20201008Application.pdf

Y ROCKY MOUNTAIN
POA'ER
A OMS'Oil Of PACtFtCOf,P
r; "i: r: ii i r,'t L,;
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't407 W. North Temple, Suite 330
Salt Lake Ci,ty, Utah 84116
October 8,2020 - "t .'r-i!-r
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ELECTRONIC DELIWRY
Jan Noriyuki
Commission Secretary
Idaho Public Utilities Commission
t 1331 W. Chinden Blvd
Building 8 Suite 20lA
Boise,ID 83714
RE: CASE NO. PAC-E 20-14
IN THE MATTER OF THE APPLICATION OF ROCKY MOUNTAIN POWER X'OR
AUTHORIZATION TO UPDATE THE WIND AND SOLAR INTEGRATION RATE
FOR SMALL POWER GENERATION QUALITUNG FACILITIES
Attention: Jan Noriyuki
Commission Secretary
Please find for filing Rocky Mountain Power's Application in the above-referenced matter and
AttachmentNo. I which is Appendix F, the Flexible Reserve Study, from Volume II of the 2019
IRP study.
Informal inquiries may be directed to Ted Weston, Idaho Regulatory Manager at (801) 220-
2963.
Very truly yours,
"^.D
Vice President, Regulation
Emily Wegener
Rocky Mountain Power
1407 West North Temple, Suite 320
Salt Lake City, Utah 84116
Telephone: [phone]
IN THE MATTER OF THE APPLICATION )
oF ROCKY MOUNTNN POWER FOR )
AUTHORIZATION TO UPDATE TIIE WIND )
AIYD SOLAR INTEGRATION RATE FOR )
SMALL POWER GENERATION )
QUALIFYING FACILITIES )
CASE NO. PAC-EAO.I4
APPLICATION
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Attorney for Rocky Mountain Power
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
Rocky Mountain Power, a division of PacifiCorp ("the Company"), in accordance with
Idaho Code g6l-502, $61-503, and RP 052, hereby respectfully submits this application
("Application") to the Idaho Public Utilities Commission ("Commission") requesting
authorization to increase the wind and solar integration rate applicable to new power purchase
agreements ("PPA"), by Rocky Mountain Power of electric power from wind-powered qualified
facilities, ("QFs"), from $0.57 to $ l. I I per megawatt-hour (*MWh"), and the solar integration rate
from $0.60 to $0.85 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 PPA 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:
l. Rocky Mountain Power is a division of PacifiCotp, ffi 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
APPLICATION OF ROCKY MOI.INTAIN POWER - I
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
84,000 customers in the state.
I. BACKGROUND
2. Commission Order No. 298391 stated: "we find that the unique supply
characteristics of wind generation and the related integration costs provided a basis for adjustment
to the published avoided cost rates, a calculated figure that may be different for each regulated
utility."
3. Pursuant to Order No. 29839 Rocky Mountain Power filed Case No. PAC-E-07-07
on April 23,2007, requesting 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.2 The Commission
also ordered the Company to file any changes to its wind integration charge as reflected in
subsequent IRPs.3
4. On August 28, 2017, after filing the 2017 Integrated Resource Plan ("IRP"), the
Company filed to update the wind integration rate and implement a solar integration rate based on
the results of the 20l7IRP Flexible Reserve Study.
I In the Matter of the Petition of ldaho Power Companyfor an Order Temporarily Suspending ldaho Power's
PURPA Obligation to Enter into Contracts to Purchase Energt Generated by Wind-Powered Small Power
Production Facilities. Case No. IPC-E-05-22, Order 29839 at 8 (August 4,2005).
2 In the Matter of the Petition of Rocly Mounlain Powerfor an Order Revising Certain Obligations to Enter into
Contracts to Purchase Energt Generated by Wind-Powered Small Power Generation Qualified Facili/les, Case No
PAC-E-7-07, Final Order No.30497 at 12 (February 20, 2008).
3 Id. atl3
APPLICATION OF ROCKY MOUNTAIN POWER _ 2
5. In compliance with Order No. 30497, Rocky Mountain Power hereby files this
Application to update its wind and solar integration rates that can be deducted from the published
avoided cost rates to determine a purchase and sale price established for the duration of the PPA
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. These integration rates
assure that QFs that deliver less than 100 KW have a predictable rate.
6. On October 25,2020,the Company filed its 20l9Integrated Resource Plan, as Case
No. PAC-E-19-16. In support of this Application the Company submitted as Attachment No. l,
Appendix F -Flexible Reserve Study from Volume II of the 2019IRP. AttachmentNo. I explains
in detail the methodology used and the results derived from PacifiCorp's analysis of wind and
solar integration costs.
II. 2019 IRP - FLEXIBLE RESERVE STUDY
7. Appendix F of the 2019 IRP 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.
8. The FRS is based on PacifiCorp's actual operational data from January 2017
through December 2017 for load, wind, solar, and Non-Variable Energy Resources ("Non-
VERs"). PacifiCorp's primary analysis, focuses on the variability of load, wind, solar, and Non-
VERs during 2017. A supplemental analysis discusses how the total variability of PacifiCorp's
system changes with varying levels of load, wind and solar capacity.
APPLICATION OF ROCKY MOUNTAIN POWER _ 3
9. The methodology in the FRS is similar to that employed in PacifiCorp's previous
regulation reserve requirement analysis inthe}Ol7IRP, but has been enhanced in some key ways.
First, regulation reserve requirements are co-optimized in a quantile regression model. Second,
actual hourly load schedules are employed as compared to the proxy schedules developed in the
previous study. Third, the FRS uses actual solar schedules reflecting the widespread penetration
of utility scale solar facilities that has occurred since the previous study. Fourth, the FRS reflects
updated data based on actual operational experience, including the data and benefits from
PacifiCorp's participation in the Energy Imbalance Market ("EIM").
10. 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. 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 EIM operated by the California lndependent System
Operator Corporation.
ll The FRS produces an hourly forecast of the regulation reserve requirements for
each of PacifiCorp's Balancing Authority Areas that is sufficientto 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 levels of wind, solar, and load.
12. 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. Next the
APPLICATION OF ROCKY MOUNTAIN POWER _ 4
FRS calculates the cost of holding regulation reserve for incremental wind and solar resources.
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.
13. 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 for the diversity of
using a single portfolio of regulation reserve resources to cover variations in load, wind, solar, and
Non-VERs. Table F.l summarizes the regulation reserve requirements for the various portfolios
considered in this analysis, the 2017 IRP FRS are also included for reference.
Table F.l - Portfolio Reserve uirements
L4. In the 2017 FRS, the Company calculated an inter-hour system balancing
integration cost reflecting sub-optimal gas plant commitment based on day-ahead load, wind, and
solar forecasts, rather than actuals. However, gas plants are dispatched in EIM to meet regional
demand, not just the PacifiCorp demand reflected in the PaR model, and quick-start gas plants can
be committed within EIM. In light of the minimal impact of the calculated cost in the 2017IRP,
and possible interaction with EIM, the company opted not to include inter-hour system balancing
integration costs in the 2019 IRP.
APPLICATION OF ROCKY MOUNTAIN POWER - 5
MW (MW)t%l (MW}Case (MW}
6t72017 Base Case 2,757 1,050 998 38%
1,O21 994 47%5312019 Base Case 2,750
15. The integration costs determined from the FRS are summarized in Table F.2 which
provides the wind and solar costs on a dollarper megawatt-hour ($/IvIWh) of generation basis. The
results of the 2017IRP FRS are also included for comfarison.
Table F.2 -2019 FRS Flexible Resource Costs as to2017 $/lVtWh
1,6. Based on the results of the FRS from the 2019 IRP the Company respectfully
requests that the wind integration rate be increased from $0.57 to $l.l I per MWh, in 2018 dollars,
and the solar integration rate increases from $0.60 to $0.85 per MWh, applicable to wind and solar
QFs that qualif 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 841l6
Telephone: [phone]
Email : ted.weston@nacifi com.com
Emily Wegener,
Rocky Mountain Power
1407 WestNorth Temple, Suite 320
Salt Lake City, Utah 84116
Telephone : (80 l) 220-4526
Email : emily.wegener@oacifi corp.com
Studv Period 2017 2017 2018-2036 2018-2036
Intra-hour Reserye $0.43 $0.46 $l.r r $0.85
Inter-hour System
Balancing $0.14 $0.14 nla nla
Flexible Resource Cost $0.57 $0.60 $l.l I $0.8s
APPLICATION OF ROCKY MOUNTAIN POWER _ 6
In addition, Rocky Mountain Power requests that all data requests regarding this
Application be sent in Microsoft Word to the following:
By email (prefened): [e-mail]
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
(801)220-2e63.
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. Il 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)
approving the wind integration rate of $1.11 per MWh for wind-powered QFs; and (3) approving
the solar integration rate of $0.85 per MWh. These rates will be used by the Company for purchase
of electric power from wind or solar-powered QFs, which amounts represents the integration costs
of wind and solar power, to be applied against 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.
APPLICATION OF ROCKY MOUNTAIN POWER - 7
RESPECTFULLY SUBMITTED this 8n day of October,2020.
Rocky Mountain Power
By
Emily egener
Rocky Mountain Power
I
APPLICATION OF ROCKY MOI.JNTAIN POWER- 8
Attachment L
ApppNDIx F - Frpxmrg RpsERVE Srupy
This 2019 Flexible Rel----------------erve Study (FRS) estimates the regulation reserve required to maintainPacifiCorp's system reliability and comply with North American Electric netiaUitity Corporation(NERC) reliability standards as well as the incremental cost of this regulation reserve. The FRSalso compares PacifiCorp's overall operating reserve requirements, including both regulation
reserve and contingency reserve, to its flexible resource supply over the Integraied Resource plan
(IRP) studyperiod.
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-party transmission system and the two BAAs are each required to comply withNERC standards. PacifiCorp must provide sufficient regulation reserye to remain within N|RC,,
balancing authority area control error (ACE) limit in compliance with BAL-0Ol-Z,t as well as theamount of contingency reserve required in order to comply with NERC standard BAL-002-
WECC-2.2 BAL-001-2 is a regulation reserve standard that became effective July l, 2016, and,BAL-002-WECC-2a is a contingency reserve standard that became effective January 24, 2017.Regulation reserve and contingency reserve are components of operating reserve, which NERC
defines as "the capability ab_ove firm system demand required to provide for regulation, load
forecasting error, equipment forced and scheduled outages and local area protectionl'3
Apart from disturbance events that are addressed through contingency reserye, regulation reserveis necessary to compensate for changes in load demand and geniration ou@ut, sJ as to maintain
ACE within mandatory parameters established by the BAL-001-2 standard. ine pRS estimates theamount of regulation reserye required to manage variations in load, variable energy resourcesa(VERS), and resources that are not VERs ("Non-VERs") in each of PacifiCorp's fi4as. Load,wind, solar, and Non-VERs were each studied because PacifiCorp's data indicates that thesecomponents or customer classes place different regulation reserve burdens on pacifiCorp,s systemdue to differences in the magnitude, frequency, and timing of their variations from forecasted
levels.
The FRS is based on PacifiCorp operational data recorded from January 2017 through December2017 for load, wind, solar, and Non-VERs. PacifiCorp's primary analysis, focuses on the
I NERC Standard BAL-001-2, www.nerc.com/filesiBAl-001-2.pdf, which became effective July l, 2016. ACE isthe difference between a BAA's scheduled and actual interchange, and reflects the difference Letween electricalgeneration and Load within that BAA.
2 NERC Standard BAL-002-WECC-2a www.nerc.com/files/BAl-00 2-WECC-2a.pdl which became effective
January 24,2017. BAL-002-WECC-2a clarified that non-traditional resources can quali$, as spinning reserves ifthey meet technical and performance requirements.
:NERC Glossary of Terms: www.nerc.Com/filesiglossary_of_terms.pdf, updated May 13,2019.4 VERS are resources that resources that: (1) -" r*"*ubi.; 1Z) cannot be iored ty the facility owner or operator;and (3) have variability that is beyond the control ofthe facility owner or operator. Integrattin ofvariabli Energ,Resources,orderNo.T64, |39FERCfl6l,246atp2Bl(2012)(,,orderNo.764,';; orirrnrei,g,orderNo.T64_A, 141 FERC nil,232 (2012) ("Order No. 764-4"); order on reh'g and clariJication,Order No.764-B, 144 FERC
n61,222 atP 210 (2013) ("Order No. 764-8").
77
PecnrConp-20l9IRP APPENDX F _ FLEXBLE RESBRvE Sruoy
PACTFICoRP - 2019 IRP APPENDIx F - Flsxmle RssnRvs SruoY
variability of load, wind, solar, and Non-VERs during 2017. A supplemental analysis discusses
how the iotal variability of the PacifiCorp system changes with varying levels of load, 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 covers variations in load, wind, solar, and Non-VERs, while
implicitly accounting for the diversity between the different classes. An explicit adjustrnent is also
made to-account for 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).
The methodology in the FRS is similar to that employed in PacifiCorp's previous regulation
reserve requiremlnt analysis in the 2017 IRP, but has been enhanced in some key ways.s First,
regulation reserve requirements are co-optimizedin a quantile regression model. Second, actual
ho*ly load scheduleJare employed as compared to the proxy schedules developed in the previous
study. Third, the FRS .6es a"toal solar schedules reflecting the widespread penetation of utility
scali solar facilities that has occurred since the previous study. Fourth, the FRS reflects updated
data based on actual operational experience, including the data and benefits from PacifiCorp's
participation in the EIM.6
The FRS results produce an hourly forecast of the regulation reserve requirements for each of
PacifiCorp's BAAs that is sufficient to ensure the reliabilrty of the transmission system and
compliance with NERC and WECC standards. This regulation reserve forecast covers the
comtined 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 levels of
wind, solar and load.
The regulation reserve requirement methodologies produced by the FRS was applied in the
Planning and Risk (PaR) production cost model to determine the cost of the reserve requirements
associated with incremental wind and solar capacity. These integration costs are applied to
potential wind and solar resource options in the System Optimizer (SO) model portfolio expansion
model, which does not otherwise account for regulation reserve requirements. When a portfolio is
studied in the PaR model, the regulation reserve requirements specific to that portfolio are
calculated and included in the study inputs, such that the production cost of the requirements is
incorporated in the reported results, so it is not necessary to add integration costs to the PaR results'
Overview
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. 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.
5 2017 Flexible Reserve Study, Appendix F in Volume II ofPacifiCorp's2017 IRP report:
www.pacificorp.com/content/dam/pacificorp/doc/Energy-Sources/Integrated-Resource-Plan/2017-IRP/2017-IRP-
VolumelU 0 I 7_IRP_Final.pdf
6 pacifiCorp presented the FRS for the 2019 IRP to the Technical Review Committee (TRC) that reviewed the FRS
for the ZOii m.p. In light of the robust methodology developed for the 2017 IRP, and the relatively limited
modifications for the 2019 IRP, TRC members indicated that continuing the formal review process was unnecessary.
78
P,C.CFICoRP _ 2OI9IRP APPENDx F - Frrxnrs Rrssnvr Sruoy
The FRS estimates regulation reserye 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 diversity benefits based on actual results. The FRS also includes adjustnents to
regulation reserve requirements to account for the changing portfolio of solar and wind resources
on PacifiCorpos 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. A comparison of the
results of the current analysis and that from the 2017 IRP is shown in Table F.l and Table F.2.
Table F.l - Portfolio Reserve uirements
Table F.2 -2019 FRS Flexible Resource Costs as to2017 $/lvrwh
In the 2017 FRS, PacifiCorp calculated an inter-hour system balancing integration cost reflecting
sub-optimal gas plant commitnent based on day-ahead load, wind, and solar forecasts, rather than
actuals. However, gas plants are dispatched in EIM to meet regional demand, not just the
PacifiCorp demand reflected in the PaR model, and quick-start gas plants can be committed within
EIM. In light of the minimal impact of the calculated cost in the2017 IRP, and possible interaction
with EIM, the company opted not to include inter-hour system balancing integration costs in the
20t9 rPJ.
The 201 9 FRS results are applied in the 20 I 9 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
reserye 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.
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 Electic
Reliability Corporation (NERC) regional reliability standards. Operating reserve generally
consists of three categories: (l) contingency reserve (i.e., spinning and supplemental reserve), (2)
regulation reserye, and (3) frequency response reserye. Contingency reserve is capacity that
PacifiCorp holds available to ensure compliance with the NERC regional reliability standard BAL-
79
2017 Base Case 2,',157 1,050 998 38%617
2019 Base Case 2,750 1,021 994 47%531
Studv Period 2017 2017 2018-2036 2018-2036
Intra-hour Reserve $0.43 $0.46 $t.r l $0.8s
Inter-hour Svstem Balancins $0.14 $0.14 nla nla
Total Flexible Resource Cost $0.57 $0.60 $1.11 $0.8s
PecnrConp - 2019IRP APPENDX F _ FLEXBLE RESERVE STUOY
002-WECC-2a.7 Regulation reserve is capacity that PacifiCorp holds available to ensure
compliance with the NERC Control Performance Criteria in BAL-001-2.8 Frequency response
reserve is capacity that Pacif,rCorp holds available to ensure compliance with NERC standard
BAL-003-1.e Each type of operating reserve is further defined below.
Contingency Reserve
Purpose: 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.
Volume: NERC regional reliability standard BAL-002-WECC-2a specifies that each BAA must
hold as contingency reserve an amount of capacity equal to three percent of load and three percent
of generation in that BAA.
Duration: Except within 60 minutes of a qualiffing contingency event, a BAA must maintain the
required level of contingency reserve at all times. Generally, this means that up to 60 minutes of
generation are required to provide contingency reserve, though successive outage events may
result in contingency reserves being deployed for longer periods. To restore contingency reserves,
other resources must be deployed to replace any generating resources that experienced outages,
typically either market purchases or generation from resources with slower ramp rates.
Ramp Rate: Only up capacity available within ten minutes can be counted as contingency reserve.
In accordance with Requirement 2 of BAL-002-WECC-2a, atleast half of a BAA's requirement
must be met with "spinning" resources that are online and immediately responsive to system
frequency deviations, while the remainder can come from "non-spinning" resources that do not
respond immediately, though they must still be fully deployed in ten minutes.r0
Regulation Reserve
Purpose: NERC standard BAL-001-2, which became effective July 1, 2016, does not speciff 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:
Esch 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...
7 NERC Standard BAL-002-WECC-2a- Contingency Reserve: www.nerc.com/files/BAl-002-WECC-2.pdf
8 NERC Standard BAL-001-2 - Real Power Balancing Control Performance: www.nerc.com/files/BAl-001-2.pdf
e NERC Standard BAL-003-1 - Frequency Response and Frequency Bias Setting:
www.nerc.com./palStand/Rel iabilit/o20Standards/BAl-O03 - l.pdf
r0 Retirement of the minimum spinning reserve obligation in BAL-002-WECC-2a is being considered due to
redundancy with frequency response obligations under BAL-003-1. More information is available online at:
www.wecc.org/Standards/PagesAilECC-0 I 1 5.aspx
80
PACTICoRP - 2019IRP ApprNox F - FLsxmLs REsERVE SruDy
In addition, Requirement 1 of BAL-001-2 specifies that PacifiCorp's Conhol 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 doei
not require a response to each and every ACE event, but rather requires that PacifiCorp meet aminimum aggregate level of perfonnance 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.
Volume: NERC standard BAL-001-2 does not specify a regulation reserve requirement based on
a simple formula, but instead requires utilities to hold sufficient reserve to meet performance
standards as discussed above. The 2019 FRS estimates the regulation reserve necessary to meet
Requirement 2 by compensating for the combined deviations of the load, wind, solar and Non-
VERs on PacifiCorp's system. These regulation reserve requirements are discussed in more detail
later on in the study.
Ramp Rate: Because Requirement 2 includes a 30 minute time limit for compliance, ramping
capability that can be deployed within 30 minutes contributes to meeting Pacifi-orp's regulaiioi
reserve requirements. 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.
Duration: PacifiCorp is required to submit balanced load and resource schedules as part of itsparticipation in EIM. PacifiCorp is also required to submit resources with up flexibility and downflexibility to cover uncertainty and expected ramps across the next hour. because forecasts are
submitted prior to the start of an hour, deviations can begin before an hour starts. As a result, aflexible resource might be called upon for the entire hour. In order to continue providing flexible
capacity in the following hour, energy must be available in storage for that ho* us well. Thelikelihood of actually deploying for two hours or more for reliability compliance (as opposed to
economics) is expected to be small.
Frequency Response Reserve
Purpose: NERC standard BAL-003-I specifies that each BAA must arrest frequency deviations
and support the interconnection when frequency drops below the schedulet level. When a
frequency drop occurs as a result of an event, PacifiCorp will deploy resources that increase thenet interchange of its BAAs and the flow of generation to the rest of the interconnection.
Volume: 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 sizeof the frequency drop and the BAA's Frequency Response Obligation, expressed in megawatt(MWy0.l Herts (Hz). 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 2019 Frequency Response Obligation was 20.2MW0.lHz for PACW, and 47.4 MW0.lHz for PACE. PacifiCorp's combined obligation
amounts to 67 .6 MW for a frequency drop of 0.1 H4 or 202.8 MW for a frequency drop of 0.1 Uz.
8r
PacrprCoRp - 2019 IRP APPENDIX F - FLExtsLE RBsgnvs SruoY
The performance measurement for contingency reserve under the Disturbance Control Standard
@Aa-002-3)l l, allows for recovery to the lesser of zero or the ACE value prior to the contingency
event, so increasing ACE above zero during a frequency event reduces the additional deployment
needed ifa contingency event occurs. Because contingency, regulation, and frequency events are
all relatively infrequent, they are unlikely to occur simultaneously. Because the frequency response
standard is based on median performance during a year, overlapping requirements that reduced
PacifiCorp's response during a limited number of frequency events would not impact compliance.
As a result, any available capacity not being used for generation is expected to contribute to
meeting PacifiCorp's Frequency Response Obligation, up to the technical capability of each unit,
including that designated as contingency or regulation reserves. Frequency response must occur
very rapidly, and a generating unit's capability is limited based on the unit's size, governor
.orrtrol., and available capacity, as well as the size of the frequency drop. As a result, while a few
resources could hold alarge amount of contingency or regulation reserve, frequency response may
need to be spread over a larger number of resources. Additionally, only resources that have active
and tuned gorerno. controls as well as outer loop control logic will respond properly to frequency
events.
Ramp Rate: Frequency response performance is measured over a period of seconds, amounting
to under a minute. Compliance is based on the average response over the course of an event. As a
result, a resource that immediately provides its full frequency response capability will provide the
greatest contribution. That same resource will contribute a smaller amount if it instead ramps up
to itr t tt frequency response capability over the course of a minute or responds after a lag.
Duration: Frequency response events are less than one minute in duration.
Black Start Requirements
Black start service is the ability of a generating unit to start without an outside electrical supply
and is necessary to help ensure the reliable restoration of the grid following a blackout. At this
time, PACW grid restoration would occur in coordination with Bonneville Power Administration
black start resources. The Gadsby combustion turbine resources are capable of supporting grid
restoration in PACE. PacifiCorp has not identified any incremental needs for black start service
during the IRP study period.
Ancillary Services Operational Distinctions
In actual operations, PacifiCorp identifies two types of flexible capacity as part of its participation
in the EIM. The contingency reserve held on each resource is specifically identified and is not
available for economic dispatch within the EIM. Any remaining flexible capacity on participating
resources that is not designated as contingency reserve can be economically dispatched in EIM
based on its operating cost (i.e. bid) and system requirements and can contribute to meeting
regulation reserve obligations. Because of this distinction, resources must either be designated as
rorrtiog.rr"y reserye or as regulation reserve. Contingency events are relatively rare while
opportunities to deploy additional regulation reserye in EIM occur frequently. As a result,
It NERC Standard BAL-002-3 - Disturbance Control Standard - Contingency Reserve for Recovery from a
Balancing Contingency Event: www.nerc.com/palStand/Reliability StandardVBAl-002-3.pdf
82
PecrprConp - 2019 IRP AppTNox F _ FLEXBLE RESERVE STuoy
PacifiCorp typically schedules its lowest-cost flexible resources to serve its load, and blocks off
capacity on its highest-cost flexible resources to meet its contingency obligations, subject to any
ramping limitations at each resource. This leaves resources with moderate costs available for
dispatch up by EIM, while lower-cost flexible resources remain available to be dispatched down
by EIM.
Overview
This section describes the data used to determine PacifiCorp's regulation reserve requirements. In
order to estimate PacifiCorp's required regulation reserye 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 EM and represent the best information available concerning the upcoming hour.12
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
five-minute intervals are used throughout the regulation reserve analysis.
EIM base schedule and deviation data for each wind, solar and Non-VER transaction point were
downloaded using the SettleCore application, 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 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 ffansaction 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.
12 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 Entity (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 EM Entity only, at 40 minutes (T-40) prior to the delivery hour in response to CAISO
sufficiency tests. T40 is the base schedule time point used throughout this study
83
PecmrConp - 2019 IRP APPENDx F - FI-Bxmle RssrRvr SrunY
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 data
o Five-minute interval actual load
o Hourly base schedules
VER data
o Five-minute interval actual generation
o Hourly base schedules
Non-VERdata
o Five-minute interval actual generation
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
underlyrng 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 intemrptible 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, intemrptible 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
treatrnent is consistent with that used in the CAISO load forecast methodology (used for PACE
and PACW operations), which also nets these intemrptible 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. Load data was downloaded from PacifiCorp's Ranger PI system and has not been
adjusted for transmission and distribution losses.
Wind and Solar Data
The wind and solar classes include resources that (1) 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.l3 Wind and solar, in comparison to load, often have larger upward and downward
13 Order No. 764 atP 281; Order No.764-B at P 210.
84
P.e.cnrConp - 2019IRP ApprNox F - FLExBLE Rrssnvs Sruny
fluctuations in output that impose significant and sometimes unforeseen challenges when
attempting to maintain reliability. For example, as recognized by FERC in Order No. 764,
"Increasing 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."l4 The data included in the FRS for the wind and solar
classes include all wind and solarresources in PacifiCorp's BAAs, which includes: (1) third-party
resources (OATT or legacy confract transmission customers); (2) PacifiCorp-owned resources;
and (3) other PacifiCorp-contracted resources, such as qualifuing facilities, power purchases, and
exchanges. In total, the FRS includes 2,750 megawatts of wind and 1,021megawatts of solar.
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."lsThe 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 hansmission customers); many PacifiCorp-owned resowces; and other
PacifiCorp-contracted resources, such as qualifying facilities, powerpurchases, and exchanges. In
total, the FRS includes2,202 megawatts ofNon-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 otherhours. 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
requirement is also zero. The allocation of regulation reserve requirements and diversity benefits
is discussed in more detail later on in the study.
Overview
This section provides details on adjustments made to the data to align the ACE calculation with
actual operations, and address data issues.
Base Schedule Ramping Adjustment
In actual operations, PacifiCorp's ACE calculation includes a linear ramp from the base schedulein one hour to the base schedule in the next hour, starting ten-minutes before the hour and
ta Order No. 764 atP 20 (emphasis added).
ts Id. atp 92.
85
PacmrConp - 2019 IRP APPENDX F - FLEXBLE RESERVE STUDY
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 adjusfrnent 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.1 below illustates the hourlybase schedule
and the ramping adjustment. The same calculation applies to all base schedules: Load, Wind, Non-
VERs, and the combined portfolio.
Figure F.l - Base Schedule Ramping Adjustment
6000
5900
5800
5700
5600
5500
5400
5300
5200
5100
5000
4900
4800
I Adjusted Base Schedule I Base Schedule
Data Corrections
The data extracted from PacifiCorp's systems for, wind, solar and Non-VERs was sourced from
CAISO settlement quality data. This data has already been verified for inconsistencies as part of
the settlement process and needs minimal cleaning as described below. Regarding five minute
interval load data from the PI Ranger system, intervals were excluded from the FRS results if any
five-minute interval suffered from at least one of the data anomalies that are described further
below:
Load
..E3
=-g3!o,E(,vtootUa
()oooooooooo ooqQooooqQQoa ooooQE666rrlq6+OF+OOOOeaea?ce *Y!::G o o F |-J N ru trr trr s $ (,r (n o o r F N Nl ry ur + $ !f (n Q c) e t(, o (, b Ln o tr o tr, b tn o tn o u o t^ o (,l o Ln o u o (, o (, o (^
Time (lnterval Ending)
86
a Stuck meter/flat meter reading
a Telemetry spike/poor connection to meter
Wind, Solar, and Non-VERs:o Generator trip events. Curtailment events
Load in PacifiCorp's BAAs changes continuously. While a BAA could potentially maintain the
exact same load levels in trvo five-minute intervals in a row, it is extemely 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 availabli load
measurement for the BAA will continue to be reported.
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. Such events couldbe 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. Load ielemetry
spike irregularities were identifred by examining the intervals with the largest changes from onl
interval to the next, either up or down. Intervals with inexplicably large andrapid 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.
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,
contingency reserye 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 thi equipment.
When wind speed oscillates above and below the cut-offpoint, 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.
After review of the data for each of the above anomaly types, and out of 105,120 five-minute
intervals evaluated, only 1.1 percent and 0.52 percent of the total FRS term hours were removed
from PACW and PACE, respectively. The system-wide error rate was 1.36 percent, slightly lower
than the sum of the PACW and PACE rates due to coincident hours. While cieaning up oi 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 period.
87
PlcrprConp - 2019IRP ApprNox F - Fmxnrp RrsrRvB Sruoy
PACFICORP _ 2019 IRP AppBNoX F - FLEXTBLE RTSENVT STUOY
Overview
This section presents the methodology used to determine the initial regulation reserve needed to
manage the lbad 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 uruilubl. at time of EIM base schedule submission at T-40.16
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
- 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;- Solar;- Non-VERs; and- Load.
Components of Operating Reserve Methodology
Operating Reserve: Resene Categories
Oierating reserve consists of three categories: (1) contingency reserve (i.e., spinning and
r"ppf"*""tal 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 and frequency responso requirements are defined formulaically by their
respective reliability standards.
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
deviaions .u6"d by contingency events are covered by contingency reserve rather than regulation
reserye, they are excluded from the determination of the regulation reserve requirements. Because
frequency i"rporr. reserve can overlap with that held for contingency and regulation reserve
requirernents it is similarly excluded from the determination of regulation reserve requirements.
16 See footnote l2 above for explanation of PacifiCorp's use of the T-40 base schedule time point in the FRS.
88
PecnrConr - 2019IRP APPENDx F - FLExBLE Rrsrnvr Sruoy
The tlpes of operating reserve and relationship between them are further defined in in the FlexibleResource Requirements section above.
Regulation reserve is capacity that PacifiCorp holds available to ensure compliance with the NERCControl Performance Criteria in BAL-001-2, which requires a BAA to carry regulation reserveincremental to contingency reserve to maintain reliability.lT The regulation ro.*-" requirement isnot defined by a simple formula, but instead is the amount of resirve required by eaih BAA tomeet specified control performance standards. Requirement two of BAL-00i-2 defines thecompliance standard as follows:
Each Balancing Authority shall operate such that its clock-minute average ofReporting ACE does not exceed its clock-minute Balancing Authority ACE Limit
(BAAL) for more than 30 consecutive clock-minutes...
PacifiCorp has been operating under BAL-001-2 since March l, 2010, as part of a NERCReliability-Based Control field trial in the Western Interconnection, so pacifrcorp has experience
operating under the new standard, even though it did not become effective until iuly t,ZdtA.
The three key elements in BAL-001-2 are (l) the length of time (or "interval,,) used to measure
compliance; (2) 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 aninterval is considered out of compliance. These changes are discussed in further detail below.
The first element is the length of time used to measure compliance. Compliance under BAL-001-2 is measured over rolling thirty-minute intervals, with 60 overlapping piriods per hour, some ofwhich include parts of two clock-hours. [n effect, this means thit-every minuti of every hour isthe beginning of a new, thirty-minute compliance interval under the new BAL-001-2 standard. IfACE is within the allowed limits at least once in a thirty-minute interval, that interval is incompliance, so only the minimum deviation in each rolling thirty-minute interval is considered in
{etgrmining compliance. As a result PacifiCorp does not need to hold regulation reserve fordeviations with duration less than 30 minutes.
The second element is the numberof intervals where deviations are allowed to be outside the limits
set in the standard. BAL-001-2 requires 100 percent compliance, so deviations must be maintainedwithin the requirement set by the standard for all rolling thirty-minute intervals.
The third element is the bandwidth of acceptable deviation before an interval is considered out ofcompliance. Under BAL-001-2, the acceptable deviation for each BAA is dynamic, varying as afunction of the frequency deviation for the entire interconnect. When interconnection freqiencyexceeds 60 Hz, the dynamic calculation does not require regulation resources to be deployeiregardless of a BAA's ACE. As interconnection frequency drops further below 60 Hz, u BAA,spermissible ACE shortfall is increasingly restrictive.
Planning Reliability Target: Loss of Load probability
When conducting resource planning, it is common to use a reliability target that assumes aspecified loss of load probability (LOLP). In effect, this is a plan to ",ytuit firm load in rare
r7 NERC Standard BAL-001-2, www.nerc.com/files/BAl-001-2.pdf
89
PecntConp - 2019 IRP APPENDx F - FLsxmLB RESERvE SrUDY
circumstances, rather than acquiring resources for extuemely 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 *re 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'
The 2019 FRS assumes that a regulation reserve forecasting methodology that results in 0.50 loss
of load hours per year due to regulation reserve shortages is appropriate for planning and
ratemaking prr.por"r. 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:
. Ifthe regulation reserve available is greater than the regulation reserve need for an hour,
the LOLP is zero for that hour.
o If the regulation reserve held is less than the amount needed, the LOLP is derived from the
Balancing Authority ACE Limit probability distribution as illustrated below.
Balancing Authority ACE Limit: Allowed Deviations
Even if insufficient iegulation reserve capability is available to compensate for a thirty-minute
sustained deviation, a violation of BAL-001-2 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 interconneition frequency. When WECC frequency is close to 60H2, the Balancing Authority
ACE Limit is large and large deviations in ACE are allowed. As WECC frequency drops further
and further below 60 Hz, AiBdeviations 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, thqhistorical probability distribution of Balancing Authority ACE Limit values is known.
Figure F.2 below shows the probability of exceeding the allowed deviation during a five-minute
interval for a given level of ACE shortfall. For instance, a43 MW ACE shortfall in PACW has a
one percent.h*". of exceeding the Balancing Authority ACE Limit. WECC-wide frequency can
change rapidly and without notice, and this causes large changes in the Balancing Authority ACE
Limii over short time frames. Maintaining ACE within the Balancing Authority ACE Limit under
those circumstances can require rapid deployment of large amounts of operating reserve. 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 br four times Lro. This also limits the occurrence of transmission flows that
exceed path ratings as result of large variations in ACE.I8'le This cap is reflected in Figure F.2.
18 ,,Regional Industry Initiatives Assessment." NWPP MC Phase 3 Operations Integration Work Group. Dec. 31,
21la.7g. t4. Available at: www.nwpp.org/documents/IvlC-PublicA{WPP-MC-Phase-3-Regional-Industry-
Initiatives-Assessmentl2-3 l-20l4.pdf
re *NERC Reliability-Based Control Field Trial Draft Report." Westem Electricity Coordinating Council. Mar.25,
2015. Available at: www.wecc.bizlReliability/RBC%20Field%20Trial%o2Okepo*o/,20Approved%203-25-2015.pdf
90
PacnrCoRp - 2019 IRP AppeNox F - FrBxnLr RESERVE Sruoy
F.2 -of Allowed Deviation
LOOo/o
9tr/o
8Oo/o
7Ao/o
600/o
5tr/o
40%
3Oo/o
20%
Ltr/o
o%
50 100 150 200
AcE shortfall (MW|
-Exceedance
Probability (PACE)
-Exceedance
Probability (PAcw)
In2017, PacifiCorp's deviations and Balancing Authority ACE Limits were uncorrelated, 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.
Regulation Reserue Forecast: Amount Held
ln order to calculate the amount of regulation reserye required to be held while being compliant
with BAL-001-2 - using a LOLP of 0.5 hours per year or less - a quantile regression methodology
was used. The regression variables consist of;o The combined deviation of load, wind, solar, and Non-VERs;o Forecasted load as apercentage ofpeak load;o Forecasted wind generation as a percentage of total system wind capacity;o Forecasted solar generation as a percentage oftotal system solar capacity; ando Forecasted Non-VER generation as a percentage of maximum Non-VER schedules.
x
c
.9a,.o
oo!to3e
h0tr
EIooIJxIU
o
.E
EG.cIo
o.
0
91
PecmrConp - 2019 IRP AppsNox F - FmxnrE RrssRvs StuoY
The combined deviations of load, wind, solar and non-VERs (Combined Diversity Error) is
calculated as [Load Error - Wind Error - Solar Error - Non VER Error] as illustrated below in
Table F.3 for PACE.
Table F.3 - Combined Error
3 -21
5 -16
3 -t4
3 -55
J -48
-26
4l
-39
The individual errors (load, wind, solar and non-VERs) are calculated as the difference between
the actual meter data and the adjusted hourly base schedules as illusfrated below for PACE wind
in Table F.4.
Table F.4 - Wind Error
Ur/2017 3 5 957 936 -2t
Ul20t7 J 956 940 -16
\tr!?t917
t/y2017
941
900
!U2017 3 25 955 908 -48
yU20t7 3 955 929 -26
t/U2017 3 35 955 9t4 4l
3
3
J
3
3
J
-?'7
-37
-39
-3260
!s
20
9tJ
955
-14
-55
UU20t7 3
3
40 955
955
e!9
916
-39
Ut/2017 45 -39
1lu20t7 50 955 918 -37
t/t/2017 954 917 -37
Ut/2017 J 60 951 -32
An illustration of the combined diversity error and the forecasted levels of load as a percentage of
peak load, the forecasted levels of wind as a percentage of total system capaclty, the forecasted
levels of solar as a percentage of total system capacity and the forecasted levels of Non-VERs as
a percentage of peak schedule are illustrated below in Table F.5 for PACE.
Table F.5 -
J
3
t/U20t7
l/t/2017
J
3
J
5
t9
l5
5015:%
50.4%
a%
0%
0%
s,lYe
s1%
55o/o
UU20t7
!!!t20_r7
U|l20t7
0
0
0
yt/2017
lU20t7
r/u2017
t/y20t7
6t
75
87
67
84
80
53
97
-5
-6
-J
-6
-6
4
7
-8
-5
lU20t7
yu2017
35
5
20
50
55
l5
l0
40
45
t/U2017
Uu20t7
0
0
0
0
0
0
74
66
73
75t/Lt20t7
19-
36
35
32
37
49
34
45
30
3l
40
36
2
I
)
92
UU20t7 50.304
UU20t7
UU20t7
UU20t7
lt/2017
Ut/2017
t/t/2017
Uu20t7
Ut/2017
l/t/2017
yy20t7
t/U2017
1/U20r7
llll20r7
l/U2017
UU20t7
UU20t7
UU20t7
UU20t7
Ut/2017
yt/2017
Ut/2017
I 898
I 898
I 898
I 898
I 898
I 898
l 898
l 898
I 898
I 898
l 898
I 898
505%
50.4%
50.3%
503%
50.3%
50.3v,
s03%
s0.3%
50.3%
50.3%
s0.3%
50.1v,
3
J
3
J
J
J
J
.,,
20
25
30
35
40
45
sg
55
60
0%
0%
0%
0%
0%
0%
0%
0%
0%
97
87
67
84
80
74
66
68
58
50.3%
s03%
s0.3%
s0.3%
s0.3%
50.1%
50.3%
s0.3%
50.1o
56%
s6%
560/o
s6%
s6%
s6%
56%
56%
56%
s5%
55%
55%
s5%
55%
55%
55o/o
55%
55o/o
The Load Forecast, Wind Forecast, Solar Forecast and Non VER Forecast are calculated as a
percentage of some measure of capacity or peak. The forecasted levels of PACE wind as a
percentage of total system capacity is illustrated below in Table F.6.
Table F.6 - Wind Forecast Level
l
3
J
3
3
J
J
J
J
J
J
J
5
l0
l5
20
25
30
35
40
45
50
55
60
957
956
955
955
955
955
955
955
955
955
954
951
Quantile regression is a type of regression analysis. Whereas the typical method of ordinary least
squares results in estimates of the conditional mean (50th percentile) of the response variable given
certain values of the predictor variables, quantile regression aims at estimating other specified
percentiles of the response variable. For the 2019 FRS the response variable - Combined Diversity
Error - was expressed as a function of four predictor variables - Wind Forecast, Solar Forecast,
Load Forecast and Non VER Forecast. Each predictor variable contributes to the regression as a
combination of linear, square, and cubic effects. Specifically:
Combined Diversity Error varies as a function of:
Wind Forecast + Wtnd Forecastz + Wtnd Forecast3 *
Solar Forecast * Solar Forecast2 * Solar Forecast3 *
LoadForecast + LoadForecostz + LoadForecast3 +
NonVER Forecast + NonVER Forecast2
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. The regulation reserve forecast is not intended to
compensate for every potential deviation. lnstead, when a shortfall occurs, the size of that shortfall
determines the probability of exceeding the Balancing Authority ACE Limit and a reliability
93
PecrrConp - 2019IRP ApppNox F - FLExBLE RrsrRvs Sruov
PACFICoRP-2019IRP APPENDX F _ Fmxmrr RESERVE Sruoy
violation occurring. The forecast is adjusted to achieve a cumulative LOLP that corresponds to the
annual reliability target.
2017 Regulation Reserve Forecast
Overview
The following forecasts are polynomial functions that cover a targeted percentile of all historical
deviations. These forecasts are stand-alone forecasts - based on the difference between hour-ahead
base schedules and actual meter data - expressing the errors as a function of the level of forecast.
The stand-alone reserve requirement shown achieves the annual reliability target of 0.5 hours per
year, after accounting for the dynamical Balancing Authority ACE Limit. The combined diversity
error system requirements are discussed later on in the study.
Wind
Figure F.3 illustrates the relationship between the regulation reserve requirements for PACE wind
during 2017 andthe forecasted level of output, stated as a capacity factor (i.e., apercentage of the
nameplate wind capacity). Figure F.4 illustrates this relationship for PACW.
Figure F.3 - Wind Regulation Reserve Requirements by Forecast - PACE
2017 PACE Wnd Forecastw Enor
40.0%
oEE.o
E(!z
oo
CDoEooo(L
6o6
30.096
.:..i'
t
I.,,ir'j
20.096 ,4,
:5
- Obggftetons
- RaganDRoqulrement
coEo.E
=qlo'u
;;
z'J; ..
0096-
0q6 1096 20% 30% 40% 50% 60s 70% 8096 90% '100%
Forecast Capacity Factor
94
PecmrConp - 20l9IRP ApprNox F - FLEXBLE RESsRve Sruoy
Figure F.4 - Wind Regulation Reserve Requirements by Forecast Capacity Factor-pACW
2017 PACW Wnd Forecast vs Enor
40.056
- Obs8natons
- ResenE Rsqulremert
0.096
B% 10% 20% 30i6 4015 5096 60%70% 80j6 9016 .100%
Forecasl Capacity Factor
The forecast results in an averag e 2017 stand-alone regulation reserve requirement for wind of 434MW for the PacifiCorp system, or approximately 15.8 percent of nameplate capacity.
Solar
Figure F.5 illustrates the relationship between the regulation reserve requirements for pACE solarduring 20L7 andthe forecasted level of output, stated as a capacity factor (i.e., apercentage of the
nameplate solar capacity). Figure F.6 illustrates this relationship for pACW.
Ioo
-o30.0%-oEoz
ooCDoEo
$ eo.o*-
(Loo0
co
E
.g3
u
l.
95
PlcmrCoRp-20l9IRP Appsxox F - FI-BxmI-B Rrspnvn Sruov
Figure F.5 - Solar Regulation Reserve Requirements by Forecast Capacity Factor-PACE
2017 PACE Solar Forecast vs Enor
70.095 -
60.096
50.096 -
o6a{)
Eoz
ooCDEEogo(Looo
Eo
Eo.!fatoE.
+.
;
o 60 0!6-
6ao
E
2Eoox-
oo(Do
5 qo.oso -oo(L
o
Eroos*-
EoEo.E
+20 0% -
ot
'10.096 -
40.096 -
30.0% -
20.016 -
10.096 -
0.0% -
- Obssoalions
- RoseneRegulrement
- Obgoruatons
- ReseireRequirement
0% 10% 2096 3096 40% 5096 6096 70% 80}6 s096 100%
Forecast Capaci$ Factor
Figure F.6 - Sotar Regulation Reserve Requirements by Forecast Capacity Factor-PACW
2017 PACW Solar Forecast vs Enor
70.0% -
., t.
0% 10% 2096 3096 40i6 50% 60% 70% 80s 9096 100%
96
0.0% -
Forecast Capacity Factor
PecmrConp-2019IRP APPENDx F - Fr-BxmrB RrssRvs SruDy
The forecast results in an averag e 2017 stand-alone regulation reserye requirement for solar of 145MW for the PacifiCorp system, or approximately 14.8 percent of nameplate capacity.
Non-VERs
Figure F.7 below illustrates the regulation reserye requirements for PACE Non-VERs &ulng20l7
as a function of the forecasted level of output, stated as a peak schedule factor (i.e., apercentage
of the peak Non-VER schedule observed for 2017). Figure F.8 illustrates this relationship for
PACW.
Figure F.7 - Non-YER Regulation Reserve Requirements by Forecast Schedule Factor-
PACE
2017 PACE Non VER Forecasfi vs Enor
II
15.095 -
14.0!6 -
13.096 -
12,096 -
11.096 -
10.096 -
9.095 -
8.0% -
7.0%-
6.096 -
5096-
,1.0% -
3.0!5 -
2.095 -
1.0% -
0.0!6 -
t
a tl'a
l.'-gfT'oEqU'!r!{,&
ooCDoEoooo-(!o(!
co
Eo.EfCTou
I
t.
t
D
i':!.'
ItI
t
I
.tt
a
-.RoBerYs Rgqdrsm6(fr
. Fall
. Sprlng
' Summer. WintEr
I
10.096 20.0% 30.096 40,0% 50.0.f 60.096 70.096 80.096 90.016 100.096
Forecast Peak Schedule Factor
97
PacnrConp - 2019 IRP APPENDx F-FLExIBLE RESERVE SruoY
Figure F.8 - Non-VER Regulation Reserve Requirements by Forecast Schedule Factor-
PACW
2017 PACW Non VER Forecast vs Enor
15.016 -
14.095 -
'13.0% -
t
,J
oE 12.0%-Eo€ rr.oc6-(t
I
310.096-(L
b go*-oog s.096-co
$ rox-
ILo 60%-oo
$ s.oto-
Eg 4o%-
=rfi 3os-
2.0l,6 -
l, 1I
.t
l;
t.
t
I
It
-.Rssgn s Rosrlrem3nt
. Fall
. Spnng
. Summer
. Iirintsr
?
t
ar
t
0.0% -
10.096 20.096 30.096 ,10.096 50.0% 60.0% 70.096 80.0% 90.0% 100.096
Forecast Peak Schedule Factor
The forecast results in an average 2Ol7 stand-alone regulation reserve requirement for non VERS
of 110 MW for the PacifiCorp system, or approximately 5.7 percent of the peak schedule.
Load
Figure F.9 below illustrates the regulation reserve requirements for PACE load during 201'7 as a
function of the forecasted level of output, stated as a peak load factor (i.e., apercentage of the peak
load observed during 2Ol7) for PACE. Figure F.10 illustrates this relationship for PACW.
98
P,qcnrConp-2019IRP ApprNox F - Frnxnr,s Ressnvs STUDY
Figure F.9 - stand-alone Load Reguration Reserve Requirements-pACE
2017 PACE Lod Forecactw Enor
6.0096 -t
I
i.
lo5.0016 -
!,ooJ
!ooL
ooIDEcoooo-
4.0096 -
3.0016 -
t
a.t
ota
,
o0l!
EoEo'5rou
-.R!senrReQrl emsfit. Fall
' sglng
. Srmrncr
. WUliet
2.00t6 -
1.00ts -
0.0096 -
40.096 45.0!6 50.0% 55.0% 60.096 65.09a 70.09r
Forecast Ped(
75.095 80.096 85.0* S0.0* 95.096 100_0*
Load F*tor
Figure F.10 - stand-alone Load Reguration Reserve Requirements-pACW
2017 PACW Load Foreca$lls Enor
6.0096 -
5.0096 -
t,ooJ!(9t a.oolo -
oottoEo
$ :.oox -
(Looocp e.oor -o'5trou
1.00%-
0.0096 -
a
.1.'.!. .
.a 3'.ri
,
l'
-l
I
t a
t
I
-.Roseru. RcsJlrsmsrt. Fall
. Sprlng
. Su,nmu
. wfllef
30.096 35.0%.t0.016 45.0X50.016 55.09i 60.096 65.096
ri '
70.0s 75.096 00.0r5 95.09690.096 95.0X100.096
Forecast Pedr Load Factor
99
PACTICORP - 20I9 IRP ApPTNOX F - FLEXBLE RESERVE STUNY
The forecast results in an averag e2017 stand-alone regulation reserve requirement for load of 305
MW for the PacifiCorp system, or approximately 3.0 percent of the peak load'
The EIM is a voluntary energy imbalance market service through the CAISO where market
systems automatically balance-supply and demand for electricity every fifteen and five minutes,
dispatching least-cost resources every five minutes.
pacifiCorp and CAISO began full EIM operation on November 1,2014. A number of additional
participants have since joined the EIM, and more participants are scheduled to join in the next
r"r"rui years. PacifiCorp's participation in the EIM results in improved power production
forecasting and optimiz"a intru-tro* resource dispatch. This brings importanlbenefits including
reduced "i"rgy dlspatch costs through automatic dispatch, enhanced reliability with improved
situational awareness, better integration of renewable energy resources, and reduced curtailment
of renewable energy resources.
The EIM also has direct effects related to regulation reserve requirements. First, as a result of EIM
participation, PacifiCorp has improved data used in the analysis contained in this FRS. The data
and control provided Uy ttre EIM allow PacifrCorp to achieve the portfolio diversrty benefits
described in the first part of this section. Second, the EIM's intra-hour capabilities across the
broader EIM footprint provide the opporhmity to reduce the amount of regulation reserve
necessary for PacifiCorp to hold, as further explained in the second part of this section.
Portfolio Diversity Benefit
The regulation reserve forecasts described above independently ensure that the probability of a
reliabil-ity violation for each class remains within the reliability target; how€ver, 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
quantrty of reserve is sufficient to maintain the desired level of reliability. This reduction in the
rir"*" requirement is the diversity benefit from holding a single pool of reserve to cover
deviations in Sol*, Wind, Non-VERs, and Load. As a result, the regulation reserve forecast for
the portfolio can be reduced while still meeting the reliability target. For this reason the portfolio
regulation requirements were calculated on the Combined Diversity Error'
As shown in Table F.7 below, PacifiCorp calculated the proportional reduction to the standalone
requirements that could be applied such ihat the PacifiCorp system achieves the target determined
through the quantile ,"gr.rrion on the Combined Diversity Error. A total portfolio requirement of
635 MW was the r".,.lt of this regression, a reduction of 36 percert. Applying this 36 percent
reduction to each of the stand-alone regulation forecasts results in the diversity benefits shown in
the second column. The last column shows the regulation requirements for each class after
subtracting the portfolio diversity benefit.
100
PacnrConp-2019IRP APPENDx F-FLExtsLE RBseRve Sruoy
Table F.7 - Results with Portfolio
EIM Diversity Benefit
In addition to the direct benefits from EIM's increased system visibility and improved intra-houroperational performance described above, the participation of other entities in the broader EIMfootprint provides the opportunity to further reduce the amount of regulation reserve pacifiCorp
must hold.
By pooling variability in load, wind, and solar ou@ut, EIM entities reduce the quantity of reserverequired to meet flexibility needs. The EIM also facilitates procurement of flexible rampingcapacity 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 flexibleramping requirement for the entire EM fooprint can be iess tha., the sum of individual BAArequirements. This difference is known as the "diversitybenefit" in the EIM. This diversitybenefitreflects offsetting variability and lower combined uncertainty. This flexibility reserve (uncertaintyrequiremenQ is in addition to the spinning and supplementai reserve carried against generation oitransmission system contingencies under the NERC standards.
The CAISO calculates the EM diversity benefit by first calculating an uncertainty requirementfor each individual EIM BAA and then by comparing the sum of those requirements to theuncertainty requirement for the entire EM area. The latter amount is expected to b" l"r, than thesum of the uncertainty requirements from the individual BAAs due to thi ponfolio diversificationeffect of forecastingalarget pool of load and resources using intra-hour r"h"d,rlirrg and increasedsystem visibility in the hypothetical, single-BAA EIM. Each EIM BAA is then iredited with ashare of the diversity benefit calculated by CAISO based on its share of the stand-alonerequirement 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 particrpatingin the EIM. Thus, each EIM participant remains responsible for all reliability obligations. oispitlthese limitations, EIM imports from other participating BAAs can help balance fafifiCorp,s loadsand resources within an hour, reducing the size ofreserve shortfalls and the likelihood of a
!4ancing Authority ACE Limit violation. While substantial EIM imports do occur in some hours,it is only appropriate to rely on PacifiCorp's diversity benefit ursociated with EIM participation,
as these are derived from the structure of the EIM rather than resources contributed by otherparticipants.
Table F.8 below provides a numeric example of uncertainty requirements and application of thecalculated diversity benefi t.
Non-VER lr0 (40)70Load305010)195VER-Wind 434 0s7)277VER - Solar 145 (s3)93Total994(360)63s
101
6l 10437.0%s83 342100925110165I550 57 10834.8%636 3391009751101652600
55 11033.4%689 3461101,03s1101653650
56 r24313%742 3381131,080t201804667
PacnrConp - 2019 IRP APPENDX F - FTTXTSLT RESERVE SruOY
Table F.8 - EIM Benefit
While the diversity benefit is uncertain, that uncertainty is not signifrcantly differe'nt from the
uncertainty in the ilalancing Authority ACE Limit described above. In the 2019 FRS, PacifiCorp
has creditld the regulation reserve forecast with a historical distribution of calculated EIM
diversity benefits. lfrrit" this FRS considers regulation reserve requirements rn20l7, the CAISO
identified an error in their calculation of uncertainty requirements in early 2018. CAISO's
published uncertainty requirements and associated diversitybenefits are now only valid for March
2018 forward. To capture these additional benefits for this analysis, PacifiCorp has applied the
historical distribution of EM diversity benefits from March 2018 through the beginning of this
study in July 2018. Relatively smali incremental EIM diversity benefits are expected going
forward as additional entities iarticipate in EIM; however, operational data on new participants
was not available at the time the study was prepared.
The inclusion of EIM diversity benefits in the 2019 FRS reduces the probability of reserve
shortfalls and, in doing ,o, ,"drr"", the overall regulation reserve requirement. This allows
pacifiCorp's forecasted-requirernents to be reduced. As shown in Table F.9 below, the resulting
regulation reserve requirement is 53 I Mw, a 47 percentreduction (including the portfolio diversity
beirefrt) compared tothe stand-alone requirement for each class. The average regulation reserve
requirement ls reduced by 104 MW relative to the PacifrCorp portfolio reserve requirement
without the EIM diversity benefit. The portfolio regulation forecast is expected to achieve an
LOLp of 0.5 hours per year, based on a quantile regressionat a99.35 percent exceedance level.
Table F.9 -2017 Results with Portfolio and EIM Benefits
As previously discussed, Requirement I of BAL-001-2 specifies that PacifiCorp's CPS1 score
,,rri b" greater than .qrrul to lbO percent for each preceding 12 consecutive calendar month period,
evaluatel monthly. The CpSl score compares PacifiCorp's ACE with interconnection frequency
during each clock minute. A higher score indicates PacifiCorp's ACE is helping interconnection
12CP1,912593.1%s.7%110Non-VER 12cPl0,0zl41631.6%3.0%305Load Nameplate2,7502328.4%ts.8%434VER-Wind
Nameplate983787.9o/o14.8%t45VER- Solar
531994Total
t02
PecrprCoRp - 2019 IRP APPENDx F - Fmxmls RrsenvB Sruoy
frequency, while a lower score indicates it is hurting interconnection frequency. Because CpSl isaveraged and evaluated on a monthly basis, it does not require a response to each and every ACEevent, but rather requires that PacifiCorp meet a minimum aggregatilevel of performance in eachmonth.
The 2017 Regulation Reserve Forecast described above is evaluating requirements for extremedeviations that are at least 30 minutes in duration, for compliance wilth Requirement 2 of BAL-001-2' In contrast, compliance with CPSI requires reserve capability to compensate for themajority of over a minute to minute basis. These fast-ramping resourc", *orrid be deployedfrequently, and would also contribute to compliance with Requirement 2 of BAL-001-2, so tleyare a subset of the 2017 Regulation Reserve Forecast described above.
To evaluate CPSI requirements, PacifiCorp compared the net load change for each five-minuteinterval lri,2017 to the corresponding value for Requirement 2 complianJe in that hour from the2017 Regulation Reserve Forecast, after accounting for diversity (resulting in the 531 MW averagerequirement shown in Table F.9). Resource-s may deploy for i.equirem"it 2
"orrrpliance or". ipto 30 minutes, so the average requirement of 531 MW would."qri." ramping
"upu^Uitity of at least17.7 NNV per minute (53 1 MW / 30 minutes).
Because CPS I is averaged and evaluated on a monthly basis, it does not require a response to eachand every ACE event, but rather requires that PacifiCorp meet a minimum aggregate level ofperformance in each month. Resources capable of ensuring compliance in 95 peilent of intervals
are expected to be sufficient to meet CPS 1, and given that ACE may deviate in either a positiveor negative direction, the 97.5ft percentile of incremental requirements was evaluated. Thiscorresponds to 87 MW, or approximately 16.3 percent of tho average Requirement 2 value.Because this value is for a five-minute interval, meeting it would requir:e u rrrrping capability ofat least 17.3 MW per minute (87 MW / 5 minutes). This value is actually sligdly lower than theramping capability for Requirement 2.
Note that resources must respond immediately to ensure compliance with Requirement 1, asperformance is measured on a minute to minute basis. As u r"rt,lt, resources that respond aft.er adelay, such as quick-start gas plants or certain intemrptible loads, would not be suitable forRequirement 1 compliance, so these resources cannot be allocated the entire regulation reserverequirement. However, because Requirement I compliance is a small portion ofthJtotal regulationreserve requirement, these restrictions on resource type are unlikely to be a meaningful coistraint.
In addition, CPSI compliance is weighted toward performance during conditions wheninterconnection frequency deviations are large. The largest frequency deviatiirs would also resultin deployment of frequency response reserves, which are somiwhai larger in magnitude, thoughthey have a less stringent performance metric under BAL-003-1, based on median i"rpor." d*i"gthe largest events.
In light of the overlaps with BAL-001-2 Requirement 2 andBAL-0O3-l described above, cpSlcompliance is not expected to result in an additional requirements beyond what is necessary tocomply with those standards.
103
PACTFTCoRP - 2019 IRP APPENDD( F _ FI-BXNI-B RTSTNVB STUOY
The IRp portfolio optimization process contemplates the addition of new wind and solar capacity
as part of its selection of future resources, ut *"ll as changes in peak load dueto load growth and
""irgy effrciency measures. As PacifiCorp's portfolio grows, the diversity of that portfolio is also
expeicied to incrlase. As a result, incrementai 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 inciernental diversity effect a diffrcult proposition. Instead, PacifiCorp's FRS
evaluatedhe change in regulatior rir"*" requirements associated with cumulatively stacking the
individual wind and solar facilities throughout the two BAAs. Under this methodology as each
MW of VERs is added to the system the iate of increase of the regulation reserve_requirement is
quantified and incorporated in the forecasted portfolio regulation results discussed later on in the
.toay. Figure F.11 and Figure F.12 show this relationship between increased capacity and
increasing reserve requirements for wind and solar by BAA'
Similarty for load the relationship between the daily peak load and the daily maximum elror over
the course of Z0l7 was observeilfor both BAAs and this relationship was extrapolated forward to
develop a multiplier for the effect of peak load on the reserve requirements. A linear relationship
between daily piak load and daily maximum eror was observed for both BAAs as illustrated in
Figure F.l3 through Figure F.14.
Figure F.11 - Incremental Wind Capacity
lncremental Wind - ExtraPolated
t
=o
u,l
700
500
500
400
300
200
100
0
0 soo 1000 15oO 2000 2500 3000
Capacity (Mwl
-a-pACE Wind *pACW Wind
-PACE
Wind Extrapolated
-PACW
Wind Extrapolated
104
PACFICoRP - 2OI9 IRP APPENDIX F _ FLexmLr RrsrRvg Sruoy
Figure F.lz - Incremental Solar Capacity
lncremental Solar - Extrapolated
3
E
o
lrJ
450
400
350
300
250
2m
150
100
50
0
0 200 400 600 800 1000
Capacity (MWl
1200 1400 1500 1800
'+-PACE Solar
-PACE
Solar Extrapolated {-PACW Solar
-PACW
Solar Extrapolated
Figure F.13 - Increasing Peak Load-PACE
PACE Daily Peak Load - Extrapolated
600
3E
o
lrJ
tr
5
ExG
=
500
400
300
200
100
o
o
a Oj a
o
oao
O
a
a t
a taa
oo a ,t a
o a a
t
0
4,000 5,000 6,000 7,OAO 9,000
Daily Peak Load (MWh)
9,000 10,000
*-
o Max Error
-
Linear (Max Error)
105
Figure F.14 -Increasing Peak Load-PACW
PACW Daily Peak Load - Extrapolated
400
350 t
==o
UI
tr
xG
=
.t a
a
ot
a
a
o
a
ooa
300
250
200
150
100
50
o
a
a
0
2,000 2,500 3,000 3,500 4,000
Daily Peak Load (MWhl
4,500 5,000
o Max of Error
-[i6g3;
(Max of Error)
Overview
A single pool of regulation reserve is held to cover deviations by load, wind, solar, and non-
Oispatctratte 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
ieduction in regulation reserve is a result of the diversity of the portfolio of requirements. The most
important element in PacifiCorp's portfolio diversity estimate is the system diversity, including
EIivI benefrts, associated wittr loid, wind, solar and Non-VERs during 201 7. This diversity reduced
reserve requiremants by 47 percent. This captures the majority of the regulation reserve
requirements today and in likely future scenarios over the near term. However, as PacifiCorp's
ponfoto evolves over time, the regulation reserve requirernents and diversity associated with that
portfolio will vary. This section describes how incremental regulation reserve requirements for
load, wind, and solar are combined to produce portfolio-specific requirernents.
Results
Table F.10 presents the portfolio regulation requirement results for various scenarios. As the wind
and solar capacity on PacifiCorp's system increases, regulation requirements increase, but those
requirementi are partially offset by the increasing diversity of the portfolio. The 2019 base case
regulation rese*e requirernents are 531 MW. By comparison, PacifiCorp's 2017 base case from
the2}lT IRP identified regulation reserve requirements of 617 MW.
106
PecnrConp - 2019IRP APPENDX F _ FLEXBLE RESBNVE SIUNY
PACTToRP-2OI9IRP Apprxox F - Frsxnr-B REsrnvr Sruoy
Table F.10 - Total Scenario
Table F.1 I presents a comparison of the regulation reserve requirement results in the current study
and the prior study.
Table F.11 - Portfolio Percent ofN
The 2019 FRS calculates the regulation reserve requirement for the entire portfolio implicitly
accounting for diversity among components at various penetration levels. This allows incrementalrequirements for load, wind and solar to be aligned with the new resource additions being
contemplated in the IRP. The incremental requirements for wind are slightly highe. than theaverage requirements for wind when diversity is included, but still well bilow the stand-alone
requirements for wind without diversity. On the other hand, the incremental requirements for solar
are less than the average requirements for solar even when diversity is included. These outcomes
are reasonable since solar capacity is smaller than wind capacity in the evaluated portfolio, soincremental solar capacity makes the portfolio relatively more diverse.
For the first time, the2019 FRS accounts for the incremental impact of changes in forecasted load
on regulation reserve requirements. For instance, energy efficiency selectionr 1*hi.h r"duce load),
also reduce reserye requirements. The impact of these changes isaccounted for within the resulis
reported by the PaR model.
Regulation Reserve Cost
A series of PaR scenarios were prepared to isolate the regulation reserve cost associated withincremental wind and solar capacity additions as discussed below. All studies reflect regulation
reserve requirements on an hourly basis.
l. Base Case
The base case portfolio is the same as that used to set the planning reserve margin for the
2019 IRP, as discussed in Appendix I. This case incorporates assumptions consistent with
the 2017 IRP Update, updated to reflect current inputs as of August 2018 and without anywind or solar resources additions beyond those that had already been committed at that
time. This case was evaluated over the study period20lg-2036.
2017 Base Case 2015 Actuals +Proiected Solar 2.757 1,050 6t7
2019 Base Case
2019 Forecast
2019Incr. Wind
2019 Incr. Solar
2017 Actuals
2030 Portfolio
2030 Portfolio + 500 MW Wind
2030 Portfolio + 500 MW Solar
2,750
3,196
3,696
3.196
1,021
2,201
2,201
2,701
531
672
722
698
2017 FRS Base Case 2.8%8.9%2.4%4.6%2015 portfolio
2019 FRS Base Case
Sensitivities:
Without diversity
Incremental Wind
Incremental Solar
1.6%
3.0%
8.4%
rs.8%
l0.lo/o
3.1%
5.7%
7.9%
14.8%
5.1%
2017 portfolio
2030 portfolio: +500 MW wind
2030 portfolio: +500 MW solar
2017 portfolio
t07
PACFICORP _ 2OI9 IRP APPENDx F - Flrxmls RESERVE SruoY
2. Wind Reserve Case
The wind reserve case adds the incremental regulation reserve requirernent associated with
500 MW of proxy wind resource additions. Wind capaclty increases by 100 MW at each
of five locations: Dave Johnston, Goshen, Utah South, Walla Walla, and Yakima. The
addition of this wind capacity results increases regulation reserve requirements by an
average of 50 MW. This case was evaluated for the study period 2030. Wind integration
costs ire equal to the increase in system cost in Study 2 relative to Study 1, divided by the
incremental wind generation.
3. Solar Reserve Case
The solar reserve case adds the incremental regulation reserve requirement associated with
500 IvtW of proxy solar resource additions. Solar capacity increases by 250 MW in Utah
South and by 12i MW each in Southern Oregon and Yakima. The addition of this solar
capacity ,.rrrltr increases regulation reserve requirernents by an average of 24 MW. This
.ui" *u, evaluated for the study period 2030. Solar integration costs are equal to the
increase in system cost in Study 3 relative to Study l, divided by the incremental solar
generation.
4. 50 NIW Reserve Case
This case includes an additional 50 MW reserve requirement in every hour. This case was
evaluated over the study period 2018-2036 and was used to escalate the wind and solar
results over time, relative to the 2030 values.
The incremental regulation reserve cost results for wind and solar are shown in Figure F'15. The
comparable regulation reserve costs from the 2017 FRS are also shown. While regulation reserve
costi in 2018 are comparable to the result in the prior study, the 2019 FRS demonstrates how these
costs are expected to vary over time.
108
PecrprCoRp - 2019IRP AppBNox F - FLExtsLE RESERVE Sruoy
Study Period
2077 IRP:2017
20t9lRP: 2018-2036
Figure F.15 - Incremental wind and solar Regulation Reserve costs
s2.00
S1.80
S1.60
s1.40
2017 20L9 202t 2023 2025 2027 2029 203L 2033 2035
-2Ot9lRP Wind "-*2OL9lRP Solar a 201-7lRP Wind a }OLT lRP Solar
The difference in regulation reserve costs for wind and solar reflects timing differences. per MWhof generation, the wind reserve obligation is approximately 60 percent higher than the solar
obligation; however, the solar obligation is higher during the summer when market prices and
marginal reserve costs are typically higher. As a result, per MWh of generation, wind integration
costs are only slightly higher than solar integration costs.
The 2019 FRS results are applied in the portfolio development process as an additional cost for
proxy wind and solar generation resources available for selection within the SO model. Once the
SO model has developed a candidate resource portfolio, the PaR model is used to evaluate portfolio
risks. The PaR model inputs include regulation reserve requirements specific to the ieso*ce
portfolio developed using the SO model, so the costs identified in the2019 FRS are not applied in
the PaR results. Instead, the IRP risk analysis using PaR specifically accounts forboth differences
in regulation reserve requirements and the resources available to meet those requirements in eachportfolio.
When evaluated in Pa& a portfolio will be evaluated on its ability to meet operating reserye
requirements, including regulation reserves, but as indicated previously, the SO model does not
account for either reserve obligations or the reserve capability that resources can provide. While
integration costs have previously been used to account for regulation reserve obligations, for the
first time in the 2019 IRP an analogous credit has been applied to highly flexible resources thatprimarily provide operating reserves. This "operating reserve credit" has been applied to proxy
storage, gas peaking units, and Class 1 DSM (intemrptible load) that are available for selection
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109
PncruConp-2019IRP Appsxox F - FLsxnLs RssrnvE SruoY
within the SO model. White other resources, such as combined cycle gas plants and renewables,
are also capable of providing operating reserves these resources primarily provide energy which
the SO motel is already accounting for. As a result, no operating reserve credits are applied to
these other resources. Fbr a resource that is available throughout the year, such as a gas peaking
unit, the operating reserve credit amounts to $5O/kw-year (2018$), based on the costs calculated
in the 50 MW Reserve Case relative to the Base Case. For resources with limited availability, such
as seasonal Class 1 DSM resources or storage combined with wind or solar, the credits are prorated
to account for the periods when a resource provides operating reserves.
0verview
ln its Order No. 12013 issued on January 19,2Ol2 in Docket No. UM 1461 on "lnvestigation of
matters related to Electric Vehicle Charging", the Oregon Public Utility Commission (OPUC)
adopted the OPUC stafls proposed IRP guideline:
l. Forecast the Demand for Flexible Capacity: The electric utilities shall forecast the
balancing reserves needed at different time intervals (e.g. ramping needed within 5
minuteslo 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 differenttime intervals (e.g.ramping available within 5 minutes) from
existing generating resources over the 2}-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 capacrty, the electric utilities shall evaluate
al[ 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
2019 through 2038, 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 rul 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 rir"*. requirements include three distinct components and are modeled separately
in the 2019 IRP: l0-minute spinning reserve requirements, lO-minute non-spinning reserve
requirements, and 30-minute regulation reserve requirements. The reserye requirements for
PacifiCorp's two balancing authority areas are shown in Table F.12 below.
r10
Table F.l2 - Reserve uirements
Flexible Resource Supply Forecast
Requirements byNERC 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 grd;
o lO-minute non-spinning reserve maybe 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 ofproviding 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
111
a
2019 193 193 359 93 93 196
2020 194 194 377 94 94 207
2021 194 194 491 96 96 2tt
2022 t96 196 493 97 97 198
2023 199 199 502 97 97 196
2024 202 202 593 98 98 283
202s 203 203 601 99 99 282
2026 203 203 592 99 99 280
2027 205 205 591 100 100 278
2028 207 207 597 l0t 101 275
2029 208 208 539 101 l0l 288
2030 210 210 651 102 102 286
203t 212 212 642 102 102 286
2032 214 214 644 102 102 282
2033 215 215 625 102 102 296
2034 216 216 620 102 102 296
2035 217 217 604 l0l 101 299
2036 219 219 601 l0l l0l 308
2037 220 220 600 101 101 307
2038 22t 221 560 101 101 301
Pacm'rConp - 2019IRP APPENDX F _ FTTxBIT RTsERVE SruDY
PACIFICORP - 2019 IRP APPENDx F - Fr-exnLB ResBnvn SruoY
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
reserye.
Thermal resogrces 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 nafural gas-fired thermal resources, 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.13 lists the annual reserve capability from resources in PacifiCorp's East and West
balancing authority areas.20 All the resources included in the calculation are capable of providing
all types of ."."*1. 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 ofnew 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.
Table F.13 - Flexible Resource X'orecast
Figure F.l6 and Figure F.17 graphically display the balances of reserve requirements and
capability of spinning reserve resources in PacifiCorp's East and West balancing authority areas
20 Frequency response capability is a subset of the l0-minute capability shown. Battery resources are capable of
,".pordiog withiheir maximumoutput during a frequency event, and can provide an ever greater response ifthey
were charling at the start ofan eveni. PacifiCorp has sufficient frequency response capability at present andby 2024
the battery capacity added in the preferred portfolio will exceed of PacifiCorp's current 202.8 MW frequency response
obligation foi a O.: Hz event. As a result, compliance with the frequency response obligation is not anticipated to
require incremental supply.
tt2
96525287011,84320t9
96725287031,8932020
9482472684202r1,897
935248867120221,913
947238768320231,931
126226t396520242,158
1260262196320252,166
r260273496320262,278 r26t273496420272,228
r44026501,14320282,144
187627731,64520292,268
t8762987L,64520302,562
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19963029L,76520322,604
201630291,88420332,604
20t627891,88420342,426
201628041,88420352,44r
212028081,98820362,445
237233082,24020373,104
262238042,62220383,601
Pacn'lConp - 2019 IRP AppnNox F _ FLEXBLE RESERVE STUDY
respectively. The graphs demonstrate that PacifiCorp's system has sufficient resources to serve its
reserve requirements throughout the IRP planning period.
Figure F.16 - comparison of Reserve Requirements and Resources, East Balancing
Area
Figure F.17 - Comparison of Reserve Requirements and Resources, West Balancing
Area
4000
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PacnrConp - 2019 IRP AppsNox F - Flrxmm RESERVE SrunY
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
plaruring, market fiansactions, utilization of the transmission capability between the two balancing
u"tt oritl, areas, and operational activities that are performed on an economic basis.
pacifiCorp and the California Independent System Operator Corporation implemented the energy
imbalance market (Bf1l[) on Novemb er 1,2014, and participation by other utilities has expanded
significantly with more participants scheduled for entry through 2022. By pooling variability in
load and resogrce o,rp.rq Ell\fentities reduce the quantity of reserve required to meet flexibility
needs. Because variaUitity across different BAAs may happen in opposite directions, the
uncertainty requirement foi ttre entire EIM footprint can be less than the sum of individual BAAs'
requirementr. ittir difference is known as the "diversity benefit" in the EIM. This diversity benefit
reflects offsetting variability and lower combined uncertainty. PacifiCorp's regulation reserve
forecast includes a credit to account for the diversity benefits associated with its participation in
EIM.
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 evaluate whether electric vehicles could be used to meet future flexible resource
needs.
It4