven substation are on
tabs "HAVN 161kV Source" and "Atomic City Station," respectively, of the confidential
spreadsheet provided on the confidential CD. The confidential CD will only be provided
to those parties that have executed the Protective Agreement in this matter.
The response to this Request is sponsored by David Angell, Customer
Operations Planning Manager, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMM]SSION STAFF TO IDAHO POWER COMPANY - 18
REQUEST NO. 17: Please provide supporting documentation for the load
forecasts and the projected date of the future service requirements, plus the current
transmission use by retail, wholesale, and generation customers served in the Blackfoot
area.
RESPONSE TO REQUEST NO. 17: The Blackfoot, ldaho, area is served by 161
kV and 138 kV transmission lines through two substations, Blackfoot and Pingree, that
transform the voltage to 46 kV sub-transmission, which then serves 15 distribution
substations. The peak demand for the Blackfoot area occurred on July 1 , 2013, when
the total demand reached 160 MW. The load growth forecast for the area is provided in
the confidential Exce! file (Attachment 1) provided on the confidential CD.
This area load forecast is comprised of the load growth rates for the 15
distribution substations as shown below.
Substation Historical Growth Rates
Substation Growth Rate Substation Growth Rate
AIKN 0.75o/o MRLD 0.50%
AMPT 0.50%MSPE 0.50%
BKFT 1.00%PNGE 0.90%
CNDR 0.50%RKFD 0.75o/o
FTHL 0.75o/o RSFK 0.50%
HAVN 0.50%SRLG 1.00o/o
HULN 0.50%TABR 0.50%
LAVA 0.75o/o
Please refer to the confidential documents (Attachments 2 through 15) provided
on the confidential CD which provide 14 substation area confidential studies in support
of the load growth forecast.
Additionally, please refer to the confidential document (Attachment 16) provided
on the confidential CD which provides the 2014 "Ten-Year Transmission Reliability
Assessment 2015-2024" study, in draft form. Section 3.2 (page 12\ and Section 6,
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 19
Table 6.1 (page 29) of the study identify the Blackfoot - Goshen 161 kV line outage and
resulting overload of Don - Pingree Junction 138 kV line section along with a proposed
solution to tap the existing Antelope - Goshen 161 kV line included in the asset
exchange. The Antelope - Goshen 161 kV tap and line to Haven will need to be in
place prior to an overload of the Don - Pingree Junction 138 kV line section. Based on
project permitting time frames, ldaho Power anticipates that the project may be
constructed and placed in-service by 2020, which should coincide with near 100 percent
load of the Don - Pingree Junction 138 kV line section.
The confidential CD will only be provided to those parties that have executed the
Protective Agreement in this matter.
The response to this Request is sponsored by David
Operations Planning Manager, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 20
Customer
REQUEST NO. 18: Please provide supporting cost estimates associated with
Dave Angel's testimony regarding the benefits of ownership in the American Falls -
Malad line. (Application, Angels Dl, pg. 13, lines 23-24.)
RESPONSE TO REQUEST NO. 18: The cost for a typical 138 kV class
substation of the size necessary to serve the Arbon Valley area is $1.8 million. An
additional $300,000 would be required to fully integrate the substation, for a total cost of
$2.1 million. Please refer to the confidential Excel file provided on the confidential CD
for the cost estimate to rebuild the existing distribution feeder. The confidential CD will
only be provided to those parties that have executed the Protective Agreement in this
matter.
The response to this Request is sponsored by David Angell, Customer
Operations Planning Manager, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 21
REQUEST NO. 19: Please provide supporting documentation for the load
forecasts and the projected date of the future service requirements, plus the current
transmission use by retail, wholesale, and generation customers served in the Arbon
Valley area.
RESPONSE TO REQUEST NO. 19: The Arbon Valley customers are served by
Portneuf 42, a 34.5 kV distribution feeder that originates at the Portneuf substation near
the town of Portneuf, Idaho. Please refer to the Portneuf 42 distribution feeder section
of the confidential PDF provided on the confidential CD, the Portneuf small area study,
for the area load forecasts that include the Arbon Valley load. The area load forecast is
broader than the Arbon Valley; therefore, the recent change in Arbon Valley retail
customer count is provided in the table below as additional supporting evidence of Ioad
growth.
The response to this Request is sponsored by David Angel!, Customer
Operations Planning Manager, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 22
Arbon Vallev Customer Count at the End of Each Given Year
2009 2010 2011 2012 2013 2014
196 201 206 211 213 218
REQUEST NO. 20: Regarding the benefits related to the Midpoint - Hemingway
acquisition of 700 MW of eastbound capacity, please describe whether this acquisition
through the proposed asset exchange eliminates the need for additional transmission
investments. (Application, Angel Dl, pg. 15, lines 22-23.)
RESPONSE TO REQUEST NO. 20: The proposed asset exchange does not
eliminate the need for additional transmission investments.
The response to this Request is sponsored by David Angell, Customer
Operations Planning Manager, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 23
REQUEST NO. 21: Please provide supporting data for cunent transmission use
by retai!, wholesale, and generation customers served by ldaho Power via the
westbound reservations made on the Hemingway - Summer Lake line. Further, please
provide supporting documentation for the projected increased transmission use and
date(s) of the future service requirements for this same line and westbound direction.
(Application, Angel D!, pg. 17, lines 2-18.)
RESPONSE TO REQUEST NO. 21: Idaho Power does not have and is not
acquiring any westbound Hemingway - Summer Lake 500 kV line ownership.
The response to this Request is sponsored by David Angel!, Customer
Operations Planning Manager, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 24
REQUEST NO. 22: Please provide an explanation of how the Bonneville
transmission wheeling expense will be reduced or eliminated from ldaho Powe/s
acquisition of the Walla Walla - Hurricane transmission line. (Application, Angel Dl, pg.
18, lines 24, 18-19.)
RESPONSE TO REQUEST NO.22: The existing ownership and capacity rights
result in both a Bonneville Power Administration ('BPA") and PacifiCorp wheeling
expense when ldaho Power imports energy from the Mid-C market through the Walla
Walla - Hurricane transmission line. David Angell's direct testimony refers to the
elimination of only the PacifiCorp transmission wheeling expense (the BPA wheeling
expense will remain) when the Wa!!a Walla - McNary line is constructed and Idaho
Power exercises the option to participate in the construction. These components will
provide ldaho Power with uninterrupted capacity ownership from Hurricane, ldaho
Powe/s existing boundary, to BPA's McNary substation.
The response to this Request is sponsored by David Angell, Customer
Operations Planning Manager, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 25
REQUEST NO. 23: What are the estimated changes to the ldaho-Northwest
path ratings following the anticipated Walla Walla Hurricane Iine upgrades?
(Application, Angel DI, pg. 18, lines 12-14.)
RESPONSE TO REQUEST NO. 23: David Angell's direct testimony references
upgrades to the ldaho to Northwest path rather than the Walla Walla - Hurricane line
itself. These conceptualized upgrades have not been modeled and analyzed to an
extent to estimate a change to the ldaho to Northwest path rating.
The response to this Request is sponsored by David Angell, Customer
Operations Planning Manager, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 26
REQUEST NO. 24: Please explain whether ldaho Power is currently prepared to
implement an Energy lmbalance Market or Security Constrained Economic Dispatches,
or whether there are specific areas within ldaho Powe/s Balancing Authority Area
where short term balancing is not able to be implemented. Please also explain how the
proposed acquisition of assets may create new opportunities or improved functionality
for load balancing within shortened intervals (i.e., 5 minute). Please provide a general
overview of additional investments that may be required in the future in order to
increase this type of dispatch functionality.
RESPONSE TO REQUEST NO. 24: ldaho Power is an active participant in the
Northwest Power Pool MC lnitiative, which is looking at the development of a Security
Constrained Economic Dispatch ("SCED") model for that footprint. ln preparation for a
SCED or energy imbalance market ("ElM"), ldaho Power has entered into a professional
services agreement with a consulting company to perform a detailed EIM impact
assessment to provide a better understanding of the potential impacts of participating in
the proposed Northwest Power Pool SCED Market. The contractor will assess the
potential impacts to ldaho Powe/s existing technology, business processes and
organizational structure, document the major gaps, and develop a roadmap for
resolving those gaps. The project is currently in progress and is anticipated to be
complete by March 2015. At that time, ldaho Power will have a better understanding of
the gaps needed to overcome prior to entering any SCED or ElM.
The proposed acquisition of assets provides additional access to resources in the
Northwest, eliminating some of the additional wheeling charges Idaho Power is subject
to today. The asset swap also provides Idaho Power an opportunity to participate in
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 27
transmission upgrades as an owner and further increasing the ability to participate in
Northwest markets without incurring additiona! wheeling charges.
The response to this Request is sponsored by Lisa Grow, Senior Vice President
of Power Supply, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 28
REQUEST NO. 25: PIease explain whether the asset exchange will cause any
increases or decreases in retai! customer rates.
RESPONSE TO REQUEST NO.25: As stated on page 19 of Lisa Grow's direct
testimony, "Commission approval of the Legacy Replacement will have no immediate
retail customer rate impact for Idaho Power. A change to the revenue credit used to
offset retail customer rates will occur when the Company files its next general rate
case." The date of such a filing is unknown.
The response to this Request is sponsored by Lisa Grow, Senior Vice President
of Power Supply, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY.29
REQUEST NO. 26: The JPSA includes Planned Improvements (Application,
JPSA) to be completed by both ldaho Power (Schedule 1.1(e)) and PacifiCorp
(Schedule 1.1(f)). Please explain whether there will be any impacts to path ratings, the
flexibility of transmission transfers, or transmission capacity as a result of the listed
improvements.
RESPONSE TO REQUEST NO. 26: No planned improvements wil! impact path
rating or the flexibility of transmission transfers. There are three planned improvements
that will result in impact to transmission capacity as described in the table below.
The response to this Request is sponsored by David Angell, Customer
Operations Planning Manager, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 30
Planned lmprovement Transmission Capacitv lmpact
8ORA150001 - BORA Replace C341 Series
Capacitor
The parties plan to replace the existing series
capacitor with a higher capacity series
capacitor to match the transmission line
conductor caoacitv.
KPRT150005 - KPRT Replace C341 Series
Capacitor Bank
The parties plan to replace the existing series
capacitor with a higher capacity series
capacitor to match the transmission line
conductor caoacitv.
T601130001 - T601 Goshen-State Line
FAC008 Compliance
The parties plan to replace the existing
conductor with a higher capacity conductor in
the Goshen substation to Jefferson substation
line section, which will increase the capacity of
only that line section.
REQUEST NO. 27: Please provide the current OATT formula Exce! spreadsheet
and calculations, and the anticipated revised OATT formula Excel spreadsheet as a
result of the elimination of the various legacy agreements.
RESPONSE TO REQUEST NO. 27: ldaho Power's current OATT rate
calculation is publicly available and located on ldaho Power's Open Access Same-time
lnformation System at:
http://www.oatioasis.com/IPCO/IPCOdocsffransmission Rate October 1 2014-
Sept 30 2015 Final lnformational Postino.xlsx
ln the confidential Excel spreadsheet provided in the Company's response to
lClP's Request for Production No. 7(a), the tab labeled "Trans Revenue Assumptions"
contains ldaho Poweds analysis of the estimated impact of future OATT formula rates if
the transfer of assets is approved.
The response to this Request was prepared by Kelley Noe, Financial Analyst,
ldaho Power Company, under the direction of Lisa Grow, Senior Vice President of
Power Supply, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 31
REQUEST NO. 28: Please provide supporting data for current transmission use
by retai!, wholesale, and generation customers served by ldaho Powe/s 161 kV
transmission line between Goshen and Jeffercon.
RESPONSE TO REQUEST NO. 28: ldaho Powe/s Load Serving Operations
group has a firm 87 MW transmission reservation on the above-referenced transmission
path. Please see the attached transmission reservation detail, OASIS reference
number 76866224.
The response to this Request is sponsored by David Angell, Customer
Operations Planning Manager, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 32
REQUEST NO. 29: Please provide a copy of the responses submitted to the
Western Electricity Coordination Council (WECC) for the 2014 Operational Practices
Survey Report along with an explanation of whether any of the practices are anticipated
to be revised during 2015, including as a result of the proposed asset exchange.
RESPONSE TO REQUEST NO. 29: Please see the attached documents for
ldaho Powe/s responses to parts one, two, and three of WECC's 2014 Operational
Practices Survey. ldaho Power has revised operational practices to include a realtime
contingency analysis improving situational awareness.
ldaho Power does not anticipate revising its Operations Practices as a result of
the proposed asset exchange.
The response to this Request was prepared by Jared Ellsworth, System Planning
Engineer, ldaho Power Company, under the direction of David Angell, Customer
Operations Planning Manager, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 33
REQUEST NO. 30: Please explain how the Parties plan to coordinate
compliance with NERC- or State-required physical and cyber security program
requirements given the proposed asset exchange.
RESPONSE TO REQUEST NO. 30: The JOOA sets forth the obligations of
each party in its role as both owner and operator with respect to compliance with
Governmental Requirements and Governmental Authorizations. Govemmental
Requirements and Governmental Authorizations, which include federal and state laws,
rules, and regulations, are defined terms in Article 1 of the JOOA. The obligations of
each party with respect to Governmental Requirements and Govemmental
Authorizations as operator are set forth in Article lV of the JOOA.
The response to this Request is sponsored by David Angell, Customer
Operations Planning Manager, Idaho Power Company, in consultation with Julia Hilton,
Corporate Counsel, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 34
REQUEST NO. 31: Please explain how the Parties cunently ensure the
accuracy and sharing of near term studies and whether the current methods will be
revised following the proposed asset exchange. If current methods will be revised,
please further explain how the Parties will ensure the interconnection-model and near-
term-studies are accurate in the future.
RESPONSE TO REQUEST NO. 31: Because of the joint ownership of the Jim
Bridger power plant and the contractual anangements between ldaho Power and
PacifiCorp for transmission seryice, planning for these facilities has been and will
continue to be conducted cooperatively and, where relevant, related system studies are
shared to enhance planning and operational coordination between the utilities. ldaho
Power and PacifiCorp, as Transmission Operators, must comply with all requirements of
NERC Reliability Standards, which include requirements for coordinating with
neighboring Transmission Operators. ln addition, WECC base cases are utilized by
both ldaho Power and PacifiCorp to mode! the electrical system for study purposes, and
both utilities contribute to the development of these cases. The proposed purchase and
sale will not change either ldaho Powe/s or PacifiCorp's interest in or commitment to
coordinated planning.
The response to this Request is sponsored by David Angell, Customer
Operations Planning Manager, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 35
REQUEST NO. 32: Please explain how the Parties plan to ensure the accuracy
and sharing of long-term operation studies, including shoulder periods, relay settings,
remedial action scheme impacts, and outage coordination following the proposed asset
exchange.
RESPONSE TO REQUEST NO. 32: ldaho Power and PacifiCorp, as
Transmission Operators and Transmission Planners, must comply with all requirements
of NERC Reliability Standards, which include requirements for coordinating with
neighboring Transmission Operators on outages and protection system changes (relay
settings). ldaho Power and PacifiCorp, as Transmission Planners, must comply with all
requirements of NERC Reliability Standards, including the sharing of planning
assessments, which contain simulations of impacts of remedial action schemes.
Following the proposed asset exchange, the utilities will continue to comply with the
NERC Reliability Standards.
The response to this Request is sponsored by David Angell, Customer
Operations Planning Manager, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 36
REQUEST NO. 33: Please explain how the asset exchanges and upgrades to
the Idaho - Northwest Transmission (Hemmingway - Summer Lake 500 kV, Walla
Walla - Hurricane 230 kV, and Midpoint - Hemmingway 500 kV) and associated
substations revise the costs and benefits of the proposed Boardman to Hemmingway
transmission expansion.
RESPONSE TO REQUEST NO. 33: There are no anticipated changes to the
costs and benefits of the proposed Boardman to Hemingway project.
The response to this Request is sponsored by David Angell, Customer
Operations Planning Manager, ldaho Power Company.
DATED at Boise, Idaho, this 25th day of February 2015.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 37
Attomey for ldaho Power Company
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on this 25th day of February 20151 served a true and
correct copy of IDAHO POWER COMPANY'S RESPONSE TO THE FIRST
PRODUCTION REQUEST OF THE COMMISSION STAFF TO IDAHO POWER
COMPANY upon the following named parties by the method indicated below, and
addressed to the following:
Commission Staff
Daphne Huang
Deputy Attomey General
Idaho Public Utilities Commission
472 West Washington (83702)
P.O. Box 83720
Boise, ldaho 83720-007 4
PacifiCorp
Daniel E. Solander
Rocky Mountain Power
201 South Main Street, Suite 2300
Salt Lake City, Utah 84111
lndustrial Customers of ldaho Power
Peter J. Richardson
RICHARDSON ADAMS, PLLC
515 North 27h Street (83702)
P.O. Box 7218
Boise, ldaho 83707
Dr. Don Reading
6070 Hill Road
Boise, ldaho 83703
X Hand Delivered
U.S. Mail
Overnight Mail
FAX
Email [e-mail]
Hand Delivered
U.S. Mail
Overnight Mail
FAX
Emai! [e-mail]
Hand Delivered
U.S. Mail
Ovemight Mail
FAXX Email pete r@ richa rd so nad a ms. com
Hand DeliveredX U.S. Mail
,Ovemight Mai!
FAXX Email [e-mail]
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION
REOUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 38
Christa Bearry, Legal
BEFORE THE
IDAHO PUBLIC UTILITIES GOMMISSION
CASE NOS. IPG-E -14-41 and PAC-E -14-11
RESPONSE TO STAFF'S REQUEST NO. 7
Plant:
Plant Acct Plant Acct Description
Idaho Power Company
Assets To PAC
Net Book Value
Plant Balance Accumulated Reserve Net Book Value
352
353
354
355
356
Structures & Improvements
Station Equipment
Towers & Fixtures
Poles & Fixtures
Overhead Conductors, Devices
Totals
11.297.137.00 (4.916.078.00)
3,139,604.00
30,168,018.00
16,306,540.00
2,876,300.00
(698,496.00)
(8,229,061.00)
(5,s 18,556.00)
(1, r60,371.00)
2,441,108.00
21,938,957.00
10,787,984.00
1,715,929.00
6.381.059.00
Plant Acct Plant Acct Description
63,787,599.00
Annual Depreciation
Accrual Rate
(20,522,562.00\
Annual Depreciation
Expense
43,265,037.00
352
353
354
355
356
Structures & Improvements
Station Equipment
Towers & Fixtures
Poles & Fixtures
Overhead Conductors, Devices
Total
2.25o/o 254,185.58
1,242,03133
1.84o/o
1.90o/o
2.77%
57,768.71
573,192.34
277,211.18
79,673.51
BEFORE THE
IDAHO PUBLIC UT]LITIES COMMISSION
CASE NOS. IPC-E-14-41 and PAG-E-14-11
RESPONSE TO STAFF'S REQUEST NO. 28
OATI webOASIS Page I of I
Transm issi on Reservation Detail 7 6866224 CON F I RM E D
sar", l!1;f" lE3S
Roquest
Tvoe Start Stop twltuw
teqlGrant
Bid
Prlco
Olfer
Prlce Prlce
Prico
Unlt
PCM ,EFF
PCO
TESALE 101 2-05-0 1
)0:00 PD
2021-01 -01
CO:(X) PS
t7 t7 0.000(0.000{$/MW
HOUR
RESERVEDPathr WIPCO/PACE-IPCC IEFF.IPCO/
ieillce Code llncrement I Clasc TYDo I Period Wndow Subclass
YEARLY IYEARLY IFIRM POINT TO POINT I FULL PERIOD FIXED
Preconflrmed: Yes I CompetinE: No I Nogotlrtod: No I l{erc Prlortty: t I Affiliats: No
Reservation Profile
Start Dato Stop Dato MWReq lrIW Grant MWH 8id
Prlce
Oftrer
Prlce
2012-0541 00:00 PD , 202141-0'1 00:00 PS 87 87 I 6612783.00 0.00 I 0.00
Profile Total: I OOtZzgO.OO
Tirne!Refelences
Queued 2012-04-30 10:58:27 PD Deal
uDdated 2015-02-19 05:34:35 PS Sale
Re3Donso Posilng
Request
lmoactec i58
ReassiEnod 74110557
Seller
Conftrmed Time 2012-0d-3010:58:27 PD Relat€d
CG Ooadline
Commonts
Statuc I
Sellor lReassign it at full tariff rate with full renewal riqhts and oblhations
Provldor luodabd Path - SF
Custonrer I
Provi!ions
CG Statur
Statu. l{otification
Anc€ewlc.-Llnk
RolloverWalved
Concomltant Eva! FlaE
Customec IPCL Soller: lPctl
Namo I Name StefanieF lPCo
Phone I Phone [phone]
Fax I Fax
E.mall I E.mail [e-mail]
https://www.oasis.oati.com/cgi-bin/webplus.dll?script:/woa/woa-tsr-viewtsr-printview.w... 2120/2015
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NOS. IPC-E-14-41 and PAC-E-14-11
RESPONSE TO STAFF'S REQUEST NO.29
2014 Operational Practices Survev
The annual Operational Practices Survey is an important toolWECC uses to fulfill its role as the
Reliability Assurer in the Western lnterconnection. The WECC Operations Performance Analysis
Department conducts the Operational Practices Survey to identiff processes, best practices, and
opportunities for improvement and to discern trends by comparing survey responses across years.
lndividual responses to the 2014 Operational Practices Survey are confidential and will not be shared
with any entity or person other than the submitting entity. WECC may share a list of the entities
surveyed and their response status, i.e., has or has not responded. Responses are not shared with the
WECC Compliance Department or personnel. Responses to the survey do not constitute a compliance
submission or indicate compliance or non-compliance with any Reliability Standard.
Please direct questions about the Survey to Tim Reynolds, Reliability Vulnerability Staff Specialist,
[e-mail].
Part 1: Near-Term Operations: Next-Day Studies
This is Part 1 of the 3-part 2014 Operational Practices survey. This part of the survey addresses near-
term operations, specifi cally next-day studies.
The questions that follow are generally applicable to TOPs, GOPs, RCs, and BAs; however, the
applicability of specific questions is indicated. PIease fill out those questions applicable to your
company. Fields outlined in red are required. This form and your responses can be saved. When you
have completed all of your responses, please submit the form in one of two ways:
Automatic Submission
1) To submit electronicalty,lCtrcX flfRel
2) From the pop-up box, select you email method
3) lf you select Desktop EmailApplication (e.9.,
Outlook), an emailwill be automatically
generated. Send the email.
Entity Name:ldaho Power
Entity Acronym; IPCO
Entity Registration Number (NGnl; 51 91
Contact p"oon. Jared Ellsworth
ng", System Planning Engineer
gr"; ;. jel [e-mail]
phone: [phone]
Manual Submission
Send the completed PDF form to
opsu rvev@wecc. biz and reference
Operational Practices Survey
Response in the subject.
Registered Function
(select allthat apply)
Balancing Authority (BA)
Reliability Coordinator (RC)
Owner (GO)
ransmission Owner (TO)
Operator (GOP)
ransmission Operator (TOP)
Planning Coordinator (PC)
ransmission Planner (TP)
2014 Operational Practices Survey Part 1 Page 2
Question 1: Applicable to TOPs and RCs
Which of the following do you include in your next-day studies? (Select all that apply)
Planned internal transmission/generation outages
external (neighboring TOP) transmission/generation outages
conditions within appropriate thermal and voltage limits
conditions within appropriate thermaland voltage limits
stability to identiff stability limits
sient stability to identify stability limits
analysis
of required reactive reserves for defined areas
Expected generation reserve commitments
lnternal projected loads
External projected loads
Expected net interchange
Modeling and simulation of remedial action schemes
NaturalGas supply for generation
Other
Question 2: Applicable to TOPs and RCs
r Day-Ahead Study Engineer(s) compare the planned system outages
line/generation/reactive device), with actual outages and determine if
SOLs provided day-ahead need to be adjusted for same-day operations.
Question 3: Applicable to TOPs
Describe how projected load, interchange, and generation are calculated (determined) for input
into the next-day studies.
light load paths, we assume a general light load distribution that we check
times over the course of a year to determine if our models are still accurate.
heavy load paths, we assume a load comparable to our alltime system peak
performing heavy load studies. By making these assumptions, we are taking a
approach. lf it appears that this approach is causing problems, we will
load/generation values to match expected values for the next day (factoring
the orevious several d and exoected weather
How do vou check studies for and data
2014 Operational Practices Survey Part 1
Question 4:Applicable to TOPs
Do you validate projected load, interchange, and generation values with actualvalues?Iv"t
n*o
Page 3
Question 5: Applicable to TOPs
Are there sutr100-kV facilities in your transmission system that can adversely impact the Bulk
Electric System?
Yes (lf Yes, proceed to Question 5.a)
No (lf No, proceed to Question 5.b)
Question 5.a
. Are the facilities modeled in your next-day studies and simulated as contingencies?
Ivesflltto. Are the facilities modeled for real-time operations and simulated as contingencies in real-
time contingency analyses?
Ive{.llro. Are the facilities monitored in real-time for pre- and post-contingency exceedances?
Iv"s[xo. \trUhat events would trigger a r+evaluation of the sub-100-kV facilities in your transmission
system to determine which facilities would be added or dropped?
Question 5.b. Have you performed studies to identiff any sub-100-kV facilities that may have an adverse
impact on the Bulk Electric System?
Ive{.lruo
will only do this if we find N-1 and N-2 issues (thermal overloads, or
reactive violations) in our conservative models (high load for heavy-load
and liqht load for liqht-load
have 69 kV lines in several areas that run electrically parallel to BES lines. ln
€ses we have determined these lines wil! never adversely impact the BES
Additiona! comments (optional):
2014 Operational Practices Survey Part 1
Question 6:Applicable to TOPs
Page 4
No (lf No, proceed to Question 6.b)
Question 6.a. ls this the primary way you share next-day studies with your neighboring BAs and
TOPs?
Iv"'[ruo. Have you confirmed that allyour neighboring TOPs and BAs have access to the Peak
RC website?
Ives[r.ro' *
Hil"lc," |lxr,:::"*
stud ies i n other wavs?
lf we find that we have an impact on a neighboring TOP, or we believe that the
neighboring TOP will have an impact on us, we will coordinate with them
Question 6.b
How do you share your next-day studies?
Question 7:Applicable to TOPs
ln reviewing your neighboring TOPs' next-day studies, which of the following applies?
(Select One)
We review all neighboring TOP next-day studies every day
We review some neighboring TOP next-day studies every day
We review neighboring TOP next-day studies only if the entity contacts us
Other (Explain below)
2014 Operational Practices Survey Part 1 Page 5
Question 8:Applicable to TOPs
\Mth regard to how often your next-day studies are updated, which of the following applies?
(Select one)
l-lW" update our next-day studies daily.t-t
We evaluate our next-day studies every day to determine whether the study performed
the day prior or another recent "similar day study" needs to be updated.
We perform a master study (e.9., seasona! study) and update our next-day study as
needed
We perform a master study (e.9., seasonal study) but do not update it untilthe next
season/year
Question 9:Applicable to TOPs and RCs
On average, how many buses externalto your system are monitored in next-day analysis
simulations for pre.and post-contingency conditions? (Select one)
1-2
34
5-6
>6
None
Other (Explain below)
Question 10: Applicable to TOPs
within your company, receives a copy of your next-day studies? (Select allthat apply)
lnternal operators
Management
Transmission planners
Substation operators
Relay department
Other (Explain below)
H
E
next-day studies are posted to an interna! sharepoint site. Planners and
have access to this sharepoint site, and can view day-ahead studies
they desire. Planned and unplanned outages are coordinated with our
department. The Relay department is involved in the day-ahead study
2014 Operational Practices Survey Part 1
Question 11: Applicable to TOPs
Do you receive the RC Next-day Operations Planning Analyses?
BVes (lf Yes, proceed to Question 11.a)
LlNo (lf No, proceed to Question 11.b)
Page 6
Question 11.a
With regard to how you use the RC Next-day Assessment, which of the following
applies? (Select one)
We do not complete our next-day studies untilthe RC Next-day
Assessment is reviewed
We complete our next-day studies then compare them to the RC Next-
day Assessment
We review the RC Next-day Assessment but do not compare it to the
next-day study
We receive the RC Nextday Assessment but do not review it unless
requested or noticed by the RC
Question 11.b
Question 12: Applicable to TOPs
lf applicable, have you met with all of the GOPs in your territory to identiff information sharing
needs?
Not applicable because we have no GOPs
Yes
No
lf no, do you plan to meet with them and when?
ldaho Power is a Load Serving Entity that acts as the TOP and GOP. For the
bset of generation not owned by ldaho Power that is connected to the ldaho Power
Question 13: Applicable to TOPs
With regard to the information provided by the GOPs for the next-day studies, which of the
following applies: (Select one)
Bru the information that is needed is provided within an acceptable timeframe
I lsome information provided is adequate but some needed information is omitted
[fn" information is incomplete and results in frequent follow-up phone catls or meetings
[Otn", (Explain below)
2014 Operational Practices Survey Part 1 Page 7
Question 14: Applicable to TOPs
With regard to question 13, in cases where information provided by the GOPs is consistently
incomplete, what information is missing?
ldaho Power is a Load Serving Entity that acts as the TOP and GOP. Most none
ldaho Power controlled generation is wind, which we attempt to forecast through
Question 15: Applicable to TOPs, BAs, and RCs
Would any of the following make your next-day studies more effective? (Select all that apply)
More visibility into neighboring BAs or TOPs
Updated tools to perform the next-day studies
More training for operators to perform next-day studies
Metrics to improve accuracy of the next-day studies
Peer reviews of next-day studies for best practices and feedback
Other (Explain below)
Question 16:Applicable to GOPs
Have you ever met with your TOP to identify what information needs to be shared for them to
perform next-day studies?
Ives
[*o
Question 17: Applicable to GOPs
\ffhich of the following do your next-day assessments address: (Select all that apply)
flunit outages
Mforecasted generation one day out
nforecasted generation for multiple days out
Vtr
Any current issues with Automatic Voltage Regulators or Power System Stabilizers on
any unit
Any potential issues with protection systems or remedial action schemes
Other (Explain below)
single unit with an AVR or PSS issue would not affect the SOLs associated
of ldaho Power's lines or transfer paths.
next-day study process is very effective as it exists today. Obviously
ional visibility, and real-time tools cost make the process more effective
2O14 Operational Practices Survey Part 1
Question 18: Applicable to GOPs
\ffhat would make next-dav assessments more effective?
Page 8
of the expected (next-day) loop-flow across the ldaho Power system.
2014 Operational Practices Survev
The annual Operational Practices Survey is an important tool WECC uses to fulfill its role as the
Reliability Assurer in the Western lnterconnection. The WECC Operations Department conducts the
Operational Practices Survey to identify processes, best practices, and opportunities for improvement
and to discern trends by comparing survey responses across years.
lndividual responses to the 2014 Operational Practices Survey are confidential and will not be shared
with any entity or person other than the submitting entity. WECC may share a list of the entities
surveyed and their response status, i.e., has or has not responded. Responses are not shared with the
WECC Compliance Department or personnel. Responses to the survey do not constitute a compliance
submission or indicate compliance or non-compliance with any Reliability Standard.
Please direct questions about the Survey to Tim Reynolds, Reliability Vulnerability Staff Specialist,
[e-mail].
Parl2: Long-Term Operations - Seasonal Studies
This is Part2 of the 3-part 2014 Operational Practices survey. This part of the survey addresses long-
term operations, specifically seasonal studies.
The questions that follow are generally applicable to TOPs, TPs, and PCs; however, the applicability of
specific questions is indicated. Please fill out those questions applicable to your company. Fields
outlined in red are required. This form and your responses can be saved. When you have completed all
of your responses, please submit the form in one of two ways:
1)
2)
3)
Automatic Submission
To submit electronically, lct-rcx nenel
From the pop-up box, selEtT!6[6i6il'imethod
lf you select Desktop Email Application (e.9.,
Outlook), an emailwill be automatically
generated. Send the email.
Entity Name:ldaho Power Company
Entity Acronym; IPC
Entity Registration Number (NCR/WGR;:5191 s
Gontact percon: Jared Ellsworth
Title: Svstem Planninq Enqineer
Email: [e-mail] a
Phone:[phone] s
Manual Submission
Send the completed PDF form to
opsu rvey@wecc. biz and reference
Operational Practices Survey
Response in the subject.
Registered Function
(select all that apply)
Balancing Authority (BA)
Reliability Coordinator ( RC)
GeneratorOwner (GO)
Transmission Owner (TO)
Generator Operator (GOP)
Transmission Operator (TOP)
Planning Coordinator (PC)
Transmission Planner (TP)
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2O14 Operational Practices Survey Parl2 Page 2
Question 1: Applicable to TOPs, TPs, and PCs
Which of the following do you include in your seasonal studies? (Select all that apply)
fZeUnneO internal transmission/generation outages expected to last for the
majority of the season
M eUnneO external (i.e., neighboring TOP) transmission/generation outages expected
to last for the majority of the season
Voltage stability to identify stability limits
Transient stability to identify stability limits
Pre-contingency conditions within appropriate thermal and voltage limits
Post-contingency conditions within most severe thermaland voltage limits
analysis
of required reactive reserves for defined areas
Expected generation reserve commitments
lntemal projected loads
External projected loads
Expected net interchange
Natural Gas supply for generation
Relay settings
Modeling and simulation of RemedialAction Schemes
(Explain)
ned External outages are limited to those we are aware of in our neighboring
Ps.
Question 3: Applicable to TOPs, TPs, and PCs
Do vou validate load, i and values actual data?
Seasonal forecasts are compared to actuals after{he-fact to improve future forecasts.
Question 2:Applicable to TOPs, TPs, and PCs
ldaho Power performs light load and heavy load seasonalstudies.
For light load studies, projected load is assumed to closely match historical light load
For heavy load studies, ldaho Power utilizes a 1 in 20 year peak summer load
i.e. ldaho Power onlv exoects the forecast to be exceeded 1 vear in 20
2014 Operational Practices Survey Parl2 Page 3
Question 4: Applicable to TOPs and TPs
With what entities do you share adverse or unexpected conditions identified in your seasonal
studies? (Select allthat apply)
INr"ignuoring BAs
f,N"ignooring ToPs
f r.r"ignooring PGs
f rn" nc
Question 5: Applicable to TOPs, TPs, and PCs
Do you always perform seasonal studies for shoulder periods?
Iv"t
E*o
not?
are continuously studying our transfer paths during peak and shoulder months,
, we only provide "seasonal studies" to the NOPSG workgroup on a
rotation (every three years for each path).
Question 6: Applicable to TPs, PCs, and RCs
How do you communicate to appropriate operating personnel information about elements that
Question 7: Applicable to TPs, PCs, and RCs
How do you manage those elements referred to in question 6 in near-term operational planning
studies (e.9., outage studies, day-ahead studies)? (Select allthat apply)
MtOentified elements are monitored in realtime
l-ltOentified etements are included in Real-Time Contingency Analysis (RTCA) studies
fZldentified elements are highlighted in the next-day studies
EO', elements are monitored regardless of the seasonal study
notn"r (Explain)
whv
ldaho Power's planning department has a meeting scheduled every-other week to
uss Operations and Planning issues. These types of issues may be brought on at
time, or communicated by phone at times in-between these biweekly meetings.
discussions occur for all extraordinary system conditions that
2014 Operational Practices Survey Part2
Question 8: Applicable to TOPs and TPs
Do you consider relay settings in your seasonal planning process?
[V"r (lf Yes, proceed to Question 8.a)
E *o (lf No, proceed to Question 8.b)
Page 4
Question 8.a
Do you participate in a regional review of relay and/or RAS scheme implementations
and coordination?
[]ves
E*o
Question 8.b
Question 9: Applicable to TOPs and TPs
How do you coordinate your seasonal studies with other groups? (Select allthat apply)
A regional or sub regional study group
Directly with neighboring TOPs
Directlywith the RC
Directly with other PCs
Ma email without follow-up
Other (Explain)
Question 10: Applicable to TOPs and TPs
How do you utilize seasonalstudies within the company? (Select allthat apply)
with the transmission operatorc
with management
Share with transmission planning
with substation operations
(explain)
Power participates in the NOPSG regional study group. lf necessary, ldaho
will coordinate with neighboring TOPs, the RC, and other PCs, however,
is not the standard process.
studies are available to anyone in the company with a Balancing Area
desire/need to know the information.
2014 Operational Practices Survey Part2 Page 5
Question 11: Applicable to TPs and PCs
How do you evaluate the impacts of major transmission outages under heavy transfer
model the major transmission outage with the system curtailed for the given
, and run all of our standard N-1 and Multiple Facility Contingencies to
each of ldaho Power's impacted transfer paths temporary SOLs.
Question 12:Applicable to TPs, PCs, and RCs
How do you evaluate the impact of major transmission outages under heavy transfer conditions
on sub-'l00-kV facilities, especially those operated in parallel with the BPS, to identify any
potential system cascading risks?
ho Power models and evaluates sub-100-kV facilities when necessary.
Question 13: Applicable to TPs and PCs
How do you ensure that seasonal studies address the interaction of various protection systems,
especially special protection systems that are designed to mitigate undesired post-contingent
conditions?
ldaho Power models the functionality our our SPS and RAS.
Question 14:Applicable to TPs and PCs
Do you benchmak models against real system conditions and events?
fV"r (lf Yes, proceed to Questions 14.a)
E*o
Question 14.a. Does the benchmark include severe and/or unusual system conditions?
f,ves E*o. How do you resolve differences between model results and actual system
conditions?
ho Power attempts to match our model cases with a real-life timeframe.
we notice discrepancies between flows on the lines in the path in the
versus real life, we will redispatch generation to achieve the desired
. lf this doesn't work, we have looked into adjusting transmission line
X, and B values if we can find reasons why these may have changed
in vour seasonal studies?
2014 Operational Practices Survev
The annual Operational Practices Survey is an important toolWECC uses to fulfill its role as the
Reliability Assurer in the Westem lnterconnection. The WECC Operations Department conducts the
Operational Practices Survey to identify processes, best practices, and opportunities for improvement
and to discern trends by comparing survey responses across years.
lndividual responses to the 2014 Operational Practices Survey are confidential and will not be shared
with any entity or person other than the submitting entity. WECC may share a list of the entities
surveyed and their response status, i.e., has or has not responded. Responses are not shared with the
WECC Compliance Department or personnel. Responses to the survey do not constitute a compliance
submission or indicate compliance or non-compliance with any Reliability Standard.
Please direct questions about the Survey to Tim Reynolds, Reliability Vulnerability Staff Specialist,
[e-mail].
Part 3: Situational Awareness, Protection Slstems, Angular Separation, EMS
This is Part 3 of the 3-part 2014 Operational Practices survey. This part of the survey addresses
situational awareness, protection systems, angular separation, and EMS topics.
The questions that follow are generally applicable to TOs, TOPs, GOs, GOPs, BAs, TPs, and PCs;
however, the applicability of specific questions is indicated. Please fill out those questions applicable to
your company. Fields outlined in red are required. This form and your responses can be saved. When
you have completed all of your responses, please submit the form in one of two ways:
Automatic Submission Manual Submission
Send the completed PDF form to
opsu rvey@wecc. biz and reference
Operational Practices Survey
Response in the subject.
't) To submit electronicalfy,lCf-rcf t enel
Entity Name:ldaho Power Company
2)
3)
From the pop-up box, select you email method
lf you select Desktop Email Application (e.9.,
Outlook), an emailwill be automatically
generated. Send the email.
Entity Acronym; IPC
Entity Registration Number (NCR/WCR): 5191
Contact person: Jared Ellsworth
Titte: System Planning Engineer
Email : [e-mail]
Registered Function
(select allthat apply)
Balancing Authority (BA)
Reliability Coordinator ( RC)
Generator Owner (GO)
Transmission Owner (TO)
Generator Operator (GOP)
Transmission Operator (TOP)
Planning Coordinator (PC)
Transmission Planner (TP)
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Phone:[phone]
2014 Operational Practices Survey Part 3
Situational Awareness
Question 1: Applicable to TOPs, BAs, GOPs, PCs and RCs
Which of the following Reliability Tools do you use for situational awareness?
(Select allthat apply)
RTCA
Real-time Line Outage Distribution Factor (LODF) calculations
SCADA realtime displays and overview
State estimation
Real-time voltage stability analysis
Real-time transient stability analysis
Alarm Tools
Signal error detection for both analog and digital inputs (e.9. heart beat)
Power Flow
Other (Explain)
Question 2: Applicable to TOPs, BAs, GOPs, and RCs
For which of the following analyses do you rely on another entity to perform?
(Select allthat apply)
Page 2
RTCA
Real-time Line Outage Distribution Factor (LODF) calculations
SCADA realtime displays and overview
State estimation
Real-time voltage stability analysis
Real-time transient stability analysis
Alarm Tools
Signal error detection for both analog and digital inputs (e.9. heart beat)
Power Flow
Other (explain)
The PEAK RC performs an RTCA check of our system. On rare occasions these
results will uncover something that improves our situational awareness. The
majority of the time there is an issue with the mode! (and in most cases we have
already provided data to correct the model issues but the PEAK RC has yet to E
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2014 Operationa! Practices Survey Part 3
Question 3:Applicable to TOPs, TPs, RCs, and PCs
Page 3
What is your process to ensure consistency between real-time and planning models in order to
maintain accurate netwok models?
Our planning department utilizes a conservative approach with their planning models.
lf these models have unacceptable results, the model will be trued up to something
that is more representative of the near-term system (i.e. adjust load and generation),
and the planninq department will restudv usinq the updated model to determine nextg
Question 4: Applicable to TOPs, BAs, and RCs
Following a contingency on your system, on average, how long does it take the real-time tools
to perform an updated analysis of System Operating Limits or other contingency conditions?
(Select one)
71. r ,in
2-3 min
4-5 min
>5min
Question 5: Applicable to TOPs, BAs, and RCs
Do you have a procedure for the loss of real-time tools?
8I""",
lf yes, do you share the procedure with the RC?
!v""
Z*o
lf yes, do you share the procedure with all neighboring TOPs?
!v"t
lf no, please explain.
Question 6: Applicable to TOPs and BAs
Have you read the WECC Pre- and Post-Contingency Plan Guideline that was approved by the
Operating Committee on May 20,2014 (Link)?
Yes
No
atrtr
No
E*o
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2014 Operational Practices Survey Part 3
Question 7:Applicable to TOPs and BAs
Do you have pre-contingency measures in place?
Page 4
Yes
No
Question 8: Applicable to TOPs and BAs
Do you have post-contingency measures in place?
Yes
No
Question 9: Applicable to TOPs, and BAs
lf applicable, which of the following do your pre- and/or post-contingency measures consider?
(Select allthat apply)
Adjustment or re-dispatch of generation to ensure acceptable system performance
(operating within Facility Ratings, bus voltage limits, stability limits, and any other SOL or
IROLs) while implementing proposed transmission or generation outages
Adjustment of generation and interchange schedules to ensure adequate reserves and
regulating margins are maintained
Z| neOrest or dispatch of reserves as necessary from Reserve Sharing Group, if applicable
|7l provision of notification procedures prior to or following a forced outage
7l ruec."sary actions to resynchronize and reconnect to the lnterconnection
Actions to determine whether a manual load shed is needed to prevent imminent
separation from the lnterconnection, voltage collapse, or other adverse consequence
Direct actions to return the system to a secure state following a major system
disturbance
Other (Explain)
Question 10:Applicable to TOPs, BAs, and RCs
Which of the following best describes what you consider appropriate post-contingency mitigation
actions for an exceedence of the highest available Facility Rating or bus voltage limit (an RTCA
exceedence)? (Select all that apply)
l_lnOlustlng generation ortransmission as necessary within 30 minutes
MRrtorrted responses such as RAS or automatic capacitor switching
f]*o action because they are RTCA results, not cunent system conditions
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2014 Operational Practices Survey Part 3 Page 5
Question 11: Applicable to TOPs and RCs
lf a pre- or post-contingency measure is created, do you provide training to your operators to
ensure understanding?
Yes
No (Explain)
Protection Svstems
Question 12: Applicable to TOPs, TOs, GOPs, and GOs
For which of the following do you share overload trip settings with the RC and neighboring
TOPs? (Select allthat apply)
f rranstormers
l/l rr"n"rission lines
17 otn", (Explain)
Settings are shared as needed or requested in order to properly coordinate all
types of Protection Systems. Typical communication takes place via email, and
all correspondence is saved for future reference.
Question 13: Applicable to TOs and GOs
When calculating relay settings, how do you perform stability studies?
Relay settings are calculated by the System Protection Engineering group and made
available to the Planning group should they be needed to perform their stability studies.
lf the Planning group discovers a stability limitation on a line/path, and relay settings
ehanoes are reorired this will he eoordinatcd with lhe Svstem Protcetinn Fnninccrinn E
Question 14: Applicable to TOs and GOs
How do you coordinate the results with impacted neighboring GOPs, TOPs, BAs, and PCs
before the settings are in place?
Settings are shared as needed or requested in order to properly coordinate all types of
Protection Systems. Typical communication takes place via email, and all
correspondence is saved for future reference.
Question 15: Applicable to TOs, TOPs, TPs, and PCs
What is your process for reviewing the purpose and impact of RemedialAction
Schemes/Special Protection Systems in your footprint to ensure they are properly classified,
serve their intended purposes, are coordinated properly with other protection systems, and do
not have unintended consequences to reliability of the BPS?
The purpose and impact of a RAS would be reviewed if there were a major system
change (new major transmission line or generator) or modification to the associated
^^+r., -^+i-a A tr^^-+ ^ *aiar arraaaa lt.^,^ :^ .,^-, r:*l^ ^^^.t r^, ^. ,^l. ^ .l^+^il^-l -^.,:^.., ^EHow frequently do you conduct a revieu/'?
Reviews of these systems are always ongoing as we continue to study our system and
its transmission lines and paths. Adjustments are made from time-to-time. Detailed RAS
reviews are generally done while studying their corresponding path in our regiona! stud6
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2014 Operational Practices Survey Part 3
Question 16: Applicable to TOPs, BAs, and RCs
Page 6
Do you have the ability to determine standing angles in real time following a major transmission
outage?
lf yes, how do you determine that angle?
ldaho Power has installed Phasor Measurement Units (PMUs) at various bus
locations in our system.
Question 17:Applicable to TOPs, BAs, and RCs
Do you have the ability to determine expected post-contingency standing angles (in a RTCA or
similar tool) in real-time?
[] ves E*o
! v"t E*o
lf yes, how do you determine that angle?
Question 18: Applicable to TOPs and TOs
Have you checked the sync-check relays on major transmission paths within the last five years
to identify potential issues with phase angle settings?I v""
lf yes, please answer the following questions:
. Did you identify phase angle settings that were too conservatively set based
on historical performance?
Yes
No
E*o
. Did you identify phase angle settings that were too conservatively set based
on transmission studies?
f v"t
E*o. Do you plan to perform this routine sync-check analysis again?
|7| V"" lf yes, on what interval? As system topology changes.
E*o
lf no, when do you plan to perform the analysis?
2014 Operational Practices Survey Part 3 Page 7
Question 19:Applicable to TOPs and BAs
Do you have plans in place for reducing angles to within synch-check relay settings to allow
prompt reclosing of lines?
Mv"t
E*o
Question 20: Applicable to TOs and GOs
Do you have any RemedialAction Schemes (RAS) that are identified by the WECC Remedial
Action Scheme Review and Assessment Plan (Link)?
Iv"t
lf yes, please answer the following questions:
. How many RAS have you identified?
Seven
During each of the following time periods, how many times has any RAS
operated?
2013
2013
2013
2013
2014
2014
. Do you have any plans to add another RAS that will be identified by the
WECC Remedial Action Scheme Review and Assessment Plan in the next 5
years?
Yes
No
E*o
lf no, do you have plans to add a RAS that will be identified by the WECC
Remedial Action Scheme Review and Assessment Plan in the next five years?
f ves
E*o
Q1
Q4:
Q1:
Q2:
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2O14 Operational Practices Survey Part 3
Enerqv Manaoement Svstems (EMSI
Question 21: Applicable to TOPs
Page 8
Within in your company, which of the following functions is within the purview of the EMS staff?
(Select allthat apply)
Network infrastructure
Displays/User interface
Real-time database
Data historian
Advanced applications
Automatic Generation Control (AGC)
Training simulator
SCADA - Control Center
SCADA- Field
Control center hardware support
Other (Explain)
Question 22: Applieable to TOPs
How many of your EMS support staff are dedicated solely to your EMS?
6 people.
Question 23: Applicable to TOPs
On average, how many years of relevant experience does your EMS staff have?
12years
Question 24: Applicable to TOPs
Do you rely on vendors for EMS support or event response support? (Please explain)
No. We handle EMS support and event response almost exclusively in-house.
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2014 Operational Practices Survey Part 3 Page 9
Question 25: Applicable to TOPs
ln which of the following does your EMS support staff participate? (Select all that apply)
NERC Continuing Education Training courses
ln-house operations training
Job shadowing in the department they support (e.g. dispatch, scheduling)
System Dispatch training
Substation awareness
Factory Acceptance Testing (FAT)
Vendor training
Other training (explain)
Question 26:Applicable to TOPs
Which of the following apply to the formal technical training provided to your EMS support staff?
(Select allthat apply)
Training is provided to new support staff
Training is provided to existing staff on a periodic basis
Training is conducted by company staff
Training is conducted by the vendor
Other (explain)
Question 27: Applicable to TOPs
How old is your EMS (i.e., when did it come online)?
25 years, although we upgraded our EMS vendor to Alstom in2007.
Question 28: Applicable to TOPs
When was your EMS last upgraded?
2013
Question 29: Applicable to TOPs
Do you have plans to update or rgrlace your EMS?[4; E*o'
lf yes, what is your timeline?
We follow the vendor's roadmap and use it to supplement our own EMS
technology roadmap. We update EMS hardware and software applications on a
regular basis.
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2014 Operational Practices Survey Part 3 Page 10
Other
Question 30: Applicable to TOPs, GOPs, RCs, TOs, GOs, TPs, PCs, and BAs)
What measures could WECC or others take that would help you address gaps in practices
regarding the reliable operation of the Westem lnterconnection?
The implementation of pseudo ties across the Western lnterconnection needs to
become more consistent. Today pseudo ties are implemented in many different
ways and without some prescriptive processes and requirements the practices haveo
Question 31: Applicable to TOPs and BAs
Does your company use synchrophasor data?
Yes
ln which of the following ways is it used?
E*o
E*o
n Real-time viewing (e.g. alarms, state estimation, etc.)
V enalyzing system events
M aencnmarking models
n Otner (Explain)
Do you have plans to use synchrophasor data? (Please explain)
Question 32: Applicable to TOPs
Do you communicate planned outages to the RC's Coordinated Outage System (COS)?
I ves
How often? Daily, when necessary.
Do you use another process to inform the RC of changes? (Please explain)
Question 33: Applicable to TOPs
What, if any, suggestions do you have to improve the COS to meet your needs with regard to
outage reporting and coordination? Do you communicate planned outages to the RC's
Coordinated Outage System (COS)?
None.
Do you use information in the COS to perform Next-Day studies?
Mves E*"
2O14 Operational Practices Survey Part 3 Page 1 1
Question 34: Applicable to TPs and GOs
Which of the following documents have you or others in your company read and utilized?
(Select allthat apply)
Tlc"n"rrting Unit Model Validation Policy (Link)
lZGenerating Facility Data, Testing and ModelValidation Requirements (Link) (GO)
fZG"n"rrting Facility ModelValidation Requirements (Link, see Appendix A) (GO)t.L.t
Mlc"n"r"ting Unit Baseline Test Requirements (Link. see Apoendix B) (GO)
Question 35: Applicable to all Registered Entities
This year, WECC issued this survey in three parts in an attempt to ease the burden that one
large survey created for entities. We would like your input on this approach, as well as any
improvements we might make to this process. Please provide your input below.
We liked it.