HomeMy WebLinkAbout20170925Utah_OCS Set 1 (1-62).pdf1407 W.North Temple
ROCKY MOUNTAIN Salt Lake City,UT 84116
POWER
A DIVISION OF PACIFICORP
July 31,2017
Béla Vastag
Office of Consumer Services
160 East 300 South
Salt Lake City,Utah 84111
bvastag@_utahgov (C)
RE:UT Docket No.17-035-39
OCS 16'Set Data Request (1-62)
Please find enclosed Rocky Mountain Power's Responses to OCS 16'Set Data Requests 1.1-1.62,
including Confidnetial Response OCS 1.22.Also provided electronically are non-confidnetial
Attchments.Provided on the enclosed Confidential CD is Confidential Response OCS 1.22 and
Confidential Attachments.Confidential information is provided subject to Public Service
Commission of Utah (UPSC)Rules 746-1-602 and 603.Also provided is Confidential
VENTYX Attachment OCS 1.3.Only individuals covered under the VENTYX-ABB mutual
confidentialityagreement may view Confidential Attachment OCS 1.3.
If you have any questions,please call Tarie Hansen at (801)220-2053.
Sincerely,
Bob Lively
Manager,Regulation
Enclosures
C.c.Erika Tedder/DPU etedder@utah.gov(C)
Dan Kohler/DPU (C)
Dan Peac/DPU (C)(W)
Sam Brandin/DPU sbrandin lacapra.onmicrosoft.com (C)(W)
Philip Hayet/OCS p_hayet@jkennn.co_m (C)
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.1
OCS Data Request 1.1
Please provide copies of all past and future data requests and responses received by or
sent from Rocky Mountain Power to any party in this docket.Please include both formal
and informal responses.
Response to OCS Data Request 1.1
Please refer to Attachment OCS 1.1 -1 and Confidential Attachment OCS 1.1 -2.
Going forward,the Office of Consumer Services (OCS)will be provided copies of data
requests and responses.
Confidential information is provided subject to Public Service Commission of Utah
(UPSC)Rules 746-1-602 and 603.
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.2
OCS Data Request 1.2
General (IRP)
For each year over the last 20 years,provide one set of CO2 ($/Ton)forecasts (low,mod,
high)that the Company used in the given year.
Response to OCS Data Request 1.2
The Company objects to this request on the basis that it is undulyburdensome,not
reasonably calculated to lead to the discovery of admissible evidence,and seeks
information that is not maintained in the ordinary course of business.Without waiving
these objections,the Company responds as follows:
Please refer to Attachment OCS 1.2,which provides CO2 PTICO fOrecasts used in the
Company's past integratedresource plans (IRP),dating from 2003.IRP filings pre-dating
2003 are not in a readily accessible format.Note:in some instances,the CO2 price
forecasts are incomplete,since some work papers were not available.
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.3
OCS Data Request 1.3
General (IRP)
Please provide a copy of the PaR and System Optimizer User's Manuals.If a signed
copy of a confidentialityagreement is necessary,please expeditethat process so that it
may be taken care of.
Response to OCS Data Request 1.3
The Planning and Risk (PaR)and System Optimizer (SO)models are proprietary
software licensed to the Company by ABB (formerlyVENTYX).User manuals and
associated documentation are considered confidential and ABB intellectual property,and
may not be distributed by the Company to third parties under the terms of the license
agreement.A confidentialityagreement between the recipient and ABB must be in place
to receive this information.
Please refer to Confidential Attachment OCS 1.3,which provides the user manuals for
PaR and the SO model.Note:the aforementioneduser manuals are proprietary and
confidential materials of ABB.Only individuals covered under the VENTYX-ABB
mutual confidentialityagreement may view Confidential Attachment OCS 1.3.
Confidential information is provided subject to Public Service Commission of Utah
(UPSC)Rules 746-1-602 and 603.
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.4
OCS Data Request 1.4
General (IRP)
The IRP process required Aurora to develop long-term wholesale power price forecast.
Why doesn't the Company use Aurora,or GRID,instead of SO and PaR for expansion
planning and quantifyingproduction costs?Please explain how the Company determines
which models are appropriate for which analysis.
Response to OCS Data Request 1.4
Optimization models capable of meeting the complex modeling needs of PacifiCorp's
integratedresource plan (IRP)are highly specialized.
AuroraXmp (Aurora)is a leading power market simulation model in the energy industry.
This model is capable of producing short-term and long-term price forecasts for major
markets zones and trading hubs,and lends itself well to regional analysis such as that
conducted by the Western ElectricityCoordinating Council (WECC).These capabilities
do not exist in the System Optimizer (SO)model or the Planning and Risk model (PaR).
The SO model is a capacity expansion model.The SO model optimizes capacity
expansion for PacifiCorp within the broader framework of WECC,informed by the
Aurora-determined pricing.While Aurora produces a capacity expansion forecast for
WECC as part of price curve development,the SO model is more granular and is part of
the same software package as PaR,enabling the two primary IRP models (SO and PaR)
to sync smoothly.
PaR provides stochastic cost and risk data,taking the SO model's capacity expansion
results as an input.Because of the necessary detail and iterations,PaR can take 20 or
more hours to produce results of a single IRP case.The Aurora model and the SO model
are not capable of producing this type of analysis.
The Generation and Regulation Initiative Decision Tool (GRID)is a production cost
model developedprimarily to support regulatory analysis.GRID is capable of producing
results similar to a PaR stochastic mean outcome,but the model lacks PaR's detailed
stochastics and cannot compute capacity expansion.
For additional discussion of the SO model,the Aurora model and the PaR model uses and
capabilities,please refer to the Company's 2017 Integrated Resource Plan,specifically
Volume I,Chapter 7 (Modeling and Portfolio Evaluation Approach),pages 145-168.
The Company's 2017 IRP is publicly available and can be accessed using the following
website link:
http://www.pacificorp.com/es/irp.html
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.5
OCS Data Request 1.5
General (IRP)
Please provide the SO and PaR inputs,outputs,and summary spreadsheets,electronically
with all formulas intact,associated with the 2017 IRP preferred portfolio,
Response to OCS Data Request 1.5
Please refer to Attachment OCS 1.5 -1 and Confidential Attach OCS 1.5 -2.
The information provided in these attachments was included in the public and
confidential data disks that accompanied the Company's 2017 Integrated Resource Plan.
Confidential information is provided subject to Public Service Commission of Utah
(UPSC)Rules 746-1-602 and 603.
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.6
OCS Data Request 1.6
General (IRP)
Please provide the latest GRID modeling files,includingwork papers and GRID access,
consistent with 2017 IRP assumptions.Please supply the Schedule 38 GRID database
from June 21,2017,if a more recent study is not available.
Response to OCS Data Request 1.6
The Company is in the process of compiling the requested Generation and Regulation
Initiative Decision Tool (GRID)information and will provide with a supplemental
response to this request shortly.
In addition,the Company will shortlybe in contact with the Office of Consumer
Services'consultants (Philip Hayet and Leah Wellborn of J.Kennedy and Associates,
Inc.)to provide access to the requested GRID project(s)to their external GRID instance.
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.7
OCS Data Request 1.7
General (Repower)
Please provide copies of PacifiCorp's responses to wind repowering data requests
submitted by all parties in the states of Idaho,Washington,Oregon,Wyoming,and
California in addition to those in Utah.This includes public and confidential data
responses.Please provide the responses at,or shortlyafter,the time when the Company
files its responses to other parties.As responses are provided,please include a summary
of the state name,organization and DR#s for the DRs containedwithin each response.
This is an ongoing request.
Response to OCS Data Request 1.7
Please refer to Attachment OCS 1.7.
Going forward,the Office of Consumer Services (OCS)will be provided copies of
responses in the only otherjurisdictionsin which it filed applications for approval of
wind repowering,includingin Wyomingand Idaho as a supplemental response to this
request.
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.8
OCS Data Request 1.8
General (Repower)
Please explain how the technology chosen for repowering compares to the technology
under consideration for new sites considered in 17-035-40.Please explain if the
technology available to repowering existing sites are limited compared to new sites.
Please address any re-powering limitations such as sizing or technology limitations due to
spacing between towers,tower specifications,foundation specifications,or other
engineering considerations.
Response to OCS Data Request 1.8
Technology employed for repowering is similar to that being considered for new wind
resources,apart from the equipment sizing.The turbines purchased by the Company in
2016 to support repowering,and planned for future deliveryand installation in 2019 and
2020,use the equipment manufacturer's latest turbine technologies available.Since the
turbines to be used for repowering are also used for the development of new wind sites,
the turbine manufacturers anticipate updating these repowering turbines with new loads
mitigation,controls,and generator power quality technologies as those technologies
become available before project implementation.As addressed in the Mr.TimothyJ.
Hemstreet's direct testimony,new rotors for repowering wind turbines are also under
development.However,unlike new wind development,equipment to repower an existing
wind project that reuses the tower and foundation is limited by the design capacities of
those existing structural elements as well as constraints related to the medium voltage
collection system (although collection system constraints can be fairly readily addressed
if economic to do so).Generally,turbine types and rotor sizes must be sized appropriately
so that the extreme,operational,and fatigue loads of the repowering wind turbine remain
within the design envelopes of the existing foundation and tower.Limitations on the rotor
size will also generally influence the nameplate capacity of the repowered turbines so the
generator is sized appropriately given the energythat can be developed from the rotor.As
with the development of any new wind resource,spacing between the turbines may create
operational limitations at some wind directions to address wake effects on downwind
turbines.
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.9
OCS Data Request 1.9
General (Repower)
Has the Company ever had any experience with repowering a wind project.Please
explain the Company's prior experience.
Response to OCS Data Request 1.9
The Company has not had prior experience repowering a wind project;however,
repowering is similar to installingwind turbine generators at a new wind project,with
which the Company has significant experience.Repowering is also similar to removing
and replacing wind turbine generator equipment at an existing operating wind project -
an activity that the Company routinelyperforms as part of the maintenance of its existing
wind projects.To perform the repowering projects PacifiCorp will also be contracting
with known experts in the field (General Electric and Vestas).
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.10
OCS Data Request 1.10
General (Repower)
Please provide all research,studies conducted or reviewed,memos,reports,or any other
documents of any kind that the Company possesses regarding repowering wind projects.
Response to OCS Data Request 1.10
Company employees generally keep informed of wind industrytrends -which includes
repowering -through industrygroups and trade journals,conferences,and online
information services without retaining or maintaining this information in the ordinary
course of business.Regarding specific materials that the Company has reviewed,please
refer to Attachment OCS 10.1,which includes copies of specific reports retained by the
Company.
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.11
OCS Data Request 1.11
General (Repower)
Please explain what assumptions were required in the Aurora development of wholesale
market prices and if the input assumptions were identical with those used in developing
the SO and PaR models.If any assumptions were different,please compare the
assumptions used in Aurora versus SO/PaR that were different.
Response to OCS Data Request 1.11
AuroraXmp (Aurora)is a production simulation model that produces wholesale market
price forecasts for major power hubs across the Western ElectricityCoordinating Council
(WECC).As such,it models over 5,000 existing generating units,versus less than 100
generatingunits within PacifiCorp's system as modeled using the System Optimizer (SO)
model and /or Planning and Risk (PaR)model.Aurora solves for marginal costs,by hub,
by optimizinggeneration from generatingunits across the WECC subject to operating
and transmission constraints.It is Aurora's hub-specific marginal costs that are used as
inputs to the system-specific SO and PaR models.Aurora's marginal costs by hub
therefore become an economic constraint for both SO and PaR in optimizing PacifiCorp's
system.
PacifiCorp's unit characteristics,inflation,and relevant natural gas hub prices are in sync
among models,subject to the modeling limitations of each model.However,topology,
loads,transmission,front-office transactions (FOT),reserve margins,generic resource
offerings,and hydro assumptions among Aurora and the SO and PaR models are not
comparable given differences in each model's scope and purpose.The SO model and PaR
optimize internal system-specific marginal costs,whereas Aurora optimizes WECC-wide
marginal costs.Thus many assumptions exogenous to the SO and PaR models are
endogenous to Aurora.For example,market transactions are modeled as an exogenous
resource option in the SO and PaR models.Aurora endogenouslydetermines the
forecasted price for these prospective transactions.Because the Aurora model has a
different scope and purpose than the SO and PaR models,it is not feasible,nor
appropriate,to compare assumptions used in Aurora with those used in the SO and PaR
models.
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.12
OCS Data Request 1.12
General (Repower)
Please provide a narrative explanation and supporting work papers for how the Company
modeled EIM and market depth /market transactions for this docket in SO /PaR.
Response to OCS Data Request 1.12
The market depth and market transactions in this docket are modeled in the same manner
as those used in PacifiCorp's 2017 Integrated Resource Plan (IRP).The market depth and
market transactions are affected by firm transmission in the models.For front office
transactions (FOTs),please refer to the discussion in the 2017 IRP;specifically Volume
1,Chapter 6 (Resource Options),pages 141 and 142,and Table 6.16 (Maximum
Available Front Office Transactions Quantityby Market Hub).The Company's 2017 IRP
can be accessed by using the followingwebsite link:
http://www.pacificorp.com/es/irp.html
Please refer to the Direct Testimony of Company witness,Rick T.Link,lines 374-389,
for an explanation of how the Company modeled California Independent System
Operator Corporation energy imbalance market (EIM)benefits in its wind repowering
analysis.
Please refer to Confidential Attachment OCS 1.12,which shows how the assumed
transfer capability associated with the EIM was applied to the topology used in the
System Optimizer model (SO Model)and Planning and Risk (PaR)model.
Confidential information is provided subject to Public Service Commission of Utah
(UPSC)Rules 746-1-602 and 603.
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.13
OCS Data Request 1.13
General (Repower)
Explain whether the underlyingSO and PaR databases used in this docket were identical
to the databases used in the 17-035-40 docket.If any assumptions were different,please
compare the assumptions that were different in each of the studies.
Response to OCS Data Request 1.13
The System Optimizer model (SO model)and Planning and Risk (PaR)model database
used in Dockets No.17-035-39 and 17-035-40contain identical assumptions,except
where specifically necessary to represent the repowering project or new wind and
transmission in specific simulations for these investments.
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.14
OCS Data Request 1.14
Hemstreet
Refer to lines 70 to 72 and lines 361 to 367 of Mr.Hemstreet's testimony:
(a)Please explain what analysis was conducted that led to the determination that it is
now economic to repower GoodnoeHills.
(b)Please provide all cost-benefit analyses associated with the GoodnoeHills
repowermg.
(c)Please provide the historic budgeted and actual costs for blade failures and
refurbishments over the last 10 years for the Company's owned Wyoming wind
projects,by facility.
Response to OCS Data Request 1.14
(a)The Company was able to obtain indicative turbine supply pricing and energy
production estimates for the repowering of the GoodnoeHills project.This
information,along with estimates of ongoing operations and maintenance,
administrative and general (OMAG)and capital expenditures (CAPEX),allowed the
Goodnoe Hills project to be included in the Company's economic modeling for the
repowering project.The results of this analysis are described in the Mr.Rick T.
Link's direct testimony.
(b)The Company has no financial analysis for the GoodnoeHills repowering project
other than that described in the Company's response to subpart (a)above.The
Company's economic analysis demonstrating the general benefits of wind repowering
supports repowering of the Goodnoe Hills project,as described in Company witness
Mr.Rick T.Link's testimony (Link 325-329).
(c)Please refer to Confidential Attachment OCS 1.14.
Confidential information is provided subject to Public Service Commission of Utah
(UPSC)Rules 746-1-602 and 603.
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.15
OCS Data Request 1.15
Hemstreet
Refer to lines 305 to 308 and lines 312 to 314 of Mr.Hemstreet's testimony:
(a)Does the Company currentlyhave any long-term service agreements in place for
maintenance of owned wind facilities?
(b)Will the Company be contracting for Long Term Service Agreements for service of
the repowered facilities?
Response to OCS Data Request 1.15
(a)Yes,the Company has long-term maintenance service agreements in place at each of
its owned wind facilities.
(b)Yes,the Company anticipates that it will continue to contract for operations and
maintenance of its wind projects through long-term service agreements following
repowermg.
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.16
OCS Data Request 1.16
Hemstreet
Refer to lines 321 to 325 of Mr.Hemstreet's testimony:
(a)Have there been any pre-repowering generation decreases due to component failures
at this time?
(b)Are there any turbines that have already been idled in anticipation of repowering?
(c)Explain how the pre-repowering generation impacts discussed at line 325 were
factored into the Company's repowering economic analysis.
(d)At line 321,the Mr.Hemstreet states that it would be more economic to idle the
turbines than to repair given the short period before repowering.Will,in fact,an
economic analysis be performed when a turbine failure occurs or has the Company
already made the decision that it will not perform the necessary repair while it waits
to repower the turbines?
Response to OCS Data Request 1.16
(a)As of July 25,2017,the Company has not yet experiencedpre-repowering generation
decreases due to component failures that cannot be economically returned to service
before repowering.
(b)As of July 25,2017,no turbines have been idled in anticipation of repowering.
(c)Please refer to the direct testimony of Company witness,Rick T.Link;specifically
Exhibit RMP_(RTL-3),which shows the net (benefit)/cost for each of the nine
scenarios referenced in Mr.Link's direct testimony.The change in net power costs
(NPC)shows an increase in NPC in the first three years as a result of the pre-
repowering generation impacts discussed at line 325 of direct testimony of Company
witness,Timothy J.Hemstreet.The impact of any lost production tax credits (PTC)is
included in the "Cost of Project"line.
Please also refer to the confidential work papers filed with Mr.Link's direct
testimony;specifically the folder titled "Exhibits Figures Tables,"the file titled
"Repower Results Direct Testimony.xlsm."
Among other things,this file contains the calculations used to produce the data in
Exhibit RMP (RTL-3).The worksheet labeled "Price-Policy Annual -PaR"shows
the change in expected energy associated with the wind repowering project (i.e.,for
the medium natural gas and medium carbon dioxide (CO2)SCORSTIO,the change in
energy is shown in row 51 of this worksheet).These data represent the change in
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.16
energy as modeled in the Company's economic analysis.The change in energy is the
same for each price-policy scenario (i.e.,the values are identical in rows 51,150,249,
etc.).These data show that there is an assumed net reduction in incremental energy
under the repowering simulation for the period 2017 through 2019.
(d)An economic analysis will be performed to evaluateeach turbine failure to determine
whether the turbine can economically be returned to service before repowering.The
Company has not made a blanket determination that turbine failures will not be
addressed before repowering.
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.17
OCS Data Request 1.17
Hemstreet
Refer to lines 388 to 410 of Mr.Hemstreet's testimony:
(a)With respect to the additional features that improve reliability for the repowered
facilities,will those features also be added to the new turbines contemplated in the
17-035-40 docket?Are these features unique to a single WTG or are these features
added to a set of WTGs or the System as a whole?Please explain.
(b)Please provide a technical explanation of how the two additional features work and
improve reliability,and explain how the WindFREE Reactive Power feature can
"often exceed -the performance of a conventional (non-wind)power plant".
(c)Please explain how even when wind turbines are not generatingactive power,they
can provide reactive power.
Response to OCS Data Request 1.17
(a)The location and type of the new proposed turbines in Docket No.17-035-40 are
currentlyunknown.Therefore,no large generator interconnection parameters or
system impact data are available to determine potential benefits of these features to
the grid.As this information becomes available,the benefits of these features will be
evaluated.
These features are unique to a single wind turbine generator (WTG)and could be
added to some or all of the WTGs.
(b)The WindFREE feature provides reactive power even when there is no active power
generation(wind speed below cut-in or cut-out).A conventional non-wind power
plant is not capable of providingVAr support if the unit is not generatingbut the
WindFREE feature benefits the grid by providingvoltage support even when the
turbines are not generating real power.The WindINERTIA feature provides inertia
response to help stabilize grid frequency.This feature supports the grid during under
frequency events by providinga temporary increase in power production for a short
duration,contributing towards frequency recovery.This is achieved by tapping into
the stored kinetic energy in the rotor mass.
(c)Supply of reactive power is achieved by using capabilities of the line-side converter.
Since the converter is connected to the grid even when the WTG is not generating,
voltage regulation and VAr support is independentof the WTG generatingreal active
power.
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.18
OCS Data Request 1.18
Hemstreet
See Hemstreet,beginning at line 410 "The provision of continued voltage support and
regulation provides grid benefits not possible with conventional generation,while
mitigating adverse voltage impacts of wind turbines being off-line due to wind
conditions.This feature can eliminate the need for grid reinforcements specifically
designed for no-wind conditions,and may allow for more economic commitment of other
generatingresources that will enhance grid security by reducing the risk of voltage
collapse".
(a)Provide a technical explanation of what that sentence means.
(b)Why can wind turbines provide grid benefits from the provision of continued voltage
support and regulation that are not possible with conventional generation?Please
explain.
(c)How can wind turbines provide these benefits when the wind does not blow
particularlygiven that the Company believes that wind turbines provide grid benefits
that are not possible with conventional generation?
(d)What grid reinforcements would have to be made that can be avoided by these
enhancements that would be needed for the no-wind conditions?
Response to OCS Data Request 1.18
(a)WindFREE provides continued voltage support even when the wind turbine generator
(WTG)is not generating real power due to wind speed below cut-in or cut-out
conditions.This is not possible with conventional non-wind generation.Without the
WindFREE feature,to support system voltage under no wind condition,the Company
may be required to place other resources such as thermal or hydro generators on line
even if market/fuel conditions are not economical.
(b)As explained in the Company's response to subpart (a)above,WindFREE can
provide voltage support even if the WTG is not generating active power.This is not
possible with conventional generation.
(c)With WindFREE feature the reactive power is supplied to the grid utilizing
capabilities of the line-side converter which is connected to the grid even when the
generator itself is not on line.
(d)Typically to provide reactive power to the grid for voltage control,capacitor banks,
static VAr compensators or synchronous condensers are installed.The WindFREE
minimizes the need for these components.Similarly,to address under-frequency
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.18
conditions on the grid,load shedding schemes are implemented.The WindINERTIA
feature would minimize load shedding by increasing power generationfor a short
period of time to respond to under-frequency conditions.
Also,please refer to the Company's response to OCS Data Request 1.17.
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.19
OCS Data Request 1.19
Hemstreet
See Hemstreet at line 431.
(a)Explain how these features will improve transmission system reliability and
compared to what?
(b)Is this to suggest that the System would be operated less reliablywithout these new
features,or that it would be more-costly to operate the System reliably without these
new features?Can this benefit be quantified?
(c)Please explain exactly how these new features would defer the need to add
synchronous condensers or static VAr compensators,and under what conditions,at a
later time,would the Company have to add these components?
Response to OCS Data Request 1.19
(a)The addition of WindFREE and WindINERTIA options of the General Electric
International,Inc.(GE)wind turbines will improve system reliabilityby providing
system voltage support during low or no wind conditions and frequency support
without initiating load shedding.The WindFREE feature provides reactive power
even when there is no active power generation (wind speed below cut-in or cut-out).
A conventional non-wind power plant is not capable of providing VAr support if the
unit is not generatingbut the WindFREE feature benefits the grid by providing
voltage support even when the turbines are not generatingreal power.The
WindINERTIA feature provides inertia response to help stabilize grid frequency.This
feature supports the grid during under frequency events by providing a temporary
increase in power production for a short duration,contributingtowards frequency
recovery.This is achieved by tapping into the stored kinetic energy in the rotor mass.
(b)Operating the System reliablywould be more costly without the WindFREE and
WindINERTIA options.Similar system performance improvements would require
addition of synchronous device(s)that would dynamicallycontrol voltage and
frequency.In comparing the cost (dollars per kilovolt ampere reactive ($/kVAr))of
stand-alone voltage control (synchronous condenser)versus addition of the
WindFREE technology,the stand-alone voltage control cost would be more
expensive than the price of implementing WindFREE technology on a given wind
farm.
(c)Reactive output from wind farms that include WindFREE technology can be
coordinated by using advanced control methods to control voltage in a centralized
location.This technology is planned to provide voltage control in the Aeolus area and
should defer the need for stand-alone voltage control device in this area for the
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.19
Energy Gateway D.2 system configuration.This technology should provide needed
voltage support during steady-state and line outage conditions.
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.20
OCS Data Request 1.20
Hemstreet
What is the cost of these two new reliability features,and would the repowered turbines
still be economically viable without the new features?Please explain.
Response to OCS Data Request 1.20
The requested cost information is considered highly confidential and commercially
sensitive.The Company requests special handling.Please contact Bob Livelyat (801)
220-4052 to make arrangements for review.
The repowered turbines would still be economically viable without the two new
reliabilityfeatures.The Company's economic analysis accounts for the costs of these
new features,but has yet to account for the benefits,which are anticipated to outweigh
the costs.A direct estimate of the benefits of these reliability features will require the
completion of transmission system impact studies (SIS)currentlyunderway by the
Company.
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.21
OCS Data Request 1.21
Hemstreet
Please provide the Company's most recent wind integration cost study,and indicate if
these new reliabilityfeatures were accounted for in the development of the integration
costs.If the reliabilityfeatures were accounted for,please explain what was done,if not,
please explain why not,and explain how the Company expects that the reliabilityfeatures
would affect the determination of the integration costs.
Response to OCS Data Request 1.21
The Company's most recent wind integration costs were calculated as part of the 2017
Integrated Resource Plan (IRP)and the associated Flexible Reserve Study is included in
Appendix F of the 2017 IRP.The study is available at:
http://www.pacificorp.com/content/dam/pacificorp/doc/Energy Sources/Integrated Reso
urce Plan/2017 IRP/2017 IRP VolumeII 2017 IRP Final.pdf
The Flexible Reserve Study calculates the reserve requirements and costs associated with
balancing variations in load,wind,solar,and non-variable resources to maintain
PacifiCorp's system reliablyand comply with North American Electric Reliability
Corporation (NERC)reliabilitystandard BAL-001-2,requirement 2.Under this standard,
the area control error (ACE)for each of the Company's balancing authorityareas (BAA)
is required to remain within specified dynamic limits,based on the frequency of the
interconnect as a whole.If the Company's ACE goes outside these boundaries,the
Company must bring ACE back within the boundaries within 30 minutes by dispatching
additional resources or curtailingload.The study identifies the dispatchable capacity that
must be set aside to account for unexpected changes.
The reliabilityfeatures identified in Company witness TimothyJ.Hemstreet direct
testimony address reliabilityrequirements pertaining to local voltage limits and short-
duration frequency excursions,and were not within the scope of the Flexible Reserve
Study as neither of the referenced reliabilityfeatures would be addressed by setting aside
additional dispatchable capacity.
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.23
OCS Data Request 1.23
Hemstreet
Please refer to lines 546 to 551 of Hemstreet's testimony,how did the Company
determine the schedule and order for re-powering facilities?Please explain.
Response to OCS Data Request 1.23
The Company determined the schedule by first seeking to complete as much of the
repowering in 2019 -a year before the December 31,2020 deadline for commercial
operation of the projects.Because a 2019 in-service date would truncate the existing
production tax credit (PTC)window at the Dunlap I project (original commercial
operation date (COD)of October 1,2010),the Dunlap I project,repowering was delayed
until 2020 to maximize customer benefits available from the original 10-year period of
PTCs.Given the number of turbines (126 wind turbine generators (WTG))to be
repowered at the Glenrock/RollingHills project sites,construction of that project was
scheduled to begin in March 2019 (the beginning of the construction window)and run
through September 2019.To reduce overlap between the projects and reduce demands on
limited crane resources,the Seven Mile Hill 1/Seven Mile Hill 2 and High
Plains/McFadden Ridge 1 projects (164 WTGs in total)were scheduled to be constructed
sequentially in 2019,also beginning at the start of the construction window in March.
Since the PTCs from original construction of the Seven Mile Hill 1/Seven Mile Hill 2
projects (original COD of December 31,2008)will have expired at the beginning of
2019,that project was scheduled first.The PTCs from original construction of the High
Plains and McFadden Ridge 1 projects (original CODs of September 13,2009,and
September 29,2009,respectively)can also be maximized with this sequencing,while
still completing construction before the close of the construction window in November
2019.
For the Marengo 1/Marengo 2 projects,the size of the project (117 WTGs)also resulted
in construction for the entire construction season to obtain a 2019 COD.The Goodnoe
Hills and Leaning Juniper projects were both scheduled for construction in the summer of
2019 during the period with favorable conditions for wind construction.
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.24
OCS Data Request 1.24
Hemstreet
Please refer to TJH-3,page 1,columns F and I.
(a)If the Company's request to re-power is granted and work is completed as
contemplated,what additional capacity will be acquired for reserve margin
calculations?Please add to this table the capacity contribution used in the evaluation
of reserve margin,both before repowering,and after.
(b)Does the Company anticipate the capacity contribution for wind and/or LOLP to
change based on new transmission capacity,advancements in wind technologies and
reliabilityfeatures"as discussed starting at Hemstreet line 388,or EIM benefits
associated with efficient use of transmission?Please explain.
Response to OCS Data Request 1.24
(a)PacifiCorp's base analysis assumes the repoweredwind facilities continue to operate
within their existing large-generatorinterconnection agreements (LGIA).
Consequently,this base analysis assumes that there is no incremental capacity
associated with repowered wind facilities,and therefore,assumes no additional
capacity would apply toward meeting the 13 percent planning reserve margin (PRM).
As part of its filing,PacifiCorp performed a sensitivitystudy assuming the repowered
facilities are able to operate at their full generatingcapability,providingadditional
capacity and energy to the Company's system (please refer to the direct testimony of
Company witness Rick T.Link,lines 76 through 79,295 through302,and 760
through774).
For this sensitivitystudy,the incremental capacity that applies toward meeting the
13 percent PRM is the difference between the data in the column labeled "Future
Project Capacity (MW)"and "Current Project Capacity (MW)"within Confidential
Exhibit RMP_(TJH-3),multipliedby a 15.8 percent capacity contribution value for
repowered wind facilities located in Wyoming and multipliedby an 11.8 percent
capacity contribution value for repowered wind facilities located in Washington and
Oregon.The capacity contribution values for wind resources is the same as assumed
in PacifiCorp's 2017 Integrated Resource Plan (IRP),Volume I,Chapter 5,Table
5.13 at page 88.These same capacity contribution values would apply to current
project capacity before repowering.The Company's 2017 IRP is publicly available
and can be accessed by using the followingwebsite link:
http://www.pacificorp.com/es/irp.html
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.24
(b)PacifiCorp has not updated its capacity contribution study,and therefore,has not
produced loss-of-load-probability (LOLP)analysis to assess how capacity
contribution values for wind resources might be impacted by new transmission
capacity,advancements in wind technologies and reliabilityfeatures,or California
IndependentSystem Operator Corporation energy imbalance market (EIM)benefits.
There are many factors that can influence capacity contribution values beyond those
identified in this data request,and it is not feasible to reasonablyanticipate how
capacity contribution values might change in an updated analysis.Even with these
limitations,when isolated from other factors,repoweredwind units have a higher
capacity factor and an increased opportunityto contribute system energy during high
LOLP hours.
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.25
OCS Data Request 1.25
Hemstreet
Please refer to TJH-3,page 2,columns D and E.
(a)Please provide supporting work papers or historic data used to derive the Current
Long-Term Generation (MWh)in Dl2:D:29.
(b)Please provide supporting work papers or engineering study documentation for the
Turbine Generation Increase (%)values provided in E12:E29.
(c)Please provide supporting work papers or engineering study documentation for the
Turbine Generation Increase (%)values provided in Il2:I29.
Response to OCS Data Request 1.25
(a)Please refer to Confidential Attachment OCS 1.25,as well as the Company's
response to DPU Data Request 1.5.
(b)Please refer to the Company's response to DPU Data Request 1.9.
(c)Please refer to the Company's response to DPU Data Request 1.9.
Confidential information is provided subject to Public Service Commission of Utah
(UPSC)Rules 746-1-602 and 603.
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.26
OCS Data Request 1.26
Hemstreet
As a general matter,for any column in TJH-3,either on page 1 or page 2,in which the
Company has additional work papers that have not alreadybeen provided,and that were
used in the derivation of the data,such as the derivation of the Project In-Service Dates,
please provide those additional work papers,electronically,with all formulas intact.
Response to OCS Data Request 1.26
The requested information is considered highly confidential and commercially sensitive.
The Company requests special handling.Please contact Bob Livelyat (801)220-4052 to
make arrangements for review.
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.27
OCS Data Request 1.27
Link
Please refer to Mr.Link's testimony.Please provide a detailed reconciliation and a
detailed cost breakdown (work papers used in the derivations of the estimates)of the
followingcosts:
(a)Link testimony line 93:purchased safe-harbor equipment in Dec 2016 for $77.8
million.
(b)Link testimony line 341:upfront investment of $1.13 billion.For reconciliation
purposes,is the $77.8 million part of the $1.13 billion?
(c)RTL-1:capital costs in cells G25:G36 by facility.Please confirm that these values
are consistent with the $1.13 billion at line 341 of Mr.Link's testimony.
(d)$52,640,700 referenced in the January 13,2017 letter to the Commission.Again,is
this part of the $1.113 billion?
Response to OCS Data Request 1.27
(a)The requested information is considered highly confidential and commercially
sensitive.The Company requests special handling.Please contact Bob Livelyat (801)
220-4052 to make arrangements for review.
(b)Yes,the $77.8 million is included within the $1.13 billion.Additional information is
considered highly confidential and commercially sensitive.The Company requests
special handling.Please contact Bob Livelyat (801)200-4052 to make arrangements
for review.
(c)Yes,the $1.13 billion referenced at line 341 of Mr.Link's testimony is the sum of the
capital costs for the individual pro ects in cell G25:G36 of Exhibit RMP (RTL-1).
Additional information is considered highly confidential and commercia sensitive.
The Company requests special handling.Please contact Bob Livelyat (801)200-4052
to make arrangements for review.
(d)The Company assumes that the reference in this subpart to "$1.113 billion"was
intended to reference "$1.13 billion".Based on the foregoing assumption,the
Company responds as follows:
Yes,this is part of the $1.13 billion.For a reconciliation,please refer to the
Company's response to subpart (a)above.
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.28
OCS Data Request 1.28
Link
Refer to lines 337 to 343 of Mr.Link's testimony.Please provide a side by side
comparison of the assumptions used in the re-powering analysis updated since the 2017
IRP.
(a)Price-policy assumptions.
(b)Up-front capital costs.
(c)Run-rate operating costs.
(d)Energy output for both the existing and repowered wind facilities.
(e)Any other significant assumptions that changed between the two studies,including
fuel costs,load forecast,etc.
Response to OCS Data Request 1.28
Please refer to Attachment OCS 1.28 -1 and Attachment OCS 1.28 -2,as well as
Confidential Attachment OCS 1.28 -3 through Confidential Attachment OCS 1.28 -5.
Confidential information is provided subject to Public Service Commission of Utah
(UPSC)Rules 746-1-602 and 603.
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.29
OCS Data Request 1.29
Link
Please explain how the Company stepped from the 2017 IRP preferred portfolio to the
"repower"and base (no projects)cases provided in this docket.Please provide a listing
of assumptions that varied between the 2017 IRP preferred portfolio and the
"repowering"and "base (no projects)"cases provided in this docket.
Response to OCS Data Request 1.29
Please refer to Company's responses OCS Data Request 1.28 and OCS Data Request
1.39.
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.30
OCS Data Request 1.30
Link
Refer to line 352 of Mr.Link's testimony.
(a)Did the Company model the 36.5 MW reduction in transfer capacity in its IRP
analysis?If not,why not?
(b)Does the Company currentlymodel this reduction in GRID?If not,why not?
(c)Does the Company's PaR analysis reflect an equivalent expected transfer capability?
Does the PaR model perform iterations reflecting variability and potential
unavailabilityof this transmission?If not,why not?
Response to OCS Data Request 1.30
(a)Yes.
(b)At present,the Generation and Regulation Initiative Decision Tool (GRID)reflects
PacifiCorp energy supply management's long-term firm reservations,plus short-term
firm and non-firm reservations based on history.The only path which is derated for
outages within GRID is the California-Oregon Intertie (COI)between West Main and
the California-Oregon Border market,which reflects historical derates.Derates on the
COI path are frequentlya substantial portion of the reserved capacity.While derates
of firm reservations can occur on many paths,they are generally relativelysmall or
infrequent and as a result have not previouslybeen quantified for inclusion in GRID.
(c)Yes.The planning and risk (PaR)model reflects the expected transfer capability
assuming a 36.5 megawatts (MW)de-rate on the existing 230 kilovolt (kV)
transmission system as stated in Mr.Link's testimony..PaR is not capable of
modeling variability and potential unavailabilityof transmission as a stochastic
variable.
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.31
OCS Data Request 1.31
Link
Refer to lines 382 to 389 of Mr.Link's testimony.Please confirm that EIM benefits of
more efficient use of transmission are accounted for in all cases studied,both under the
scenarios with and without repowering,and provide a step by step explanation of the
methodology that was used to incorporate modeling of EIM benefits.
Response to OCS Data Request 1.31
The Company confirms that the energy imbalance market (EIM)benefits of more
efficient use of transmission are accounted for in all cases,with and without repowering.
As shown on lines 382 to 389 in the direct testimony of Company witness Rick T.Link,
this benefit was modeled as 300 megawatts (MW)of additional transmission capability
from the Jim Bridger plant to south-central Oregon.This increase in transmission path
capacity was incorporated in all cases,with and without repowering.Please also refer to
the Company's response to OCS Data Request 1.12.
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.32
OCS Data Request 1.32
Link
Refer to line 196 of Mr.Link's testimony.Did the System Optimizer select repowering
as a resource alternative(s),or was the re-powering assumption for that case "locked in"
and the model filled in resources around that decision to then compare to other cases?
Please explain.
Response to OCS Data Request 1.32
In the simulations that include the wind repowering project,the repowered wind
resources were "locked in".For these simulations,the System Optimizer (SO)model then
endogenouslychooses the least-cost mix of all other resources in the portfolio.
It is not feasible to configure wind repowering projects as a new supply-side resource
option for endogenous selection by the SO model.Wind repowering reflects
modifications to existing generating facilities that resets the facility's life,modifies the
facility's expected wind generation output profiles,changes production tax credit (PTC)
eligibility,and changes operating costs.The SO model is not well-equipped to capture
these types of modifications to existing generating facilities endogenously.
Consequently,the Company developed a methodology to capture the economic impact of
the wind repowering project by calculating the change in forecasted system costs between
a portfolio with and without the wind repowering project.For any give price-policy
scenario,any simulation where the present-valuerevenue requirement (PVRR)with the
wind repowering project is lower cost than the PVRR in those simulations without the
wind repowering project demonstrates wind repowering is part of the least cost resource
mix.
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.33
OCS Data Request 1.33
Link
In this proceeding or the IRP,were the Repowering Resources ever set up as an Option
that could be selected if economic as part of the System Optimizer runs?If so,please
explain when,and how it was setup,and what the results were,and if not,please explain
why this was never done.
Response to OCS Data Request 1.33
Please refer to the Company's response to OCS Data Request 1.32.PacifiCorp has not
performed any simulations with endogenous selection of wind repowering.
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.34
OCS Data Request 1.34
Link
For the input files provided in the SO Model Inputs-Outputs.zipand the PaR Inputs-
Outputs.zip files that accompanied Mr.Link's work papers,there must have been
spreadsheets that were created that analyzed information and created the model inputs.
These spreadsheets would have been used to analyze information such as generating
resource characteristics,fuel costs,capital costs,load data,transmission topology map
and transfer capacities,CO2 emission rates,renewableresource characteristics,market
data,transaction data,and any other data important to study performed.Please provide
the supporting work papers that were used to develop and format the input values.
Response to OCS Data Request 1.34
The Company provided 50+work papers for inputs specific to the wind repowering cases
and related sensitivities with the confidential work papers supporting the direct testimony
of Company witness,Rick T.Link,in the folders entitled "Other Summary Reports"and
"Wind Projects."
The purpose of the work papers is to develop the inputs entered into the models.The
inputs are shown formatted for data entry.As an example,refer to the "Gateway"
worksheet in the folder entitled "Other Summary Reports,"the file entitled
"Gateway_IRP Data.xlsx."The table appearing in columns T through Y is labeled
"Model Input."The appropriate values in this table are entered directly from this
worksheet into the model.
All data not specific to updates made for Dockets No.17-035-39 (Repowering)and 17-
035-40 (Energy Vision 2020 (New Wind/New Transmission)are the same values as
developed for the Company's 2017 Integrated Resource Plan (IRP).Please also refer to
the Company's response to OCS Data Request 1.5.
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.35
OCS Data Request 1.35
Link
Refer to lines 473 to 474 of Mr.Link's testimony.Did the Company perform a
retirement study to optimize the timing of Dave Johnston retirement?Please provide the
Company's analysis that determined 2027 as the retirement date,and all supporting work
papers,SO,PaR,spreadsheet,or otherwise regarding this determination.
Response to OCS Data Request 1.35
The United States Environmental Protection Agency's final regional haze Federal
Implementation Plan requires the installation of selective catalytic reduction (SCR)
equipment at the Company's Dave Johnston Unit 3 by 2019,or in lieu of installing SCR
equipment,a commitment to retire the Dave Johnston Unit 3 by 2027,which coincides
with the currentlyapproved depreciablelife of the Dave Johnston plant.In the
Company's 2015 Integrated Resource Plan (IRP),PacifiCorp analyzed the option of
installingSCR equipment on Dave Johnston Unit 3 by 2019 versus retiring the unit by
2027.Results from this study were provided in the Company's Confidential Volume III
of the 2015 IRP,provided as Confidential Attachment OCS 1.35,and demonstrated that it
is more economical to continue to operate and retire by 2027.Consistent with this
analysis for Dave Johnston Unit 3 and assumptions used to develop the 2017 IRP,
PacifiCorp continues to assume that the Dave Johnston plant retires at the end of its
depreciablelife.
Confidential information is provided subject to Public Service Commission of Utah
(UPSC)Rules 746-1-602 and 603.
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.36
OCS Data Request 1.36
Link
Refer to lines 69-71,466 -467,and Table 1 of Mr.Link's testimony.
(a)How was the Company's inflation rate assumption determined for PTC and the
levelization calculations (revenue requirement,gas forecast in Table 1)?Please
explain.
(b)Please provide all alternative inflation rate assumptions considered or reviewed
during the 2017 IRP process or in conjunctionwith developing this filing.In other
words,if there is an inflation rate associated with a gas forecast provided in
Confidential Exhibit 2,please provide that inflation rate.
(c)Please confirm that the inflation rate used for PTC,gas and CO2 forecasting,and
revenue requirement levelization are consistent.
Response to OCS Data Request 1.36
(a)PacifiCorp maintained the same 2.22 percent inflation rate assumption it used in its
2017 Integrated Resource Plan (IRP).This inflation rate is derived from PacifiCorp's
official inflation curve,which is updated on a quarterlybasis.The official inflation
curve is a 50/50 blend of the gross domestic product (GDP)deflator and consumer
price index (CPI)projections developedby IHS Global Insights.The 2.22 percent
inflation rate is the average of the blended GDP deflator and CPI projection over the
2017 through 2036 forecast time frame and is based on GDP deflator and CPI
projects from PacifiCorp's official inflation curve developed in September 2016.
Levelized prices in Table 1 of the Direct Testimony of Company witness,Rick T.
Link are derived from a nominal gas price forecast using a nominal discount rate,not
an inflation rate.PacifiCorp uses nominal inflation rates from its official inflation
curve to convert third-partyforecasts in real dollars to nominal dollars.This nominal
inflation curve is based on the most recent current inflation forecast available at the
time the official forward price curve (OFPC)containing natural gas and power prices
is produced.
(b)Please refer to Confidential Attachment OCS 1.36.
(c)Please refer to the Company's response to subparts (a)and (b)above.
Confidential information is provided subject to Public Service Commission of Utah
(UPSC)Rules 746-1-602 and 603.
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.37
OCS Data Request 1.37
Link
Refer to lines 488 -490 of Mr.Link's testimony,please provide a narrative explanation
as to how the extension is computed.Please identify where this calculation was
provided,or provide supplemental work papers with formulas to derive these values.
Response to OCS Data Request 1.37
Please refer to lines 457 through 470 in the direct testimony of Company witness Rick T.
Link,for an explanation of how the extended benefits beyond the 20-year forecast are
computed.The computations were provided with the confidential work papers supporting
Mr.Link's direct testimony,specifically the folder entitled "Exhibits Figures Tables",the
file entitled "Repower Results Direct Testimony.xlsm".
Within this document,please refer to the "Price-Policy Annual -PaR"worksheets.For
each case,there is a table (in red)entitled "PVRR(d)(Benefit)/Cost:Nom 2050"(e.g.,
row 87 for the "Medium Gas,Medium CO2"CRSe)where the calculation is performed.
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.38
OCS Data Request 1.38
Link
Please provide the peak and energy load forecasts used in each S.O and PaR run studying
repowering as well as the forecasts used in the preferred 2017 IRP portfolio.
Response to OCS Data Request 1.38
Please refer to Attachment OCS 1.38.This information was included on the public data
disks that accompanied PacifiCorp's 2017 Integrated Resource Plan (IRP).
Note:in Attachment OCS 1.38,column D provides the annual energy load forecast,and
column J provides the annual coincident peak forecast used in each system optimizer
model and planning and risk model run used for analyzing repowering as well as the
forecast used in the 2017 IRP preferred portfolio.
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.39
OCS Data Request 1.39
Link
Refer to the 2017 IRP page 309 (FS-REP final selection fact sheet).Please provide the
work papers and explanation for each of the system optimizer costs included in the
Portfolio Summary Table,and explain if these costs are consistent with those used in
modeling the cases used in this application.If they are not consistent,please provide this
fact sheet for the application,and explain the differences.Please address the following
specifically:
(a)System cost without transmission upgrades ($22,907 m PVRR).
(b)Transmission integration ($123 m PVRR).
(c)Transmission reinforcement ($12 m PVRR).
(d)Total cost ($23,042 m PVRR).
(e)Total cost thru 2050 ($22,78lm PVRR).
Response to OCS Data Request 1.39
Please refer to Attachment OCS 1.39.
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.40
OCS Data Request 1.40
Link
Please refer to "RePower Data 20170516 LGIA Limit vl3.xlsx":
(a)Please provide historic O&M costs consistent with those forecasted on the "O&M"
tab for all facilities on this page.Please provide historic data since in-service,and
include every year of operation.
(b)Please explain if the OMAG rows (16 and 33)are intended to be blank in the tabs of
this file.Please explain if all OMAG costs are embedded in the Fixed OM rows (12
and 29).Please explain.
(c)Does the Company believe annual OM expenses will be the same after re-powering
as with the Status Quo?Please explain.
Response to OCS Data Request 1.40
(a)Please refer to Attachment OCS 1.40.
(b)Operations and Maintenance,Administration and General (OMAG)is represented in
rows 12 and 29,labeled as "Fixed O &M".It is correct that the rows labeled
"OMAG"are intended to be blank.
(c)No.The Company anticipates differences between status quo and repower OMAG
costs,as represented in the differences between rows 12 and 29 beginning in 2019
(column G).
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.41
OCS Data Request 1.41
Larsen
Refer to line 286 -289 of Mr.Larsen's testimony.Please clarify if /how the loss of
PTC's will be included in the EBA.
Response to OCS Data Request 1.41
The Company clarifies lines 286 through 289 in the direct testimony of Company witness
Jeffrey K.Larsen,as follows:
The loss of associated production tax credits before repowering will not flow through the
Utah Energy Balancing Account because they are included in base rates and the impact of
expired PTCs will be borne entirelyby the Company.The cost of replacement generation
before and during repowering will result in increased net power costs,which will flow
through the EBA.
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.42
OCS Data Request 1.42
Larsen
Refer to line 289 of Mr.Larsen's testimony.Please explain if there is any reason that
would prevent the Company from filing a rate case,and if such a rate case could mitigate
the impact of the current PTC's ending.
Response to OCS Data Request 1.42
The Company is not aware of any restrictions prohibitingthe Company from filing a rate
case.Whether,and to what extent,a rate case could mitigate the impact of current
production tax credits ending would depend on the timing of the rate case,the test period
used,and the rate effective date.
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.43
OCS Data Request 1.43
Larsen
Refer to lines l 14 -129 of Mr.Larsen's testimony.Please quantifythe costs,benefits,
and net benefits that would flow to rate-payers and shareholders with and without RTM.
Also for comparison purposes,please quantifythe costs,benefits and net benefits that
would flow to rate-payers and shareholders with and without rate-cases filed when the re-
powering investment was completed and again when the new PTC's expire.
Response to OCS Data Request 1.43
Please refer to Exhibit RMP_(JKL-2),line 19,Revenue Requirement,which shows the
total-company and Utah-allocated share of the incremental revenue requirement from
wind repowering for years 2019 through 2022.The revenue requirement components that
make up the amounts on line 19 are shown on lines 1 through 18.
The Utah-allocated share of net power costs (NPC)incremental savings that will be
returned to customers through the energy balancing account (EBA)is shown on line 22,
EBA pass-through,and is therefore subtracted from line 19 to show the remaining
revenue requirement that will flow through the Resource Tracking Mechanism (RTM),
subject to the proposed cap as described in footnote 5.Without an RTM,the Company
would receive the costs and benefits shown on line 23,Revenue Requirement after EBA
pass-through,and the customers would receive the NPC incremental savings through the
EBA.
As the repowering projects are placed in service,the RTM will true-up customer rates to
account for actual production tax credit (PTC)values that are different than the amount
included in base rates,includingany adjustment necessary to eliminate the PTC benefit
from rates when the PTC expire after 10 years.
Please refer to lines 258 through 280 in the direct testimony of Company witness Jeffery
K.Larsen for a further detailed description of how PTCs will be included in the RTM.
When the repowering investment is completed,all repowering costs,benefits and net
benefits included in general rate cases will not be included in the RTM calculation;thus
avoiding any double counting in customer rates.Once all repowering costs and benefits
are included in rates,the RTM and the associated cap will no longer be applicable except
for the annual PTC true-up.Other than the difference that may be created by applying the
cap under the RTM,customers would receive the same repowering costs and benefits
with and without rate cases,and the shareholders would receive the same return on
repowermg mvestment.
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.43
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.44
OCS Data Request 1.44
Larsen
With regard to JKL-3 and JKL-4,please provide a more detailed narrative explanation of
how the rider works with regard to net power costs,and how the rider works in
conjunctionwith the EBA proceeding.Also,with the understandingthat the EBA does
nothing more than true-up the actual costs that PacifiCorp incurred,and the actual
revenues PacifiCorp received,why has the Company proposed to have a Net Power Cost
Incremental Savings calculation as part of the RTM rider?
Response to OCS Data Request 1.44
The Company proposes that the incremental savings in net power costs (NPC)from
repowering be reflected with other NPC in the energy balancing account (EBA),thus
passing the repowering NPC savings to customers through the EBA.Please refer to lines
229 through 257 in the direct testimony of Company witness,Jeffery K.Larsen for a
detailed description of how the Resource Tracking Mechanism (RTM)would recover any
repowering NPC incremental savings should the EBA be modified such that less than 100
percent of the incremental NPC benefits is credited to customers through the EBA.
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.45
OCS Data Request 1.45
Larsen
With regard to JKL-3 confirm and clarify:
(a)Actual Net Power Costs are computed based on the annual costs and by definition
would already account for reduced costs (benefits)due to wind-repowering,correct?
(b)Is the Company suggesting that the EBA Actual NPC will be adjusted upward in the
EBA Docket to a level that was expected without re-powering,so that the net power
cost savings could be assigned and tracked through the RTM?It appears that this
process could be burdensome,and why would it be desirable to go through this
effort?
(c)Aside from the inclusion of NPC benefits in the RTM,is the main result of
implementing the RTM a cost recovery mechanism for the capital projects and the
PTC impacts?
(d)The company intends to "cap"the costs recovered through the RTM at a level
equivalent to the derived savings,correct?
(e)Will all Customers be subject to this RTM?Please provide detailed explanation as to
which classes and special customers will or won't be a part of this rate schedule.
(f)Please explain if/how capping the RTM would imply the capped balance would be
carried monthlyat the annual simple interest rate of 6%that ratepayers would have to
pay.
Response to OCS Data Request 1.45
(a)Yes.As currentlyconstructed,the energybalancing account (EBA)would return to
customers 100 percent of the repowering net power cost (NPC)benefits.
(b)No.The Company proposes to put in place the Resource Tracking Mechanism (RTM)
to return 100 percent of the repowering incremental NPC benefits should,at some
future date,the EBA structure get modified such that less than 100 percent of the
incremental benefits is credited to customers through the EBA.Please refer to lines
229 through 257 in the direct testimony of Company witness,Jeffrey K.Larsen for a
detailed description of how the RTM would recover any repowering NPC incremental
savings should the EBA be modified such that less than 100 percent of the
incremental NPC benefits is credited to customers through the EBA.
(c)The NPC benefits will flow through the RTM only to the extent that the EBA,as
currentlyconstructed,is modified such that less than 100 percent of the incremental
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.45
benefits is credited to customers through the EBA.The RTM is intended to return
100 percent of the net benefits to customers,includingthe costs and benefits as
shown in Exhibit RMP_(JKL-3),lines 1 through 19,subject to the cap as described
in footnote 4.
(d)Please refer to Mr.Larsen's Direct Testimony,lines 40 through 43 and Exhibit
RMP_(JKL-3),footnote 4.
(e)Please refer to Exhibit RMP_(JKL-5),page 6 of 6,for a listing of schedules that
may be subject to the RTM Rate Adjustment.The determination of rates adjustments
will be addressed as part of future regulatory rate reviews.
(f)The proposed capping of the RTM will not result in the amount above the cap being
included in the deferral balance,and will therefore not receive a carrying charge.
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July 31,2017
OCS Data Request 1.46
OCS Data Request 1.46
Larsen
To accomplish the Company's objective in introducing the RTM tariff,which is provided
as JKL-5,wouldn't there need to be a complimentary adjustment to the EBA tariff,
Schedule 94?If so,why didn't Mr.Larsen discuss that and provide the adjustment to
Schedule 94,and if not,why not?
Response to OCS Data Request 1.46
As stated in Exhibit RMP_(JKL-5),page 2,under the definition of Resource Tracking
Mechanism (RTM)Net Power Cost (NPC)Benefit,the proposed RTM will pass back
any incremental NPC savings that are not included in the energy balancing account
(EBA).Also refer to Exhibit RMP_(JKL-5),page 5,part 2 states the following:
The RTM NPC Savings will represent any incremental NPC savings associated with
repowering that is not captured in the EBA.
Therefore,the RTM,as proposed by the Company,does not affect the EBA.The EBA
calculation is unchanged.Any savings not in the EBA will be included in the RTM.
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.47
OCS Data Request 1.47
Contracts and PTC
Refer to the Direct Testimony of Mr.Hemstreet at page 6 at lines 122-133.Please
provide copies of all contracts executed with General Electric International,Inc.and
Vestas American Wind Technology,Inc.associated with the December 2016 equipment
purchases for wind repowering.
Response to OCS Data Request 1.47
Please refer to the Company's response to DPU Data Request 1.3;specifically subparts
(1)and (4).
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July 31,2017
OCS Data Request 1.48
OCS Data Request 1.48
Contracts and PTC
Refer to the Direct Testimony of Mr.Hemstreet at page 6 at lines 122-133.Please
provide copies of all purchase orders and invoices for equipment purchases from General
Electric International,Inc.and Vestas American Wind Technology,Inc.applicable to the
December 2016 safe-harbor equipment purchases for wind repowering.
Response to OCS Data Request 1.48
Please refer to the Company's response to DPU Data Request 1.4
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July 31,2017
OCS Data Request 1.49
OCS Data Request 1.49
Contracts and PTC
Refer to the Direct Testimony of Mr.Link at page 5 at line 93.Please provide a listing of
all equipment and amounts purchased from GeneralElectric International,Inc.and
Vestas American Wind Technology,Inc.for wind repowering that summed to the $77.8
million indicated by Mr.Link.
Response to OCS Data Request 1.49
Please refer to the Company's response to OCS Data Request 1.27 subpart (b).
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.50
OCS Data Request 1.50
Contracts and PTC
Refer to the Direct Testimony of Mr.Hemstreet at page 6 at lines 122-133.Please
provide copies of all analyses or reports completed to justify that the 5%safe-harbor
requirements are expected to be met by the December 2016 equipmentpurchases from
General Electric International,Inc.and Vestas American Wind Technology,Inc.for the
wind repowering.Please provide copies of all analyses in electronic format with all
formulas intact.
Response to OCS Data Request 1.50
Please refer to Confidential Attachment OCS 1.50.
Confidential information is provided subject to Public Service Commission of Utah
(UPSC)Rules 746-1-602 and 603.
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July 31,2017
OCS Data Request 1.51
OCS Data Request 1.51
Contracts and PTC
Refer to the Direct Testimony of Mr.Hemstreet at page 6 at lines 122-133.Please
describe the current status and location of the equipment purchased in December 2016 for
the wind repowering.Be sure to indicate if the Company has taken possession of the
equipment or whether it is being held by the vendors.
Response to OCS Data Request 1.51
PacifiCorp has taken possession of safe harbor equipment purchased from General
Electric International,Inc.(GE),and it is currentlylocated onsite at the Company's
Glenrock wind plant.Safe harbor equipmentpurchased from Vestas American Wind
Technology,Inc.(Vestas)is currentlylocated at the vendor's facility in Adams County,
Colorado.
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July 31,2017
OCS Data Request 1.52
OCS Data Request 1.52
Contracts and PTC
Please identify any other equipment purchases made or other costs incurred to date for
the wind repowering that were not recorded in December 2016.
Response to OCS Data Request 1.52
No purchases were made that were not recorded in December 2016.The Company has
ongoing costs associated with maintenance and storage of safe harbor equipment.Please
refer to Attachment OCS 1.52,which provides other costs incurred to date for the wind
repowermg project.
17-035-39 /Rocky Mountain Power
July 31,2017
OCS Data Request 1.53
OCS Data Request 1.53
Contracts and PTC
Please describe what would be done with the wind repowering equipment purchased from
General Electric International,Inc.and Vestas American Wind Technology,Inc.in
December 2016 if regulatory approvals for cost recovery are not granted and the
repowering project does not proceed.
Response to OCS Data Request 1.53
If cost recovery is not granted for the repowering equipment purchased in December
2016,PacifiCorp will evaluate alternatives to identify best use.Options could include
repowering those units that experience a major component failure requiring crane
mobilization,selling the equipment to an entitythat is repowering or developing new
wind.
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July 31,2017
OCS Data Request 1.54
OCS Data Request 1.54
Contracts and PTC
Please describe in detail the extent to which equipment purchased for the repowering
project and for the new development wind powering project are expected to be
interchangeable.For instance,if the repowering project is authorized and the new wind
project is either not authorized or different vendors are chosen through the RFP process,
describe whether the equipment already purchased for the new wind project could be
utilized in the repowering project?
Response to OCS Data Request 1.54
The equipment purchased for the repowering project is not the same as the equipment
expected to be used for new wind development and is not interchangeable.However,the
new wind equipment can be installed on an existing wind project to meet the safe-harbor
investment requirements for a repowering project.In addition,because there are no
Internal Revenue Service (IRS)limitations on mixingsafe-harbor equipment from one
manufacturerwith project build-out equipment by another manufacturer,the project can
contam two or more equipment types.
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July 31,2017
OCS Data Request 1.55
OCS Data Request 1.55
Contracts and PTC
Refer to the Direct Testimony of Mr.Hemstreet at page 7 at lines 151-158.Please
provide copies of all analyses or reports completed to ensure that the 80/20 test will be
met for each turbine repowered.Please provide copies of all analyses in electronic
format with all formulas intact.
Response to OCS Data Request 1.55
Please refer to Confidential Attachment OCS 1.55.
Confidential information is provided subject to Public Service Commission of Utah
(UPSC)Rules 746-1-602 and 603.
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July 31,2017
OCS Data Request 1.56
OCS Data Request 1.56
Contracts and PTC
Refer to the Direct Testimony of Mr.Hemstreet at page 7 at lines 139-150.Please
describe the fair market values assumed for each component (foundation,tower,and
machine head includingnacelle,hub,and rotor)of the typical repowered wind-turbine-
generator utilized in the Company's assessments to ensure that the 80/20 test will be met
for each turbine repowered and the source of those assumptions.
Response to OCS Data Request 1.56
Please refer to the Company's response to OCS Data Request 1.55;specifically
Confidential Attachment OCS 1.55.
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July 31,2017
OCS Data Request 1.57
OCS Data Request 1.57
Contracts and PTC
Please provide copies of all internal or external accounting or legal assessments,analyses,
reports,or opinions available to the Company regarding the Company's attainment of the
5%safe-harbor requirements or the 80/20 test requirements for the wind repowering.
Response to OCS Data Request 1.57
The Company objects to the request to the extent it seeks information protected by the
attorney-client privilege and work product doctrines.Without waiving the objection
please refer to the Company's response to OCS Data Request 1.50;specifically
Confidential Attachment OCS 1.50,for documentation related to attainment of five
percent safe-harbor requirements.
Please refer to the Company's response to OCS Data Request 1.55;specifically
Confidential Attachment OCS 1.55,for documentation related to 80/20 test requirements.
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July 31,2017
OCS Data Request 1.58
OCS Data Request 1.58
Contracts and PTC
Please provide citations to all IRS or other sourced guidance relied upon by the Company
in regards to the 5%safe-harbor or 80/20 test requirements.If the Company is aware of
any specific IRS Private Letter Rulings related to these decision criteria,please cite in the
response.
Response to OCS Data Request 1.58
The Company relied upon the followingguidance issued by the Internal Revenue Service
(IRS)in regards to the five percent safe-harbor or 80/20 test requirements as applicable
prior to entering into the General Electric safe harbor turbine contract:
Revenue Ruling94-31
Notice 20 13-29
Notice 2013-60
Notice 2014-46
Notice 2015-25
Notice 2016-31
Subsequently,the IRS issued additional guidance in the form of Notice 2017-04 which
did not alter the Company's conclusions with respect to the five percent safe-harbor or
80/20 test requirements.
The Company is unaware of any specific IRS Private Letter Rulings related to these
decision criteria.
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July 31,2017
OCS Data Request 1.59
OCS Data Request 1.59
Contracts and PTC
Refer to the Direct Testimony of Mr.Hemstreet at page 7 at lines 142-148.Please
describe how the Company plans to determine the fair market value of the remaining
equipment to apply the provisions of the IRS's 80/20 test on a "turbine-by-turbine"basis
and when such an evaluation would take place.
Response to OCS Data Request 1.59
Please refer to the Company's response to DPU Data Request 1.13.
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July 31,2017
OCS Data Request 1.60
OCS Data Request 1.60
Contracts and PTC
Please describe the timing of the Company's decision to engage in the purchase of the
equipment necessary to meet the 5%safe-harbor requirements and whether the final
determination was delayed until a specific IRS guidance was issued.If so,please cite
that guidance.In addition,please state what in that guidance was a crucial decision-
making factor(s)in the decision to proceed.
Response to OCS Data Request 1.60
The Company's timing related to purchasingthe safe harbor equipment was determined
by the timing of confirmingthe technical feasibility of installingthe equipment.
The Company's final decision to make the safe-harbor equipment purchase was not
delayed until specific IRS guidance was issued.
The IRS guidance regarding the ability to renew production tax credits for repowered
wind projects,issued in May 2016,was instrumental in the Company's decision to
further analyze repowering.
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July 31,2017
OCS Data Request 1.61
OCS Data Request 1.61
Contracts and PTC
Please provide copies of all corporate board minutes related to the decision to move
forward with the purchase of equipment necessary to meet the 5%safe-harbor
requirements for the wind repowering.
Response to OCS Data Request 1.61
Consistent with the Company's corporate governance,the decision to go forward with the
purchase of equipment necessary to meet the 5%safe-harbor requirements for the wind
repowering was based on preparation and approval of the APR provided in the
Company's response to DPU 1.4.
There are no board minutes regarding the Company's decision to move forward with the
purchase of equipment necessary to meet the five percent safe-harbor requirements for
wind repowering.
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July 31,2017
OCS Data Request 1.62
OCS Data Request 1.62
Contracts and PTC
Refer to the Company's 2016 Form 1 at page 216 line 8 which details the CWIP in
account 107 for "Wind Repowering/New Development/Safe Harbor Equipment
Purchases"for $111,124,301.Please provide the amount of safe-harbor equipment
purchased separately for the "Wind Repowering"and the "New Development"projects.
If not purchased separately or disaggregated,please explain why.
Response to OCS Data Request 1.62
Please refer to Confidential Attachment OCS 1.62.
Confidential information is provided subject to Public Service Commission of Utah
(UPSC)Rules 746-1-602 and 603.