20210126PAC to Staff 17-25.pdf

Y ROCKY MOUNTAIN
PCIWER
A OIVISION OF PACIFICORP
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1407 W North Temple, Suite 330
Salt Lake City, Utah 84116
January 26,202I
Jan Noriyuki
Idaho Public Utilities Commission
472W. Washington
Boise,ID 83702-5918
ian.noriyuki@ouc. idaho. eov (C)
RE: ID PAC-E-20-14
IPUC 2nd Set DataRequest(17-25)
Please find enclosed Rocky Mountain Power's Responses to IPUC Data Requests 17-25.
Provided on the Confidential CD are Confidential Attachments IPUC 19,24, and25 <l-2).
Confidential information is provided subject to protection under IDAPA 31.01.01.067 and
31.01.01.233, the Idaho Public Utilities Commission's Rules of Procedure No. 67 - Information
Exempt from Public Review, and further subject to any subsequentNon-Disclosure Agreement
(NDA) executed in this proceeding.
If you have any questions, please feel free to call me at [phone]
Sincerely,
-Jsl-J. Ted Weston
Manager, Regulation
Enclosures
PAC-E-20-14 / Rocky Mountain Power
January 26,2021
IPUC Data Request l7
IPUC Data Request 17
Tab "Wind 2030" of File "App F-Flex Study PaR results", submitted by the
Company in Response to Staffs Production Request No. 2 includes generation
data of the incremental, 500 MW wind energy and its associated reserve amount.
Please answer the following questions.
(a) The annual 500 MW wind generation amount in Row 54 is calculated as
(100x0.413)+(100x0.38)+(100x0.31)+(100x0.38)+(100x0.38))x8.87. Please
veriff that the amounts 0.413,0.38, 0.31, 0.38, and 0.38 are the annual
capacity factors of the five wind farms. What does 8.87 represent and how
was it determined?
(b) Are the costs associated with the incremental, 500-MW wind energy reflected
in the Wind 500 MW Reserves Case (Il9_FxWD500_MM_Det)? If no! does
this case only consider costs ofreserve resources?
(c) Row 74 reflects the cost difference between the scenarios with and without
incremental wind. Please explain why all the cost difference between the two
scenarios (e.g., Change in NPC, Change in Emissions, and Change in VOM)
should be categorized as reserve costs and be used for calculating wind
integration charges.
Response to IPUC Data Request 17
Referencing the Company's response to IPUC Data Request 2, specifically
Attachment IPUC 2-1, frle "App F-Flex Study PaR results', tab "Wind 2030"
(a) The referenced amounts are the annual capacrty factors (CF) ofthe proxy
wind resources for the Wyoming, Idaho, Utah, Oregon, and Washington
locations, respectively. The value of 8.87 was intended to reflect the hours in a
year (8,760) divided by 1,000 megawatt-hours (MWh) per gigawatt-hour
(GWh). The correct value is 8.76, as shown in row 54 of tab "solar 2030".
Because the reserve cost is being spread across the assumed generation, which
is slightly overstated, correcting this error would increase the wind integration
charge by approximately I percent.
(b) The "Wind 500 MW Reserves Case" only includes the reserve requirement
associated with the incremental wind generation, and not the costs or output of
the wind generation itself. As shown in row 66 through 74 of tab "Wind
2030", most of the change in costs is net power costs (NPC), which includes
fuel costs and market purchases, net of wholesale sales revenue. When
additional reserves are required, economic generation resources may be
backed down, resulting in foregone wholesale sales, or incremental market
PAC-E-20-14 / Rocky Mountain Power
January 26,2021
IPUC Data Request l7
purchases. Because a generating unit is backed down fuel costs, variable
operations and maintenance (VOM), and emissions costs are reduced.
(c) Row 74 reflects the cost difference between the scenarios with and without
incremental reserves-for wind qeneration Please refer to the Company's
response to subpart (b) above for more details on the referenced categories.
The only change between the two scenarios is the additional regulation
reserve requirement associated with incremental wind generation, which
results in changes in dispatchable generation that could otherwise provide
economic benefits by generating a higher level of output. The loss of these
economic benefits is due to the uncertainty of wind resource ou@ut and is thus
the basis for the Company's wind integration charge.
Recordholder:
Sponsor:
Dan MacNeil
To Be Determined
PAC-E-20-14 / Rocky Mountain Power
January 26,2021
IPUC DataRequest l8
IPUC Data Request 18
Tab "Solar 2030" of File "App F-Flex Study PaR results" submitted by the
Company in Response to Staff s Production Request No. 2 includes generation
data for the incremental, 500-MW solar energy and its associated reserye amount.
The associated annual reserve amount for the 500-MW solar plants is 2I4 GWh,
which is equivalent to 24.4 aMW. Please explain why the escalator percentages
determined based on 50 MW in Row 77 in Tab "50 MW Reserve" can be applied
to escalate the reserve cost of the 24.4 aNIW reserve in Row 78 in Tab "Solar
2030".
Response to IPUC Data Request 18
Referencing the Company's response to IPUC Data Request 2, specifically
Attachment IPUC 2-1, file "App F-Flex Study PaR results", tab "Solar 2030":
Tab "50 MW Reserve" represents the cost of a flat quantity: 50 megawatts (MW)
ofreserves in all hours. The escalator percentages in row 77 represent the cost of
reserves over time, relative to the cost in 2030.
The wind and solar reserve studies only calculated reserve costs for 2030,
therefore a mechanism was needed to identiff costs for other years. While wind
reserves and solar reseryes can be expected to have costs that are different from
each other and from a flat requirement, the Company felt the relative changes
calculated for the flat requirement were also reasonable to reflect for wind and
solar. Note: the 2030 wind and solar reserve costs are not adjusted, and reflect
modeled results specific to wind and solar. To the extent this escalation is less
accurate further across time, the Company would note that the earliest years in the
projection through 2020 are no longer relevant, and the last years in the projection
through 2038 are subjectto avariety ofother uncertainties.
Recordholder:
Sponsor:
Dan MacNeil
To Be Determined
PAC-E-20-14 / Rocky Mountain Power
January 26,2021
IPUC Data Request l9
IPUC Data Request 19
In reference to the File "App F-Flex Study PaR results" submitted by the
company in Response to Staffs Production Request No. 2, please response to the
following:
(a) The base scenario on Tab "50 MW Reserve" (I19_FxBase_MM_Det) is
different than the base scenario used in Tabs "wind 2030" and "solar 2030-
(Il9-FxBasehr-MM-Det). The difference between the two base scenarios in
Total Mean System cost is one million dollars. why do the three cases not
use the same base scenario?
(b) Please provide the SO and PaR portfolio files including the resources in each
portfolio and the cost for each year for the following portfolios: (l)
I I 9_FxBase_MMi et; (2) I I 9-Fx5 ORes_MM_Det; (3)
I I 9_FxBasehr_MM_Det; (a) I I 9_FxWD500_MM_Det; and (5)Il9 FxSR500 MM Det.
Response to IPUC Data Request 19
Referencing the company's response to IPUC Data Request 2, specifically
Attachment IPUC 2-1, file "App F-Flex Study PaR results":
(a) The base case "Il9-FxBasehr-MM-Det" reflected an hourly (8,760) reserve
granularity to beffer capfure the relationship between reserve requirements and
renewable generation over a wide range of conditions and was focused on the
2030 results only. The base case "Ilg_FxBase MM Def'reflected a monthly
reserve granularity for comparabil iry ;ith other analysis.
(b) Please refer to Confidential Attachment IPUC 19.
confidential information is provided subject to protection under IDAPA
31.01.01.067 and 31.01.01.233, the Idaho Public Utilities Commission's Rules of
Procedure No. 67 - Information Exempt from Public Review, and further subject
to any subsequent Non-Disclosure Agreement (NDA) executed in this proceeding
Recordholder:
Sponsor:
Dan MacNeil / Dan Swan
To Be Determined
PAC-E-20-14 / Rocky Mountain Power
January 26,2021
IPUC Data Request 20
IPUC Data Request 20
Please describe the purpose of Tab "SCCT Study", Tab, "Bat Study", and Tab
"SCCT Bat" in the File "App F-Flex Study PaR results" submitted by the
Company in Response to Staff s Production RequestNo. 2. How are they used in
determining the integration charges?
Response to IPUC Data Request 20
Referencing the Company's response to IPUC Data Request 2, specifically
Attachment IPUC 2-1, file "App F-Flex Study PaR results":
The Company's integration charges assume that the generation capacity necessary
to provide regulation reserves is available and can be repurposed from 9xlsling
generation units. Tabs "SCCT Study" and "Bat Study" illusftate how additional
flexible generation units would contribute to system costs. Tab "SCCT Baf'
provides a breakdown of the unit-specific cost components including both
variable costs and fixed costs. When fxed costs are accounted for, it is more cost-
effective to source regulation reserve from existing resources, but the cost of new
resources represents the upper bound on possible integration costs. Other than as a
verification of this upper bound, these calculations are not used in determining the
integration charges.
Recordholder:
Sponsor:
Dan MacNeil
To Be Determined
PAC-E-20-14 / Rocky Mountain Power
January 27,2021
IPUC Data Request 2l
IPUC Data Request 21
Response to Staffs Production Request No. 12 describes a situation where a QF is
in another balancing authority area @AA) and chooses to wheel its generation to
the Company. The Company states that the QF will be subject to charges for
ancillary services from its source BAA that would include the Company's
integration cost and that the Company would receive firm output at an intertie
with the source BAA consistent with the QF's transmission schedules. Please
answer the following questions.
(a) Why will the QF be subject to charges for ancillary services from its source
BAA?
(b) Why would the charge include the company's integration cost?
(c) Who decides whether the charge should include the Company's integration
cost?
(d) Is energy received at an intertie always firm? If not, why does the Company
believe the output received would be firm?
Response to IPUC Data Request 21
(a) Qualiffing facilities (QF) in external balancing authority areas (BAA) are
responsible for all charges associated with the fransmission service up until
the point where output is delivered to the Company, as the Company is not
obligated to take QF power unless it is delivered to its system. Most BAAs
have various ancillary service requirements for generators, and those same
requirements would apply to a transmission service customers regardless
those requirements are
(b) Transfers between BAAs are primarily fixed hourly schedules. To the extent
the QF provides the Company with a fixed hourly schedule of output, the
Company would not need to carry reserves to account for unexpected changes
in the QF's output across an hour. To provide a fixed hourly schedule, the
source BAA would need to make up any intra-hour imbalance, and would
likely charge the QF for that service in accordance with its ransmission tariff.
As a result, the Company would not incur an integration cost in that instance.
Because the published rate is adjusted by the wind or solar integration charge,
as applicable, wind or solar QFs that do not incur integration charges would
receive rates that are higher than the published rate by the amount of the
integration charge.
(c) The Company's contracts for off-system resources delineate the obligations of
the QF, and a wind or solar QF that receives an avoided cost price without
PAC-E-20-14 / Rocky Mountain Power
January 27,2021
IPUC Data Request 2l
integration charges would be obligated to provide firm hourly schedules at its
designated point of delivery to the Company, consistent with standard
transmission processes.
(d) No, energy at an intertie may not be a firm hourly schedule. Energy scheduled
on non-firm (NF) tansmission can be cut by the transmission provider in a
variety of circumstances. Energy can also be scheduled in l5-minute
increments and adjusted up until shortly before the operating interval. Finally,
under a pseudo-tie arrangement a generator can be moved from one BAA to
another "electrically", despite its physical location. With a pseudo-tie, a
resource is effectively within the importing BAA, rather than the source BAA.
Transmission service on the source BAA would still be necessary, and
additional costs or studies would likely be necessary to arrange the pseudo-tie,
but this arrangement can avoid most ancillary service charges from the source
BAA. The ancillary services would instead be provided by the importing
BAA, i.e. the Company in this example. As discussed in the Company's
response to subpart (c) above, the Company's contracts for off-system
resources would ensure output was provided on a firm basis.
Recordholder:
Sponsor:
Dan MacNeil
To Be Determined
PAC-E-20-14 / Rocky Mountain Power
January 26,2021
IPUC Data Request 22
IPUC Data Request22
Response to Staffs Production Request No. 16 states that integration charges for
IRP-based contracts will be portfolio specific and will be embedded within the
overall results. Please answer the following questions and provide explanations.
(a) Please explain how the integration charges for IRP-based contracts are
embedded in the overall results.
(b) Are the integration charges included as part of the avoided cost of energy or
avoided cost of capacity or both? Please explain if and how the avoided costs
would reflect the integration charges.
(c) How does the Company build a portfolio to be used under the IRP-based
method? Is it the prefened portfolio from the latest acknowledged [RP? If not,
please explain which portfolio is used and how the resources are determined
for inclusion.
Response to IPUC Data Request22
(a) Starting with the 2019 Integrated Resource Plan (IRP), integration costs for
the "IRP QF" pricing methodology are captured within the Generation and
Regulation Initiative Decision Tools (GRID) production dispatch, using the
same calculations used to produce regulation reserve requirements by
portfolio for the Planning and Risk (PaR) model as part of portfolio evaluation
in the 2019 IRP. The hourly regulation reserye requirement (in megawaffs
(MW)) is calculated for the portfolio of resources prior to adding the
qualiffing facility (QF), and the calculation is then repeated with the QF.
These two regulation reserve requirements are modeled in the base scenario
prior to adding the QF, and to the scenario that includes the QF's generation,
respectively. In both cases, the reserve requirement is economically allocated
among the available dispatchable generation resources. As a result, the
integration cost is embedded in the reported avoided cost results.
(b) Under the IRP Methodology, GRID is used to calculate the avoided energy
cost, and integration costs are embedded within the avoided energy cost
results. Please refer to the Company's response to subpart (a) above.
(c) The portfolio used on the IRP-based method is derived from the most recently
acknowledged tRP preferred portfolio. Updates to the portfolio between [RPs
primarily reflect committed resources, typically signed or terminated
conftacts. Indicative pricing also accounts for prior QF requests that are timely
proceeding through contract negotiations. When adding or removing resources
to incorporate recent commitments and prior QF requests, each resource being
added replaces an equivalent capacity contribution of similar IRP resources:
PAC-E-20-14 / Rocky Mountain Power
January 26,2021
IPUC DataRequest 22
solar contracts replace solar resources in the preferred portfolio, wind
contacts replace wind resources in the preferred portfolio, and if no wind or
solar remain, or for other resource types, gas resources are displaced. Prior to
the start date of a deferrable resource in the preferred portfolio, front office
tansactions identified in the preferred portfolio are displaced.
Recordholder:
Sponsor:
Dan MacNeil
To Be Determined
PAC-E-20-14 / Rocky Mountain Power
January 26,2021
IPUC Data Request 23
IPUC Data Request 23
In reference to Figure F.l5 on page 109 of the Flexible Reserve Study, please
explain why the regulation reserve cost for wind and solar are decreasing the first
three years when the Company has: (1) a large amount of renewable resources
coming on to the system during this time frame; Q) coal unit retirements and
continued load growth during this time frame; and (3) limited amounts of new
dispatchable resources coming on to the system during this time frame. Please
provide any evidence available to support the explanation.
Response to IPUC Data Request 23
The Company's integration costs represent the margin between marginal energy
prices on the Company's system and the operating cost of the highest cost
generator that is dispatched above its minimum operating level and can hold
additional reserves.
The Flexible Reserve Study (FRS) was prepared in fall 2018 at the beginning of
the development of the 2019 Integrated Resource Plan (IRP), and does not include
the resource additions or retirements identified in the preferred portfolio.
The portfolio used to produce the integration costs does include significant
increases in wind and solar capacity by 2021, including the new wind associated
with Energy Vision 2020 (EY 2020), and 559 megawatts (MW) of new solar
contracts executed in 2018 (see new solar resources since the 2017 IRP Update in
Table 5.6 of the 2019 IRP). While these resources increase the reserve obligation,
they have zero marginal costs (or negative in the case of wind producing
production tax credits (PTC) that reduces the marginal energy prices on the
Company's system. When incremental solar generation results in back-down of a
coal or natural gas plant because of limits of transfer capability, the cost of
holding reserves on that unit to cover a portion of that solar generation is zero - in
the absence of the reserve obligation, the coal unit would already have been
backed down. As more renewable resources are added, this becomes more
common.
The Company would also note that the first FRS results in Figure F.15 start in
2018, which had relatively high market prices. This is partially driven by
renewable generation additions across the Western Electricity Coordinating
Council (WECC), similar to the effect within the Company's portfolio.
While integration costs for the FRS were used to help drive portfolio selection
within the System Optimizer model (SO model) in the 2019IRP, the Company
recognized that variations in both renewable and flexible resources could result in
different integration costs. For that reason, the Reliability Analysis and Planning
and Risk production dispatch modeling in the 2019 IRP used the reserve
PAC-E-20-14 / Rocky Mountain Power
January 26,2021
IPUC Data Request 23
requirement algorithm described in the FRS to identiff the hourly MW regulating
reserve requirement specific to each portfolio. The cost of meeting the portfolio-
specific integration requirements is thus baked into the reported results for each
portfolio. The Company has not attempted to break out the integration cost from
other elements.
Recordholder:
Sponsor:
Dan MacNeil
To Be Determined
PAC-E-20-14 / Rocky Mountain Power
January 26,2021
IPUC Data Request 24
IPUC Data Request24
In reference to Table F.l0 on page 107 ofthe Flexible Reserve Study. Please
respond to the following:
(a) Why is the wind capacity (3,196 MW) for the 2019 Forecast Case lower than
the existing wind resources capacity (3,908 MW) found on page 99 of
PacifiCorp's 2019 IRP, Volume I? Please provide a list of wind resources with
individual capacity amounts included in the 2019 Forecast Case wind capacity
column.
(b) Why is the solar capacity (2,201MW) for the2Olg Forecast Case higher than
the existing solar resources capacity (1,759 MW) found on page l0l of
PacifiCorp's 2019 [RP, Volume I? Please provide a list of solar resources with
individual capacity amounts included in the 2019 Forecast Case solar capacity
column.
(c) Please provide a list of the wind and solar resources with individual capacrty
amounts that make up the wind and solar capacity columns for the 2019 Base
Case.
Response to IPUC Data Request24
(a) The wind in PacifiCorp's 2019 lntegrated Resource Plan (IRP), Volume I,
Chapter 5 (Load and Resource Balance), page 99 reflects the existing and
planned wind projects, but does not reflect wind and contract retirements in
2030. Please refer to Confidential AttachmentLPuc 24.
(b) The solar in PacifiCorp's 2019 IRP, Volume I, Chapter 5 (Load and Resource
Balance), page l0l reflects the existing and planned solar projects, but does
not reflect contracted solar additions through 2030. Please refer to
Confidential Attachmen t IPU C 24.
(c) Please refer to the response Company's response to subparts (a) and (b)
above.
Confidential information is provided subject to protection under IDAPA
31.01.01.067 and31.01.01.233, the Idaho Public Utilities Commission's Rules of
Procedure No. 67 - Information Exempt from Public Review, and further subject
to any subsequent Non'Disclosure Agreement (NDA) executed in this proceeding
Recordholder:Dan Swan
Sponsor:To Be Determined
PAC-E-20-14 / Rocky Mountain Power
January 26,2021
IPUC Data Request 25
IPUC Data Request 25
Please provide the work papers in Excel format with formulae intact and enabled
used to create Tables F.7 ,F .9, and F.10 of the Flexible Reserve Study.
Response to IPUC Data Request 25
Please refer to Confidential Attachment IPUC 25-l for the requested work paper
supporting Table F.7 and Table F.9 of the Flexible Reserve Study (FRS).
Please refer to Confidential Attachment IPUC 25-2 for the requested work paper
supporting Table F.l0 of the FRS.
Confidential information is provided subject to protection under IDAPA
31.01.01.067 and 31.01.01.233, the Idaho Public Utilities Commission's Rules of
Procedure No. 67 - Information Exempt from Public Review, and further subject
to any subsequentNon-Disclosure Agreement (NDA) executed in this proceeding
Recordholder:
Sponsor:
Dan MacNeil
To Be Determined