Attachment III: 2012 Long-Term Reliability Assessment – Methods and
Assumptions (PART II)
Methodology
For purposes of reliability assessments, the WECC region is divided into the 19 zones. The zones
are configured around demand centers and transmission hubs. The subregions with associated
zones and Balancing Authorities (BA) are identified below.
Subregion
Zones in Subregion
Balancing Authorities in Subregion
Canada
Alberta, British Columbia
Alberta Electric System Operator, British Columbia Transmission Corporation
Avista Corporation, Bonneville Power Administration - Transmission, Tacoma
Power , NaturEner Glacier Wind Energy, Northwestern Energy, Pacificorp West, Portland General Electric Company, PUD No. 1 of Chelan County, PUD
Northwest
Montana, Pacific Northwest
No. 2 of Grant County, PUD No. 1 of Douglas County, Puget Sound Energy,
Seattle Department of Lighting, Western Area Power Administration - Upper
Great Plains West
Basin
Idaho, No. Nevada, Utah
Idaho Power Company, Pacificorp - East, Sierra Pacific Power Company
Public Service Company of Colorado, Western Area Power Administration Rockies
Colorado, Wyoming
Colorado-Missouri Region
Arizona Public Service Company, Arlington Valley, El Paso Electric
Company, Gila River Maricopa Arizona, Griffith Energy, Harquahala
Arizona, New Mexico, So.
Desert Southwest
Generating Maricopa Arizona, Nevada Power Company, Public Service
Nevada
Company of New Mexico, Salt River Project, Tucson Electric Power
Company, Western Area Power Administration - Lower Colorado Region
Northern CA, Balancing
California Independent System Operator, Balancing Authority of Northern
Northern California
Authority of Northern California
California, Turlock Irrigation District
Los Angeles Department of
Water and Power, San Diego,
California Independent System Operator, Imperial Irrigation District, Los
Southern California
Southern CA, Imperial Irrigation
Angeles Department of Water and Power
District
Comision Federal de
Mexico
Comision Federal de Electricidad
Electricidad
WECC Total
A production cost model is used to calculate a supply/demand balance and the associated
power transfers among the zones. The resource allocation seeks the lowest overall cost, while
maintaining resource adequacy within the subregions. Data elements needed for the model to
calculate the WECC-wide, and subregional reserve margins include: monthly and annual peak
demand and energy forecasts, expected generation availability, annual energy for energy
limited resources, coincident hourly shaping data for loads and energy-limited resources, and a
simplified transmission interconnection that reflect nominal power transfer capability limits.
This data is collected from the 37 BAs in WECC.
The assessment model is designed to measure the supply/demand margins based on the
forecasts of monthly peak demands and expected available resources. While peak demand
forecasts for several future years are readily available for BAs, the forecast for future resources
additions are more dynamic. Therefore, the certainty associated with the results decrease as
one looks further into the future.
Planning Reserve Margins
The seasonal reserve margin calculations in this assessment reflect seasonal ratings for ExistingCertain, Future-Planned, and Conceptual resources. WECC’s assessment modeling process does
not make a distinction between Energy-Only resources and any other resource. Capabilities for
Transmission-Limited resources would be reduced to reflect the transmission limitation but
presently WECC does not report any such resources. Demand-Side Management is treated as a
reduction to Total Internal Demand. Behind-the-meter generation is excluded from the model,
as is any associated load. The model assumes that there are no transactions with entities
external to WECC. Demands are modeled as BA-level hourly load shapes that are scaled to
reflect the BA-level monthly peak demand and energy load forecasts. Subregion demands
reported in this assessment reflect sums of the internal BA demands coincident to the
subregion-wide coincident peak demand.
Region and subregion Target Reserve Margins are calculated using a building block
methodology created by WECC’s Loads and Resources Subcommittee. As such, they do not
reflect a criteria-based margin determination process and do not reflect any BA or Load Serving
Entity (LSE) level requirements that may have been established through other processes (e.g.,
state regulatory authorities). Moreover, they are not intended to supplant any of those
requirements.
The building block methodology is comprised of four elements:
1. Contingency Reserves – An additional amount of operating reserve sufficient to reduce
area control error to zero in 10 minutes following loss of generating capacity, which
would result from the most severe single contingency. The BA-level contingency reserve
is equal to the percent required in BAL-STD-002-WECC-1, or approximately six percent
of Total Internal Demand for all BAs. (Footnote BAL-STD-002-WECC-1) Contingency
Reserves are required to be carried by BAs (individually or through reserve sharing
pools) by NERC and WECC Standards.
2. Regulating Reserves – The amount of spinning reserves responsive to automatic
generation control that is sufficient to provide normal regulating margin. The regulating
component of the guideline was calculated using data provided in WECC’s annual loads
and resources data request responses. The BAs are asked how much Regulating Reserve
they expect to carry during the current year, as either a Megawatt (MW) value or as a
percentage of load. MW responses are converted to a percentage of load by dividing the
MW provided by the forecasted peak demand. A "sanity" check is done for all responses
and those that seemed unreasonably low or high are replaced by the subregional
weighted average of reported regulating reserves. This component also includes
reserves to balance variations in output from variable resources (such as wind) and may
be significant for some BAs. The BAs are required to carry Regulating Reserves by NERC
and WECC Standards.
3. Additional Forced Outages – Reserves for additional forced outages, beyond what might
be covered by operating reserves in order to cover second contingencies, are calculated
using the forced outage data supplied to WECC through the loads and resources (L&R)
data request responses. Ten years of data are averaged to calculate both a summer
(July) and winter (December) forced outage rate. (The actual calculation is total forced
outages divided by total resources reported in the loads and resourced data request
responses.) The same forced outage rate is used for all BAs in WECC when calculating
the building block margin. Neither NERC nor WECC standards require these reserves.
4. Temperature Adders – Using historic temperature data for up to 20 years, the annual
maximum and minimum temperature for each BA’s area was identified. That data was
used to calculate the average maximum (summer) and minimum (winter) temperature
and the associated standard deviation. The standard deviation was multiplied by a 90
percent probability factor, and added to the average historic temperature to convert
from a 1-in-2 temperature (50 percent exceedence) condition to a 1-in-10 (10 percent
exceedence) condition. The 1-in-2 temperature was subtracted from the 1-in-10
temperature to calculate the temperature change associated with the 1-in-10 outlook.
The temperature change was then multiplied by the MW per degree change supplied by
the individual BAs to arrive at a MW increase associated with converting from a 1-in-2
temperature related forecast to a 1-in-10 forecast. This MW change was divided by the
forecast peak demand to create a percentage change to be applied to future demand
forecasts to convert from a 1-in-2 forecast to a 1-in-10 forecast. Neither NERC nor WECC
standards require these reserves.
Below is an example of the temperature adder calculation.
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
AVG
STD
Summer
Temp
91.0
94.0
97.0
89.3
95.5
92.7
92.0
88.2
93.0
99.2
91.5
98.3
102.8
102.0
95.2
95.8
95.2
94.9
4.1
z = (x - xbar)/s
x = xbar + z*s
z=
Temp =
Pr() =
1.28
100.121
0.900
Temp Increase
MW/Degree
MW Increase
MW Load
% Increase
5.3
7.030
37.0
1,500
2.5%
The following table relates the building block elements to a hypothetical total forecasted
demand.
Reserve Guideline Elements
5,600
5,400
1 - 10 Temperature Adder
(WECC Average 3.1%)
MW
5,200
5,000
4,800
Regulating Reserve (WECC
Average 2.0%)
Contingency Reserve (WECC
Average 6.0%)
Forced Outage (WECC Average
2.6%)
1 - 2 Temperature Demand
Forecast
4,600
4,400
Demand
Actual-year Total Internal Demands are coincident sums of BA-level hourly demands. For future
year Total Internal Demands, BA historical hourly load shapes are averaged and scaled by BAlevel peak demand and energy load forecasts (1-in-2) that are aggregated to create Region and
subregion load projections. The Total Internal Demands (firm and non-firm) presented in this
assessment reflect extractions of the monthly demands coincident with the WECC Region and
subregion monthly maximum demands. The BA-level peak demand and energy load forecasts
are based on assumed average weather and expected economic conditions. It should be noted
that the BA-level forecast submittals to WECC are generally based on the most recently
approved forecast and, as such, may reflect a significant time laps between expected conditions
at the time the forecast preparation was initiated and the expected conditions as of the
publication of this assessment. This time lag effect may result in apparent over-forecasts during
declining economic conditions and under-forecasts during periods of rapid economic
expansion.
Demand-Side Management
WECC neither tracks nor assesses energy efficiency and conservation programs. WECC does
collect monthly dispatchable and controllable demand response (CDR) information for inclusion
in this assessment but notes that the activation of the CDR is generally at the discretion of the
LSE. CDR programs in WECC often have limitations such as having a limited number of times
they can be called on and some can only be activated during a declared local emergency.
Consequently, an individual LSE may not activate its CDR in response to a request for assistance
from an LSE in a different part of the Interconnection and CDR should not be considered as
widely sharable. Thus, total Region and even subregion margins may be overstated by an
undetermined amount.
Generation
Resources represented in the WECC assessment model are limited to generation that is
available, or is expected to be available, to serve the forecasted load. Any load that is not to be
metered by a BA’s energy management system is excluded, as is the generation that is serving
that load. Hence, distributed generation, such as residential rooftop solar facilities and behindthe-meter generation are not included in this assessment.
The expected output to the grid of existing generation is reported in this assessment as
Existing-Certain capacity while the derated portion of variable resources is reported as ExistingOther capacity. Existing-Inoperable resources are excluded from the reporting. All future
resources are reported as Future-Planned or Conceptual as WECC does not classify any
resources as Future-Other. WECC uses the NERC definitions for Future-Planned resources and
Conceptual resources when classifying those capabilities. Confidence factors that units
classified as Future-Planned and Conceptual will be built are determined by the resource
reporting entities.
Hydro generation in the model is constrained by annual energy limits that are based on actual
energy production from 2003 for Northwest Hydro generation and from 2002 for California
Hydro generation. These two years were selected by WECC’s Transmission Expansion Planning
Policy Committee (TEPPC) Data Work Group as low water years that would best reflect adverse
hydro conditions.
Scheduled Maintenance and Inoperable Generation as reported in the Loads and Resources
data are included in the studies as a reduction in available capacity. The majority of the July
outages are scheduled for generation in the Canada and Northwest subregions. Other areas try
to have all their units available for the summer peak. The generation owners in the summer
peaking zones usually schedule their maintenance in the fall or spring.
Variable generation modeling of wind resources is based on wind curves created using three
years worth of one-hour interval wind speed data. Solar resource output curves were created
using two years of synthetic data.
On-Peak Capacity Transactions
WECC’s assessment process is based on a system-wide modeling that aggregates BA-based load
and resource forecasts by geographic subregions with conservatively assumed power transfer
capability limits between the zones. The model calculates transfers between the subregions
based on assumed economic dispatch criteria. This modeling approach excludes a
representation of contractual commitments by individual entities and assures that capacity
margins reflect potential forecast conditions that are independent of variable contractual
transfer assumptions.
However, resources that are physically located in one BA area but are owned by an entity, or
entities, located in another BA’s geographic footprint, are modeled as “forced transfers”. These
resources are “moved” into the owners BA with a corresponding reduction in transfer capability
between the locations. The net effect of this treatment is an increase in generation in the
receiving BA and reduction in generation in the sending BA.
Transfers with other regional councils, such as the Midwest Reliability Organization and the
Southwest Power Pool, are ignored in this assessment as this would require an assumption
regarding the amount of surplus or deficit generation in those councils.
Transmission
For modeling purposes, the western interconnection is separated into 19 load area zones.
These zones are used in a simplified transmission model to calculate potential transfers
between zones. The simplified model reflects transfer capabilities between the 19 zones used in
the studies, wheeling costs, and loss factors. The wheeling costs for each path are used to
calculate the transfer costs for any imports into a zone. The wheeling costs range from $0.00 to
$6.48 per MWh. Since the L&R data request specifies that line losses be included in all demand
forecasts, a loss factor of zero (0) percent is used in the model. Note that neither the wheeling
cost nor the loss factor impedes the model from importing surplus resources to meet load.
British
Columbia
Summer
800
Alberta
0
2200
1000
2000
Pacific
Northwest
MRO
Montana
1000
325
400
500 1800
200
300
300
200
0
Idaho
4200 3675
Wyoming
2200
350 185
680
Northern
California
775
400
400
100
1400
1400
Northern
Nevada
100
360
650
Utah
235
650
Colorado
2750
2750
1920
BANC
140
1400
250
614
2600 2858
664
250
1275 3000
Southern
Nevada
2300
LADWP
250
SPP
600 530
3883
3750 3750
1700
362
2814
4727 4785
New
Mexico
468
Southern
California
5582
1600
600
50
2200 2440
150
1082
IID
5522
Arizona
195
163
150
San
Diego
1163
1168
408
0
Legend
Mexico
For each pair of numbers, the top or left number is the
transfer capability (MW) in the direction of the arrow.
The bottom or right number is the transfer capability in
the opposite direction of the arrow.
These diagrams represent the seasonal capacity limits between zones. The colors of the zones
in the diagrams also identify the aggregated subregions.
British
Columbia
Winter
600
Alberta
0
800
1500
2000
Pacific
Northwest
MRO
Montana
1000
250
400
600 2100
400
300
300
250
0
Idaho
4800 3675
Wyoming
2200
350 185
680
Northern
California
785
400
400
100
1450
1400
Northern
Nevada
100
360
650
Utah
235
650
Colorado
3750
3750
1920
BANC
260
1400
365
614
2900 2858
664
250
1275 3000
Southern
Nevada
3823
LADWP
250
SPP
600 530
3883
4000 3750
2814
468
2814
4634 4785
New
Mexico
468
Southern
California
5582
1802
600
50
2200 2440
150
1082
IID
5522
Arizona
195
163
150
San
Diego
1163
1168
408
800
Legend
Mexico
For each pair of numbers, the top or left number is the
transfer capability (MW) in the direction of the arrow.
The bottom or right number is the transfer capability in
the opposite direction of the arrow.
WECC entities, recognizing the need for a regional approach to transmission expansion
planning, organized the TEPPC to provide transmission expansion planning coordination and
leadership across the Western Interconnection. TEPPC works in close coordination with
subregional planning groups, transmission operators, and others in order to facilitate regional
economic transmission expansion planning. The functions performed by TEPPC complement,
but do not replace the responsibilities of WECC members and stakeholders regarding the
planning and development of specific projects.
Each year TEPPC develops a study program that details the transmission system expansion
studies they will perform. The program is based on study requests received during TEPPC’s
open season request window (November 1st – January 31st). Any interested party can submit a
study request to TEPPC for consideration. Analysis and studies performed by TEPPC focus on
plans with interconnection-wide implications and include a high-level assessment of
transmission congestion and operational impacts. Results from TEPPC’s studies provide useful
insight into transmission expansion needs within the Western Interconnection. TEPPC’s Annual
Report, and other documents produced by TEPPC are located in the “Documents” section of the
TEPPC webpage.1
Funded through a grant from the Department of Energy, awarded on December 18, 2009,
TEPPC is undertaking additional transmission planning activities under the Regional
Transmission Expansion Planning (RTEP) project. All information about this effort is on the RTEP
web page.2
WECC’s website provides links to the nine
regional transmission planning groups that
cover the Canadian and U.S. portions of the
interconnection.3 The geographic coverage
of each of the nine groups is depicted in
the attached graphic. It should be noted
that generally the transmission planning
groups themselves do not have a
responsibility regarding implementation of
transmission plans in their respective
areas. That responsibility is left to the
individual planning group member and its
appropriate oversight entity (e.g., state
utility
commission).
State/provincial
oversight activities vary widely within the
West. In conjunction with commission
oversight activities, individual entities may
prepare long-term transmission plans on a
regular basis. For example, the Arizona
Corporation Commission collects entitylevel biennial transmission plans and
published a biennial transmission assessment report.4
1
2
3
4
TEPPC Documents
RTEP Web Page
WECC Regional Planning Groups
ACC Biennial Transmission Assessment Information
WECC’s TPL-001-WECC-CRT2 System Performance Criterion, requirement R 3.2.5 addresses
reactive power and voltage stability margins. It specifies that voltage stability is required for an
area modeled at a minimum of 105 percent of the reference load level for system normal
conditions and for single contingencies. For multiple contingencies, post-transient voltage
stability is required with the area modeled at a minimum of 102.5 percent of the reference load
level. For this criterion, the reference load level is the maximum established planned load limit
for the area under study. Summary guidelines as to how the analysis should be conducted are
presented in a Summary of WSCC Voltage Stability Assessment Methodology document.6
WECC is a large and geographically diverse area with significant distances between several
generation areas and load areas. The transmission interconnections between these
geographically dispersed areas are generally voltage stability limited, not thermally limited. The
System Performance Criterion cited above also addresses transmission system operating limit
determination for these interconnections.
Most load centers in the West are largely served from remote generation resources through
voltage stability limited transmission interconnections. Consequently, most load within the
Interconnection may be considered to be reactive power-limited. LSEs typically address reactive
power issues through the installation of local controllable compensation, strengthening
interconnections with high-voltage transmission system, and maintaining local must-run
generation to provide local voltage support.
WECC’s voltage stability margin process is centered on meeting certain voltage dip criteria
based on certain equipment outage and peak demand assumptions. Consequently, the process
indirectly establishes a voltage stability margin that Transmission Planners and LSEs are
expected to apply when planning transmission and distribution facility additions. Section II of
the CISO’s annual transmission plan provides excellent examples of the application of the WECC
Regional Criteria and associated NERC Reliability Standards in the transmission planning arena.7
As noted previously, nine subregion groups are involved in transmission planning for the
Western Interconnection. Studies that have resulted from their planning work are available on
their individual websites.8
5
6
7
8
TPL-001-WECC-CRT-2 System Performance Criterion
Summary of WSCC Voltage Stability Assessment Methodology 7-11-01-Guideline
California ISO 2011-2012 Transmission Plan
WECC Regional Planning Groups