20171026PAC to Staff 1-2.pdf

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Y ROCKY MOUNTAIN
t,lOWER
A OTVIS|ON OF P CTFTCORP
J. Ted Weston
Manager, Regulation
1407 W North Temple, Suite 330
Salt Lake City, Utah 84116
October 26,2017
Diane Hanian
Idaho Public Utilities Commission
472W. Washington
Boise, ID 83702-5918
diane. holt@puc "idaho. gov (C)
RE:ID PAC-E-I7-1I
IPUC Data Request (1-2)
Please find enclosed Rocky Mountain Power's Response to IPUC l)ata Request 1-2. Also
provided is Attachment IPUC l.
lf you have any questions, please feel free to call me at [phone].
Sincerely,
C'12/h/44a^_
PAC-E-I7-ll lRocky Mountain Power
October 26,2017
IPUC l" Set Data Request 1
IPUC Data Request I
Please list and quanti$/ the primary reasons for the reduction of the wind
integration charge from 2014 :'o2Al7.
Response to IPUC Data Request I
Please refer to Attachment IPUC 1, which provides the calculations supporting
the discussion below. including references to additional discussion within the
2014 Wind Integration Study (2014 WIS) and 2017 Flexible Reserve Study (2017
FRS).
2014 WIS (Appendix H):
http://www.pacificorp.com/content/dam/pacificorp/doc/Energy_Sources/Integrate
d-Resource*Plan/20 I 5 IRP/Pacifi Corp*20 I 5lRP-Vol2-Appendices.pdf
2017 FRS (Appendix F):
http://www.oacificorp.comlcontent/dan/pacificorp/doclEnergy_Sources/intqgfate
d_Resource_Plan/20 I 7-IRP120 1 7_lRP_VglumeII_20 I 7-lRP-Final.pdf
The total wind integration costs dropped from $3.06 per megawatt-hour ($/MWh)
to $0.57llt4Wh, or roughly 8l percent.
The average intra-hour reserve requirement embedded in the wind integration cost
calculation has dropped by 2l percent. The estimated impact relative to the
previous wind integration costs is a I6 percent reduction. The Company has not
specifically identified the impact of individual assumption changes, which include
the tbllowing:
o Reliability Standardo Portfolio Diversityo Energy imbalance market (EIM)o Historical Period
o Data granularity
Inter-hour / system balancing integration costs have dropped from $0.71lMWh to
$0. l4l]v1wh, representing approximately I 9 percent of the total change in wind
integration costs. 'fhe methodology for these costs is largely the same, reflecting
the incremental cost of sub-optimal gas plant commitment using forecasted load
and rvind, rather than actual load and wind. However, the methodology was
updated to reflect portfolio diversity, spreading the costs arnong, load, rvind and
solar, rather than the incremental impact of wind after accounting for load as in
fieZA14 WIS. This may have contributed to higher-hour costs for load and
decreased costs associated with wind. Because this cost is related to gas plant
commitment, it is impacted by changes in gas prices and the Company's resource
PAC-E-17-I I / Rocky Mountain Power
October 26,2017
IPUC I't Set Data Request 1
needs. The Company has not quantified the effect of these specific elements. The
system balancing integration cost results are discussed in more detail on pages
121 through 123 of the 2017 FRS.
The remaining reduction in wind integration costs is associated with the marginal
cost ofoperating reserves, and represents a 47 percent reduction relative to the
2014 WIS. The change in regulation reserve costs is primarily attributable to the
following factors: lower market prices, transmission congestion, and 3O-minute
regulation reserye capability. Assuming sufticient regulating capability is
available within PacifiCorp's portfolio, the cost of regulation reserve reflects the
lost margin on resources that can provide the service, i.e. the difference between
the market price or altemative generation cost and their fuel cost. Since the prior
study, market prices have declined, which reduces this margin, and a l0 percent
drop in market price can reduce the margin by more than l0 percent. In addition,
transmission congestion has increased, primarily as a result of substantial
additions of solar, which has reduced the ability of resources to get to market. If
regulation-capable resources are already backed down due to transmission
congestion there is no additional cost to count that capacity as regulation reserve.
Finally, in the prior study the entire regulation reserve requirement was included
in the spinning resene category, rvhich is limited to capacity available within l0
minutes. The FRS assunes that dispatchable capacity available within 3O-minutes
can be counted toward the regulation reserve requirement. This increases the
supply of regulation resources and reduces costs when 3O-minute capacity fiom
the unit rvith the lowest-cost reserve can be used instead of being limited to only
the 1O-minute capacity of that unit. The system balancing integration cost results
are discussed in more detail on pages 119 tkough l2l of the 2017 FRS.
Recordholder: Dan MacNeil
Sponsor: Dan MacNeil
PAC-E- I 7 -l I I Rocky Mountain Power
October 76,2017
IPUC I't Set Data Request 2
IPUC Data Request 2
Please include how much of the decrease is attributable to: (1) the change in the
NERC standard; (2) the EIM market; (3) the adjustments to account for the
changing portfolio of solar and wind; and (a) the adjustments to account for
diversity benefits, and any other quantifiable re&son.
Response to IPUC Data Request 2
The Company has not separately identified the impacts of the referenced
assumption changes. Qualitatively:
The change to the North Arnerica Hlectric Reliability Corporation (NERC)
standard included elements that contributed to both higher and lower costs.
Updated energy imbalance market (EIM) inputs decrease integration costs, in
part as a result of additional EIM participants.
Additional solar and wind generation in the Company's portlolio results in
lower incremental regulation reserye requirements, relative to existing
resources. The cost of incremental operating reserves is generally higher,
however, to the extent the generation provided by incremental resources is
causing dispatchable resources to be backed down, operating reserves may be
available at limited or n0 cost.
In general, diversity provides increased benefits. however, the new
methodology shares diversity benefits among all regulation reserve
requirements (i.e. load. wind, solar). In the prior study all of the diversity
benetits were attributed to wind, which would have reduced integration costs,
Please refer to the Company's response to tPtJC Data Request I for additional
discussion of the changes in integration costs.
Recordholder: Dan MacNeil
Sponsor: Dan MacNeil
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