20170828Application.pdf

Y ROCKY MOUNTAIN
HP,Iy.E^.n"".
i:i ,: i-: ff jV[ fi
jli,i ,ii,i iS fifl{ $: r,s
1407 W. North Temple, Suite 310
Salt Lake City, Utah 84116
August 28,2017
OVERNIGHT DELIVERY
Diane Hanian
Commission Secretary
Idaho Public Utilities Commission
472W. Washington
Boise,ID 83702
RE: CASE NO. PAC-E-[7-ll
IN THE MATTER OF THE APPLICATION OF ROCKY MOUNTAIN POWER FOR
AUTHORIZATION TO REVISE THE WIND INTEGRATION RATE AI\D
IMPLEMENT A SOLAR INTEGRATION RATE FOR SMALL POWER GENERATION
QUALIFYING FACILITIES
Attention: Diane Hanian
Commission Secretary
Please find enclosed for filing an original and seven copies of Rocky Mountain Power's
Application in the above-referenced matter and Exhibit A which is Appendix F, the Flexible
Reserve Study, from Volume II of the 2017 IRP study.
Informal inquiries may be directed to Ted Weston, Idaho Regulatory Manager at (801) 220-
2963.
Very truly
Jeffrey K. Larsen
Vice President, Regulation
Daniel E. Solander
Senior Counsel
Rocky Mountain Power
1407 West North Temple, Suite 320
Salt Lake City, Utah 84116
Telephone: [phone]
Facsimile: 801 -220-4615
Attorney for Rocky Mountain Power
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF ROCKY MOUNTAIN POWER FOR
AUTHORIZATION TO REVISE THE WINI)
INTEGRATION RATE AI\D IMPLEMENT A
SOLAR INTEGRATION RATE FOR SMALL
POWER GENERATION QUALIFYING
FACILITIES
CASE NO. PAC-E-I7-II
APPLICATION
Rocky Mountain Power, a division of PacifiCorp ("the Company"), in accordance with
Idaho Code $61-502, $61-503, and RP 052, hereby respectfully submits this application
("Application") to the ldaho Public Utilities Commission ("Commission") requesting an Order to
decrease the wind integration rate applicable to new purchase power agreements by Rocky
Mountain Power of electric power from wind-powered qualified facilities, ("QFs"), from $3.06 to
$0.57 per MWh, and implement a solar integration rate of $0.60 per MWh applicable to purchases
by Rocky Mountain Power of electric power from solar-powered QFs. These amounts represent
the integration costs of wind and solar power to be applied against published avoided cost rates
except in those circumstances where the QF developer specifies in the power purchase agreement
to deliver the QF output to Rocky Mountain Power on a firm hourly schedule. In support of this
Application, Rocky Mountain Power states as follows:
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APPLICATION OF ROCKY MOUNTAIN POWER- I
l. Rocky Mountain Power is a division of PacifiCorp, an Oregon corporation, which
provides electric service to retail customers through its Rocky Mountain Power division in the
states of Idaho, Utah, and Wyoming. Rocky Mountain Power is a public utility in the state of Idaho
and is subject to the Commission's jurisdiction with respect to its prices and terms of electric
service to retail customers in Idaho pursuant to Idaho Code $ 6l-129. Rocky Mountain Power is
authorized to do business in the state of Idaho and provides retail electric service to approximately
75,000 customers in the state.
I. BACKGROUND
2. With respect to the costs of integrating wind generation into existing utility systems,
Commission Order No .298391 found that the supply characteristics of wind generation and related
integration costs provided a basis for adjustment to the published avoided cost rates, an adjustment
that may be different for each utility.
3. Rocky Mountain Power's Case No. PAC-E-07-07 filed on April 23, 2007,
requested approval of a utility-specific wind integration adjustment to the published avoided costs
rates. The Commission reviewed the facts and the stipulation entered into by the parties in that
case and determined that a utility-specific wind integration cost adjustment to a utility's published
avoided costs, among other adjustments, was appropriate. The Commission also ordered the
Company to file any changes to its wind integration charge as reflected in subsequent IRP.2
4. In compliance with Order No. 30497, Rocky Mountain Power hereby files this
Application to update its wind integration rate and implement a solar integration rate that can be
deducted from the published avoided cost rates to determine a purchase and sale price established
I Case No. IPC-E-05-22.
2 Order No. 30497.
APPLICATION OF ROCKY MOUNTAIN POWER- 2
for the duration of the power purchase agreement with a QF. This reduction to the published
avoided cost rate is intended to reflect the cost of integrating wind and solar generation into the
Company's electrical system. The integration rate assures that QFs that deliver less than 100 KW
have a predictable rate.
5. The Company filed its2017 Integrated Resource Plan ("IRP") on April 4,2017, as
Case No. PAC-E-17-03. In support of this Application the Company submits as Exhibit A,
Appendix F - Flexible Reserve Study from Volume II of the 2017 IRP. Exhibit A explains in detail
the methodology used and the results derived from PacifiCorp's analysis of wind and solar
integration costs.
[ 2017IRP. FLEXIBLE RESERVE STUDY
6. Appendix F of the 20l7IRP summarizes a Flexible Reserve Study ("FRS") which
estimates the regulation reserve required to maintain PacifiCorp's system reliability and comply
with North American Electric Reliability Corporation ("NERC") reliability standards as well as
the incremental cost of this regulation reserve. The FRS also compares PacifiCorp's overall
operating reserve requirements, including both regulation reserve and contingency reserve, to its
flexible resource supply over the IRP study period.
7. The FRS is based on PacifiCorp's operational data from January 2015 through
December 2015 for load, wind, and Non-Variable Energy Resources ("Non-VERs"). Solar
generation on PacifiCorp's system was insignificant during that time period, but is expected to
amount to over 1,000 MW by the end of 2017. PacifiCorp's primary analysis focuses on the
variability of load, wind, and Non-VERs during 2015. A supplemental analysis was prepared to
determine how the total variability of the PacifiCorp system changes with varying levels of wind
and solar capacity.
APPLICATION OF ROCKY MOUNTAIN POWER - 3
8. The estimated regulation reserve amounts determined in the FRS represent the
incremental capacity needed in a particular operating hour to ensure compliance with NERC
Standard BAL-001-2, which became effective July 1,2016. The regulation reserve requirement
for the combined portfolio is the sum of the individual requirements for load, wind, solar, and Non-
VERs, less the reserye "savings" associated with diversity between the different classes, including
diversity benefits realized as a result of PacifiCorp's participation in the Energy Imbalance Market
("EIM") operated by the Califomia Independent System Operator Corporation ("CAISO").
9. The methodology used in the FRS differs in several ways from that employed in
PacifiCorp's previous regulation reserve requirement analyses. First, regulation reserve
requirements are now tied directly to compliance with the BAL-001-2 standard. Second, the FRS
uses a portfolio wide approach to determine the overall regulation reserve requirement, including
the aggregated diversity benefits for all customer classes. Third, all customer classes that
contribute to the overall regulation reserve requirement are now allocated a share of the diversity
benefits resulting from aggregating their requirement with that of the system as a whole. Fourth,
the FRS reflects updated data based on actual operational experience, including the data and
benefits from PacifiCorp's participation in the EIM.
10. The FRS results produce an hourly forecast of the regulation reserve requirements
for each of PacifiCorp's BAAs that is sufficient to ensure the reliability of the transmission system
and compliance with NERC and WECC standards. This regulation reserve forecast covers the
combined deviations of the load, wind, solar and Non-VERs on PacifiCorp's system and varies as
a function of the wind and solar capacity on PacifiCorp's system, as well as forecasted wind and
solar output.
APPLICATION OF ROCKY MOUNTAIN POWER - 4
1 1. In addition to estimating the regulation reserve based on the specific requirements
of NERC Standard BAL-001-2, the FRS also incorporates the current timeline for EIM market
processes, as well as EIM resource deviations and flexibility reserve benefits based on actual
results. The FRS also includes adjustments to regulation reserve requirements to account for the
changing portfolio of solar and wind resources on PacifiCorp's system and accounts for the
diversity of using a single portfolio of regulation reserve resources to cover variations in load,
wind, solar, and Non-VERs. The regulation reserve requirements for the various portfolios
considered in this analysis including values from the 2014 Wind Integration Study for reference
are shown in Table F.l below.
Table F.1 - Portfolio Reserve Scenario
12. PacifiCorp incorporated the revised methodology in the FRS compared to its 2014
Wind Integration Study for the following reasons: (1) the FRS now estimates regulation reserve
based on the specific requirements of NERC Standard BAL-00 I -2 ; (2) it incorporates the current
timeline for EIM market processes, as well as EIM resource deviations and flexibility reserve
benefits based on actual results; (3) the FRS also includes adjustments to regulation reserve
requirements to account for the changing portfolio of solar and wind resources on PacifiCorp's
2014 wIS 2,543 nla nla nla 626
2,588 0 900 37.5o/o s622015 (No Sohr)
2017 Base Case 2,757 1,050 998 38.2o/o 6t7
IrrrenrrfialWird 3,007 1,050 1,023 38.3o/o 631
Irrrenpntal Sohr I 2,757 1,5 50 1,033 38.60/o 635
Irrrenpntal Sohr 2 2.757 2,050 r.07 4 39.2o/o 653
APPLICATION OF ROCKY MOUNTAIN POWER - 5
StanGehnc
Regubton
Regterent
(MW)Case
wtd
Cepcty
(MUD
Sohr
Cepcfi
(MW)
hrfolo
Dtrrcrcfry
Credft(%)
Regdethn
Reqdrcmil
nfrh Dhrenfry
(MUD
system; and (4) it accounts for the diversity of using a single portfolio of regulation reserve
resources to cover variations in load, wind, solar, and Non-VERs.
13. Two categories of flexible resource costs are estimated using the Planning and Risk
(PaR) model: one for meeting intra-hour regulation reserve requirements, and one for inter-hour
system balancing costs associated with commiffing gas plants using day-ahead forecasts of load,
wind, and solar. The integration costs determined from the FRS are summarized in Table F.2
which provides the wind and solar costs on a dollar per megawatt-hour ($iMWh) of generation
basis. The results of the 2014 Wind Integration Study are also included for comparison.
Table F.2 -2017 Flexible Resource Costs Com to 2014 WIS
14. Based on the results of the FRS from the 2017 IRP the Company respectfully
requests that the wind integration rate be reduced from $3.06 to $0.57 per megawatt hour and that
the Commission authorize the Company to implement a solar integration rate of $0.60 per
megawatt hour, applicable to wind and solar QFs that qualify for the Company's published QF
rates.
III. COMMUNICATIONS
Communications regarding this filing should be addressed to:
Ted Weston
Idaho Regulatory Affairs Manager
Rocky Mountain Power
1407 West North Temple, Suite 330
Salt Lake City, Utah 84116
Telephone : [phone]
Emai I : ted.weston@nacifi corp.com
Iilra-hour Reserve $2.35 s0.43 $0.46
s0.71 $0.1 4 s0. l4Irter- hour/System Bahrrcing
Total Fkxlble Resource Cost s3.06 s0.s7 s0.60
APPLICATION OF ROCKY MOUNTAIN POWER - 6
whd
2014 WIS
(2014$)
whd
2017InS
(2015$)
Sohr
2017 rRS
(2015S)
Daniel E. Solander
Senior Counsel
Rocky Mountain Power
1407 West North Temple, Suite 320
Salt Lake city, Utah 841l6
Telephone : [phone]
Emai I : daniel.solander@oacifi com.com
In addition, Rocky Mountain Power requests that all data requests regarding this
Application be sent in Microsoft Word to the following:
B y emai I (preferred) : datarequest@fracifi corp.com
By regular mail: Data Request Response Center
PacifiCorp
825 Multnomah, Suite 2000
Portland, Oregon 97232
Informal questions may be directed to Ted Weston, Idaho Regulatory Affairs Manager at
(80r)220-2963.
IV. MODIFIED PROCEDURE
Rocky Mountain Power believes that a hearing is not necessary to consider the issues
presented herein and respectfully requests that this Application be processed under Modified
Procedure; i.e., by written submissions rather than by hearing, RP 201. If, however, the
Commission determines that a technical hearing is required, the Company stands ready to prepare
and present its testimony in such hearing.
V. REQUEST FOR RELIEF
WHEREFORE, Rocky Mountain Power respectfully requests that the Commission issue
an Order: (l) authorizing this Application to be processed under Modified Procedure; (2) reducing
the published avoided cost rate applicable to purchases by Rocky Mountain Power of electric
power from wind-powered QFs from $3.06 per MWh to $0.57 per MWh; and (3) implementing a
solar integration rate of $0.60 per MWh to be used by the Company for purchase of electric power
APPLICATION OF ROCKY MOUNTAIN POWER - 7
from solar-powered QFs, which amount represents the integration costs of wind and solar power,
to be applied against scheduled avoided cost rates in those circumstances, except where the QF
developer agrees in the power purchase agreement with Rocky Mountain Power to schedule and
deliver, via a transmission provider, the QF output to Rocky Mountain Power on a firm hourly
basis.
RESPECTFULLY SUBMITTED this 28th day of August, 2017
Rocky Mountain Power
1,fihBy
Daniel E. Solander, Sr. Counsel
Rocky Mountain Power
APPLICATION OF ROCKY MOLINTAIN POWER - 8
\
PACIFICORP - 20 I7 IRP APPENDIX F - FLEXIBLE RESERVE STUDY
AppgNDIx F - FTPXIBTP RESERVE Sruoy
This 2017 Flexible Reserve Study ("FRS") estimates the regulation reserve required to maintain
PacifiCorp's system reliability and comply with North American Electric Reliability Corporation
('NERC") reliability standards as well as the incremental cost of this regulation reserve. The FRS
also compares PacifiCorp's overall operating reserve requirements, including both regulation
reserve and contingency reserve, to its flexible resource supply over the IRP study period.
PacifiCorp operates two Balancing Authority Areas ("BAAs") in the Western Electricity
Coordinating Council ("WECC") NERC region, PacifiCorp East ("PACE") and PacifiCorp West
("PACW"). The PACE and PACW BAAs are interconnected by a limited amount of transmission
across a third-pany transmission system and the two BAAs are each required to comply with
NERC standards. PacifiCorp must provide sufficient regulation reserve to remain within NERC's
balancing authority area control error ("ACE") limit in compliance with BAL-OOl-2,1 as well as
the amount of contingency reserve required in order to comply with NERC standard BAL-002-
WECC-2.2 BAL-001-2 is a new regulation reserve standard that became effective July 1,2016,
and BAL-002-WECC-2 is a contingency reserve standard that became effective October 1,2014.
Regulation reserve and contingency reserve are components of operating reserye, which NERC
defines as o'the capability above firm system demand required to provide for regulation, load
forecasting error, equipment forced and scheduled outages and local area protection."3
Apart from disturbance events that are addressed through contingency reserye, regulation reserve
is necessary to compensate for changes in load demand and generation output, so as to maintain
ACE within mandatory parameters established by the BAL-001-2 standard. The FRS estimates
the amount of regulation reserve required to manage variations in load, variable energy resources4
("VERs"), and resources that are not VERs ('Non-VERs") in each of PacifiCorp's BAAs. Load,
wind, solar, and Non-VERs were each studied because PacifiCorp's data indicates that these
components or customer classes place different regulation reserve burdens on PacifiCorp's system
due to differences in the magnitude, frequency, and timing of their variations from forecasted
levels. Specifically, PacifiCorp's calculations demonstrate that the regulation reserve burden
associated with wind deviations from scheduled amounts are twice the amount associated with
solar, three times the amount associated with load, and four times the amount associated with Non-
1 NERC Standard BAL-001-2, http://www.nerc.com/files/BAl-001-2.pdf, which became effective July l,
2016. ACE is the difference between a BAA's scheduled and actual interchange, and reflects the difference between
electrical generation and Load within that BAA.
' NERC Standard BAL-002-WECC-2, htto://wvu,.nerc.com/files/BAl-002-WECC-2.pdf, which became
effective October l, 201 4.
3 NERC Glossary of Terms: http://www.nerc.com/files/elossary_of terms.pdf, updated July 13, 2016.
4 VERs are resources that resources that: (l) are renewable; (2) cannot be stored by the facility owner or
operator; and (3) have variability that is beyond the control ofthe facility owner or operator. Integration of Variable
EnergyResources,OrderNo.T64, 139 FERCfl6l,246 atP28l (2012)("OrderNo.764"); orderonreh'g,Order
No. 764-4, 141 FERC n 61,232 (2012) ("Order No. 764-4"); order on reh'g and clarification, Order No. 764-8,
144 FERC n6l,222atP 210 (2013) ("OrderNo.764-8").
73
Introduction
PACIFICoRP-2017IRP APPENDIx F - FLEXIBLE RESERVE STuoy
VERs. As a result, PacifiCorp attributes different levels of regulation reserve to load, wind, solar,
and Non-VERs.
The FRS is based on PacifiCorp operational data recorded from January 2015 through December
2015 for load, wind, andNon-VERs. Solar generation on PacifiCorp's system was insignificant
during that time period, but is expected to amount to over 1,000 MW by the end of 2017.
PacifiCorp's primary analysis, focuses on the variability of load, wind, and Non-VERs during
2015. A supplemental analysis discusses how the total variability of the PacifiCorp system
changes with varying levels of wind and solar capacity. The estimated regulation reserve amounts
determined in this study represent the incremental capacity needed to ensure compliance with
BAL-001-2 for a particular operating hour. The regulation reserve requirement for the combined
portfolio is the sum of the individual requirements for load, wind, solar, and Non-VERs, less the
reserve "savings" associated with diversity between the different classes, including diversity
benefits realized as a result of PacifiCorp's participation in the Energy Imbalance Market ("EIM")
operated by the California Independent System Operator Corporation ("CAISO").
The methodology in the FRS differs in several ways from that employed in PacifiCorp's previous
regulation reserve requirement analyses.s'6'7 First, regulation reserve requirements are now tied
directly to compliance with the BAL-001-2 standard. Second, the FRS uses a portfolio wide
approach to determine the overall regulation reserye requirement, including the aggregated
diversity benefits for all customer classes. Third, all customer classes that contribute to the overall
regulation reserve requirement are now allocated a share of the diversity benefits resulting from
aggregating their requirement with that of the system as a whole. Fourth, the FRS reflects updated
data based on actual operational experience, including the data and benefits from PacifiCorp's
participation in the EIM.
The FRS results produce an hourly forecast of the regulation reserve requirements for each of
PacifiCorp's BAAs that is sufficient to ensure the reliability of the transmission system and
compliance with NERC and WECC standards. This regulation reserve forecast covers the
combined deviations of the load, wind, solar and Non-VERs on PacifiCorp's system and varies as
a function of the wind and solar capacity on PacifiCorp's system, as well as forecasted wind and
solar output.
The regulation reserve requirements produced by the FRS were applied in the Planning and Risk
(PaR) production cost model to determine the cost of the reserye requirements associated with
incremental wind and solar capacity. These costs are attributed to the integration of wind and solar
generation resources inthe 2017 Integrated Resource Plan (lRP).
s 2Ol2 Wind Integration Study report, Appendix H in Volume II of PacifiCorp's 2013 IRP report:
http://www.pacificom.com/contenVdarn/pacificom/doc/Energy SourcesAnteerated_Resource_Plar/20l3IRP/Pacifi
Corp-2Ol3lRP_Vol2-Appendices 4-30-l 3.pdf
6 2013 PacifiCorp Schedule 3 and 3A Study, Exhibit PAC-8 in testimony of Greg Duvall, FERC Docket No.
ERl3-1206 (filed April 1,2013).
7 2014 Wind Integration Study, Appendix H in Volume II of PacifiCorp's 2015 IRP report:
htto://www.pacificorp.com/content/dam/pacificorp/doc/Energ.v_Sources/InteCrated_Resource_Plan/20l5IRPlPacifi
Corp-20 I 5IRP-Vol2-Apoendices.pdf
74
PACIFICORP _ 2017 IRP APPENDIX F _ FLEXIBLE RESERVE STuoy
Executive Summary
The FRS first estimates the regulation reserve necessary to maintain compliance with NERC
Standard BAL-001-2 given a specified portfolio of wind and solar resources. The FRS next
calculates the cost of holding regulation reserve for incremental wind and solar resources and the
cost of using day-ahead load, wind, and solar forecasts to commit gas units. Finally, the FRS
compares PacifiCorp's overall operating reserve requirements over the IRP study period, including
both regulation reserve and contingency reserve, to its flexible resource supply.
The FRS estimates regulation reserve based on the specific requirements of NERC Standard BAL-
001-2. It also incorporates the current timeline for EIM market processes, as well as EIM resource
deviations and flexibility reserve benefits based on actual results. The FRS also includes
adjustments to regulation reserve requirements to account for the changing portfolio of solar and
wind resources on PacifiCorp's system and accounts for the diversity of using a single portfolio of
regulation reserve resources to cover variations in load, wind, solar, and Non-VERs. The
regulation reserve requirements for the various portfolios considered in this analysis including
values from the 2014 Wind lntegration Study for reference are shown in Table F.l.
Table F.l - Portfolio Regulation Reserve Requirements, by Scenario
Two categories of flexible resource costs are estimated using the Planning and Risk (PaR) model:
one for meeting intra-hour regulation reserye requirements, and one for inter-hour system
balancing costs associated with committing gas plants using day-ahead forecasts of load, wind,
and solar. Table F.2 provides the wind and solar costs on a dollar per megawatt-hour ($AvIWh) of
generation basis. The results of the 2014 Wind Integration Study are also included for reference.
Table F.2 -2017 FRS Flexible Resource Costs as Compared to 2014 WIS Costs, $/MWh
The 2017 FRS results are applied inthe 2017 IRP portfolio development process as a cost for wind
2014 wts 2,543 n/a n/a nla 626
2,588 0 9002015 (No Solar)375%562
2,757 I,050 998 38.2%6172017 Base Case
Incremental Wind 3,007 1,050 1,023 38.3%631
Incremental Sohr I 2,757 1,550 1,033 38.6%63s
Incrernental Solar 2 2,757 2,050 1,074 39.zYo 6s3
Infta-hour Reserve $2.3s $0.43 s0.46
Inter- hour/System Bahnc ing $0.71 $0.1 4 $0.1 4
Total Flexible Resource Cost $3.06 $0.s7 $0.60
75
Case
Wind
Capacity
(MW)
Solar
Capacity
(MW)
Stand-alone
Regulation
Requirement
(MW)
Portfolio
Diver.lsity
Credit (%)
Regulation
Requirement
with Divenity
(MW)
Wind
2014 WrS
(2014$)
Wind
2017 FRS
(2016$)
Solar
2017 FRS
(2016$)
PACIFICoRP - 20 17 IRP APPENDIX F - FLEXIBLE RESERVE STuoy
and solar generation resources. Once candidate resource portfolios are developed using the SO
model, the PaR model is used to evaluate portfolio risks. The PaR model inputs include regulation
reserve requirements specific to the resource portfolio developed using the SO model. As a result,
the IRP risk analysis using PaR includes the impact of differences in regulation reserye
requirements between portfolios.
PacifiCorp's flexible resource needs are the same as its operating reserve requirements over the
planning horizon for maintaining reliability and compliance with the North American Electric
Reliability Corporation (NERC) regional reliability standards. Operating reserye consists of three
categories: (l) contingency reserve (i.e., spinning and supplemental reserve), (2) regulation
reserve, and (3) frequency response reserve. Contingency reserve is capacity that PacifiCorp holds
available to ensure compliance with the NERC regional reliability standard BAL-002-WECC-2.8
Regulation reserve is capacity that PacifiCorp holds available to ensure compliance with the NERC
Control Performance Criteria in BAL-001-2.e Frequency response reserve is capacity that
PacifiCorp holds available to ensure compliance with NERC standard BAL-003-1.r0 Each type of
operating reserve is further defined below.
Contingency Reserve
NERC regional reliability standard BAL-002-WECC-2 specifies that each BAA must hold as
contingency reserye an amount of capacity equal to three percent of load and three percent of
generation in that BAA. Contingency reserve must be available within ten minutes, and at least
half must be from "spinning" resources that are online and immediately responsive to system
fluctuations. Contingency reserve may be deployed when unexpected outages of a generator or a
transmission line occur. Contingency reserve may not be deployed to manage other system
fluctuations such as changes in load or wind generation output.
Regulation Resene
NERC standard BAL-001-2, which became effective July 1, 2016, does not specify a regulation
reserve requirement based on a simple formula, but instead requires utilities to hold sufficient
reserve to meet specified control performance standards. The primary requirement relates to area
control error ("ACE"), which is the difference between a BAA's scheduled and actual interchange,
and reflects the difference between electrical generation and load within that BAA. Requirement
2 of BAL-001-2 defines the compliance standard as follows:
Each Balancing Authority shall operate such that its clock-minute average of
Reporting ACE does not exceed its clock-minute Balancing Authority ACE Limit
8 NERC Standard BAL-002-WECC-z- Contingency Reserve: htto://www.nerc.com/files/BAl-002-WECC-2.pdf
e NERC Standard BAL-001-2 - Real Power Balancing Control Performance: http://www.nerc.com/files/BAl-001-
2.pdf
t0 NERC Standard BAL-003-I - Frequency Response and Frequency Bias Setting:
htto ://www.nerc.com/palStand/Reliabilitv%20 Standards/BAL-003 - I .pdf
76
Flexible Resource uirements
PACIFICoRP-20I7IRP APPENDIX F - FLEXIBLE RESERVE STuoy
(BAAL) for more than i0 consecutive clock-minutes
In addition, Requirement I of BAL-001-2 specifies that PacifiCorp's Control Performance
Standard I ("CPSI") score must be greater than equal to 100 percent for each preceding 12
consecutive calendar month period, evaluated monthly. The CPSI score compares PacifiCorp's
ACE with interconnection frequency during each clock minute. A higher score indicates
PacifiCorp's ACE is helping interconnection frequency, while a lower score indicates it is hurting
interconnection frequency. Because CPSI is averaged and evaluated on a monthly basis, it does
not require a response to each and every ACE event, but rather requires that PacifiCorp meet a
minimum aggregate level of performance in each month.
Regulation reserve is thus the capacity that PacifiCorp holds available to respond to changes in
generation and load to manage ACE within the limits specified in BAL-001-2. Because
Requirement 2 includes a 30 minute time limit for compliance, ramping capability that can be
deployed within 30 minutes contributes to meeting PacifiCorp's regulation reserve requirements.
PacifiCorp has not specifically evaluated reserve needs for CPSI compliance. The reserve for
CPSI is not expected to be incremental to the need for compliance with Requirement 2,but may
require that a subset of resources held for Requirement 2 be able to make frequent rapid changes
to manage ACE relative to interconnection frequency. Regulation reserve requirements are
discussed in more detail later on in the study.
F requency Response Reserre
NERC standard tiel-OO:-t specifies that each BAA must arrest frequency deviations and support
interconnection frequency when it drops below the scheduled level. When a frequency drop occurs,
each BAA is expected to deploy resources that are at least equal to its Frequency Response
Obligation. The incremental requirement is based on the size of the frequency drop and the BAA's
Frequency Response Obligation, expressed in MW/0.lHz. The additional capacity must be
deployed immediately, and performance is measured over a period of seconds, amounting to under
a minute. To comply with the standard, a BAA's median measured frequency response during a
sampling of under-frequency events must be equal to or greater than its Frequency Response
Obligation. PacifiCorp's 2017 Frequency Response Obligation was 19.51 MW/O.1Hz for PACW,
and 48.93 MW0.lHz for PACE. PacifiCorp's combined obligation amounts to 68.44 MW for a
frequency drop of 0.1Hz, or 205.32 MW for a frequency drop of 0.3 Hz.
Because the performance measurement for contingency reserve under the Disturbance Control
Standard (BAL-002-l) is similar to that for BAL-003-1, frequency response capacity is effectively
incremental to contingency reserve obligations. As Standard BAL-003-I is based on median
performance under selected WECC-wide events, while regulation reserve obligations under BAL-
001-2 are based on minimum performance during BAA-specific events, frequency response
capacity can be considered a subset of the BAL-001-2 obligation. Since median performance is
adequate for BAL-003-l compliance, BAL-001-2 compliance can take precedence, so long as the
overlap is sufficiently low, i.e. BAL-001-2 events are rare and there don't have a positive
correlation with BAL-003- I events.
While frequency response reserve can meet regulation reserye requirements, the reverse is not
necessarily true. Frequency response must occur very rapidly, and a generating unit's capability is
limited based on the unit's size, governor controls, and available capacity, as well as the size of
77
PACIFICoRP _ 20 I7 IRP APPENDIX F -FLEXIBLE RESERVE STUOy
the frequency drop. As a result, while a few resources could hold a large amount of regulation
reserve, frequency response needs to be spread over a larger number of resources. Because
PacifiCorp has excess spinning reserve capability compared to its contingency reserve obligation,
the capacity and response time requirements for its frequency response obligations are expected to
be met by drawing from its existing pool of regulation reserve resources. As a result, no
incremental capacity requirements or resource constraints related to frequency response were
included in the 20l7IRP analysis beyond those already included for contingency and regulation
reserye.
Overview
This section describes the data used to determine PacifiCorp's regulation reserve requirements. In
order to estimate PacifiCorp's required regulation reserve amount, PacifiCorp must determine the
difference between the expected load and resources and actual load and resources. The difference
between load and resources is calculated every four seconds and is represented by the ACE. ACE
must be maintained within the limits established by BAL-001-2, so PacifiCorp must estimate the
amount of regulation reserve that is necessary in order to maintain ACE within these limits.
To estimate the amount of regulation reserve that will be required in the future, the FRS identifies
the scheduled use of the system as compared to the actual use of the system during the study term.
For the baseline determination of scheduled use for load and resources, the FRS used hourly base
schedules. Hourly base schedules are the power production forecasts used for imbalance settlement
in the EIM and represent the best information available concerning the upcoming hour.ll
The deviation from scheduled use was derived from data provided through participation in the
EIM. The deviations of generation resources in EIM were measured on a five-minute basis, so the
Regulation Reserve Study used five-minute intervals throughout the analysis.
EIM base schedule and deviation data for each wind and Non-VER transaction point were
downloaded using the Report Explorer application to query PacifiCorp's nMarket Application
database, which is populated with data provided by the CAISO. Since PacifiCorp's
implementation of EIM on November 1,2014, PacifiCorp requires certain operational forecast
data from all of its transmission customers pursuant to the provisions of Attachment T to
" The CAISO, as the market operator for the EIM, requests base schedules at 75 minutes ("T-75") prior to the hour
of delivery. PacifiCorp's transmission customers are required to submit base schedulesby 77 minutes (*T-77")
prior to the hour of delivery - two minutes in advance of the EIM Entity deadline. This allows all transmission
customer base schedules enough time to be submitted into the EIM systems before the overall deadline of T-75 for
the entirety of PacifiCorp's two BAAs. The base schedules are due again to CAISO at 55 minutes ("T-55") prior to
the delivery hour and can be adjusted up until that time by the EIM Entify (i.e., PacifiCorp Grid
Operations). PacifiCorp's transmission customers are required to submit updated, final base schedules no later than
57 minutes (*T-57") prior to the delivery hour. Again, this allows all transmission customer base schedules enough
time to be submitted into the EIM systems before the overall deadline of T-55 for the entirety of PacifiCorp's two
BAAs. Base schedules may be finally adjusted again, by the EIM Entity only, at 40 minutes ("T-40") prior to the
delivery hour in response to CAISO sufficiency tests. T-55 is the base schedule time point used throughout this
study because it is the deadline which most closely corresponds to the final T-57 deadline for all transmission
customers to submit final base schedules.
78
of Data
PACIFIC0RP-20I7IRP APPENDIX F - FLEXIBLE RESERVE STUDY
PacifiCorp's Federal Energy Regulatory Commission ("FERC")-approved Open Access
Transmission Tariff ("OATT"). This includes EIM base schedule data (or forecasts) from all
resources included in the EIM network model at transaction points. EIM base schedules are
submitted by transmission customers with hourly granularity, and are settled using hourly data for
load, and fifteen-minute and five-minute data for resources. A primary function of the EIM is to
measure load and resource imbalance (or deviations) as the difference between the hourly base
schedule and the actual metered values.
A summary of the data gathered for this analysis is listed below, and a more detailed description
of each type of source data is contained in the following subsections.
Source data:- Load datao Five-minute interval actual Load
o Proxy hourly base schedules developed from actual prior hour and prior week data
VER data
o Five-minute EIM deviations
o Hourly base schedules
Non-VER data
o Five-minute EIM deviations
o Hourly base schedules
Load Data
The Load class represents the aggregate firm demand of end users of power from the electric
system. While the requirements of individual users vary, there are diurnal and seasonal patterns
in aggregated demand. The Load class can generally be described to include three components:
(l) average load, which is the base load during a particular scheduling period; (2) the trend, or
"ramp," during the hour and from hour-to-hour; and (3) the rapid fluctuations in load that depart
from the underlying trend. The need for a system response to the second and third components is
the function of regulation reserve in order to ensure reliability of the system.
The PACE BAA includes several large industrial loads with unique patterns of demand. Each of
these loads is either interruptible at short notice or includes behind the meter generation. Due to
their large size, abrupt changes in their demand are magnified for these customers in a manner
which is not representative of the aggregated demand of the large number of small customers
which make up the majority of PacifiCorp's loads.
In addition, interruptible loads can be curtailed if their deviations are contributing to a resource
shortfall. Because of these unique characteristics, these loads are excluded from the FRS. This
treatment is consistent with that used in the CAISO load forecast methodology (used for PACE
and PACW operations), which also nets these interruptible customer loads out of the PACE BAA.
Actual average load data was collected separately for the PACE and PACW BAAs for each five-
minute interval over the Study Term. Load data for the Study Term was downloaded from
PacifiCorp's Ranger PI system and has not been adjusted for transmission and distribution losses.
Only actual load data is available from Ranger PI, not base schedule data that could be used to
79
PACIFICoRP - 20 I7 IRP APPENDIX F - FLEXIBLE RESERVE STuoy
determine the deviation associated with Load. Because of differences in the load defined in EIM
and in the Ranger PI system, the EIM load base schedules are not consistent with the Ranger PI
actual results. To address the inconsistency, PacifiCorp developed proxy load base schedules, as
discussed below.
Wind Data
The Wind class includes resources that: (l) are renewable; (2) cannot be stored by the facility
owner or operator; and (3) have variability that is beyond the control of the facility owner or
operator.l2 Wind, in comparison to load, often has larger upward and downward fluctuations in
output that impose significant and sometimes unforeseen challenges when attempting to maintain
reliability. For example, as recognizedby FERC in OrderNo.T64,oolncreasing the relative amount
of [VERs] on a system can increase operational uncertainty that the system operator must manage
through operating criteria, practices, and procedures, including the commitment of adequate
reserves."t3 The data included in the FRS for the Wind class includes all wind resources in
PacifiCorp's BAAs, which includes: (1) third-party resources (OATT or legacy contract
transmission customers); (2) PacifiCorp-owned resources; and (3) other PacifiCorp-contracted
resources, such as qualifying facilities, power purchases, and exchanges. Appendix F.B, Table I
contains the list of the wind plants included in the study. In total, the FRS includes 2,588
megawatts of wind.
Non-VER Data
The Non-VER class is a mix of thermal and hydroelectric resources and includes all resources
which are not VERs, and which do not provide either contingency or regulation reserve. Non-
VERs, in contrast to VERs, are often more stable and predictable. Non-VERs are thus easier to
plan for and maintain within a reliable operating state. For example, in Order No. 764, FERC
suggested that many of its rules were developed with Non-VERs in mind and that such generation
"could be scheduled with relative precision."l4 The output of these resources is largely in the
control of the resource operator, particularly when considered within the hourly timeframe of the
FRS. The deviations by resources in the Non-VER class are thus significantly lower than the
deviations by resources in the Wind class. The Non-VER class includes third-party resources
(OATT or legacy transmission customers); many PacifiCorp-owned resources; and other
PacifiCorp-contracted resources, such as qualifying facilities, power purchases, and exchanges.
Appendix F.B, Table 2 contains the list of the Non-VERs included in the study. In total, the FRS
includes 2,228 megawatts of Non-VERs.
In the FRS, resources that provide contingency or regulation reserve are considered a separate,
dispatchable resource class. The dispatchable resource class compensates for deviations resulting
from other users of the transmission system in all hours. While non-dispatchable resources may
offset deviations in loads and other resources in some hours, they are not in the control of the
system operator and contribute to the overall requirement in other hours. Because the dispatchable
resource class is a net provider rather than a user of regulation reserve service, its stand-alone
regulation reserve requirement is zero (or negative), and its share of the system regulation reserve
t2
13
t4
Order No. 764 atP 281; Order No.764-B atP 210.
Order No. 764 atP 20 (emphasis added).
Id. atP 92.
80
PACIFICoRP - 20 I7 IRP APPENDIX F - FLEXIBLE RESERVE STUDY
requirement is also zero. The allocation of regulation reserve requirements and diversity benefits
is discussed in more detail later on in the study..
Overyiew
This section provides details on adjustments made to the data to develop base schedules that
correspond to the load data, align the ACE calculation with actual operations, and address data
issues.
Load Base Schedule Development
Load deviations are settled using hourly imbalance data in EIM, whereas resource deviations are
settled using fifteen-minute and five-minute imbalance data. As a result, the five-minute
deviations necessary to assess the regulation reserve requirements associated with Load were not
available through EIM. For the FRS, PacifiCorp used actual load data from its Ranger PI system,
which can provide data at a five-minute granularity. The Ranger PI system does not have the
associated base schedules necessary to calculate deviations, however, so PacifiCorp developed
proxy load base schedules consistent with the measured actual loads.
The load base schedule for each hour was calculated from actual load at 55 minutes prior to the
hour ("T-55") in question, with a scaling factor applied based on the change in load over that same
interval in the prior week. The five-minute interval ending at T-55 is the last load data point
available prior to base schedule submission to CAISO at hour T-55 and represents the current state
of load in the PacifiCorp BAAs. Load follows different pattems depending on season and day of
the week. Using data from one week prior ensures that recent conditions on a similar day are used
in the calculation of the load base schedule.
Figure F.1 below illustrates measurement of the expected load change between T-55 data and the
hourly base schedule over three hours. The five-minute interval ending at 17.05 (first green
column) has a load of 2,643 MW. The actual load in hour l8 averages 2,837 MW (middle solid
horizontal line), an increase of 7.4 percent. Similarly, the expected load change from the five-
minute interval ending at l8:05 to hour 19 is a decrease of L l percent (difference between second
green column and second horizontal line). Figure F.2 below shows how those load measurements
are applied seven days later to determine the proxy load base schedules for hours l8 and 19. The
proxy load base schedule for hour 18 is calculated as the actual load in the five-minute interval
ending at 17:05, plus an additional 7.4 percent. The proxy load base schedule for hour 19 is
calculated as the actual load in the five-minute interval ending at 18:05, minus l.l percent.
Deviations are then calculated as the difference between the proxy load base schedule and actual
five-minute loads over the hour.
8l
and
PACIFICORP-20I7IRP APPENDIX F - FLEXIBLE RESERVE STUDY
Figure F.l - Expected Load Change from Prior Week
r Actual Load (5-minute)
dp Actual Load (Hourly)
2,900
2,850
2,800
2,750
2,700
2,6s0
2,600
-l.l%, T-55 to next hour
z
r.l
ohonohohonohonono nonohohohohononohohI I - :1 C ql ql cl S S n n I 9 - - 9l ql n t:) :t t Y?'1? I I i i Cl Sl !'l !? S i 1? Y?F- F- r- F. r a- F- F- F- t-. F- F- € € € € € € € € € € € € 6 6 6 6 6 6 6 6 6 6 A A
Time (Interval Beginning)
+7 .4Yo,T-55 to next hour ITCIH
-ll
82
ataaaararalaaar..
PACIFICORP - 20I7 IRP APPENDIX F - FLEXIBLE RESERVE STUDY
Figure F.2 - Proxy Load Base Schedule
r Actual Load (5-minute)
u Base Schedule (Hourly)
- l. l7o, fiom prior week
o honoh ono nonoho hono nohohoho hc) hoho no hO O H r .l c.l o o + <t n h O O - - N N o o * * h n O O - - an c{ 6 o + $ n nf- f- F r i- C- f- r r F F F € € € € - a a € @ € € € O' O\ O\ O. O\ O. O\ O\ O. 6 O, 6
Time (Interval Beginning)
+7.4Yo,
2,900
2,8s0
2,800
4 r.rroE
E.l
2,700
2,650
2,600
83
rll
PACIFICoRP - 20 I7 IRP APPENDIX F -FLEXIBLE RESERVE STuoy
Base Schedule Ramping Adjustment
In actual operations, PacifiCorp's ACE calculation includes a linear ramp from the base schedule
in one hour to the base schedule in the next hour, starting ten-minutes before the hour and
continuing until ten-minutes past the hour. The hourly base schedules used in the study are
adjusted to reflect this transition from one hour to the next. This adjustment step is important
because, to the extent actual load or generation is transitioning to the levels expected in the next
hour, the adjusted base schedules will result in reduced deviations during these intervals,
potentially reducing the regulation reserve requirement. Figure F.3 below illustrates the hourly
base schedule and the ramping adjustment. The same calculation applies to all base schedules:
Load, Wind, Non-VERs, and the combined portfolio.
Figure F.3 - Base Schedule Ramping Adjustment
Data Corrections
The raw data extracted from PacifiCorp's systems for Load, Wind, and Non-VERs was reviewed
to identify potentially spurious data points prior to performing the regulation reserve requirement
calculations contained in the next section. Hourly intervals of data were excluded from the FRS
results if any five-minute interval within that hour suffered from at least one of the data anomalies
that are described further below:
r Base Schedule
Adjusted Base Schedule
t25
r20
ll5
>ilO
th -^_o lU)
6le
100
95
90 ohohohohohohohohohohohohononohonohonI C :: - ql q'! ql !? n :l: n Y? C I i i c! fl 11 i1 :t :l: Y?'1? C I i : ql !! 1M S n ! nOOOOOOOOOOOONNN'INNNNNNNN
Time (Interval Beginning)
84
T -
PACIFICORP-2017IRP APPENDIX F - FLEXIBLE RESERVE STupy
Load:
a
o
Stuck meter/flat meter reading
Telemetry spike/poor connection to meter
Wind and Non-VERs:o Deviations missing in CAISO databaseo Base schedules missing in CAISO databaseo Generator trip eventso Wind curtailment events
Load in PacifiCorp's BAAs changes continuously. While a BAA could potentially maintain the
exact same load levels in two five-minute intervals in a row, it is extremely unlikely for the exact
same load level to persist over longer time frames. When PacifiCorp's energy management system
("EMS") load telemetry fails, updated load values may not be logged, and the last available load
measurement for the BAA will continue to be reported. For instance, in one observed example,
PACW BAA load remained stuck at a single level for two days beginning at2:00 PM on January
6,2015. The change in load relative to the prior interval was calculated for the entire test period
and instances where multiple successive intervals showed no change in load were excluded from
the analysis since they are not indicative of actual operating conditions.
Similarly, rapid spikes in load either up or down are also unlikely to be a result of conditions which
require deployment of regulation reserve, particularly when they are transient. For example, a 637
MW drop in PACE BAA load occurred over one five-minute intervalon May 15,2015. Roughly
one hour later, PACE BAA load increased by 849 MW over two five-minute intervals. Such
events could be a result of a transmission or distribution outage, which would allow for the
deployment of contingency reserve, and would not require deployment of regulation reserve. A
similar spike on March 23,2015, spanned just one five-minute interval, and was likely a result of
a single bad load measurement. Load telemetry spike irregularities were identified by examining
the intervals with the largest changes from one interval to the next, either up or down. Intervals
with inexplicably large and rapid changes in load, particularly where the load reverts back within
a short period, were assumed to have been covered through contingency reserve deployment or to
reflect inaccurate load measurements. Because they don't reflect periods that require regulation
reserye deployment, such intervals are excluded from the analysis.
The available Wind and Non-VER data also includes some data irregularities. PacifiCorp
evaluated these irregularities and in some cases removed data that appears to be inaccurate. For
instance, PACW wind deviation data is missing in 36 five-minute intervals out of the 105,108
intervals in the study. Deviations are directly tied to regulation reserve requirements, so the hours
in which deviation data is missing are excluded from the analysis. Base schedules for PACE Non-
VERs are missing in 75 hours, while the other wind and Non-VER categories have smaller
amounts of missing data. While Wind base schedules are directly linked to the regulation
requirement forecast, missing base schedule data in PacifiCorp's database may be indicative of
inconsistencies in deviation results, which may be calculated off of a stale or erroneous base.
Given the limited frequency of such events, PacifiCorp has excluded from the analysis intervals
where deviations or base schedules are missing.
As with Load, certain Wind and Non-VER deviations are more likely to be a result of conditions
that allow for the deployment of contingency reserve, rather than regulation reserve. In particular,
85
PACIFICoRP-20I7IRP APPENDIX F - FLEXBLE RESERVE STUDY
contingency reserve can be deployed to compensate for unexpected generator outages. For Non-
VERs, these are relatively straightforward-namely, periods when generation drops to zero despite
base schedules indicating otherwise. Certain Wind outages also qualify as contingency events.
Notably, wind generators can be curtailed when wind speed exceeds the maximum rating of the
equipment (sometimes referred to as "high speed cutout"). In such instances, generation is
curtailed until wind speeds drop back into a safe operating range in order to protect the equipment.
When wind speed oscillates above and below the cut-off point, generation may ramp down and up
repeatedly. Because events which qualify for deployment of contingency reserve do not require
deployment of regulation reserve they have been excluded from the analysis.
As the regulation reserve requirements are calculated using a rolling thirty-minute timeline, data
from the prior hour is necessary during the first several five-minute intervals of the next hour. An
error in one hour thus results in the need to remove the following hour. This is relevant to error
adjustments for both Wind and Non-VERs.
For load, an hour of spurious data will prevent the calculation of the base schedule for the next
hour, since the actual load at T-55 is not available. The spurious data also impacts the same two
hours in the following week as the expected load change used to determine the base schedule for
those hours utilizes the hour in question. For example, if the hour beginning at midnight on
February 1,2015, is found to be spurious, four hours are removed from the Study Term: the
spurious hour (the hour ending midnight, February 1,2015); the hour following the spurious hour
(the hour ending l:00 AM, February 1,2015), which relies on the spurious hour to inform the
regulation forecast; and the two corresponding hours in the following week (the hour ending at
midnight, February 8, 201 5 and the hour ending at I :00 AM, February 8, 20 I 5), each of which no
longer has a valid prior-week hour from which to develop a proxy load base schedule. The
description of "Load Base Schedule Development" above contains further discussion about this
relationship and development of the base schedule.
After review of the data for each of the above anomaly types, and out of 105,120 five-minute
intervals in the Study Term, only 5.9 percent and 3.6 percent of the total FRS term hours were
removed from PACW and PACE, respectively. The system-wide error rate was 9.1 percent,
slightly lower than the sum of the PACW and PACE rates due to coincident hours. While cleaning
up or replacing anomalous hours could yield a more complete data set, determining the appropriate
conditions in those hours would be difficult and subjective. By removing anomalies, the FRS
sample is smaller but remains reflective of the range of conditions PacifiCorp actually experiences,
including the impact on regulation reserve requirements of weather events experienced during the
Study Term.
Non-VER Deviation Adjustment
The deviations associated with the Non-VER class show a clear anomaly between January 2015
and April 14,2015. The abrupt change is evident in the hourly data for PACW shown in Figure 4
below and a comparable anomaly was seen over the same time frame for PACE (not shown). The
anomaly ends abruptly at midnight on April 14,2015, in both BAAs. PacifiCorp has concluded
that this issue is a result of errors in base schedule submission rather than an actual deviation.
During the early stages of the EIM there were differences between the CAISO's EIM model and
PacifiCorp's EMS. The modeling of Colstrip generation was one of those differences. Within the
PacifiCorp EMS, 100 percent of Colstrip generation output is pseudo-tied into the PACW BAA.
However, the EIM modeled 50 percent of Colstrip generation as being in the PACW BAA and the
86
PACIFICoRP _ 20 I7 IRP APPENDIX F - FLEXTBLE RESERVE STuoy
other 50 percent of Colstrip generation as modeled in the PACE BAA. This mismatch between
the two systems resulted in the measured deviation.
The Colstrip EIM base schedule of 50 percent to PACE and 50 percent to PACW was compared
to the EMS output of 100 percent to PACW to determine the deviation. This resulted in a positive
deviation to base schedule for PACW. When the EIM model mismatch was discovered it was
corrected to align to PacifiCorp's EMS system. This eliminated the persistent deviation on April
14,2015. For the purposes of the FRS, the regulation reserve requirement for this period was
reduced by 58 MW such that the average requirement during this period is equal to the average in
the remainder of 2015. The box in Figures F.4 and F.5 below shows the affected data before and
after the adjustment is applied.
Figure F.4 - Original PACW Non-VER Deviations
The adjusted regulation reserve requirement is shown in Figure F.5 below.
.irr-. Iil
t .3r
Ir!r
160
140
120
100
2
Eso
6
60
40
20
0Ut/ts 2t1n5 3nn5 4lllts sluls 6lUt5 '7/Urs 8^fi5 9t1tr5 t0tv15 rvvts t2ntrs
. Original PACW Deviation
I
I
.t
a
ri.t'.F
a
I
a
aI
a II
87
a
Dr a
I
I
' r.i
PACIFICoRP-20I7IRP APPENDIX F - FLEXIBLE RESERVE STUDY
Figure F.5 - Adjusted PACW Non-YER Deviations
a
t.ftr
t.
?
{}-
160
140
120
100
2
Eso
6
60
40
20
0UUt5 2/t/15 3iln5 4lyt5 5ll7t5 61U15 7nn5 8fit15 9n/15 10iln5 tln/ts t2t1n5
. Adjusted PACW Deviation
a
a
I
;l
.t
a a
:.1
t
I
a
I
ttFI!
Overview
This section presents the methodology used to determine the initial regulation reserve needed to
manage the load and resource balance within PacifiCorp's BAAs. The five-minute interval load
and resource deviation data described above informs a regulation reserve forecast methodology
that achieves the following goals:
Complies with NERC standard BAL-001-2;
Minimizes regulation reserve held; and
Uses data available at time of EIM base schedule submission at T-55.1s
The components of the methodology are described below, and include:
Operating Reserve: Reserve Categories;
Calculation of Regulation Reserve Need;
Balancing Authority ACE Limit: Allowed Deviations;
Planning Reliability Target: Loss of Load Probability ("LOLP"); and
ts See footnote I I above for explanation of PacifiCorp's use of the T-55 base schedule time point in the FRS.
88
Methodologv to Determine Initial Reeulation Reserve Requirement
PACIFICoRP-20I7IRP APPENDIX F _ FLEXIBLE RESERVE STuoy
Regulation Reserve Forecast: Amount Held.
Following the explanation below of the components of the methodology, the next section details
the forecasted amount of regulation reserve for:
Wind;
Non-VERs;and
Load.
Components of Operating Reserre Methodology
Operating Reserve: Reserve Categories
Operating reserve consists of three categories: (1) contingency reserve (i.e., spinning and
supplemental reserve), (2) regulation reserve, and (3) frequency response reserve. These
requirements must be met by resources that are incremental to those needed to meet firm system
demand. The purpose of the FRS is to determine the regulation reserve requirement. The
contingency reserve requirement is defined formulaically by a regional reliability standard.
Of the three categories of reserve referenced above, the FRS is primarily focused on the
requirements associated with regulation reserve. Contingency reserve may not be deployed to
manage other system fluctuations such as changes in load or wind generation output. Because
deviations caused by contingency events are covered by contingency reserve rather than regulation
reserve, they are excluded from the determination of the regulation reserve requirements. On the
other hand, frequency response reserve can be considered a subset of the regulation reserve
obligation, though it requires faster responding resources than those contemplated in the FRS.
Because PacifiCorp has excess spinning reserve capability compared to its contingency reserye
obligation, the capacity and response time requirements for its frequency response obligations are
expected to be met by drawing from its existing pool of regulation reserve resources. As a result,
no incremental capacity requirements or resource constraints related to frequency response were
included in the FRS analysis. The types of operating reserve and relationship between them are
further defined in in the Flexible Resource Requirements section above.
Regulation reserve is capacity that PacifiCorp holds available to ensure compliance with the NERC
Control Performance Criteria in BAL-001-2, which requires a BAA to carry regulation reserve
incremental to contingency reserve to maintain reliability.l6 The regulation reserve requirement is
not defined by a simple formula, but instead is the amount of reserve required by each BAA to
meet specified control performance standards. Requirement 2 of BAL-001-2 defines the
compliance standard as follows:
Each Balancing Authority shall operate such that its clock-minute average of
Reporting ACE does not exceed its clock-minute Balancing Authority ACE Limit
(BAAL) for more than 30 consecutive clock-minutes...
The BAL-001-2 standard became effective as of July 1,2016 and, upon its effectiveness, officially
replaced the BAL-001-1 standard. The new BAL-001-2 standard is a fundamentally different
l6 NERC Standard BAL-00 l -2, http://www.nerc.com/files/BAl-001-2.pdf
89
PACIFICORP_20I7IRP APPENDIX F -FLEXIBLE RESERVE STuoy
requirement than the prior standard, BAL-001-1, though it is intended to achieve a similar result.
BAL-001-l required ten-minute average ACE to be within the static Lro limit in at least 90 percent
of non-overlapping ten-minute intervals in a month.17 The new BAL-001-2 standard requires
average ACE to be within a dynamic limit for at least one minute in 100 percent of all rolling
thirty-minute intervals. PacifiCorp has been operating under BAL-001-2 since March 1,2010, as
part of a NERC Reliability-Based Control field trial in the Western Interconnection, so PacifiCorp
has experience operating under the new standard, even though it did not become effective until
July 1,2016.
PacifiCorp's2012,2013, and 2014 studies were all based on compliance with BAL-001-1. These
studies utilized deviations over ten-minute intervals and allowed deviations up to the fixed Lro
value.l8,le While these studies all used a99.7 percent confidence interval, they did not necessarily
achieve 99.7 percent compliance with the BAL-001-1 standard. For instance, the 2014 Wind
Integration Study had a failure rate of 1.4 percent for PACE and2.0 percent for PACW.2o This is
higher than the 90 percent compliance requirement under BAL-001 - l, but significantly lower than
the 100 percent compliance requirement under BAL-001-2. In addition, prior studies separately
distinguished between three categories of regulation reserve, all of which were intended to capture
the total potential deviation over the ten-minute interval relevant under BAL-001- l :
Ramping - flexibility required to follow the change in actual net system Load from hour
to hour;
Regulating - flexibility required to manage forecast uncertainty over ten-minute intervals;
and
Following - flexibility required to manage forecast uncertainty over sixty-minute intervals.
The FRS fundamentally differs from the 2012,2013, and 2014 studies because it is based on
compliance with BAL-001-2. The impacts of the changes in three key elements of the new BAL-
001-2 standard relative to the old standard are summarized in Table F.3 below. The three key
elements shown in Table F.3 include: (l) the length of time (or "interval") used to measure
compliance under the old versus new BAL standard; (2) the change in compliance threshold
between the two standards, which represents the percentage of intervals that a BAA must be within
the limits set in the standard; and (3) the bandwidth of acceptable deviation used under each
standard to determine whether an interval is considered out of compliance. These changes are
discussed in further detail below.
17 BAL-001-I (R2) stated: Each Balancing Authority shall operate such that its average ACE for at least 90
percent of clock-ten-minute periods (6 non-overlapping periods per hour) during a calendar month is within a
specific limit, referred to as Lro.
't L,o represents a bandwidth of acceptable deviation under BAL-001-l prescribed by WECC between the net
scheduled interchange and the net actual electrical interchange ofPacifiCorp's BAAs.
le The Lro for PacifiCorp's BAAs in 2015 were approximately 33.49 MW for PACW and 49.92 MW for
PACE. For more information, please refer to:
hfio..llwww.nerc.com/comm/OClRSo/o20Landineo/o20Paseo/o20DL/CPS2o/A0Bowdso/o20Reoortsl20l5yo20CPS2o/A
0B oundso/o20 Report%2O F inal %o202 0 I 5 06 I 5.pdf
20 See Redacted Rebuttal Testimony of Brian S. Dickman, Wyoming Public Service Commission Docket No.
20000-469-ER-15 at p.46:1-6 (filed Sept. 16,2015).
90
PACIFICORP-20I7IRP APPENDIX F -FLEXIBLE RESERVE STuny
Table F.3 - BAL-001-1 vs BAL-001-2
The first change in Table F.3 is related to the length of time used to measure compliance. Under
the prior standard, BAL-001-1, compliance was measured over six, non-overlapping ten-minute
intervals within each hour. If ACE was within the allowed limits for all ten minutes of an interval,
that interval was in compliance, and only the maximum deviation in that interval was considered
in determining compliance. Compliance under BAL-001-2 is measured over rolling thirty-minute
intervals, with sixty overlapping periods per hour, some of which include parts of two clock-hours.
In effect, this means that every minute of every hour is the beginning of a new, thirty-minute
compliance interval under the new BAL-001-2 standard. If ACE is within the allowed limits at
least once in a thirty-minute interval, that interval was in compliance, and only the minimum
deviation in each thirty-minute interval is considered in determining compliance. This change
reduces regulation reserve requirements because PacifiCorp does not need to hold regulation
reserve for deviations with duration less than 30 minutes.
The second change in Table F.3 above is related to the compliance percentage, or the number of
intervals where deviations are allowed to be outside the limits set in the standard. BAL-001-I
required 90 percent compliance, that is, l0 percent of ten minute intervals were allowed to have
deviations in excess of the requirement in the standard. BAL-001-2 requires 100 percent
compliance, so deviations must be maintained within the requirement set by the standard for all
rolling thirty-minute intervals. Under the old standard, overall compliance could be achieved
despite shortfalls in the intervals with the largest deviations. Because shortfalls are not permitted
when the compliance requirement is 100 percent, this change increases regulation reserve
requirements.
The third change in Table F.3 is related to the bandwidth of acceptable deviation before an interval
is considered out of compliance. Under BAL-001- l, the acceptable deviation for each BAA was
set at a fixed value in all intervals, referred to as Lro.2l Under BAL-001-2, the acceptable deviation
for each BAA is dynamic, varying as a function of the frequency deviation for the entire
interconnect. The impact of this change is mixed as the limits under BAL-001-2 are generally
higher, but at times can be lower than the limits under BAL-00 I - I .
In addition, the FRS identifies a single category of flexible capacity, rather than the three categories
used in the prior studies performed in compliance with the old standard. Because deviations over
ten-minute intervals are only relevant to the extent they exacerbate deviations over longer time
2r The Lro for PacifiCorp's BAAs in 2015 were approximately 33.49 MW for PACW and 49.92 MW for
PACE. For more information, please refer to:
hr.'{:/lwww.nerc.com/comm/OClRSo/A0Landineo/A}Pageo/oZ0DLlCPS2o/o2}Boundsyo2}Reportsl20l5o/o20CPS2o/o2
0Bounds%2OReport%20Final%2020 I 506 I 5.edf .
90%Fixed: L16BAL-001-l 10
BAL-001-2 30 t00%Dynamic: BAAL
Up VariesInrpact on
Requirement Down
91
Interval
(minutes)Comoliance 7o
Allourcd
Variance
PACIFICoRP - 20I7 IRP APPENDIX F - FLEXIBLE RESERVE STUDY
frames, measuring three separate categories does not provide an accurate depiction of the
requirements under BAL-001-2. In addition, while the following and regulating requirements in
prior studies were statistically uncorrelated over the course of the year, the root sum square
methodology used in the prior studies fails to account for the few random intervals when these
components both show large requirements. Because the root sum square methodology
underestimates the frequency of outlier events, it underestimates the capacity needed to cover
them. The FRS eliminates complexity and distortion associated with combining multiple
requirements by directly calculating a single componentthat allows for compliance with the BAL-
001-2 standard.
Calculation of Regulation Reserve Need
The next step of the operating reserve methodology is to calculate the amount of regulation reserve
required to be held under BAL-001-2. Regulation reserve requirements were calculated from five-
minute EIM deviation data in a manner that emulates the requirements of the BAL-001-2 standard.
The same calculation applies to all types of imbalances: Load, Wind, Non-VERs, and the
combined portfolio.
First, the minimum five-minute imbalance was calculated for each thirty-minute rolling period in
the Study Term. Second, for each hour, the maximum five-minute imbalance was selected from
the values identified in the first step. An example is provided in the Table 2 and Figure 6 below.
In the example in Table F.4 below, the minimum five-minute imbalance in the thirty minutes
beginning at 0:15 is 40 MW. This is also the maximum five-minute imbalance in any thirty-minute
period in this hour. Assuming 40 MW of regulation reserve was available in this hour and the
allowable ACE deviation was zero, this hour would still be compliant with the BAL-001-2
requirement-even though the imbalance exceeds the regulation reserve available for five
consecutive, five-minute intervals-because the allowable ACE deviation was exceeded for less
than 30 minutes.
Table F.4 - Deviation and Regulation Reserve Requirement Example
10 100:00 2500 2510 40
0:05 2520 20 10 40
30 t00:10 2s30 40
0:15 2540 40 l0 40
50 l00202550 40
2560 60 l0 40025
0:30 2570 70 20 40
03s 2s60 60 30 40
502550 40 400:40
0:45 2540 40 40 40
2530 30 30 400:50
2520 20 20 400:55
92
fnloxrol
Base
Schedule Actual
5-Minute
Deviation
30-Minute
Deviation
Reserve
Reouircment
80
70
60
ffiDeviation
-ReserveRequirement
lll rninules
50
z
840i6
B'
2
30
20
l0
0 ohohohohohon99::inqlf)rin9n
Time (minutes)
APPENDIX F _ FLEXBLE RESERVE STUDY
As shown in Figure F.6 below, if the ACE deviations were only allowed for a ten minute interval,
the requirement would be higher.
Figure F.6 - Deviation and Regulation Reserve Requirement Example
Figure F.7 below illustrates the dishibution of the combined five-minute deviations for Load,
Wind, and Non-VERs in PACE during 2015, as well as the distribution of thirty-minute sustained
deviations relevant to the BAL-001-2 standard. The effect for PACW was comparable (not
shown). The thirty-minute window for compliance reduces the regulation reserve need. The
thirty-minute window can be particularly helpful with deviations in the last few intervals of each
hour. This period has the longest forecast horizon (i.e., the furthest out from T-55), so the potential
deviations are expected to be larger. However, if the change resulting in the deviation is reflected
in the base schedule for the next hour, PacifiCorp's ACE will return to zero on its own a few
minutes later. Thus, so long as the duration of the deviation is less than 30 minutes, the size of the
deviation in the last few intervals is irrelevant for compliance with BAL-001-2.
93
PACIFICoRP - 20 I7 IRP
araralilaaallarrlrr
< 30 minutes
rrrratatlatrtrararrattrrttrartttataatllralattt
> 30 minutes
PACIFICoRP - 20 I7 IRP APPENDIX F -FLEXIBLE RESERVE STUDY
500
450
400
350
-PACE
5-Min Deviations
... .. PACE 30-min Deviations
^ 300ta
E zso
.E
o
' zoo
1s0
100
50
0
0%l0o/o 20o/o 30%
Exceedance Probrbility
40%s0%
Figure F.7 - Probability Distribution of PACE Combined Portfolio Deviations
Balancing Authority ACE Limit: Allowed Deviations
Even if insufficient regulation reserve capability is available to compensate for a thirty-minute
sustained deviation, a violation of BAL-00 I -2 does not occur unless the deviation also exceeds the
Balancing Authority ACE Limit.
The Balancing Authority ACE Limit is specific to each BAA and is dynamic, varying as a function
of interconnection frequency. When WECC frequency is close to 60 Hz, the Balancing Authority
ACE Limit is large and large deviations in ACE are allowed. As WECC frequency drops further
and further below 60Hz,ACE deviations are increasingly restricted for BAAs that are contributing
to the shortfall, i.e. those BAAs with higher loads than resources. A BAA commits a BAL-001-2
reliability violation if in any thirty-minute interval it doesn't have at least one minute when its
ACE is within its Balancing Authority ACE Limit.
While the specific Balancing Authority ACE Limit for a given interval cannot be known in
advance, the historical probability distribution of Balancing Authority ACE Limit values is known.
Figure 8 below shows the probability of exceeding the allowed deviation during a five-minute
interval for a given level of ACE shortfall. For instance, a 47 MW ACE shortfall in PACE has a
one percent chance of exceeding the Balancing Authority ACE Limit. The fixed value under the
prior BAL-001-1 standard for Lro is also plotted for comparison. WECC-wide frequency can
change rapidly and without notice, and this causes large changes in the Balancing Authority ACE
94
PACIFICoRP - 20 17 IRP APPENDIX F - FLEXIBLE RESERVE STUDY
Limit over short time frames. Maintaining ACE within the Balancing Authority ACE Limit under
those circumstances can require rapid deployment of large amounts of operating reserye. To limit
the size and speed of resource deployment necessitated by variation in the Balancing Authority
ACE Limit, PacifiCorp's operating practice caps permissible ACE at the lesser of the Balancing
Authority ACE Limit or four times Lro. This also limits the occurrence of transmission flows that
exceed path ratings as result of large variations in ACE.22'23 This cap is reflected in Figure F.8.
Figure F.8 - Probability of Exceeding Allowed Deviation
100%
90%
80%
70o/o
EO:
x.:
o>
!c6t
:i
600/o
50%
40o/o
30o/o
20%
t0%
lYo
0 40 60 80 100 120
ACE Shortfall (MW)
140 160 180 200
-westBAAr -East
BA,AI
.....EastL10
In 2015, PacifiCorp's deviations and Balancing Authority ACE Limits were uncoffelated, which
indicates that PacifiCorp's contribution to WECC-wide frequency is small. PacifiCorp's
deviations and Balancing Authority ACE Limits were also uncorrelated when periods with large
deviations were examined in isolation. If PacifiCorp's large deviations made distinguishable
contributions to the Balancing Authority ACE Limit, ACE shortfalls would be more likely to
exceed the Balancing Authority ACE Limit during large deviations. Since this is not the case, the
probability of exceeding the Balancing Authority ACE Limit is lower, and less regulation reserve
is necessary to comply with the BAL-001-2 standard.
22 "Regional Industry Initiatives Assessment." NWPP MC Phase 3 Operations Integration Work Group. Dec. 3 1,
2014. Pg. 14. Available at: http://www.nwpp.ore/documents/MC-Public/NWPP-MC-Phase-3-Regional-Industr.y-
Initiatives-Assessment I 2-3 1 -20 I 4.pdf
23 "NERC Reliability-Based Control Field Trial Draft Report." Western Electricity Coordinating Council. Mar.25,
2015. Available at: https://www.wecc.bizlReliability/RBC%20Field%20Trial%20Reoort%20Approved%203-25-
20t5.pdf
95
20
.... . West LlO
PACIFICoRP-20I7IRP APPENDIX F - FLEXIBLE RESERVE STUDY
Planning Reliability Target: Loss of Load Probability
When conducting resource planning, it is common to use a reliability target that assumes a
specified LOLP. In effect, this is a plan to curtail firm load in rare circumstances, rather than
acquiring resources for extremely unlikely events. The reliability target balances the cost of
additional capacity against the benefit of incrementally more reliable operation. By planning to
curtail firm load in the rare event of a regulation reserve shortage, PacifiCorp can maintain the
required 100 percent compliance with the BAL-001-2 standard and the Balancing Authority ACE
Limit. This balances the cost of holding additional regulation reserve against the likelihood of
regulation reserve shortage events.
PacifiCorp's 2015 Integrated Resource Plan ("lRP") utilized a planning reserve margin of l3
percent, which is intended to achieve 0.88 loss of load hours per year.za This FRS assumes that
0.88 loss of load hours per year due to regulation reserve shortages is appropriate for planning and
ratemaking purposes. This is in addition to any loss of load resulting from transmission or
distribution outages, resource adequacy, or other causes. The FRS applies this reliability target as
follows:
If the regulation reserve available is greater than the regulation reserve need for an hour,
the LOLP is zero for that hour.
If the regulation reserve held is less than the amount needed, the LOLP is derived from the
Balancing Authority ACE Limit probability distribution. As the magnitude of the shortfall
increases, the probability of exceeding the Balancing Authority ACE Limit increases. For
instance, as indicated above, a 47 MW ACE shortfall in PACE has a one percent chance of
exceeding the Balancing Authority ACE Limit. A one percent probability of failing to
meet the Balancing Authority ACE Limit in one hour is 0.01 loss of Load hours per year.
A one percent probability of failing to meet the Balancing Authority ACE Limit in eighty-
eight hours would be 0.88 loss of load hours per year and corresponds to the targeted level
of reliability.
Regulation Resere Forecast: Amount Held
As previously shown in Figure 7, the instances requiring the largest amounts of regulation reserve
occur infrequently, and many hours have very low requirements. If periods when requirements
are likely to be low can be distinguished from periods when requirements are likely to be high,
less regulation reserve is necessary to achieve a given reliability target. As described above, the
regulation reserve forecast is not intended to compensate for every potential deviation. Instead,
when a shortfall occurs, the size of that shortfall determines the probability of exceeding the
Balancing Authority ACE Limit and a reliability violation occurring. The forecast should achieve
a cumulative LOLP that corresponds to the annual reliability target.
PacifiCorp submits balanced base schedules to CAISO for its load and resources by T-55.25
Operating reserve is intended to cover demand in excess of the balanced load and resources
submitted in base schedules. Capacity to be used as operating reserve needs to be identified and
24 2015 IRP, Appendix I, Table I.3
25 See footnote 9 for explanation of PacifiCorp's use of the T-55 base schedule time point in the Regulation
Reserve Study.
a
96
PACIFICoRP-20I7IRP APPENDIX F - FLEXIBLE RESERVE STUDY
set aside so that it is not utilized in the base schedule submission. Likewise, the regulation reserve
forecast identifying the quantity of operating reserve to be set aside for the upcoming hour needs
to be finalized by T-55.
The base schedule itself reflects the best, most up-to-date information about conditions in the
upcoming hour. The next section describes how the information available can be used to forecast
regulation reserve requirements for each of the regulation reserve classes while maintaining
reliability. The portfolio regulation reserve requirement forecast incorporates each of the
resource/load class forecasts and accounts for the reduced requirements resulting from diversity
between the classes. All of these calculations are prepared separately for each of the PacifiCorp
BAAs.
2015 Regulation Reserre Forecast
Wind
Figure F.9 illustrates the relationship between the observed regulation reserve requirements for
wind during 2015 and the forecasted level of output, stated as a capacity factor (i.e., a percentage
of the nameplate wind capacity).
Three distinct patterns are apparent in the figure. First, for capacity factors from zero percent to
approximately 20 percent, the regulation reserve requirement increases linearly. The linear
relationship in this first range reflects the fact that the largest possible deviation is equal to the base
schedule and a very small amount of negative generation (station service). Second, for capacity
factors from approximately 20 percent to approximately 80 percent, the maximum requirement
varies somewhat widely and does not exhibit significant trends. Third, as capacity factors increase
above approximately 80 percent, the observed maximum requirement declines.
97
PACIFICoRP * 20 I7 IRP APPENDIX F - FLEXIBLE RESERVE STuny
Figure F.9 - Wind Regulation Reserve Requirements by Forecast Capacity Factor
When evaluating the distribution of maximum requirements above an approximately 20 percent
capacity factor, it is important to consider the characteristics of an observed maximum within a
sample. The mean of a sample may be higher or lower than the mean of the population from which
it is drawn, but it is not expected to vary systematically with sample size. This is not the case for
the maximum of a sample, which will always be less than or equal to the maximum of the
population from which it is drawn. In addition, the expected value of the sample maximum
increases as the sample size increases.
The sample size of each forecasted capacity factor varies, with very high capacity factors occurring
less frequently. With this consideration in mind, the decline in observed maximum requirements
at high capacity factors can be viewed as an artifact of the sample rather than a real trend related
to the behavior of wind under those specific conditions. This view is reinforced by the fact that
the average and standard deviation of the requirements are relatively constant at forecasted
capacity factors above roughly 20 percent. Because the probability of a large deviation doesn't
vary for capacity factors above roughly 20 percent, a single regulation reserve requirement is a
reasonable forecast for that range.
Figure F.l0 below presents the regulation reserve forecast for PACE and PACW wind,
incorporating the two trends described above: (1) the linear increase in requirements at low
capacity factors (i. e. , below 20 percent) ; and (2) a uniform requirement at higher capacity factors
(i.e., from 20 percent to 100 percent). As illustrated in Figure 10, PACW had 888 hours with
forecasted capacity factors between 4l percent and 55 percent, while PACE had 1,115 hours in
6
z
6
6
o
45o/o
40o/o
35o/o
30%
25%
20%
l5o/o
l0o/o
5%
0o/o
-Me(
Requirement PACW
-Max
Requirement PACE
..'.....'Std Dev Req PACW
.-'.*" Std Dev Req PACE n tl
-Avg
Req PACW
-Avg
Req PACE ll Al
II
Ir II
lt
I
\l I t
^A IJ I l\/r\l[
I
/ll A,t
ill^
1l
fit
t{\}l
0% 5o/o liYo 15% 20% 25%o 30o/o 35yo 40% 45%o 50o/o 55% 60% 65% 70% 75o/o 80%o 85% 90% 95% 100%
Forecast Capacity Factor
98
\t
\l
ti . L i':r ;:it -r,j:i,ll.j U'Ja." -
^':.r!
PACIFICoRP - 2017 IRP APPENDIX F _ FLEXIBLE RESERVE STuoy
that range. PACW only had 64 hours with forecasted capacity factors of 85 percent or more, while
PACE only had 109 hours in that range.
The wind regulation reserve forecast is a fixed percentage of the wind nameplate capacity, but
never more than the difference between minimum actual output and the base schedule. The fixed
percentage of nameplate capacity is set at the minimum level that achieves the reliability target of
0.88 loss of load hours per year. The forecast resulted in the possibility of reliability violations in
roughly one percent of the hours. While the forecast does not result in any potential reliability
violations at high capacity factors, this is likely due to the small number of observations in this
range, as described above.
Using a forecast based on the hour-ahead base schedule results in a 2015 stand-alone regulation
reserve requirement for wind of 384 MW, or approximately 14.8 percent of nameplate capacity.
This forecast does not account for any diversity benefit from combining the reserve requirements
for wind with the requirements of other classes. Diversity benefits are discussed later on in the
study.
Figure F.10 - Stand-alone Wind Regulation Reserve Forecast
45o/o
40o/o
35%
30o/o
25%
20%
l5o/o
l0o/o
5o/o
0Yo
-Max
Requirement PACW
-Max
Requirement PACE
-Forecast
Reserve PACW
-Forecast
Reserve PACE n tl
il AlI
I
ill
il I \i \/
I
I ,lA/\JI/\/t l'I Art
Yv I I t
I
tA11l
0o/o 5%o l0o/o l5%;o 20o/o 25o/o 30o/o 35o/o 40%o 45% 50yo 55o/o 600/o 650/o 70Yo 75% 80yo 85% 90% 95o/o 100/o
Forecast Capacity Factor
6
6z
!
6
6
9
99
PACIFICORP _ 20 I7 IRP APPENDIX F - FLEXIBLE RESERVE STUDY
Non-VERs
Figure F.l I below illustrates the observed regulation reserve requirements for Non-VERs during
2015 as a function of the forecasted level of output, stated as a capacity factor (i.e., a percentage
of the nameplate Non-VERs capacity). For Non-VERs, the forecasted capacity factors during
2015 fall within limited ranges and do not approach either zero or 100 percent. Since the
distribution of errors appears to be essentially random, the base schedule provides limited
forecasting value for Non-VERs, resulting in a single reserve value applied in all hours.
Figure F.11 - Non-VER Regulation Reserve Requirements by Forecast Capacity Factor
-Max
Requirement PACW - - *- St Dev Req PACW
-Avg
Req PACW
-
Max Requirement PACE ----- St Dev Req PACE
-
Avg Req PACE
lnn /t
20o/o
riU
ls% d*
--S
ro%E E.=z
+EeE5o/o g
20o/o
l5o/o
l0%io
5o/o
0o/o
0%
U
64.
Ei'=z
0% 10% 20o/o 30o/o 40o/o 50o/o 600/o
Forecrst Cepacity Factor
70o/o 80o/o 90o/o l00o/o
Figure F.l2 below illustrates the observed regulation reserve requirements for Non-VERs during
2015 as a function of hour of the day. The average and standard deviation are very low compared
to the maximum events, indicating the relative rarity of large deviation events. However, the
maximum, average, and standard deviation all exhibit comparable trends, indicating that the
characteristics of the maximum are also reflected in the rest of the data for those periods. While
an overall diurnal pattern is noticeable, significant volatility in the observed maximum
requirements is apparent from hour to hour. For example, consider the significant drop in the
observed maximum requirement for PACW in hour 19 relative to hours l8 and 20. The average
and standard deviation do not indicate that hour l9 is significantly different from hours l8 and 20.
As a result, this drop is more likely to be from randomness in the sample, rather than a specific
characteristic ofhour l9 itself.
100
PACIFICORP-20I7IRP APPENDIX F _FLEXIBLE RESERVE STUDY
Figure F.lz - Non-VER Regulation Reserve Requirements by Hour of the Day
20o/o
l5o/o
l0o/o
5%
0%
U
a'd-:
Es
B' .'tz
20%
l5o/o
t0%
5o/o
0o/o
3U
6E2'.;
!al
g;'=z
0 I 2 3 4 5 6 7 8 9 l0rt12t3 14151617181920212223
Hour
NSt Dev Req PACW rAvg Req PACW @)StDev Req PACE
-Mil(
Req PACW
-Max
Req PACEIAvg Req PACE
\-/ \-_/
ht\ t\
Figure F.13 below presents the regulation reserve forecast for each hour of the day for PACE and
PACW Non-VERs. The forecast is based on the rolling three-hour maximum of regulation reserve
requirements from 2015. This produces a smoother forecast, reflecting realistic hourly variation
rather than just aligning with the large events in the sampled data for 2015. The forecasted
requirement is then reduced by a fixed percentage until it reaches the minimum level necessary to
achieve the reliability target of 0.88 loss of load hours per year. This forecast resulted in the
possibility of reliability violations roughly I .l percent of the time on PACW, and 2.6 percent of
the time on PACE. Due to the lower probability of a reliability violation in each hour for PACE
Non-VERs, more hours of potential violations are aggregated to reach the reliability target of 0.88
loss of load hours per year. Using a forecast based on the hour of the day results in a2015 stand-
alone regulation reserve requirement forNon-VERs of 83 MW, or approximately 3.7 percent of
nameplate capacity. This forecast does not account for any diversity benefit from combining the
regulation reserve requirements for Non-VERs with the requirements of other classes.
l0l
a - A-LA-A-E-Z-aLaLtt-LLa LLLa a-riL
\
PACIFICORP - 20 I7 IRP APPENDIX F _ FLEXIBLE RESERVE STUDY
Figure F.l3 - Stand-alone Non-VER Regulation Reserve Forecast
Load
Figure F.l4 below illustrates the relationship between the observed regulation reserve
requirements for load during 201 5 and hour of the day. Similar to the results for Non-VERs, the
average and standard deviation are very low compared to the maximum events, indicating the
relative rarity of large deviation events. However, the maximum, average, and standard deviation
all exhibit comparable trends, indicating that the characteristics of the maximum are also reflected
in the rest of the data for those periods.
20o/o
l5o/o
t0%
5o/o
0o/o
riU
God-s
P6
+E
&,2
20o/o
t5%
l0o/o
5o/o
0o/o
U
d0.
!d
'=Z
tr
0 l 2 3 4 5 6 7 I 9 1011121314151617181920212223
Hour
-Mil(
Req PACW oForecast PACW
-Mil(
Req PACE
-Forecast
PACE
\-_/ \_/
t\ t\
102
PACIFICORP _ 20 I7 IRP APPENDIX F *FLEXBLE RESERVE STUDY
Figure F.14 - Stand-alone Load Regulation Reserve Requirements by Hour of the Day
NlStDev Req PACW rAYg Req PACW
IAvg Req PACE
-Max
Req PACW
,/\ .^- ,--.
@St Dev Req PACE
-Max
Req PACE
lv
/
EL E S .-. * NL M il S S M S H & S S E S M fi M N T U
800
600
400
200
riU
ilij
il
400 0
B :ooU
ii9 200
9
& too
0 0 I 2 3 4 5 6 7 I 9 10111213t4151617t819202t2223
Hour
Figure F.15 below presents the regulation reserve forecast for each hour of the day for PACE and
PACW load. The forecast is based on the rolling three-hour maximum of regulation reserve
requirements from 2015. This produces a smoother forecast, reflecting realistic hourly variation
rather than just aligning with the large events in the sampled data for 2015. The forecasted
requirement is then reduced by a fixed percentage until it reaches the minimum level necessary to
achieve the reliability target of 0.88 loss of load hours per year. This forecast resulted in the
possibility of reliability violations roughly 0.7 percent of the time in both PACW and PACE.
Using a forecast based on the hour of the day results in a 2015 stand-alone regulation reserve
requirement for load of 433 MW, or approximately 4.5 percent of the lzCP. This forecast does
not account for any diversity benefit from combining the reserve requirements for load with the
requirements of other classes.
103
L L L - * hhrhhhhhhhhhhhhh il w u
PACIFICoRP - 20I7 IRP APPENDIX F - FLEXTBLE RESERVE STUDY
Figure F.15 - Stand-alone Load Regulation Reserve Forecast
PacifiCorp System-Wide Portfolio Diversity Benefit
The EIM is a voluntary energy imbalance market service through the CAISO where market
systems automatically balance supply and demand for electricity every fifteen minutes,
dispatching the least-cost resources every five minutes.
PacifiCorp began full EIM operation on November 1,2014. NV Energy began full operation in
EIM on December l, 2015. Puget Sound Energy and Arizona Public Service Company
commenced EIM participation on October 1,2016. Additionally, several other entities have
announced their intention to begin participating over the next few years. PacifiCorp's participation
in the EIM results in improved power production forecasting and optimized intra-hour resource
dispatch. This brings important benefits including reduced energy dispatch costs through
automatic dispatch, enhanced reliability with improved situational awareness, better integration of
renewable energy resources, and reduced curtailment of renewable energy resources
EIM also direct effects related to regulation reserve requirements. First, as a result of EIM
participation, PacifiCorp has improved granularity for data used in the analysis contained in this
FRS. The data and control provided EIM allow PacifiCorp to achieve the portfolio diversity
benefits described in this section. Second, the EIM's intra-hour capabilities across the broader EIM
-MaxReqPACW
rForecastPACW
-MaxReqPACE -ForecastPACE
,/\ z^- ,--
\\=J/
\I\e</
800
600
400
200
riU
il
400 0
> 300
(.)
iii zoo
I
& roo
0 0 I 2 3 4 5 6 7 8 9 l0tlt2t3 14151617181920212223
Hour
104
2015 PacifiCorp System Diversity and EIM Diversity Benefits
PACIFICORP_20I7IRP APPENDIX F - FLEXIBLE RESERVE STuoy
footprint provide the opportunity to reduce the amount of regulation reserve necessary for
PacifiCorp to hold, as further explained in the next section.
The regulation reserve forecasts described above (384 MW for Wind, 83 MW for Non-VERs, and
433 MW for Load) independently ensure that the probability of a reliability violation for each class
remains within the reliability target; however, the largest deviations in each class tend not to occur
simultaneously, and in some cases deviations will occur in offsetting directions. Because the
deviations are not occurring at the same time, the regulation reserve held can cover the expected
deviations for multiple classes at once and a reduced total quantity of reserve is sufficient to
maintain the desired level of reliability. This reduction in the reserve requirement is the diversity
benefit from holding a single pool of reserve to cover deviations in Wind, Non-VERs, and Load.
As a result, the regulation reserve forecast for the portfolio can be reduced while still meeting the
reliability target.
As shown in Table F.5 below, the sum of the stand-alone forecasts for each class results in a
cumulative LOLP of 0.03 hours per year. This is significantly less than the target of 0.88 hours
per year as a result of the diversity among the different classes. PacifiCorp then calculated the
proportional reduction to the standalone requirement-the diversity benefit shown in the second
column of values in Table 3-that could be applied such that the PacifiCorp system just achieves
the reliability target for the Study Term. A total portfolio requirement of 654 MW is sufficient to
achieve the reliability target, resulting in diversity benefits equal to 118 MW for Load, 105 MW
for Wind, and 23 MW for Non-VERs. The last column of Table 3 shows the regulation
requirements for each class that incorporates the proportional allocation of portfolio diversity
benefits. The diversity benefits result in a 27 percent reduction from the total standalone
requirement of 900 MW.
Table F.5 - Results with PacifiCorp Portfolio Diversity
EIM Intra-Hour Benefit
In addition to the direct benefits from EIM's increased system visibility and improved intra-hour
operational performance described above, the participation of other entities in the broader EIM
footprint-such as NV Energy, Puget Sound Energy, and Arizona Public Service Company-
provides the opportunity to further reduce the amount of regulation reserve PacifiCorp must hold.
By pooling variability in load, wind, and solar output, EIM entities reduce the quantity of reserve
required to meet flexibility needs. The EIM also facilitates procurement of flexible ramping
(23\60Non-VER 83
Load 433 (1 18)315
VER - Wind 384 (10s)279
(246)Total 900 654
Porfolio LOLP
(hours/year)0.03 0.88
105
Scenario
Stand-alone
Regulation
Forecast
(aMW)
Diversity
Benelit
(aMW)
Portfolio
Regulation
Forecast
(aMW)
PACIFICoRP-2017IRP APPENDIX F _ FLEXIBLE RESERVE STuoy
capacity in the fifteen-minute market to address variability that may occur in the five-minute
market. Because variability across different BAAs may happen in opposite directions, the flexible
ramping requirement for the entire EIM footprint can be less than the sum of individual BAAs'
requirements. This difference is known as the "flexible ramping procurement diversity savings"
in the EIM. This intra-hour benefit reflects offsetting variability and lower combined uncertainty.
This flexibility reserve is in addition to the spinning and supplemental reserve carried against
generation or transmission system contingencies under the NERC standards.
The CAISO calculates the EIM intra-hour benefit by first calculating a flexible reserve requirement
for each individual EIM BAA and then by comparing the sum of those requirements to the flexible
reserye requirement for the entire EIM area. The latter amount is expected to be less than the sum
of the flexible reserve requirements from the individual BAAs due to the portfolio diversification
effect offorecasting a larger pool of load and resources using intra-hour scheduling and increased
system visibility in the hypothetical, single-BAA EIM. Each EIM BAA is then credited with a
share of the intra-hour benefit calculated by CAISO based on its share of the stand-alone
requirement relative to the total stand-alone requirement.
The EIM does not relieve participants of their reliability responsibilities. EIM entities are required
to have sufficient resources to serve their load on a standalone basis each hour before participating
in the EIM. Thus, each EIM participant remains responsible for all reliability obligations. Despite
these limitations, EIM imports from other participating BAAs can help balance PacifiCorp's loads
and resources within an hour, reducing the size of reserve shortfalls and the likelihood of a
Balancing Authority ACE Limit violation. While substantial EIM imports do occur in some hours,
it is only appropriate to rely on PacifiCorp's share of the intra-hour benefits associated with EIM,
as these are derived from the structure of the EIM rather than resources contributed by other
participants.
Under the current EIM operational structure, the calculated EIM intra-hour benefit is not known
to PacifiCorp prior to its base schedule submission at T-55. The CAISO does not finalize the intra-
hour benefit until T-40, therefore making it too late to incorporate any of the benefit into
PacifiCorp's base schedule.
Table F.6 below provides a numeric example of flexible reserve requirements for each EIM
participating BAA and application of the calculated intra-hour benefit.
Table F.6 - EIM Flexible Reserve Benefit
While the intra-hour benefit is uncertain, that uncertainty is not significantly different from the
uncertainty in the Balancing Authority ACE Limit described above. PacifiCorp proposes crediting
its regulation reserve forecast with a probability distribution of calculated EIM intra-hour benefits
il0 165l5-mintle Interval I 5s0 r00 925 s83 342 17.8%6t r04
15-minrle Interval 2 600 il0 165 100 975 636 339 16.9o/o 57 108
l5-minr.rte Interval 3 650 il0 r65 il0 1,035 689 346 15.90/o 55 110
667 120 180 I 13 1.080l5-minute Interval 4 742 338 16.7o/o 56 124
106
TotaI
diveIsity
benefit
(MW)
NEVP
rtq't
beforr
benefit
rMw)
PACE
rcq't
befort
benefit
(MW)Interval
CAISO
rcq't
befort
benefit
(MW)
PACW
rcq't
before
benelit
(MW)
Total
rcq't-
before
benefit
(MW)
Total
rcq't.
after
benefrt
(MW)
PACE
sharr
(Yo\
PACE
benefit
(MW)
PACE
rcq't
after
benefit
(MW)
PACIFICoRP-20I7 IRP APPENDIX F - FLEXIBLE RESERVE STUDY
based on historical results. When a potential regulation shortfall occurs, the probability that the
EIM intra-hour benefit would have exceeded that level can be calculated, and the LOLP associated
with that event goes down. As a result, PacifiCorp's regulation reserve requirements can be
reduced until the reliability target is again just achieved. While this FRS considers regulation
reserve requirements in 2015, the participation of NV Energy in the EIM starting in December
2015 has resulted in increased intra-hour benefits. To capture these additional benefits for this
analysis, PacifiCorp has applied the probability distribution of EIM intra-hour benefits from
January 2016 through June 2016 because it is a more reasonable representation of actual operations
going forward than the 2015 results. Relatively small incremental EIM diversity benefits are
expected going forward as additional entities participate in EIM; however, operational data on new
participants was not available at the time the study was prepared.
The inclusion of EIM intra-hour benefits in the 2015 regulation reserve analysis reduces the
probability of reserve shortfalls and, in doing so, reduces the overall regulation reserve
requirement. This allows PacifiCorp's forecasted requirements to be reduced until the PacifiCorp
system just achieves the reliability target for the 201 5 Study Term. As shown in Table F.7 below,
the resulting regulation reserve requirement is 562 MW, a 38 percent reduction (including the
portfolio diversity benefit) compared to the stand-alone requirement for each class. The average
regulation reserve requirement is reduced by 92 MW relative to the PacifiCorp portfolio reserve
requirement without the EIM intra-hour benefit.
Table F.7 - 2015 Results with Portfolio and EIM Intra-Hour Benefit
Since 2015, 153 MW of wind resources have been added to PacifiCorp's system. Furthermore,
the IRP portfolio optimization process contemplates the addition of new wind capacity as part of
its selection of future resources. As PacifiCorp's portfolio of resources grows, the diversity of that
portfolio is also expected to increase. As a result, incremental regulation reserve requirements are
expected to be lower than the average requirement for a given portfolio.
The need to develop realistic deviation data for a period during which resources did not exist makes
measuring an incremental diversity effect a difficult proposition. Instead, PacifiCorp's FRS
evaluated the decremental diversity associated with reducing the size of PacifiCorp's wind
portfolio. Removing specific resources produces a similar change in the size of PacifiCorp's
83 3.7%Non-VER 52 2.3%2,228 Nanrephte
load 433 4.4%271 2.7%9,852 12 CP
VER - Wind 384 14.8%240 9.2%2,588 Nanrephte
Total 900 562
Potfolio LOLP
(hours/year)0.03 0.88
Diversity Savins (%)38%
107
Incremental Wind Reeulation Reserve Requirements
Rate
Dofominqnl
Scenario
Stand-alone
Regulation
Forecast
(aMW)
Stan&alone
Rate
(%l
Portfolio
Regulation
Forecast
with EIM
(aMW)
Portfolio
Rate with
EIM
(%l
201s
Capacity
(MW)
PACIFICoRP-2017IRP APPENDIX F - FLEXIBLE RESERVE STUDY
portfolio without requiring the creation of any data points. Specifically, the PacifiCorp system-
wide results described above were recalculated using only 90 percent of the available wind
resources, by removing approximately l0 percent of the wind capacity from each geographic
location.
Regulation reserve requirements for PacifiCorp's system-wide portfolio dropped by 6.lpercent of
the wind capacity removed. This is lower than the average requirement of 9.2 percent in the 2015
portfolio results shown in Table F.7 above. This indicates that diversity is increasing as the pool
of requirements increases, as expected. These incremental wind regulation requirement results are
incorporated in the forecasted portfolio regulation results discussed later on in the study.
Overview
At the start of 2015, PacifiCorp had less than three megawatts of utility-scale solar generating
capacity on its system. Over the course of 2015, an additional 165 MW was added but the majority
was from two large resources which only came online in the second half of December. As shown
in Figure F.16, solar capacity has increased rapidly in both PACE and PACW and by the end of
2017 is expected to total over 1,000 MW. Reference Table F.25 on page 64 contains the list of
solar resources included in the study. Because solar resources have only recently been added to
PacifiCorp's system, the 2015 study period used for the regulation reserve requirements for load,
wind, and Non-VERs does not have data suitable predict current and future solar regulation reserve
requirements.
108
Solar Reserve
PACIFICoRP-20I7 IRP APPENDIX F - FLEXIBLE RESERVE STUDY
Figure F.16 - Solar Capacity Additions
l 000
800
B2
.ff ooo
E
a!U
a
'E +oo
(,
200
0
Jan-15 Apr-15 Jul-15 Oct-15 Jan-16 Apr-16 Jul-16 Oct-16 Jan-17 Apr-17 Jul-17 Oct-17
Five-minute solar data was collected from PacifiCorp's Ranger PI system for Jan. 1,2016 through
Aug.23rd,2016 for two large solar resources in southern Utah totaling 130 MW.26 PacifiCorp's
solar forecast service provider, DNV GL, provided generation forecasts for these resources during
this timeframe, which were submitted to EIM. While EIM deviation data is available for a portion
of this period, certain meteorological monitoring equipment was not in place for the entire
timeframe, and the limited availability of historical results are expected to make the forecasts for
these resources less accurate than what will be possible going forward. Instead, proxy solar base
schedules were developed for these two resources, as described in the next section. To make the
results easier to compare and apply elsewhere, the actual output of the resources was normalized
by their capacity. The calculations described below were all carried out on a capacity factor basis.
Proxy Solar Base Schedule Development
Solar resource output is primarily a function of two attributes: the position of the sun, and the
amount of cloud cover. The position of the sun is comparable from day to day at a given time,
though over the course of weeks it changes by meaningful amounts. To estimate the maximum
possible output for a particular date and time, the maximum output at that time from two weeks
prior to two weeks following is calculated. The four week span helps ensure that at least one data
point is likely to have very little cloud cover and maximum output, while limiting the effect of
- -East - Projected
-East
- -West - Projected
-West
Available 5-min data
a,------Pavant I
Red Hills
26 Pavant I, 50 Mw and Utah Red Hills, 80 Mw
109
----- --
PACIFICoRP-20I7IRP APPENDIX F - FLEXIBLE RESERVE STuoY
seasonal changes in the position of the sun. Identifying the maximum possible output for each
interval allows the forecast to account for changes in output as the sun rises and sets. The following
calculations were carried out independently for the two solar resources.
To estimate the amount of cloud cover, the solar availability is calculated by dividing the actual
output in each five-minute interval by the maximum output for that interval, as identified above.
This removes the effect of the position of the sun, and the changes that remain should primarily be
primarily associated with cloud cover. From day to day, cloud cover is expected to vary widely,
but from T-55 when the solar resource forecast is submitted as an hourly base schedule to EIM
through the course of that upcoming hour, it is reasonable to assume the prevailing cloud
conditions will continue. To improve further upon the cloud cover forecast using the available
data, the trend in cloud conditions leading up to the time of forecast submission was also accounted
for. If it is less cloudy at T-55 than it was twenty minutes earlier, that trend is also extrapolated
forward to the forecast period. The weighting of the trend versus the final measurement before
the forecast is submitted was set to maximize the correlation between the actual solar output and
the forecasted hourly base schedule, i.e. to produce the best achievable forecast. Due to the
absence of generation output, cloud cover can't be estimated from intervals prior to sunrise, so the
forecasted output during the first hours after sunrise is set at the monthly average for those
intervals.
The proxy solar base schedules incorporate cloud cover data and solar position data as follows.
The cloud cover measurement is the primary component in the forecast for the upcoming hour.
The cloud cover trend over the preceding intervals, and the cloud cover in the last interval are
locked in at the values measured just prior to base schedule submission. On the other hand the
position of the sun, embedded in the maximum output for each interval, is assumed to be fixed and
known in advance. The base schedule submission looks forward in time to the forecast hour and
incorporate the expected solar position changes over each five-minute interval in the hour.
While the forecast is created with a five-minute granularity, the base schedule submission to EIM
at T-55 reflects an hourly average value in accordance with EIM operating procedures. The
difference between this hourly average and the five-minute actual resource output (i.e. the original
source data) is the deviation of the solar resource. Once base schedule and deviation data were
prepared for the two solar resources, those deviations were applied in the same template used to
calculate hourly regulation reserve requirements for load, wind, and Non-VERs, including the base
schedule ramping adjustment described previously. This identifies the minimum hourly regulation
reserve needed to guarantee compliance with BAL-001-2 with the resource in question viewed in
isolation.
As shown in Figure F.17, the proxy solar forecasts have less frequent large deviations, and thus
produce fewer instances of large regulation reserve requirements than the available EIM deviation
data from the same period. Note that while Pavant I become operational in 2015, EIM deviations
only became available starting April 1,2016. For comparability, the proxy and EIM results for
each generator are shown for the overlapping time period only. Regulation reserve requirements
in excess of approximately 15 percent of nameplate capacity occurred more frequently in the EIM
data than the proxy data. Because the largest effors are most likely to cause a BAAL violation,
they drive the majority of the reserve requirement. Future results will show whether the forecast
accuracy that can be achieved in actual practice is higher or lower than that in the proxy data used
in this analysis.
110
PACIFICoRP_2017IRP APPENDIX F - FLEXTBLE RESERVE STUDY
Figure F.ll - Solar Regulation Reserve Requirements: Proxy vs EIM
Solar Diversity
When the hourly regulation reserve requirements of the two solar resources are measured
independently, as described above, the results do not capture any of the potential for diversity in
the intra-hour requirements. To identify the potential diversity between the two solar resources,
the average of their base schedules and actual output was used in the hourly regulation reserye
calculation. The difference between the requirements when measured independently and the
requirements when measured in aggregate is the result of diversity. The results of this diversity
measurement are shown in Figure F.18.
100%
90o/o
80o/o
70o/o
600/o
s0%
40o/o
30o/o
20o/o
r0%
0o/o
.......'.Red Hills EIM
-prox.,,
Red Hills Red Hills data Jan. - Aug. 2016
......'..Pavant I EIM
-prory
pavant I pavant I data Apr. - Aug. 2016
6
6z
6
G
0o/o l0o/o 20% 30%40o/o 50o/o 600/o
Exceedrnce Probability
70o/o 80% 90% 100o/o
Frequency of 507o Reserve RequirementEIM Proxy
Red Hills 4.4o/o l.9o/oPavant 3.0o/o l.9o/o
EIM has high reserve
requirements more
frequently than Prory
111
PACIFICoRP-20I7IRP APPENDIX F * FLEXBLE RESERVE STUDY
Figure F.18 - Solar Diversity
As shown in Figure F.18, diversity is not guaranteed to reduce hourly regulation reserve
requirements. While this is not intuitive, it is a direct result of the 30 minute maximum time limit
for deviations under BAL-001-2. If two resources each have deviations that are only 20 minutes
long, the regulation reserve requirement is zero. If the deviations both started at the same time,
then viewed together they will overlap perfectly, and the length of the deviation remains just 20
minutes with a regulation reserve requirement of zero. However, if one resource's deviation starts
l5 minutes earlier than the other, the length of the aggregate deviation will be 35 minutes, and the
regulation reserve requirement will be greater thanzero to ensure compliance with BAL-001-2.
Despite the potential for increased aggregate requirements in some instances, on average the
aggregate requirements are lower as a result of diversity. Because the regulation requirements are
bounded by zero, the diversity benefit is limited to the size of the independent requirement.
As a result, the diversity benefits increase as the independent requirements increase.
Solar Locations
The solar facilities on PacifiCorp's system are concentrated in southeastern Utah and southern and
central Oregon. As shown in Figure F.19, within these areas multiple facilities are also clustered
within relatively close proximity. Five clusters were identified in Utah, while three were identified
in Oregon. Because one of the Oregon clusters is relatively dispersed, it is treated as two
independent clusters.
40o/o
30o/o
20o/o
l0o/o
0%
-l0o/o
-20o/o
-30o/o
-40o/o
a Diversity
-Linear
(Diversity)
a
o
bg'a9L..e=.=o
a9
&
(.)
a
to
10o/o 20Yo
a
a
a
a,)
a
at aa
a
300/o 400/o 50% 60% 70%
Independent Solar Regulation Reserve Requirements
,
a
a
o
O1 aa
a
o
aa
aaaaaa
aaa y: -0.0682x - 0.0049
80Yo 90o/o 100%
a
ao
0o/o
tt2
Ii
PACIFICORP-20I7IRP APPENDIX F - FTgxIBI-e RESERVE STUDY
Figure F.19 - Solar Resource Locations
Southeastern Utahr South/Central Oregon
rrrob i
30 miles
G)
Map data@2017 Google .*ia,
- 'd6c*r data @2017
While all of the clusters identified are in close enough proximity to experience most of the same
passing weather systems, different clusters experience different cloud cover at the time of forecast
submission, and different cloud cover over the course of the operating hour. These differences are
in turn reflected in their actual output and deviations. On the other hand, due to their proximity,
facilities within a given cluster are expected to reflect more closely-related weather conditions in
their forecasts and deviations. As a result, the aggregate capacity within a given cluster is not
expected to experience offsetting deviations, i.e. diversity benefits, whereas the effect of capacity
spread among multiple clusters should create opportunities for offsetting deviations.
The IRP is focused not just on regulation reserve requirements for existing solar resources, but
also on the requirements associated with incremental solar resources added in the future. Tables
F.8 and F.9 present the solar capacity on PacifiCorp's system in three scenarios. The base scenario
reflects the contracted solar resources scheduled to be online in 2017, while two incremental
scenarios reflect the addition of 500 MW and 1000 MW of new solar resources. The incremental
solar capacity is split between the PACE and PACW BAAs, and among existing and new clusters.
I 13
o
Bend
T
30 milesU
ru l^
ul--F
Medford
,?Iil-&
PACIFICoRP - 20 I7 IRP APPENDIX F -FLEXIBLE RESERVE STuoy
Table F.8 - East Solar Clusters by Scenario
Table F.9 - West Solar Clusters Scenario
Solar Portfolio Data
Red Hills and Pavant have proxy base schedules, hourly regulation reserve requirements, and
diversity based on actual generation. It is reasonable to assume other solar resources within those
two clusters would experience comparable conditions and results. Therefore, the Red Hills and
Pavant results are scaled up to reflect any additional capacity within the cluster.
At the time the study was prepared, actual data for the other clusters in PACE and all of the clusters
in PACW was unavailable. While the varying geographic locations of these clusters impact the
timing of weather conditions, they are all relatively sunny locations, and it is reasonable to assume
that the likelihood of over-forecasting resource output, resulting in a regulation reserve
requirement, is similar in all of the clusters. With this in mind, all of the hourly regulation reserve
requirements for Red Hills and Pavant (measured independently) were taken as a single data set
and hourly regulation reserve requirements for the other clusters were assigned randomly from this
distribution. While the resulting hourly regulation reserve requirements vary from 0 percent to 95
percent of the solar nameplate capacity, 18.7 percent of the regulation reserye requirements are
zero, and half of the regulation reserve requirements are less than2 percent of the solar nameplate.
Despite being predominantly random, there is a relatively small positive correlation (+0.2638)
between the hourly regulation reserye requirements for Red Hills and Pavant. This may reflect
weather conditions that occur at the same time over a broad area, such as aftemoon thundercloud
formation, rather than as a result of passing weather fronts. This relationship is assumed to be real
effect and is reflected in each of the calculated clusters by blending a random regulation
requirement and the simultaneous requirement for one of the two source clusters. The weighting
Enterprise 83 +17 +17
+62Fiddler's Canyon 3ll +62
2s7 +51Escahnte +51
Red Hills 83 +17 +17
Pavant 120 +24 +24
New Cluster I +229
+229New Chster 2
Total 855 1,255 1,655
YoClawe vs Base 47%94%
Bend 50 +31 +6
20 +12Medford +2
Khnrath I 47 +29 +6
Klamath 2 47 +29 +6
New Chster I +90
Total 163 263 363
YoCharqe vs Base 6t%123%
tt4
East Cluster Base Incr. Solar I Incr. Solar 2
Base Incr. Solar IWest Cluster Incr. Solar 2
PACIFICoRP - 2017 IRP APPENDIX F - FLEXIBLE RESERVE STUDY
of the blend was set such that the average correlation between the new clusters and the existing
clusters matches the correlation measured between the existing clusters.
Because the hourly regulation reserve requirements described above reflect the independent
regulation reserve requirements for Red Hills and Pavant, they do not capture the diversity between
different clusters of solar resources. As discussed above, diversity is partly a linear function of the
independent hourly regulation reserve requirements - the greater the requirement, the greater the
diversity credit. However, much of the variation in diversity values appears to be unpredictable,
i.e. largely random. In a similar manner to the regulation reserve requirements described above,
the diversity results for Red Hills and Pavant were taken as a single data set and assigned randomly
to each of the clusters. A weighted average diversity value was then calculated that takes into
account the number of clusters since diversity requires two or more. In addition, because diversity
benefits are bounded by a zero regulation reserve requirement, they may be truncated in manner
that under-represents the potential diversity available. Instances when diversity leads to higher
requirements are not bounded in this manner in the sample. With more than two clusters, it may
be possible to utilize additional diversity benefits before hitting the zero bound. To help reflect
this, whenever the sampled diversity components indicated an increase in requirements, the
increase was reduced by half.
The random assignment of regulation reserve requirements described above disregards the hour of
the day, and can overstate requirements when little output is expected such as during the morning
ramp. To compensate, the aggregate regulation reserve requirements are reduced during the
morning ramp to align with the requirements seen for Pavant and Red Hills.
Solar Regulation Reserve f,'orecast
The solar regulation reserve forecast is comparable to that developed for wind, representing a fixed
percentage of the solar nameplate capacity, but never more than the maximum output in that hour,
including a portion of the ramp up across the hour in the moming and down across the hour in the
afternoon. The fixed percentage of nameplate capacity is set at the minimum level that achieves
the reliability target of 0.88 loss of load hours per year. The reserve requirement necessary to
achieve the reliability target varies in PACE and PACW, and with changes in total solar capacity.
The results of the solar regulation requirements in the various scenarios is shown in Table F.l0
below, with the wind results shown for comparison. Note that while the fixed percentage of
nameplate capacity (i.e. the maximum reserve held) for solar and wind in PACE is similar, ranging
from 14.9 percent to 18.6 percent of nameplate capacity, the average requirement for solar is
significantly lower than that for wind. This is because solar output is zero for half of the hours in
the year, whereas PACE wind output drops below the maximum reserve held infrequently. PACW
wind output is more strongly correlated and drops to zero more frequently than PACE wind.
ll5
PACIFICoRP - 2017 IRP APPENDIX F - FLEXIBLE RESERVE STuoy
Table F.10 - Solar and Wind Stand-alone Regulation Requirements, as Percentage of
Nameplate Capacity
For solar, the fixed percentage of nameplate in the reserve requirement calculation varies with the
size of the solar capacity. There are two offsetting trends related to increasing solar capacity. First,
more diverse solar resources (i.e. more clusters) have lower requirements, but the incremental
benefit declines as more diversity is added. Second, spreading the fixed allowable BAAL variation
across more capacity increases requirements, and the incremental impact increases as capacity
increases. Figure F.20 shows these relationships as well as fitted curves used to project the solar
regulation reserve requirements as a function of capacity for PACE and PACW. The solar
regulation reserve requirement in PACE is assumed to be related to capacity using a third-order
polynomial. The solar regulation reserve requirement in PACW is assumed to be related to
capacity using two linear extrapolations.
re F.20 - Stand-alone Solar Reserve
t2.3vo nla 22.3%n/aNo Sohr
8.8%4.2%ts.6%7.4%Base Sohr
Incr. Solar 1 85%53%14.9%9.6%
Incr. Solar 2 8.6%5.4%t5.2%9.8%
ts3%90% Wind 15.lYo 18.6%32.3%
14.6%15.zYo t7.8%29.8%Base Wind
25%
20o/o
l5o/o
l0o/o
2
6z
U)
^\
2
y = -2.3238E-11x3 + 1. 1 87 1 E-07x2 - 1.8940E-04x + 2.45678-01
5 6 7
5
-PACE
Nameplateo/o
4
4
-PACWNameplate
%
5Yo Solar Sites
-Poly.
(PACE Nameplate %)
--Fitted (PACW Nameplate %)
0 l 000
Independent Solar Sites
OYo
250 750
Solar Capacity (MW)
1250 1500 1750 2000
116
Scenario
Averase Reserve Held Max Reserve Held
East West East West
500
PACIFICORP - 20 I7 IRP APPENDIX F -FLEXIBLE RESERVE STuoy
Overview
A single pool of regulation reserve is held to cover deviations by load, wind, solar, and non-
dispatchable generation. Simultaneous large deviations by all classes are unlikely - as a result,
this pool of regulation reserve can be smaller than what these classes would require on their own.
The reduction in regulation reserve is a result of the diversity of the portfolio of requirements.
While the diversity of load, wind, and Non-VER generation was measured using 2015 data, the
solar deviations are from 2016 and are extrapolated from a very limited sample. As such, it is not
currently possible to measure the diversity of the PacifiCorp system, inclusive of requirements for
solar. Instead, several characteristics of the diversity of PacifiCorp's system were used to produce
an estimate of the relationship between the amount of diversity and the portfolio of regulation
requirements. These characteristics are discussed below.
Methodology
The most important element in PacifiCorp's portfolio diversity estimate is the system diversity,
including EIM benefits, associated with load, wind, and Non-VERs during 2015. The diversity in
the 2015 portfolio reduced reserye requirements by 37.51 percent. This captures the vast majority
of the regulation reserve requirements both today and in likely future scenarios over the near term.
For example, approximately 1000 MW of solar capacity is expected to be on the PacifiCorp system
in 2017 , and no solar was included in the 201 5 results. However, this additional solar increases
the stand-alone regulation reserve requirement (before accounting for diversity) by less than l0
percent. Since diversity only occurs in intervals when two or more regulation reserve requirements
exist, changes in diversity in l0 percent of the intervals will have relatively limited effects.
In a portfolio without solar capacity, incremental wind generation was calculated to have reserve
requirements of 6.1 percent of nameplate, after accounting for portfolio diversity, compared to an
average requirement of 9.2 percent for the entire wind fleet. Much of the benefits are captured
within the wind class - its stand-alone requirements increase by a limited amount; however, the
diversity of the entire portfolio increases slightly when the reserve requirements for the
incremental wind are added. This relationship between stand-alone reserve requirements and
portfolio diversity is assumed to be linear - a small increase in diversity as the reserve requirements
of the existing classes grows.
As a starting point, solar regulation reserve requirements are assumed to create equivalent amounts
of diversity as the components of the pre-solar portfolio, including the linear increase as
requirements grow. In addition, incremental diversity as a result of solar is assumed to occur in
relation to the size of the stand-alone solar regulation requirements. When the solar requirements
are equivalent in size to the requirements for load, wind, and Non-VERs, the incremental diversity
benefits are assumed to be maximized at 20 percent of the solar requirement. At lower levels of
solar requirements (i.e. for less solar capacity), the incremental diversity benefits are smaller and
are assumed to proportional to the size of the solar requirements relative to the other regulation
requirements. With four categories of requirements (load, wind, solar, Non-VER), solar
requirements would need to be 25 percent of the total to achieve the maximum level of diversity.
In the base scenario, solar requirements are 8l MW out of 998 MW total, and result in incremental
tt7
Portfolio Reserve
PACIFICoRP - 20 I7 IRP APPENDIX F - FLEXIBLE RESERVE STuoy
diversity benefits of 5.3 MW, on top of approximately 30 MW of benefits based on the diversity
in the pre-solar portfolio.2T
Based on the above, hourly regulation requirements for PACE and PACW are calculated as a
function of: wind and solar nameplate capacity, forecasted wind output and month/hour as a proxy
for expected solar output, and static hourly regulation reserve requirements for load and non-VER
generation. Diversity is a function of the total requirements and is calculated dynamically as
described above.
Results
Table F.ll presents the portfolio regulation requirement results from the various scenarios
described above. As the wind and solar capacity on PacifiCorp's system increases, regulation
requirements increase, but those requirements are partially offset by the increasing diversity of the
portfolio. The 2017 Base Case regulation reserve requirements are 617 MW. By comparison,
PacifiCorp's 2014 Wind Integration Study identified requirements of 626 MW for a smaller
amount of wind, and without any requirements for solar or Non-VERs.
Table F.11 - Portfolio Regulation Requirement Results, by Scenario
There are a significant number of changes between the PacifiCorp's 2014 Wind Integration Study
and the current study. First, the specific requirements of the BAL-001-2 standard are being
applied, as previously discussed. Second, the updated requirements are based on an expanded
portfolio of resources, including solar, Non-VERs, and additionalwind capacity. Finally, diversity
benefits are now shared among all requirements, rather than being allocated solely to wind
resources as was done in the 2014 Study. Table F.l2 presents a comparison of the regulation
reserye requirement results in the current study and prior studies.
27 8l MW solar requirement / (998 MW total requirement / 4 classes) * 20Yoincremental diversity = 5.3 MW
8l MW solar requirement* 37.60/o pre-solar portfolio diversity : -30 MW
2,543 n/a nla nla 62620I4 WIS
2015 (No Solar)2,588 0 900 37s%562
2017 Base Case 2,757 1,050 998 38.2%617
Increnrental Wind 3,007 1,050 1,023 383%631
2,757 1,550 1,033 38.6%635Increnental Sohr I
Increrrpntal Sohr 2 2,757 2,050 1,074 39.2%653
ll8
Scenario
Wind
capcity
(MW)
Solar
capacrty
(MW)
Stand-alone
regulation
requirement
(MW)
Portfolio
diversity
credit
(Vol
Regulation
requircment
with divemity
(MW)
PACIFICoRP-20I7IRP APPENDIX F - FLEXIBLE RESERVE STUDY
Table F.l2 - Portfolio Regulation Requirement Results, Percent of Nameplate Capacity
The 2012 and 2014 Wind Integration Studies calculated the regulation reserve requirement for
load only, then the incremental requirement for the entire wind fleet, allocating all diversity to
wind. The FRS calculates the regulation reserve requirement for the 2017 resource mix, allocating
the diversity among all components. As compared to prior studies, the diversity allocation
decreases the load requirement and increases the wind requirement, the changes in standards and
methodology notwithstanding. In an additional step, the FRS also calculates incremental
requirements for wind and solar which are more closely aligned with the obligations resulting from
new resource additions contemplated in the IRP. While these requirements are lower than the
average requirements in the base case, they will call on higher cost resources, as the least-cost
regulation reserye resources are dispatched first. The cost of the regulation reserve obligation is
discussed in more detail in the next section.
Regulation Reserve Cost
A series of PaR scenarios were prepared to isolate the regulation reserve cost associated with wind
and solar generation. The scenarios are shown in Table F.13. These scenarios were based on20l7
and included the existing resources in the 2015 IRP Update. In the 2014 Wind Integration Study
reserve requirements were modeled on both an hourly and monthly basis to reflect the timing
differences of reserve requirements. While the requirements are calculated on an hourly basis, due
to difficulties incorporating those requirements in the PaR model at that granularity, monthly
requirements were used to calculate regulation reserve costs discussed herein. Where possible, it
is recommended that hourly regulation requirements be modeled that are consistent with the
resource capacity and generation profiles of the specific portfolio under evaluation.
Table F.13 - Regulation Reserve PaR Scenarios
2012 WIS:201I 4.0%8.7%nla nla load -> Incr Wind
8.1%n/a2014 WIS:2012 4.1%nla Load -> Incr Wind
2014 WIS:2013 4.s%7.3%nla n/a [,oad -> Incr Wind
2016 FRS 2.8%89%2.4%4.6%Portfo lio Diversity (Base)
n/a 5.8%n/a n/a2OI6 FRS Base -> Incr Wind
2016 FRS n/a nla n/a 3.6%Base -> Incr Solar I
n/a n/a2016 FRS nla 3.8%Incr Sohr I -> Incr Solar 2
B.l Base No Reserve lllllT wind and sohr None
8.2 Base With Reserve lllllT wind and sohr lllll7 wind and solar
w.t Incr. Wind, Base Reserve StudyB.2 + 250MW wind lllll7 wind and solar
w.2 Incr. Wind * Reserve StudyB.2 + 250MW wind lllll7 wind and sohr + 250MW wind
sl.l Incr. Sohr 1, Base Reserve Study B.2 + 500MW sohr lllllT wind and sohr
sl.2 Incr.Sohrl*Reserve Study B.2 + 500MW sohr lllllT wind and sohr + 500MW sohr
s2. I Incr. Sohr 2, Base Reserve Study B.2 + 1000MW sohr lllllT wnd and solar
s2.2 Incr. Sohr2 + Reserve Study B.2 + 1000MW sohr lllll7 wnd and solar + l000MW solar
tt9
Studv Load Wind Non-VER Solar Method
#Scenario Resourrces Resulation requircment
PACIFICoRP-2017IRP APPENDIX F - FLEXIBLE RESERVE STUoY
The regulation reserve cost results are shown in Table F.14. The2014 Wind Integration Study
identified regulation reserve costs for wind generation of $2.3544Wh. This value measured the
incremental cost when regulation reserve for the existing wind fleet were added to the regulation
reserve for load. The most comparable wind reserve cost from the FRS is $0.3044Wh. This
represents the cost of the regulation reserve for existing wind, load, solar, and Non-VERs, relative
to a scenario with no regulation reserve. The result is adjusted to account for the wind regulation
reserve requirement relative to the total regulation reserve requirement.
Table F.14 - Regulation Reserve Cost Calculations
The change in regulation reserve costs is primarily attributable to the following factors: lower
market prices, transmission congestion, and 30-minute regulation reserve capability. Assuming
sufficient regulating capability is available within PacifiCorp's portfolio, the cost of regulation
reserye reflects the lost margin on resources that can provide the service, i.e. the difference between
the market price or alternative generation cost and their fuel cost. Since the prior study, market
prices have declined, which reduces this margin, and a 10 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 reserve category, which is
limited to capacity available within l0 minutes. The FRS assumes that dispatchable capacity
available within 30-minutes can be counted toward the regulation reserve requirement. This
increases the supply of regulation resources and reduces costs when 30-minute capacity from the
unit with the lowest-cost reserve can be used instead of being limited to only the lO-minute
capacity of that unit.
While the Base wind reserve rate is helpful for comparison with the 2014 Wind Integration Study,
it is not representative of the incremental cost of regulation reserye for new wind resources.
Instead, PacifiCorp's FRS calculates regulation reserve requirements specific to the incremental
resource additions contemplated in the IRP. As shown in Table F.14 above, the addition of 250
MW of wind capacity results in incremental regulation reserve costs of $0.4344Wh, while the
addition of 1000 MW of solar capacity results in incremental regulation reserve costs of
$0.4644Wh. It should be noted that the difference in reserve costs for wind and solar reflects
timing differences. Per MWh of generation, the wind reserve obligation is 16 percent higher than
a Base reguhtion reserve cost lStudy B.2l - lStudy B.ll $5,936,990
b Wind reserve requirenrnt lwind req.l / [Totalreq.]%40%
c Wind generation lStudv B.ll MWh 7,802,061
Base wind resewe rate lalxlbl/[cl $/NIWh $0.30
a'Incrernental reguhtion reserve cost [Study W.2] - [Studv W.l]$$389,890
b'lStudy W.ll - lStudv B.ll MWh 909,050I ncremental wind generation
Incremental wind rcserve rate la'l / [b'l $/MWh $0.43
a"Increnpntal reguhtion reserve cost lStudy 52.21- lstudy 52.ll $$1,221,610
btt Incremental sohr generation lSrdv 52.ll - lStudv B.ll MWh 2,667,200
fa"l / [b"l $/MWhIncremental solar rcserve rate s0.46
120
#Value Calculation Units Results
PACIFICORP-2017IRP APPENDIX F - FLEXIBLE RESERVE STUDY
the solar obligation; however, the solar obligation is higher during the summer and during the day,
when market prices and marginal reserve costs are higher.
While incremental reserve costs generally increase with volume, the 500 MW solar scenario had
a slightly higher cost than the 1000 MW scenario, likely due to lower transmission congestion. For
simplicity, the 1000 MW result was used where a specific dollar value was required in the IRP.
The2017 FRS results are applied inthe2017 IRP portfolio development process as a cost for wind
and solar generation resources. Once candidate resource portfolios are developed using the SO
model, the PaR model is used to evaluate portfolio risks. The PaR model inputs include regulation
reserve requirements specific to the resource portfolio developed using the SO model. As a result,
the IRP risk analysis using PaR includes the impact of differences in regulation reserve
requirements between portfolios. Ideally, the hourly regulation reserve requirements should be
used to determine costs specific to the requirements of the resource and portfolio under
consideration. This ensures regulation reserve costs reflect changes in market prices and fuel costs,
transmission congestion, and regulation reserve capability relative to the IRP analysis. The
corollary of a more accurate estimate of incremental regulation reserve cost is a more accurate
estimate of the value of resources that supply regulation reserve, including energy storage and
direct load control.
ln addition to using PaR for evaluating operating reserye cost, the PaR model is also used to
estimate the costs associated with daily system balancing activities. These system balancing costs
result from the unpredictable nature of load and wind generation on a day-ahead basis and can be
characterized as system costs borne from committing generation resources against a forecast of
load and wind generation and then dispatching generation resources under actual load and wind
conditions as they occur in real time. The methodology is comparable to that used in the 2014
Wind Integration Study, with modifications to account for solar and the allocation of costs between
load, wind, and solar.
The PaR model simulates production costs of a system by committing and dispatching resources
to meet system load. For this study, PacifiCorp developed nine different PaR simulations as
summarized in Table F. I 5. These simulations isolate the system balancing costs of load, wind, and
solar, plus the system balancing costs of the overall portfolio. These simulations were run
assuming operation inthe2017 calendar year, applying2015load, wind, and solar data collected
from PacifiCorp's wind forecast service provider, DNV GL. This calculation method combines
the benefits of using actual system data with current forward price curves pertinent to calculating
the costs for wind integration service on a forward basis, as well as the current resource portfolio.28
PacifiCorp resources used in the simulations are based upon its existing resource portfolio.
28 The Study uses the October 12,2016 official forward price curve (OFPC).
t2t
Day-ahead System Balancing Costs
PACIFIC0RP _ 2017 IRP APPENDIX F _ FLEXIBLE RESERVE STUDY
Table F.15 - System Balancing Cost Simulations in PaR
Simulation I identifies the unit commitment using day-ahead forecasts of load, wind, and solar.
Simulation 2 identifies the unit commitment using actual load, wind, and solar, and represents the
optimal dispatch of the system. Simulation 3 uses the unit commitment from Simulation l, along
with the actual load, wind, and solar from Simulation 2. Since Simulation 2 and 3 both have
identical load, wind, and solar, differences between them are solely due to unit commitment and
Simulation 3 represents the achievable optimization of unit commitment using the information
available on a day-ahead basis when unit commitment occurs. The difference in cost between
Simulation 3 and Simulation2 is the system balancing cost associated with changes between day-
ahead load, wind, and solar forecasts and actual output.
Simulations 4-9 isolate the total day-ahead forecast cost of the individual components.
Simulations 4-6 each calculate unit commitment using one day-ahead forecast and two actual
results. Simulations 7-9 calculate the costs of those day-ahead unit commitment decisions under
actual output. The relative costs of Simulations 7-9 are used to determine the relative allocation of
the portfolio among the individual components. The simulation results and day-ahead balancing
cost for each category is shown in Table F.16.
Table F.16 - Day-ahead Forecast System Balancing Cost Results
As indicated in the Regulation Reserve section above, the actual solar on PacifiCorp's system in
2015 was very limited, and the available solar generation averages just 2l megawatts, or roughly
3 percent of the available wind generation. Because unit commitment changes have low
granularity (a unit is either on or off), small differences can sometimes have a large effect, and this
appears to be the case for the solar results, which were far out of proportion with the measured
volumes. In light of the limited solar data set, it is unlikely those results would scale up to the
current level of solar on PacifiCorp's system. In light of this, the day-ahead forecast cost for solar
Day-ahead Study IIDay-ahead Day-ahead n/a
2 Actu,al Actual Study 2 NoneActual
J Actual Actual Actual Study 1 For Load/IVind/Solar
4 Day-ahead Actual Actual Study 4 nla
5 Day-ahead Actual Study 5 nlaActual
6 Actual Actual Day-ahead Study 6 nla
7 Actual Actual Actual Study 4 For [,oad
Actual Studv 58ActrnlActual For Wind
9 Actual Actual Studj 6 For SohrActual
a Total Combined lStudv 3l - [Studv 2l $6,208,760
b toad Onlv lStudv 7l - l-Studv 2l $6,132,860 lbl * ([al / le1\ I lActual toad MWhl $0.09
c Wind Only lStudv 8l - IStudv2l $ 1,053,s30 lcl * ([al / le]\ I lActual Wind MWhl $0.14
d Sohr Onlv lAdimtedl s3l,lll [Set equalto wind resuhl $0.r4
e Total One-otr fbl+[cl+ldl $7,217,501
122
#Load Wind pmfile Solarnrofile Commitment Dav-ahead forecast e nor
#Value Cost calculation Cost ($)Divenitv calculation
Rate W
divetsity
($lurwh)
PACIFICoRP - 20 I7 IRP APPENDIX F - FLEXIBLE RESER\G STUDY
generation has been reduced to the level calculated for wind generation.2e
Table F.l6 above has been modified from what was presented in the 2014 Wind Integration Study.
In that study, day-ahead system balancing costs associated with load were calculated first, and
incremental day-ahead system balancing costs associated with wind were calculated second. In
this analysis, the total day-ahead system balancing costs are calculated for the portfolio and are
allocated among the components based on their individual contributions. This attributes diversity
in the requirements to all of the components and avoids differences related to the order the studies
are conducted. A comparison of the day-ahead system balancing costs in the FRS and 2014 Wind
Integration Study is shown in Table F.17.
Table F.l1 - Day-Ahead System Balancing Cost Comparison
The increase in the day-ahead system balancing costs associated with load do not appear to be a
result of the portfolio allocation methodology, as load was previously calculated on a stand-alone
basis, and the portfolio adjustment reduces the stand-alone day-ahead system balancing costs by
14 percent. Instead the difference appears to be related to market prices and the composition of
the PacifiCorp's system. Market prices influence the relative costs of PacifiCorp's gas resources
and determine how close they are to being economic or uneconomic. Resources generally only
are faced with commitment changes when they have low margins. Because falling market prices
have reduced margins, this occurs more frequently. In addition, transmission congestion has
reduced the ability of resources to get to market. When resources are committed in anticipation of
high load or low resources, there may not be sufficient transmission to get them to market if load
is lower than expected or resources are higher. The costs of backing down economic resources
due to transmission constraints is higher than the cost of forgone market sales, and thus contributes
to higher day-ahead system balancing costs.
As was done for its prior Wind Integration Studies, PacifiCorp engaged a Technical Review
Commiffee (TRC) to review the study results from the FRS. PacifiCorp thanks each of the TRC
members, identified below, for their participation and professional feedback. The members of the
TRC are:
o Andrea Coon - Director, Westem Renewable Energy Generation Information System
(WREGIS) for the Westem Electricity Coordinating Council (WECC)
o Michael Milligan - Principal Analyst at the National Renewable Energy Laboratory
(NREL)
o J. Charles Smith - Executive Director, Utility Variable-Generation Integration Group
(uvrG)
$0.0eLoad$0.01
$0.1 4Wind$0.71
Solar n/a $0.1 4
2e The calculated Solar Only Day-Ahead Forecast Cost, [Study 9] - [Study 2], was $805k, or over $4A4Wh.
123
2014 WrS
(2014$/MWh)
2017 FRS
(20r6$/MWh)
Technical Review Committee
PACIFICORP-20I7IRP APPENDIX F - FLEXIBLE RESERVE STuoy
o Robert Zavadil - Executive Vice President, EnerNex LLC
In its technical review3o of PacifiCorp's FRS, the TRC provided comments and questions on
specific aspects of the analysis.
Table F.18 - FRS TRC Recommendations
30 PacifiCorp 2016 Wind Integration Study Technical Review, Dec.12,2016. Available at:
http ://www.pacifi corp.com/es/irp/irpsupport.html
EIM operating processes underlie PacifiCorp's
regulation reserye requirements and the calculations in
the FRS. Specific details on the EIM market process
are available in the FRS, specifically in footnote 11.
The TRC feels that it might be useful to state the role
of key assumptions generally - but specifically how
key requirements of the EIM may have an impact on
reserves (don't study it, just point out key issues).
This references Figure F.6 in the FRS.
The presentation stated:
40 MW is the maximum five-minute imbalance in
any thirty-minute period in this hour.
This is more accurately stated as:
When the minimum imbalances in every rolling
thirtv-minute period are compared. 40 MW is the
maximum five-minute imbalance in any thirty-
minute period in this hour.
On Slide page 8 ofthe presentation provided to the
TRC, below the table: should that be 70 MW instead of
40 MW?
This is addressed in the FRS in the section entitled
"Balancing Authority ACE Limit: Allowed
Deviations."
Would be helpful to include a few sentences about the
ACE cap of4Ll0?
The use ofwhat has traditionally been a resource
adequacy metric - LOLH - use in long term capacity
planning as a key criterion for estimating regulation
reserye requirements is both interesting and a departure
from previous studies - by Pacificorp as well as the
general wind integration community in the U.S. This
approach has been employed in a few recent
integration analyses, but given the uniqueness, it would
be good if it were more clearly called out/highlighted
in the description of the analytical methodology.
The discussion of 0.88 LOLH was helpful on the call.
It would be useful to have a similar explanation in the
report - something along the lines that the RA target
resulted in 0.88 LOLHlyear and that was judged to be
an acceptable reliability level. Using the same target
for operations, there are different drivers, but assuming
resource adequacy is not the constraint, the 0.88 LOLH
may instead result from UC errors that result in too
little regulation being available when needed.
This is addressed in the FRS in the section entitled
"Planning Reliability Target: Loss of Load
Probability."
The FRS identifies the "up" regulation reserye needed
to maintain compliance with BAL-001-2. The 0.88
LOLH in the FRS assumes that resources are available
to provide the identified hourly regulation
requirements. To the extent resources are not available
to meet the identified requirements, LOLH would
increase.
PacifrCorp's Flexible Resource Needs Assessment in
the FRS assesses the availability of resources to meet
its reserve requirements over the long term. In addition,
over the short term, maintaining adequate reserve can
be dependent on the availability of hourly market
balancing opportunities. While a single unit can
provide reserye in each hour of for a multi-hour ramp,
it can only do so to the extent alternate resources can
be procured so that it can ramp back to its starting
point. Potential market balancing constraints are an
area for future work.
124
2015 FRS TRC Recommendations Response to TRC Recommendations
PACIFICORP_20I7IRP APPENDIX F _ FLEXIBLE RESERVE STUDY
The FRS identifies the "up" regulation reserye needed
to maintain compliance with BAL-001-2. The ability
of wind or solar to provide "up" regulation reserye
would impact the cost of meeting that need. Generally,
the opportunity cost offoregone renewable resource
output is higher than the variable cost ofPacifiCorp's
regulation reserve resources. When considered relative
to the cost of adding flexible resource capacity, in
some circumstances providing regulation reserve with
wind or solar resources may be economic.
Would be useful to have discussion of how wind (and
solar) are treated in the study - do they respond to AGC
or dispatch or both? Impact of lost RECs vs.
operational fl exibility etc.
This is addressed in the FRS in the section entitled
"EIM Intra-hour Benefit."
Is there a reference to the method used by the CAISO
to allocate the diversity benefits for each EIM
participant?
There is some remaining confusion on the part of the
TRC regarding the assumptions and utilization of
forecasting into the production simulations for
calculating integration cost. Specifically, the forecast
lead time is nearly one hour prior to the operating hour.
The disconnect on the part ofthe TRC is likely driven
by cunent operation in some larger RTOs, where very
short term persistence forecasts (5 minutes ahead) are
used to dispatch generators participating in the sub-
hourly energy markets, which substantially reduces the
remaining requirement for generators providing
regulation.
While the EIM uses forecasts up to 7.5 minutes prior to
the start ofan interval, it can only dispatch the
resources made available by participants. Because of
EIM operating timelines, balanced load and resource
schedules with regulation reserve capacity identified
have to be submitted by 55 minutes prior to the hour.
Once a resource is deployed, for instance to cover
increasing load or decreasing wind, PacifiCorp cannot
restore that regulating capacity to its original levels
without buying additional resources from a third party.
Bilateral hourly markets in the West have historically
been liquid enough for this purpose, whereas sub-
hourly markets, other than EIM, have not. Because
EIM is an Energy Imbalance Market, each participant
is independently responsible for meeting its reliability
obligations and it is inappropriate to rely upon the
availability of resources from other participants,
though they will be deployed in the EIM if it is
economic to do so. As discussed in the section entitled
"EIM Intra-hour Benefit", the FRS incorporates
benefits associated with the diversity of the EIM as
whole, rather than the resources of other participants.
PacifiCorp agrees that the performance ofthe
regulation reserve forecast developed in the FRS
against future regulation reserve requirements would
provide valuable feedback. This is an area for future
work.
The use ofactual high temporal resolution operating
data, especially for wind generation (rather than
synthesized data from numerical weather simulations)
has been a key feature ofthe Pacificorp integration
studies dating back to 2012. Going forward, the TRC
feels that future Pacificorp integration studies could
benefit greatly by a thorough comparison of"study
results vs. real world", especially since a current year
baseline is part of the analysis. This would provide
perhaps the strongest validation ofthe analytical
methodology or otherwise give strong clues to
ad.justments that may be needed.
Overview
In its Order No. 12013 issued on January 19,2012 in Docket No. UM 1461 on "Investigation of
matters related to Electric Vehicle Charging", the Oregon Public Utility Commission (OPUC)
adopted the OPUC staff s proposed IRP guideline:
125
2016 FRS TRC Recommendations Response to TRC Recommendations
Flexible Resource Needs Assessment
PACIFICORP - 20 I7 IRP APPENDIX F - FLEXTBLE RESERVE STUDY
1. Forecast the Demand for Flexible Capacity: The electric utilities shall forecast the
balancing reseryes needed at different time intervals (e.g. ramping needed within 5
minutes) to respond to variation in load and intermittent renewable generation over the 20-
year planning period;
2. Forecast the Supply of Flexible Capacity: The electric utilities shall forecast the balancing
reserves available at different time intervals (e.g. ramping available within 5 minutes) from
existing generating resources over the Zl-year planning period; and
3. Evaluate Flexible Resources on a Consistent and Comparable Basis: In planning to fill any
gap between the demand and supply of flexible capacity, the electric utilities shall evaluate
all resource options including the use of electric vehicles (EVs), on a consistent and
comparable basis.
In this section, PacifiCorp first identifies its flexible resource needs for the IRP study period of
2017 through 2036, and the calculation method used to estimate those requirements. PacifiCorp
then identifies its supply of flexible capacity from its generation resources, in accordance with the
Western Electricity Coordinating Council (WECC) operating reserve guidelines, demonstrating
that PacifiCorp has sufficient flexible resources to meet its requirements.
Forecasted Reserve Requirements
Since contingency reserve and regulation reserve are separate and distinct components, PacifiCorp
estimates the forward requirements for each separately. The contingency reserve requirements are
derived from stochastic simulations run using the Planning and Risk (PaR) model. The regulating
reserve requirements are part of the inputs to the PaR model, and are calculated by applying the
methods developed in the Portfolio Regulation Reserve Requirements section. The contingency
and regulation reserve requirements include three distinct components and are modeled separately
in the 2017 IRP: lO-minute spinning reserve requirements, lO-minute non-spinning reserve
requirements, and 30-minute regulation reserve requirements. The reserve requirements for
PacifiCorp's two balancing authority areas are shown in Table F.l9 below.
126
PACIFICORP-20I7IRP APPENDIX F _ FLEXIBLE RESERVE STUNY
Table F.l9 - Reserve Requirements (MW)
2017 195 l9s 387 88 88 229
2018 197 197 387 89 89 229
390 9l 9t2019198198 231
200 390 9t 9t 2312020200
2021 203 203 454 92 92 230
2022 205 205 454 92 92 230
454 93 93 2302023207207
209 454 93 93 2302024209
2025 212 212 454 94 94 230
2026 211 2tt 4s4 95 95 230
454 95 95 23020272132r3
215 390 96 96 2322028215
2029 218 218 390 96 96 235
2030 219 2r9 390 97 97 235
398 97 97 2332031222222
225 396 98 98 2342032225
2033 227 227 398 98 98 232
2034 228 228 392 98 98 231
231 401 99 99 2312035231
2036 235 235 436 99 99 230
127
Year
East Requirement West Requirement
Spin
(1O-minute)
Non-spin
(10-minute)
Regulation
(30-minute)
Spin
(1O-minute)
Non-spin
(10-minute)
Regulation
(30-minute)
PACIFICoRP-2017IRP APPENDIX F _ FLEXIBLE RESERVE STuoy
Flexible Resource Supply Forecast
Requirements by NERC and the WECC dictate the types of resources that can be used to serve the
reserve requirements.
l0-minute spinning reserve can only be provided by resources currently online and
synchronized to the transmission grid;
10-minute non-spinning reserve may be served by fast-start resources that are capable of
being online and synchronized to the transmission grid within ten minutes. Intemrptible
load can only provide non-spinning reserve. Non-spinning reserve may be provided by
resources that are capable of providing spinning reserve.
o 30-minute regulation reserve can be provided by unused spinning or non-spinning
reserve. Incremental 30-minute ramping capability beyond the l0-minute capability
captured in the categories above also counts toward this requirement.
The resources that PacifiCorp employs to serve its reserve requirements include owned hydro
resources that have storage, owned thermal resources, and purchased power contracts that provide
reserve capability.
Hydro resources are generally deployed first to meet the spinning reserve requirements because of
their flexibility and their ability to respond quickly. The amount of reserve that these resources can
provide depends upon the difference between their expected capacities and their generation level
at the time. The hydro resources that PacifiCorp may use to cover reserve requirements in the
PacifiCorp West balancing authority area include its facilities on the Lewis River and the Klamath
River as well as contracted generation from the Mid-Columbia projects. In the PacifiCorp East
balancing authority area, PacifiCorp may use facilities on the Bear River to provide spinning
reserve.
Thermal resources are also used to meet the spinning reserve requirements when they are online.
The amount of reserve provided by these resources is determined by their ability to ramp up within
a l0-minute interval. For natural gas-fired thermalresources, the amount of reserve can be close
to the differences between their nameplate capacities and their minimum generation levels. In the
current IRP, PacifiCorp's reserve are served not only from existing coal- and gas-fired resources,
but also from new gas-fired resources selected in the preferred portfolio.
Table F.20 lists the annual reserve capability from resources in PacifiCorp's East and West
balancing authority areas. All the resources included in the calculation are capable of providing all
types of reserve. The non-spinning reserve resources under third party contracts are excluded in
the calculations. The changes in the flexible resource supply reflect retirement of existing
resources, addition of new preferred portfolio resources, and variation in hydro capability due to
forecasted streamflow conditions, and expiration of contracts from the Mid-Columbia projects that
are reflected in the preferred portfolio.
o
a
128
PACIFICORP - 20I7 IRP APPENDIX F -FLEXIBLE RESERVE Sruoy
2017 1,340 745 1,975 1,009
201 8 1,340 751 1,975 1,015
2019 1,290 700 r,875 964
2020 1,290 743 1,875 1,007
2021 1,250 724 1,755 988
2022 1,250 684 1,7 55 948
2023 1,250 725 1,755 989
2024 1,250 725 1,755 989
2025 1,250 725 1,755 989
2026 1,250 724 1,7 55 988
2027 1,250 725 1,7 55 989
2028 1,169 726 1,675 990
2029 1,281 692 1,786 890
2030 1,231 968 1,656 1,166
2031 1,231 969 1,656 1,167
2032 1,231 970 1,657 1,168
2033 1,469 936 1,832 1,069
2034 1,469 93s 1,832 1,067
93620351,469 1,832 1,068
2036 1,469 937 1,833 1,069
Table F.20 - Flexible Resource Supply Forecast (MlY)
Figure F.2l and Figure F.22 graphically display the balances of reserve requirements and
capability of spinning reserve resources in PacifiCorp's East and West balancing authority areas
respectively. The graphs demonstrate that PacifiCorp's system has sufficient resources to serve its
reserve requirements throughout the IRP planning period.
129
Year
East Supply
(10-minute)
West Supply
(1O-minute)
East Supply
(30-minute)
West Supply
(3O-minute)
PACIFIC0RP- 2017 IRP APPENDIX F - FLEXIBLE RESERVE STuoy
Figure B.2l - Comparison of Reserve Requirements and Resources, East Balancing
Authority Area (MW)
2,500
2,000
1,500
2
1,000
500
0
Z % no i-o ? gt, g$ 99 9* B* 9* %*, in n% 9r,, %r., % 99 % 9r.
r Requirement: Spin (1 0-minute)
-East
Supply (1O-Minute)
r Requirement: Non-spin ( I O-minute) r Requirement: Regulation (30-minute)
+East Supply (30-Minute)
130
PACIFICoRP - 20 I7 IRP APPENDIX F - FLEXBLE RESERVE STuoy
Figure F.22 - Comparison of Reserve Requirements and Resources, West Balancing
Authority Area (MW)
Flexible Resource Supply Planning
In actual operations, PacifiCorp has been able to serve its reserve requirements and has not
experienced any incidents where it was short of reserve. PacifiCorp manages its resources to meet
its reserve obligation in the same manner as meeting its load obligation - through long term
planning, market transactions, utilization of the transmission capability between the two balancing
authority areas, and operational activities that are performed on an economic basis.
PacifiCorp and the California Independent System Operator Corporation implemented the energy
imbalance market (EIM) on November l, 2014, and participation has since expanded to include
NV Energy, Arizona Public Service, and Puget Sound Energy, with several additional participants
scheduled for entry between 2017 and2019.By pooling variability in load and resource output,
EIM entities reduce the quantity of reserve required to meet flexibility needs. Because variability
across different BAAs may happen in opposite directions, the flexible ramping requirement for the
entire EIM footprint can be less than the sum of individual BAAs' requirements. This difference
is known as the "flexible ramping procurement diversity savings" in the EIM. This intra-hour
benefit reflects offsetting variability and lower combined uncertainty. PacifiCorp's regulation
reserye forecast includes a credit to account for the diversity benefits associated with its
participation in EIM.
2
1,400
r,200
r,000
800
600
400
200
0 ZZZH e9 e-" e* e*, A e-. e" % "i4 ? e"r e,, e,, e* e*
I Requirement: Spin (I0-minute)
-West
Supply (1O-Minute)
r Requirement: Non-spin ( l0-minute) r Requirement: Regulation (30-minute)
.+-West Supply (3O-Minute)
131
PACIFICORP-2017IRP APPENDIX F - FLEXIBLE RESERVE STUDY
As indicated in the OPUC order, electric vehicle technologies may be able to meet flexible resource
needs at some point in the future. However, the electric vehicle technology and market have not
developed sufficiently to provide data for the current study. Since this analysis shows no gap
between forecasted demand and supply of flexible resources over the IRP planning horizon, this
IRP does not include whether electric vehicles could be used to meet future flexible resource needs.
The FRS first estimates the regulation reserve necessary to maintain compliance with NERC
Standard BAL-001-2 given a specified portfolio of wind and solar resources. The FRS next
calculates the cost of holding regulation reserye for incremental wind and solar resources and the
cost of using day-ahead load, wind, and solar forecasts to commit gas units. Finally, the FRS
compares PacifiCorp's overall operating reserve requirements over the IRP study period, including
both regulation reserve and contingency reserve, to its flexible resource supply.
PacifiCorp incorporated a revised methodology in the FRS compared to its 2014 Wind Integration
Study. The FRS now estimates regulation reserve based on the specific requirements of NERC
Standard BAL-001-2. It also incorporates the current timeline for EIM market processes, as well
as EIM resource deviations and flexibility reserve benefits based on actual results. The FRS also
includes adjustments to regulation reserve requirements to account for the changing portfolio of
solar and wind resources on PacifiCorp's system and accounts for the diversity of using a single
portfolio of regulation reserve resources to cover variations in load, wind, solar, and Non-VERs.
The regulation reserve requirements for the various portfolios considered in the analysis and in the
2014 Wind Integration Study are shown in Table F.21.
Table F,2l - Portfolio Regulation Reserve Requirements, by Scenario
Solar
Capacity
Case
2014 WIS
2015 (No Solar)
2017 Base Case
lncrementalWind
lncrementalSolar 1
!ncremental Solar 2
Two categories of flexible resource costs are estimated using the Planning and Risk (PaR) model:
one for meeting intra-hour regulation reserve requirements, and one for inter-hour system
balancing costs associated with committing gas plants using day-ahead forecasts of load, wind,
and solar. Table F.22 provides the wind and solar costs on a dollar per megawatt-hour ($iMWh)
of generation basis. The results of the 2014 Wind Integration Study are also included for
comparison.
Wind
Capacity
Stand-alone
Regulation
Requirement
(Mw)
Portfolio
Diversity
Credit
l'rsl
Regulation
Requirement
with Diversity
(MW)
n/a 626n/a2,543 nla
2,588
2,757
3,007
2,757
2,757
0
1,050
1,050
1.,550
2,050
900
998
L,O23
1,033
L,O74
37.5%
38.2%
383%
38.60/o
39.2%
s62
677
631
53s
653
132
Summary
PACIFICoRP_20I7IRP APPENDIX F _ FLEXIBLE RESERVE STuoy
Table F.22 - 2017 FRS Flexible Resource Costs as Compared to 2014 WIS Costs, $/MWh
The2017 FRS results are applied in the 2017 IRP portfolio development process as a cost for wind
and solar generation resources. Once candidate resource portfolios are developed using the SO
model, the PaR model is used to evaluate portfolio risks. The PaR model inputs include regulation
reserve requirements specific to the resource portfolio developed using the SO model. As a result,
the IRP risk analysis using PaR includes the impact of differences in regulation reserve
requirements between portfol ios.
Intra-hour Reserve $2.35 $0.43 s0.46
Inter-hour/System Balancing $0.71 $0.14 $0.r4
Total Flexible Resource Cost $3.06 $0.57 $0.60
133
Wind
2014 WrS
(20lss)
Wind
2017 FRS
(2017S)
Solar
2017 FRS
(2017$)
PACIFICoRP-20I7IRP APPENDIX F - FLEXIBLE RESERVE STuoy
Reference Tables
Table F.23 - Wind
Table F,24 - Non-VERs
Resource ID Nameplate
Capacity (MW)
BAA Grouping
DUNLAP 6 TINIT ilt PACE Wind
FOOTECRE 7 TINITS 133.6 PACE Wind
FREEZOUT 6 I.INIT 1 18.s PACE Wind
GLENROCW 6 UNIT 138 PACE Wind
HINSHAW 7 LI'NITS 144 PACE Wind
HIPLAINS 7 UNITS 127.5 PACE Wind
HORSEBU 7 UNIT 57.6 PACE Wind
JOLLYHIL I GOSHEN 124.5 PACE Wind
LATIGO 6 LINIT 99 PACE Wind
MEADOWCR 6 UNIT 119.7 PACE Wind
MOONSHIN 7 LINITS 45 PACE Wind
MTWNDCOL 7 I.INITS 140.7 PACE Wind
RAWHIDE 6 LINIT l6.s PACE Wind
ROLLHILL 6 I.INIT 99 PACE Wind
SPNFKWND 7 UNIT 18.9 PACE Wind
TOPWORLD 7 UNITS 200.2 PACE Wind
WOLVERIN 7 I-INITS 64.5 PACE Wind
CAMPCOL 6 LINIT 98.9 PACW Wind
COMBINEH 6 UNIT 4t PACW Wind
DALREED 7 WIND 9.9 PACW Wind
GOODNOEH 7 UNIT 94 PACW Wind
HTNKLE 6 UNIT 64.55 PACW Wind
LEANJNPR 7 UNIT 100.5 PACW Wind
MARENGO 6 UNITS 210.6 PACW Wind
NINEMIL 7 I-INIT I 210 PACW Wind
Total 2587.65
Resource ID Nameplate
Capacity (MlV)
BAA Class
BONANZA 7 LTNIT 458 PACE Non-VER
DALTONU 7 I.]NIT 4.6 PACE Non-VER
EXXON 7 UNITS 107.4 PACE Non-VER
GEMSTATE I I.INIT 23.4 PACE Non-VER
MILLCRK 7 UNIT I 40 PACE Non-VER
134
PACIFICoRP - 20 I7 IRP APPENDIX F - FLEXIBLE RESERVE STUDY
MILLCRK 7 TINIT 2 40 PACE Non-VER
NEBOPS 7 LINITS 140 PACE Non-VER
PALISADI 7 I.INIT 1 44 PACE Non-VER
PALISADI 7 UNIT 2 44 PACE Non-VER
PALISADI 7 UNIT 3 44 PACE Non-VER
PALISADI 7 UNIT 4 44 PACE Non-VER
SLENERGY 7 TINIT PACE Non-VER
SI.INNYSIU 6 LINIT 53 PACE Non-VER
TESORO 7 LTNITS 25 PACE Non-VER
USBRGATE 7 LINIT 4.5 PACE Non-VER
WESTVALL 7 UNIT I 40 PACE Non-VER
WESTVALL 7 I.]NIT 2 40 PACE Non-VER
WESTVALL 7 UNIT 3 40 PACE Non-VER
WESTVALL 7 I.INIT 4 40 PACE Non-VER
WESTVALL 7 I.]NIT 5 40 PACE Non-VER
BIOMAS 7 PACW 32.5 PACW Non-VER
CAMASMI 7 LTNIT 61.5 PACW Non-VER
CLEARWAI 7 L|NIT 17.9 PACW Non-VER
CLEARWA2 7 LINIT 3l PACW Non-VER
COID 7 UNITS 6 PACW Non-VER
COLSTR 5 PACE 74 PACW Non-VER
COLSTR 5 PACW 74 PACW Non-VER
COPCOI 7 UNIT I t4 PACW Non-VER
COPCOI 7 UNIT 2 t4 PACW Non-VER
COPCO2 7 I-INIT 1 t7 PACW Non-VER
COPCO2 7 LINIT 2 t7 PACW Non-VER
DALREED 7 BIO 4.8 PACW Non-VER
EVERGBIO 6 BIO 10 PACW Non-VER
FALLCREE 7 LINIT 2 PACW Non-VER
FARMERS 6 UNIT 4.ts PACW Non-VER
FISHCREO 7 UNIT 10.4 PACW Non-VER
GRACE 7 LINIT 3 ll PACW Non-VER
GRACE 7 LTNIT 4 ll PACW Non-VER
GRACE 7 UNIT 5 ll PACW Non-VER
IRONGATE 7 LINIT 18.8 PACW Non-VER
JCBOYLE 7 LTNIT I 40 PACW Non-VER
JCBOYLE 7 LINIT 2 43 PACW Non-VER
LEMOLO1 7 TINIT J,/.PACW Non-VER
LEMOLO2 7 I.INIT 38.5 PACW Non-VER
MERWIN 7 I.INITS 150 PACW Non-VER
OPALSPRI 7 UNIT 4.3 PACW Non-VER
135
PACIFICoRP - 20 I7 IRP APPENDIX F - FLEXIBLE RESERVE STUDY
PELTONRE 7 UNIT 19.6 PACW Non-VER
PENSTOCK 6 UNIT 5 PACW Non-VER
PROSPEC2 7 LTNIT I l8 PACW Non-VER
PROSPEC2 7 TINIT 2 l8 PACW Non-VER
PROSPEC3 7 LTNIT 7.7 PACW Non-VER
RFP 6 UNIT l0 PACW Non-VER
ROSEBURL 7 LUMB 20 PACW Non-VER
SLIDECRE 7 I-INIT l8 PACW Non-VER
7 PACW Non-VER
SODA 7 LINIT 2 7 PACW Non-VER
SODASPRI 7 UNIT I 1.6 PACW Non-VER
TIETONHy 6 LrNIT 13.8 PACW Non-VER
TOKETEE 7 LINIT I l5 PACW Non-VER
TOKETEE 7 UNIT 2 15 PACW Non-VER
TOKETEE 7 LINIT 3 l5 PACW Non-VER
WEBER 7 UNIT 2 PACW Non-VER
Total 2227.65
Table F.25 - Solar
Resource Nameplate
Capacity (M!V)
BAA Class
Beryl Solar J PACE Solar
Buckhorn J PACE Solar
Cedar Valley J PACE Solar
Enterprise Solar I QF 80 PACE Solar
Escalante Solar I QF 80 PACE Solar
Escalante Solar II QF 80 PACE Solar
Escalante Solar III QF 80 PACE Solar
Fiddler's Canyon I -)PACE Solar
Fiddler's Canyon2 J PACE Solar
Fiddler's Canyon 3 aJ PACE Solar
Granite Mountain East Solar
QF
80 PACE Solar
Granite Mountain West Solar
QF
50.4 PACE Solar
Granite Peak J PACE Solar
Greenville 2.2 PACE Solar
Iron Springs Solar QF 80 PACE Solar
Laho #l J PACE Solar
Milford 2 2.97 PACE Solar
Milford Flat 3 PACE Solar
136
SODA 7 UNIT 1
PACIFICoRP _ 20 I7 IRP APPENDIX F - FLEXIBLE RESERVE STUDY
Pavant II Solar QF s0 PACE Solar
Pavant III Solar 20 PACE Solar
Quichapa I aJ PACE Solar
Quichapa 2 J PACE Solar
Quichapa 3 J PACE Solar
South Milford 2.93 PACE Solar
Three Peaks Solar QF 80 PACE Solar
Utah Pavant Solar QF 50 PACE Solar
Utah Red Hills Solar QF 80 PACE Solar
Adams Solar Center LLC l0 PACW Solar
Beatty Solar 5 PACW Solar
Black Cap 2 PACW Solar
Black Cap II LLC 8 PACW Solar
Bly Solar Center LLC 8.5 PACW Solar
Chiloquin Solar 9.9 PACW Solar
Collier Solar 9.9 PACW Solar
Elbe Solar Center LLC l0 PACW Solar
Ivory Pine Solar l0 PACW Solar
Norwest Energy 2LLC (Neffl l0 PACW Solar
Old Mill Solar 5 PACW Solar
OR Solar 2 (Agate Bay Solar)l0 PACW Solar
OR Solar 3 (Turkey Hill
Solar)
10 PACW Solar
OR Solar 5 (Merrill)8 PACW Solar
OR Solar 6 (Lakeview)l0 PACW Solar
OR Solar 7 (Jacksonville)l0 PACW Solar
OR Solar 8 (Dairy)l0 PACW Solar
Sprague River Solar 7 PACW Solar
Tumbleweed Solar 9.9 PACW Solar
Total 1017.7
137
PACIFICoRP - 20 I7 IRP AppgNolx F - FLEXTBLE RESERVE STUDY
138