About This Assessment
About This Report
The Summer Reliability Assessment provides an independent view of the seasonal reliability for the North American bulk power
system, while identifying trends, emerging issues, and potential concerns. Additional insight will be offered regarding seasonal
resource adequacy and operating reliability, and an overview of projected electricity demand growth, and assessment area
self-assessments.NERC’s primary objective in providing this assessment is to identify seasonal reliability concerns on the North
American bulk power system and to offer recommendations to address these issues. Additionally, NERC’s seasonal assessments
provide a platform for system users, owners, and operators to systematically document planning procedures, identify
vulnerabilities, and exchange critical information for the impending season.
Post 2011 Assessment Structure
New for 2012 and later years, NERC’s seasonal and long-term reliability assessments have been restructured. Prior NERC
assessments included Regional or Assessment Area sections with resource adequacy projections combined with additional
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information describing the methods and assumptions used to arrive at these projections. The resource adequacy outlook for
each assessment area is constantly changing, based on the most recent demand forecast, or announcements of new capacity
or capacity retirements. However, the methods and assumptions used by each assessment area are more consistent.
Therefore, this information (including the most current load forecasting models, resource adequacy studies, and other
information used in the development of the seasonal and long-term projections) has been removed from the assessment area
sections and instead has been posted separately on the NERC website.
NERC Assessment Areas
Prior to 2011, NERC seasonal and long-term reliability assessments collected and presented data and information based on
Regional Entity boundaries. These boundaries were established through consideration of the respective membership of each
Regional Entity, comprising both Planning Coordinators and Load Serving Entities (LSEs). There are approximately 80 NERC
Planning Coordinators, 10 of which are Independent System Operators (ISOs) or Regional Transmission Organizations (RTOs),
and which encompass a large portion of North America. Four of these Planning Coordinators operate in the Regional Entities
listed below:
American Transmission Co., LLC: MRO, RFC
Midwest Independent Transmission System Operator, Inc: MRO, RFC, SERC
PJM Interconnection, LLC: RFC, SERC
Southwest Power Pool: MRO, SPP
Historically, these four Planning Coordinators have provided capacity and load data to multiple Regional Entities. Consequently,
this data was divided based on political boundaries that failed to accurately reflect the planning and operational properties of
the BPS. This approach has reduced the accuracy of the resource and demand balance in these four Planning Coordinators that
span over multiple Regional Entity boundaries. Taking these considerations into account, NERC instituted the following
assessment areas in the 2011:
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2012 LTRA methods and assumptions: http://www.nerc.com/files/2012LTRA_PartII.pdf.
Figure A: 2012 LTRA Assessment Areas
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It is important to note that ISO/RTO boundaries are subject to change over time, due to consolidation of LSEs and alterations in
resource planning and acquisition arrangements. NERC’s Assessment Areas will adjust accordingly, and any potential changes
will be identified in future reliability assessments.
The term “Assessment Area” has been applied consistently throughout this reliability assessment. However, the terms
“Region” or “subregion” may also be used when the Assessment Area boundaries are synonymous to the Regional Entity or
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subregional boundaries.
Demand, Resources, and Reserve Margin Concepts
Demand
NERC uses the following terms to categorize on-peak electricity demand:
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For NERC’s seasonal reliability assessments, WECC is divided into four subregions: Northwest Power Pool (NWPP), Rocky Mountain Reserve Group (RMRG), Southwest Reserve
Sharing Group (SRSG), and California/Mexico (CAMX). These seasonal subregions are structured around WECC’s Reserve Sharing Groups that experience similar demand patterns
and employ similar operating practices. Additionally, the Western Reliability Coordination Offices collect actual demand data from the Reserve Sharing Groups, and leveraging the
same footprints allows for consistent comparisons between demand forecasts and actual demands. NERC further divides the CAMX and NWPP subregions to provide additional
data granularity for Canada and Mexico. For additional information, refer to the WECC section.
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For example, the ERCOT Assessment Area is synonymous to the ERCOT ISO and TRE Regional Entity; however, there is a PJM Assessment Area, but no PJM region within this
assessment.
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Total Internal Demand: The sum of the metered (net) output of all generators within the system and the metered line
flows into the system, less the metered line flows out of the system (forecast). Total Internal Demand includes
adjustments for indirect Demand-Side Management programs such as Conservation programs, improvements in
efficiency of electricity use, and all load-modifying non-dispatchable Demand Response programs.
Net Internal Demand: Total Internal Demand less Dispatchable, Controllable Capacity Demand Response used to
reduce peak load and not counted as a resource. This value is used in the Planning Reserve Margin calculation.
Capacity Resources
NERC uses the following terms to categorize Capacity Resources and transactions in seasonal assessments:
Existing Capacity Resources
Existing-Certain: Existing generation resources available to operate and deliver power within or into the Assessment
Area during the period of assessment.
Existing-Other: Existing generation resources that may be available to operate and deliver power within or into the
Assessment Area during the period of assessment, but that may be curtailed or interrupted at any time for various
reasons.
Existing-Inoperable: Existing portion of generation resources that are out of service and cannot be brought back into
service to serve load during the period assessment.
Future-Planned: Generation resources anticipated to be available to operate and deliver power within or into the
Assessment Area during the period of assessment.
Future-Other: Future generating resources that do not qualify in Future-Planned and are not included in the
Conceptual Category.
Capacity Transactions
Net Firm and Expected Transactions: Firm and Expected Imports, minus Firm and expected exports, including all Firm
contracts with a reasonable expectation to be implemented.
Reserve Margins
Reserve Margins are capacity-based metrics and do not provide a comprehensive assessment of performance in energy-limited
systems (e.g., hydro capacity with limited water resources or systems with significant variable generation). Each Capacity
Resource Category is also used to calculate each different Planning Reserve Margin.
Planning Reserve Margins for each Assessment Area are compared to the NERC Reference Margin Level, which is assigned for
each NERC Assessment Area as defined and imposed by the corresponding Regional Entity, State Public Utility Commission,
Provincial authority, or other delegating body. In the absence of a defined Reference Margin, NERC has applied 10 or 15
percent Reference Margin Levels for predominately hydro or thermal systems, respectively.
The NERC Reference Margin Level serves as a basis for determining whether more resources (e.g., generation, Demand-Side
Management, capacity transfers) may be needed within that Assessment Area.
Demand and Supply forecasts were reported between February and August, 2011 depending on the Assessment Area.
Values for both Total Internal Demand and Net Internal Demand for each Assessment Area represent on-peak projections.
The WECC-United States peak demands or resources do not necessarily equal the sums of the non-coincident WECC-United
States subregional peak demands or resources because of subregional monthly peak demand diversity. Similarly, the Western
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Interconnection peak demands or resources do not necessarily equal the sums of the non-coincident WECC-United States,
Canada, and Mexico peak demands or resources. In addition, the subregional resource numbers include use of seasonal
demand diversity between the winter-peaking northwest and the summer-peaking portions of the Western Interconnection.
2012 Updated Reserve Margin Calculations
The continued saturation of Demand Response highlights the need for NERC’s reliability assessments to accurately reflect how
these resources are treated in each Assessment Area. Demand Response programs offer different functionality that ultimately
depends on how each program is used by the respective Balancing Authority. While some Demand Response programs are
considered supply-side resources, others are considered as Demand-Side resources, or load modifiers. In 2010, the NERC
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Resource Issues Subcommittee (RIS) released several recommendations to address the treatment of Controllable Capacity
Demand Response (CCDR) in future NERC reliability assessments. Most importantly, all CCDR were to be considered supply-side
resources.
Attempts to impellent a uniform approach presented unforeseen complications in NERC’s 2011 reliability assessments. While
certain Assessment Areas internally modeled CCDR as a load modifier in their Loss of Load Expectation (LOLE) studies, NERC
was collecting and presenting CCDR exclusively as a supply-side resource. The most critical impact was reflected in a
misrepresentation of the Assessment Area’s Reserve Margins.
The Reliability Assessment Subcommittee (RAS) revisited this issue in early 2012 and provided new recommendations for the
treatment of Demand Response. Assessment Areas were asked to report Demand Response based on how it is modeled within
their respective LOLE studies. Ultimately, Demand Response should be considered as a Demand-Side resource only if the
Assessment Area does not carry reserves for this curtailable demand during the peak.
The modifications to the collection and presentation of CCDR have required additional modifications to the Planning Reserve
Margin calculations.
Table A: NERC Reserve Margin Updates
Period
Complete
Simplified
Pre2011
RM=
[Capacity + CCDRTOTAL] - [Total Internal Demand - CCDRTOTAL]
[Total Internal Demand - CCDRTOTAL]
[Capacity + CCDRTOTAL] - Net Internal Demand
Net Internal Demand
2011
RM=
[Capacity + CCDRSUPPLY] - Total Internal Demand
Total Internal Demand
[Capacity + CCDRSUPPLY] - Total Internal Demand
Total Internal Demand
2012
RM=
[Capacity + CCDRSUPPLY] - [Total Internal Demand - CCDRDEMAND]
[Total Internal Demand - CCDRDEMAND]
[Capacity + CCDRSUPPLY] - Net Internal Demand
Net Internal Demand
Total Internal Demand — The sum of the metered (net) output of all generators within the system and the metered
line flows into the system, less the metered line flows out of the system (forecast). Total Internal Demand includes
adjustments for the indirect Demand-Side Management programs such as Conservation programs, improvements in
efficiency of electricity use, and all non-dispatchable Demand Response Programs. This value is used in the Planning
Reserve Margin calculation.
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Recommendations
for
the
Treatment
of
Controllable
Capacity
Demand
Response
http://www.nerc.com/docs/pc/ris/RIS_Report_on_Reserve_Margin_Treatment_of_CCDR_ Percent2006.01.10.pdf.
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Programs
in
Reserve
Margin
Calculations:
Net Internal Demand — Total Internal Demand less Dispatchable, Controllable Capacity Demand Response used to
reduce peak load.
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