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Survey for Inventory of NERC Regional R
Survey QuestionsRegion ->
Describe the latest resource adequacy studies(i.e. Loss-of-Load Expectation, Expected
Unserved Energy, etc.)
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1 What criterion do you use to determine whether
existing and planned resources provide an
adequate level of reliability?
2 What is the methodology for assessing resource
adequacy? What model is used?
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3 What are the results of the assessment used for?-
- i.e. to inform resource planning, to incentivize
market participants, or for use by
state/provincial/local regulators?
4 What data is used? How is data provided?
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5 Are transmission constraints modeled? If so,
how?
Load
6 What method is used to aggregate internal peak
demands of individual members actual loads for
use in the forecast?
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7 How do you categorize load uncertainty?
8 How is load forecast uncertainty incorporated into
your assessment?
9 Are any loads within your geographic area
excluded?
Supply-Side Resources
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10 For Planned and Proposed capacity resources,
what is process used to select resources for
reliability analysis/capacity margin calculations
(i.e. forward capacity markets, obligation to serve
activities, low certainty classes of resources
under consideration, etc.)? Quantify this resourceselection if possible.
11 What criteria do you use to include future
resources in your resource adequacy
assessments?
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12 Given your definition of resource certainty above,
how does your region map resources to
"existing", "planned" and "proposed" capacity, as
defined in the 2008 LTRA instructions? (See
Footnote Column)
13 How would you recommend the uncertainty of
existing and future resources be categorized? Do
you have suggestions for improving the NERC
capacity definitions?
14 Do Loss of Load Probability problems occur in
unexpected months due to maintenance outage
scheduling assumptions?
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15 How are energy-limited resources, such as hydro
or environmentally-constrained thermal,
modeled?
16 Describe how energy-only, existing-uncertain
wind and transmission-limited resources are
considered in your resource adequacy
assessment.
17 Is there a rating system for wind resources?
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18 How are temperature impacts on resources
modeled? Is there a formal process for rating
generators?
19 Have you considered fuel supply vulnerability in
your region/subregion? If so, are there any
anticipated concerns. If not, explain why this is
not a concern. What percentage of your
generation is either natural gas or coal-fired and
are any fuel supply and delivery problems
anticipated for either fuel type?
20 Explain and/or reference documentation, and
provide the definition of deliverability used in yourregion/subregion. If there is none, explain what
is done to ensure that the resources are sufficient
and deliverable to meet your load requirements
at the time of system peak.
Demand-Side Management Resources (DSM):
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21 Describe and specify the current and forecast
demand response programs in your region that
reduce peak demand i.e. interruptible demand;
direct control load management; critical peak
pricing with control; load as a capacity resource,
etc.
ENERGY EFFICIENCY (EE) (non-dispatchable)
22 Are historical levels of EE assumed to continue
into the future? Or is EE assumed to erode?
23 What types of EE improvements are included in
the 10-year load forecast?
24 Are any types of EE improvements tabulated
separately? If so, what improvements?
25 How do you determine the peak demand
component of EE improvements?
26 Are the EE-associated peak demand reductions
incorporated into the resource adequacy
assessments?
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27 How are the certainties/uncertainties of EE
resources modeled?
28 What criteria do you use to include future EE inyour assessments?
NON-DISPATCHABLE DEMAND RESPONSE (ND2R
29 Are any ND2R resources included in the 10-year
load forecast?
30 Are any ND2
R resources tabulated separately? Ifso, what resources?
31 How do you determine the peak demand
component of ND2R?
32 Are the ND2R-associated peak demand
reductions incorporated into the resource
adequacy assessments?
33 How are the certainties/uncertainties of ND2R
resources modeled? How is retention and
diversity modeled?
34 What criteria do you use to include future ND2R
in your assessments?
DISPATCHABLE ECONOMIC DEMAND RESPONSE
35 Are any DEDR resources included in the 10-year
load forecast?
36 Are any DEDR resources tabulated separately? Ifso, what resources?
37 How do you determine the peak demand
component of DEDR?
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38 Are the DEDR-associated peak demand
reductions incorporated into the resource
adequacy assessments?
39 How are the certainties/uncertainties of DEDR
resources modeled? How is retention and
diversity modeled?40 What criteria do you use to include future DEDR
in your assessments?
DISPATCHABLE CONTROLLABLE DEMAND RESP
41 Are any DCDR resources included in the 10-year
load forecast?
42 Are any DCDR resources tabulated separately? If
so, what resources?
43 How do you determine the peak demand
component of DCDR?
44 Are the DCDR-associated peak demand
reductions incorporated into the resource
adequacy assessments?45 How are the certainties/uncertainties of DCDR
resources modeled? How is retention and
diversity modeled?
46 What criteria do you use to include future DCDR
in your assessments?
Emergency Operating Procedures (EOPs)
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47 What are your categories of emergency operating
procedures?
48 Are any emergency operating procedures
included as measures to avoid a loss of load in
resource adequacy assessments? If so, which
rocedures?Imports/Exports
49 How do you categorize imports and exports?
50 How are each of these categories considered in
your resource adequacy assessment?
51 Is there a process in place to ensure that there is
consistency of export/import assumptions
between and among regions and areas?
52 What criteria do you use for including future
imports, exports?
Tie Benefits
53 How are tie benefits considered in your resourceadequacy assessment?
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54 Is there a process in place to ensure that there is
consistency of tie benefit assumptions between
and among regions and areas?
55 What criteria do you use for including future tie
benefits?
Assessments
56 How often are probabilistic assessments
performed?
57 What is the time horizon for the assessments?
58 What type of probabilistic metric is used to
assess resource adequacy? (see footnote
column for possible choices and existing
inventory for definitions)
59 For probabilistic assessments, what parameters
are treated as stochastic variables?
60 Does the assessment include scenarios? How
are these modeled?
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61 Discuss resource adequacy and operational
measures available if peak demands are higher
than expected due to weather or other conditions.
62 Does the assessment include a threshold below
which misses are not included in the analysis, or
which denotes flexibility in reserve margin
capacity?
Reserve Margin Calculations
63 Is non-dispatchable DSM subtracted from peak
demand?
64 Is dispatchable DSM modeled as a resource or
subtracted from load forecast?
65 Is there a different PRM target "with EOP" and
another "without EOP"?
66 Are there different PRM targets with and without
tie benefits/imports/exports?
67 Are supply-side resources such as hydro and
wind derated for reserve margin presentation? If
so, how?
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Implementation
68 How is resource adequacy implemented in your
Region, sub-regions or sub-areasthrough
organized markets (ISOs, RTOS), planning
reserve sharing pools, state regulatory
mechanisms, other mechanisms or notimplemented using an organized approach?
69 Have the entities responsible for assuring
resource adequacy in your Region established
metrics and benchmarks (e.g. planning reserve
margin of 12%) with which to measure resourceadequacy? If so please list those entities and the
associated metrics and benchmarks.
70 Are there jurisdictions in your Region with
prescribed Resource Adequacy requirements? If
yes, please list those jurisdictions.
71 If resource adequacy is implemented using an
organized market approach, what is thetimeframe when a demonstration of sufficient
resources to meet the metric is required? (e.g.
month out, year out, several years out?)
Other Questions?
72 In reviewing the attached spreadsheet and the
list of questions above, have we missed any
questions, which because of their non-inclusion
preclude a complete description of the Regionsresource adequacy assessment methodology?
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source Adequacy Assessment Crit
Response to SurveyERCOT
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Previous LOLP studies have led to stakeholder
agreement that a reserve margin of 12.5% is
adequate to ensure a minimal risk of loss of load
events.
The most recent ERCOT LOLP study was
conducted by Global Energy Decisions. They
utilized the ProSym model to determine the
probability of unserved energy in each hour
throughout a year.
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To inform regulators, market participants, and
other stakeholders
These studies have been subcontracted to
outside engineering firms. These firms have
used their own databases.
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Not in previous studies.
The forecasted peak demands are produced by
ERCOT for the entire ERCOT Region (which is a
single Balancing Authority area) based on
coincident actual demands.
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Primary sources of load uncertainty are weather
and economic trends.
Probability distributions are developed based on
historical data and expected future trends.
No.
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Planned capacity additions include new
generation that has a signed interconnection
agreement and air permit, with wind generation
counted at its effective load carrying capability.
Proposed capacity additions include all other
generation that has requested interconnectionagreement, with wind generation counted at its
effective load carrying capability.
Future generation facilities for which there is a
signed transmission interconnection agreement
and a completed air permit are included in our
resource adequacy assessments.
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in ERCOT, we consider existing units and units
with signed interconnection agreements and air
permit to be equally certain.
Yes. LOLP events can occur during peak
months, during very hot periods in shoulder
months, or during winter severe cold snaps,
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ERCOT does not have a significant amount of
energy-limited resources.
Existing Uncertain capacity includes the portion
of the wind generation that is not counted as
Certain due to its variability and the existing
generating capacity that is mothballed
Based on previous LOLP studies, wind resourcesare considered to have an effective load carrying
capability of 8.7% of nameplate rating for
resource adequacy studies in ERCOT.
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ERCOT maintains summer and winter ratings for
generating units.
Over 60% of the generating capacity in ERCOT is
fueled by natural gas, resulting in some concern
about the adequacy of natural gas supply during
winter months when winter heating demand
peaks. Natural gas interruptions are not typically
a concern during the summer, when electric
power demand peaks. ERCOT has a procedure
in place to request current status of fuel supply
contracts, back-up fuel supplies and unit
capabilities if severe cold weather is in the sevenday forecast. This information would be used to
prepare operation plans. However, there is
currently no market incentive or non-market
mechanism for gas generation to maintain dual
fuel capability and storage, typically with fuel oil,
that could be critical to maintaining generation
adequacy during extended periods of gas
curtailments. .
ERCOT does not have a definition of
deliverability at this time. The deliverability ofresources at system peak is evaluated as part of
the Five-Year transmission planning process.
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ERCOT has no demand response programs
specifically designed to deploy at system peaks.
ERCOT ISO administers two market-based DR
services (Loads Acting as a Resource providing
Ancillary Services, and Emergency Interruptible
Load Service) in which Loads are available fordispatch in emergency conditions during all
hours. Emergency conditions do not necesssarily
correlate to system peaks.
Historically, EE initiatives are assumed to have
been assimilated into econometric load
forecasting.
Per statutory requirement, projected peak
demand reductions due to EE are now required
to be reported as part of long-term planning.
Only EE programs administered by IOU
transmission & distribution service providers for2008 and 2009, per statute. These include EE
standard offer and market transformation
programs, and load management standard offer
programs.
As reported by the Public Utility Commission of
Texas, based on data provided by IOU
transmission & distribution providers.
Yes
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n/a
Texas Legislature is expected to revisit EEstatutes in 2009; requirements may change at
that time.
):
No.
No.
n/a
No.
n/a
n/a
(DEDR):
No.
No.
n/a
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No.
n/a
None.
ONSE (DCDR):
Yes, Loads Acting as a Resource (LaaR)
providing Ancillary Services.
Yes. See above.
Three year average of the hourly procurement of
LaaR providing Ancillary Services during the
Summer months for HE 1600 thru HE 1800.
Yes.
There are currently in excess of 2000 MW
qualified to perform these services. Limits are
placed on the maximum participation at 1150
MW. In addition the historical average is adjusted
to show a 95% confidence level based on the
normal distribution of these Resources in the
Generation/Load Resource mix.
None at present.
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Excerpt of Current ERCOT EECP procedures are
attached. Full version can be viewed at
http://www.ercot.com/mktrules/protocols/current/0
5-100107.doc
Previous LOLP studies have included an
assumption that a loss of load event would not
occur until after the Loads Acting As Resources
LAARs have been tri ed.
ERCOT does not have any synchronous import
or export capability.
n/a
n/a
n/a
ERCOT has 1,106 MW of asynchronous tiecapacity with adjoining interconnections. One-
half of this capacity is assumed to be available
for reserve margin analysis purposes.
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No
n/a
LOLP studies have been performed every 2 - 3
years.
These studies have looked at current conditions
only.
The most recent study used a 1 event in 10 years
metric (see attached).
Loads, thermal generation availability, wind
generation availability.
No scenarios were performed in the last LOLP
study.
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ERCOT will initiate its Emergency Electric
Curtailment Plan (EECP) if available capacity
gets below required levels due to gas
curtailments or any other reason. The EECP
maintains the reliability of the interconnection by
avoiding uncontrolled load shedding.
No
No
No
N/A
N/A
Wind resources are assumed to have an
effective load carrying capability of 8.7% of
nameplate rating.
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N/A. ERCOT has a deregulated, energy-only gen
N/A
N/A
N/A
No
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ria by Regional Reliability Organiza
Response to SurveyFRCC
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Minimum 20% Reserve Margin for IOUs;
remaining utilties maintain at least a 15%
Reserve Margin.
The periodic loss-of-load probability (LOLP)
assessment validates that the Reserve Marginrequirement is adequate.
Develop resource plan that maintains FPSC
mandated Reserve Margin.
FRCC conducts periodic loss-of-load probability
(LOLP) assessments for the region using the Tie-
Line and Generation Reliability (TIGER) model
which calculates the LOLP values for the ten-
year planning horizon, with the criteria not to
exceed 0.1 days/year.
FRCC conducts annual reliability assessment by
monitoring trends in load forecasting accuracy,
unit Availability Factors, and unit Forced Outage
Rates.
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To confirm Reserve Margin criteria is adequate to
utilities and state regulators.
LOLP Analysis - Data includes load forecast,
loadshape, resource plan, unit Forced Outage
Rates, maintenance schedules, available tie-lineassistance (regional imports), and energy
management programs. Each utility provides
data to the FRCC in an online database.
Annual Reliability Assessment - Data includes
trending historic unit Forced Outage Rates and
unit Availabilities, and comparison of load
forecast to actual. Each utility provides data to
the FRCC in an online database.
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No.
Member seasonal peaks are aggregated with
care taken not to double count. The members'
individual seasonal peaks are summed to
determine a Regional non-coincident peak.
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Load uncertainty is left to the member
companies, and is not analyzed on the Regional
level.
The FRCC Load Forecast is an aggregation of
the load forecast of each of its member utilities.FRCC has pursued this avenue since it is only
logical to assume that each utility is most familiar
with its own service territory. The load forecast
evaluation process undertaken by FRCC ensures
that each utility in preparing this outlook is
availing itself of the best available information in
terms of data, forecasting models and to a
certain degree consistency of assumptions
across all utilities.
FRCCs Load Forecasting Task Force (LFTF)
reviews in detail each utilitys forecast
methodology, input assumptions and sources,
and output of forecast results. Sanity checks are
performed comparing the historical past with the
projected load growth, use per customer, weather-
normalized assumptions, and load factors.
Does not apply.
Some members exclude load served by self-
service generation since this generation is
assumed to be in-service during monthly peaks.
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All Planned and Proposed capacity additions are
based on the obligation to serve and are included
in the Reserve Margin calculation. Non-firm
energy resources are not included in calcuation
of Reserve Margins.
Minimum 20% Reserve Margin for IOUs;
remaining utilties maintain at least a 15%
Reserve Margin.
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For 'Existing - Certain' capacity, the region will
include all existing committed firm generation.
For 'Existing - Uncertain' capacity, the region
includes existing units that have been mothballed
or placed into operational standby, and any IPPswith generation that does not have a firm contract
for service.
For future generation, all generation will be
mapped as 'Planned'.
See response to question 12 above on 'Planned'
capacity.
No.
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Energy-limited resources in the region are not
significant in the FRCC Reserve Margin
calculation, and are not always modeled.
N/A
N/A
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Models contain a winter and summer rating for
each unit in the region.
The FRCC has established a Fuel Reliability
Working Group (FRWG) whose purpose is to
examine matters related to fuel and impacts to
Bulk Electric System (BES) reliability. The
FRWG provides the administrative oversight of a
Regional fuel reliability forum that studies the
interdependencies of fuel availability and electric
reliability and supports coordinated Regional
responses to fuel issues and emergencies.
The generation fuel mix is approximately 18%
Coal, 51% Natural Gas, 21% Oil, and 8%
Nuclear.
The FRCC Transmission Working Group
(composed of transmission planners from FRCCmember utilities) conducts regional studies in
accordance with the FRCC Regional Planning
Process to ensure that all dedicated firm
resources are deliverable to loads under forecast
conditions and other various probable scenarios
to ensure the robustness of the BES. In addition,
the FRCC Transmission Working Group
evaluates planned generator additions under
stressed conditions to ensure that the proposed
interconnection and/or integration are acceptableto maintain the reliability for the BES within the
FRCC Re ion.
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Interruptible, Curtailable, Residential critical peak
pricing and Commerical demand response direct
load control and standby generation.
EE is assumed to continue in the future, and
planning assumes replacement in kind. The
impact of the U.S. Energy Policy Act of 2005
increases through time as sufficient time is
allowed for the current stock of less efficientappliances to be depleted and replaced by more
efficient ones.Most Utilities are required per Florida Statute to
file plans each year with the Public Service
Commission detailing efforts in EE improvements
as outlines in the Florida Energy Efficiency and
Conservation Act (FEECA). Some entities
account for EE within the load forecast and
others account for it se aratel .Most Utilities are required per Florida Statute to
file plans each year with the Public ServiceCommission detailing efforts in EE improvements
as outlines in the Florida Energy Efficiency and
Conservation Act (FEECA). Some entities
account for EE within the load forecast and
others account for it separately (i.e., incremental
conservation, residential versus commercial
conservation .There are approved programs registered with the
Florida PSC that have both demand and energy
reduction goals assocaited with their
implementation. Those goals are the amounts
included in the EE forecast.Yes
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Most Utilities are required per Florida Statute to
file plans each year with the Public Service
Commission detailing efforts in EE improvements
as outlines in the Florida Energy Efficiency and
Conservation Act FEECA .
Most Utilities are required to file plans each yearwith the Public Service Commission detailing
efforts in EE program and improvements
FEECA .
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
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N/A
N/A
N/A
Some of the entities in the Region include DCDR
resources in their forecast.
Some of the entities in the region include DCDR
resources separately such as Residential Load
Management, Commercial Load Management,Interruptible Service, Curtailable Service and
Stanb Generation.Time-Temp Matrix - Residential Load
Management & Commercial Load Management.
Sum of estimated available MW from
Iinterruptible Service and Curtailable Service.
Sum of MW capacity for Standby Generation.
Yes.
Participation is tracked and end-use study
verifies diversified impacts and results are
reflected in future DCDR forecasts.
Cost benefit analysis includes Participant Test,
Total Resource Cost Test, and Rate Impact
Measure.
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Interruptible/Curtailable load, DSM (HVAC, Water
Heater, Pool Pump), Voltage Reduction, 10
minute fast start units, 10 minute reserve sharing,
customer stand-by generation, emergency
contracts, unit emergency capability and load
shed. (The categories described above can varyfrom entit to entit .Same as above. The inclusion of the categories
described above can vary from entity to entity in
resource adequacy assessments.
Generally, sales contracts are not expected to
renew, purchase contracts from QFs, Cogens
and Renewables are expected to renew, and
speculative contracts are not included. However,each entity in the region can account for sales
and purchase differently. The FRCC only
aggregates the information provided by each
entit .The FRCC Region only includes firm imports and
exports in the resource adequacy assessment.
The FRCC Region only includes firm imports and
exports in the resource adequacy assessment.
There is a process for coordination between the
FRCC and SERC Regions addressing import andexport transactions.
Generally, only executed contracts for firm import
and exports are included.
The FRCC Region only includes firm imports andexports in the resource adequacy assessment.
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The FRCC Region only includes firm imports and
exports in the resource adequacy assessment.
There is a process for coordination between the
FRCC and SERC Regions addressing import and
export transactions.
Generally, only executed contracts for firm import
and exports are included.
Performed as needed by evaluating input data
such as forced outage rates and availability
factors for significant changes.
Annually.
Loss Of Load Probability (1 day in 10 years).
Occurences of forced outages.
Scenarios such as change in load forecast may
be modeled as needed.
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Generally, the reserve margin includes:
Interruptible/Curtailable load, DLC (HVAC, Water
Heater, Pool Pump), Voltage Reduction, 10
minute fast start units, customer stand-by
generation, (These operational measures can
vary from entity to entity) which are availableduring unexpected conditions. Additionally, 10
minute reserve sharing, emergency contracts,
unit emergency capability and public appeal are
operational measures that can be implemented
to meet the unexpected demand.
The probabilistic assessment does not include
extreme events. However, the FRCC studies the
impact of extreme fuel shortages and/or fuel
deliverability issues (pipeline event). These
studies are used to construct regional mitigation
procedures.
Yes (Individual entity practice may be different).
Subtracted from load.
No.
No.
No.
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State Regulatory Mechanisms
The Florida Public Service Commission requires
IOUs (PEF, FPL, TEC) to maintain a Reserve
Margin of at least 20% and all other entities at
least 15%. Individual entities within the FRCCmay utilize LOLP metrics for their resource
adequacy assessment.
The Florida Public Service Commission requires
IOUs (PEF, FPL, TEC) to maintain a Reserve
Margin of at least 20% and all other entities at
least 15%.
N/A
No response
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tion (August 14, 2008)
Response to SurveyMRO
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The MRO does not set a resource adequacy
level. The MRO requires that an assessment be
performed annually based on an LOLP of no
greater than 0.1 day in one (1) year.
See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
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See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
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See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
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See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
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54/144
See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
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55/144
See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
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See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
See the responses from the PlanningCoordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
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See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
See the responses from the Planning
Coordinators within the MRO geographical area(MISO, MAPP, MHEB, ATC, SaskPower)
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See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
See the responses from the Planning
Coordinators within the MRO geographical area(MISO, MAPP, MHEB, ATC, SaskPower)
See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
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See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
See the responses from the PlanningCoordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
See the responses from the PlanningCoordinators within the MRO geographical area
MISO, MAPP, MHEB, ATC, SaskPowerSee the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
See the responses from the PlanningCoordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
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See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
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See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
See the responses from the PlanningCoordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
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See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
See MRO standard (RES-501-MRO-01)
See the responses from the Planning
Coordinators within the MRO geographical area(MISO, MAPP, MHEB, ATC, SaskPower)
See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
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See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
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MRO standard is applicable to the LSE or its
delegate. Midwest PRSG, MAPP PRSG,
SaskPower will be performing the studies
See the responses from the Planning
Coordinators within the MRO geographical area
(MISO, MAPP, MHEB, ATC, SaskPower)
state of Wisconsin
See the responses from the Planning
Coordinators within the MRO geographical area(MISO, MAPP, MHEB, ATC, SaskPower)
No response
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Response to Survey
NPCC
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Each Areas probability (or risk) of disconnecting
any firm load due to resource deficiencies shall
be, on average, not more than once in ten years.
Compliance with this criteria shall be evaluated
probabilistically, such that the loss of load
expectation [LOLE] of disconnecting firm loaddue to resource deficiencies shall be, on
average, no more than 0.1 day per year.
The evaluation makes due allowance for demand
uncertainty, scheduled outages and deratings,
forced outages and deratings, assistance over
interconnections with neighboring Areas and
Regions, transmission transfer capabilities, and
capacity and/or load relief from available
operating procedures. General Electric's Multi-
Area Reliability Simulation (MARS) program is
used.
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The annual NPCC Multi-Area Summer
Probabilistic Reliability Assessments verifies
NPCC members' (Areas) compliance to the
NPCC Document A-02 (resource adequacy
criteria), as well as demonstarting their
compliance to governmental and regulatoryofficials. Periodically, NPCC also performs an
Interregional Long Range Adequacy Overview,
extending the annual Probabilistic Multi-Area
Reliability Assessment out five years in the
future. In addition, NPCC has established a
Reliability Assessment Program to bring together
work done by the Council, its member systems
and Areas relevant to the assessment of bulk
power system reliability. As part of the Reliability
Assessment Program, the Task Force onCoordination of Planning is charged, on an
ongoing basis, with conducting reviews of
resource adequacy of each Area of NPCC.
NPCC Areas follow the requirements outlined in
NPCC's Document B-08 - Guidelines for Area
Review of Resource Adequacy. See:
http://www.npcc.org/documents/reviews/Resourc
See:
http://www.npcc.org/documents/regStandards/Gu
ide.aspx - Document B-08
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Yes - The GE MARS program models the
transmission system through transfer limits on
the interfaces between pairs of areas. The
transfer limits are specified for each direction of
the interface and can be changed on a monthly
basis. Random forced outages on the interfacesare modeled in the same manner as the outages
on thermal units, through the use of state
transition rates.
The GE MARS model uses hourly (8760) load
data that is forecast by the Areas, based on the
year 2002 load shape.
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Load forecast uncertainty is modeled. The
effects on reliability of uncertainties in the load
forecast, due to weather and economic
conditions, are captured through the load
forecast uncertainty model in the GE MARS
program. The program computes the reliabilityindices at each of the specified load levels (seven
load levels are modeled) and calculates weighted-
average values based on the associated
probabilities of occurrence. The per unit
variations in Area and sub Area load can vary on
a monthly basis.
Through the load forecast uncertainty model in
the GE MARS program. The forecast of load
uncertainty can change, depending on the nature(short term (annual) or long term (five year)) of
the analysis.
No - in fact a GE MARS representation of
neighboring regions (PJM/FRC and the
MISO/MRO) is included.
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NPCC modeling is consistent with each NPCC
Areas' resource adequacy assumptions - refer to
the individual NPCC Area responses for more
detail or the latest NPCC Review of Area
Resource Adequacy at:
http://www.npcc.org/documents/reviews/Resource.aspx
NPCC modeling is consistent with each NPCC
Areas' resource adequacy assumptions - refer to
the individual NPCC Area responses for more
detail or the latest NPCC Review of Area
Resource Adequacy at:
http://www.npcc.org/documents/reviews/Resourc
e.aspx
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NPCC modeling is consistent with each NPCC
Areas' resource adequacy assumptions - refer to
the individual NPCC Area responses for more
detail or the latest NPCC Review of Area
Resource Adequacy at:
http://www.npcc.org/documents/reviews/Resource.aspx
For short term (annual) analysis, resource
certainty can be addressed through scenario
analysis; for longer term analysis (five year), a
probabilistic representation for the expected
value of resources can be developed that
eliminates the need for characterizations such as
" lanned" or " ro osed."The NPCC LOLE criteria is an annual index that
accounts for the risks in all hours (8760)
modeled.
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Type 1 energy-limited units are modeled as
thermal units whose capacity is limited on a
random basis for reasons other than the forced
outages on the unit. This unit type can be used
to model a thermal unit whose operation may be
restricted due to the unavailability of fuel, or ahydro unit with limited water availability. It can
also be used to model technologies such as wind
or solar; the capacity may be available but the
energy output is limited by weather conditions.
Type 2 energy-limited units are modeled as
deterministic load modifiers. They are typically
used to model conventional hydro units for which
the available water is assumed to be known with
little or no uncertainty. This type can also beused to model certain types of contracts. A Type
2 energy-limited unit is described by specifying a
maximum rating, a minimum rating, and a
monthly available energy. This data can be
changed on a monthly basis. The unit is
scheduled on a monthly basis with the unit's
minimum rating dispatched for all of the hours in
the month. The remaining capacity and energy
can be scheduled in one of two ways. In the first
method, it is scheduled deterministically so as to
reduce the eak loads as much as ossible. InNPCC modeling is consistent with each NPCC
Areas' resource adequacy assumptions - refer to
the individual NPCC Area responses for more
detail or the latest NPCC Review of Area
Resource Adequacy at:
http://www.npcc.org/documents/reviews/Resourc
e.aspx
Development of NPCC guidelines for ratingintermittent resources (wind) for resource
adequacy assessments is a NPCC 2009
Corporate Goal.
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Yes - see NPCC Document A-13 Verification of
Generator Gross and Net Real Power Capability
at:
http://www.npcc.org/documents/regStandards/Cri
teria.aspx
Handled through scenario analysis - dependence
on natural gas for gas-fired generation is more of
a concern in the winter period - see: Multi-Area
Probabilistic Reliability Assessment For Winter
2007/08 at:
http://www.npcc.org/documents/reports/Seasonal
.aspx
Refer to the NPCC A-02 Document - NPCC
Members' are obligated to its conditions underthe NPCC Bylaws - see:
http://www.npcc.org/documents/aboutus/BusPlan
Bylaws.aspx
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No response
Refer to the individual NPCC Area responses for
more detail or the latest NPCC Review of Area
Resource Adequacy at:
http://www.npcc.org/documents/reviews/Resourc
e.aspx
See above
See above
See above
See above
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See above
See above
Refer to the individual NPCC Area responses for
more detail or the latest NPCC Review of Area
Resource Adequacy at:
http://www.npcc.org/documents/reviews/Resourc
e.as x
See above
See above
See above
See above
See above
Refer to the individual NPCC Area responses for
more detail or the latest NPCC Review of Area
Resource Adequacy at:
http://www.npcc.org/documents/reviews/Resourc
e.aspx
See above
See above
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See above
See above
See above
See above
See above
See above
See above
See above
See above
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Refer to the individual NPCC Area responses for
more detail or the latest NPCC Review of Area
Resource Adequacy at:
http://www.npcc.org/documents/reviews/Resourc
e.aspx
Yes -the annual LOLE index is calculated after all
Areas' EOPs are exhausted.
Firm sales/purchases of ICAP (installed capacity)
are modeled.
See: pre-seasonal assessments at
http://www.npcc.org/documents/reports/Seasonal
.aspxNeighboring Regions (PJM/RFC and MISO/MRO)
participate in the studies and review the
purchase/sale assumptions.
Only known, firm contracts are modeled.
NPCC Multi-Area modeling of its Areas with theGE MARS program and neighboring regions
precludes the need for explicit Tie Benefit
assumptions. NPCC periodically reviews the Tie
Benefits assumptions used by its Members for
reasonability - see:
http://www.npcc.org/documents/publications/Assi
s.as x
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See:
http://www.npcc.org/documents/publications/Assi
s.aspx
See:
http://www.npcc.org/documents/publications/Assi
s.aspx A range is estimated based on "As Is' and
"At Criteria"
Annually for the pre-seasonal and interim Area
reviews of resource adequacy and every three
years for the comprehensive Area reviews of
resource adequacy
Pre-seasonal assessments - current year; interim
and comprehensive - five year
annual LOLE
Refer to:
http://www.npcc.org/documents/reports/Seasonal.aspx (pre-seasonal multi-area assessments) and
http://www.npcc.org/documents/reviews/Resourc
e.aspx (interim and comprehensive reviews of
resource adequacy)
Yes - scenarios are modeled with separate multi-
area probabilistic assessment
assumptions/simulations
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NPCC modeling is consistent with each NPCC
Areas' resource adequacy assumptions - refer to
the individual NPCC Area responses for more
detail or the latest NPCC Review of Area
Resource Adequacy at:
http://www.npcc.org/documents/reviews/Resource.aspx
NPCC modeling is consistent with each NPCC
Areas' resource adequacy assumptions - refer to
the individual NPCC Area responses for more
detail or the latest NPCC Review of Area
Resource Adequacy at:
http://www.npcc.org/documents/reviews/Resourc
e.as x
NPCC modeling is consistent with each NPCC
Areas' resource adequacy assumptions - refer to
the individual NPCC Area responses for more
detail or the latest NPCC Review of Area
Resource Adequacy at:
http://www.npcc.org/documents/reviews/Resourc
e.as xSee above
NPCC does not have a reserve margin
requirement
NPCC does not have a reserve margin
requirement
See above
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Through the NPCC Areas (ISO-NE, NYISO,
IESO, NBSO, Hydro-Quebec)
Consistent with the NPCC A-02 resource
adequacy criteria; refer to the individual NPCC
Area responses for more detail or the latest
NPCC Review of Area Resource Adequacy at:http://www.npcc.org/documents/reviews/Resourc
e.aspx
New York State, the Ontario Energy Board, the
Quebec Energy Board, NECPUC, and the New
Brunswick commission have all either mandated
or accepted the NPCC A-02 resource adequacy
criteria.NPCC modeling is consistent with each NPCC
Areas' resource adequacy assumptions - refer tothe individual NPCC Area responses for more
detail or the latest NPCC Review of Area
Resource Adequacy at:
http://www.npcc.org/documents/reviews/Resourc
e.as x
Many of the questions are "reserve margin"
centric, NPCC's criteria is based on a
probabilistic multi-area LOLE index; reserve
margins in NPCC may vary by area, but eachArea adheres to the NPCC criteria when
calculating there installed capacity and resource
re uirements.
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Response to SurveyRFC
The PRSGs within ReliabilityFirst conduct LOLEanalyses to determine the required reserve
margins for their respective areas. Information on
the reserve margin requirement can be found at
the following URLs: PJM -
http://www.pjm.com/markets/rpm/downloads/plan
ning-period-parameters.xls Midwest PRSG -
www.midwestmarket.org/page/Regulatory+and+E
conomic+Standards
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ReliabilityFirst has a Regional Standard that
requires all LSEs to determine their level of
reserve margin needed to satisfy a Loss of Load
Expectation (LOLE) of 1 occurrence in ten years
(.1/year LOLE). The evaluation can be made for
individual LSEs or groups of LSEs known asPlanned Reserve Sharing Groups (PRSGs).
The choice of a particular LOLE model is up to
the LSE or PRSG.
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The ReliabilityFirst standard requires that LSEs
or PRSGs perform an LOLE analysis. The
reserve margins derived from that analysis is
used by ReliabilityFirst to assess the resource
adequacy of the region. Results from this
assessment are reported within theReliabilityFirst region and in the NERC
assessments.
Each evaluation utilizes demand data,
DSM/Demand response data, Generator capacity
and availability data, and interconnection/importcapability data. Data can be provided by
whatever functional entity has the applicable
data, or the PRSG can develop or collect the
applicable data as needed.
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Transmission constraints are required to be
factored into import capability. Internal
constraints are as determined and included by
the LSE/PRSG in their analysis.
The demand forecast for an LSE or PRSG is to
be coincident demand.
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Weather, economic forecast, and load forecast
uncertainty are the listed categories in the
regional standard.
This is incorporated into the analysis as
determined by the PRSG or LSE.
The only demand not included in the analysis is
behind the meter and customer supplied
demand.
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The two RTOs in the ReliabilityFirst region (MISO
and PJM) provide this data based on the
definitions in the NERC LTRA.
ReliabilityFirst assesses long term adequacy by
comparing the required reserves to the Planned
and Proposed capacity resources identified by
the RTOs.
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Existing capacity- Certain: Deliverable resources
included as Capacity or DNR in the RTO
markets. - Uncertain: Existing capacity not in the
certain category. All resources are to be mapped
to Planned and Proposed categories based on
the definitions and the RTO's judgement.
Planned resources should be resources that
have a reasonable expectation of commercial
operation in the next few years. Proposed
resources are uncertain and should be
recocnized as uncertain without trying to assign a
precise probability of operation.
In planning studies this does not occur.
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The modeling is determined by the LSE or PRSG
conducting the study.
Energy only and transmission limited resources
would be included as a type of future year
planned resources. Uncertain wind or other
variable generation would be included as a type
of proposed resources.
The rating of wind generation facilities isdetermined by the PJM and MISO market
requirements.
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ReliabilityFirst is developing a rating standard
that will require verification of seasonal capacity
ratings. Ratings will be adjusted to expected
seasonal ambient temperatures.
The ReliabilityFirst region monitors, at a high
level, the general fuel supply situation in the
region. About 46% of the fuel supply is coal,
about 29% is gas. As of 4-15-08 there are no
anticipated fuel supply concerns.
Both RTOs, MISO and PJM have procedures to
evaluate deliverability of generation to load withintheir respective markets. There is no regional
definition of deliverability.
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The ReliabilityFirst RTOs currently identify
interruptible demand and direct control load
management as their demand response
programs.
Energy efficiency is built in to the demand
forecasts based upon the the demand
forecasting methodology used by the RTOs and
their members. ReliabilityFirst does not have any
information on EE programs and forecasts.
See response to #22
See response to #22
See response to #22
See response to #22
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See response to #22
See response to #22
No
No
Not applicable
No
Not applicable
Not applicable
Unknown
No
Not applicable
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No
Not applicable
Not applicable
Yes
No
From RTO data responses
Yes
Modeling is assumed to be the net reduction
available at the time of the regional peak.
The current level of reduction is assumed to
continue indefinitely.
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The categories of emergency operating
procedures are determined by the RTOs.
No.
PJM and MISO provide data only for "firm"
imports and exports.
Firm imports and exports are included in
resource adequacy assessments.
No.
Whatever criteria the RTOs use for firm imports
and exports.
Tie benefits are not included in the assessments.
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Not applicable
Not applicable
Regional assessments utilize the reserve margins
of the PRSGs. Reserve margins are based upon
probabilistic analyses that are conducted
annually.
The regional assessments have seasonal and
ten year horizons according to NERC standards.
The PRSG analyses have a ten year horizon.
The PRSG analyses are required to calculate an
LOLE based on a minimum of the weekday peak
LOLPs.
Random generator outages are included in the
PRSG analyses
The region's seasonal assessments include an
exteme weather scenario.
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When peak demands exceed expectations for
any reason, the operational response will vary
from nothing (adequate reserves), to rolling
blackouts (inadequate reserves, no available
purchase power, and demand response, public
appeals and voltage reductions unable to restoredemand and capacity balance).
Not applicable
Yes, when included in the demand forecast.
Load reduction
No.
No.
Yes, based upon expected operation at peak.
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PJM has a provision to implement through the
RTO tariff. MISO is approved by FERC to
implement through the RTO tariff beginning in
2009.
Yes. PJM 15 % reserve margin. MISO uses 12%,
13.7%,14.2%, 14.3% and 18% depending on the
specific PRSG zone or state requirements.
The state of Wisconsin requires a 18% reserve
margin.
The PJM timeframe is one year. The MISO
timeframe is one month.
No.
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Response to SurveySERC
SERC as a region does not perform probabilisticresource adequacy studies, however many of
SERC's members do perform probabilistic
resource adequacy studies to project future
resource needs. These underlying probabilistic
studies will therefore influence SERC's
deterministic assessment. Under the supervision
of the SERC Engineering Committee (EC), the
SERC Reliability Review subcommittee (RRS)
conducts reviews of regional and subregional
margin assessment; assesses the adequacy and
security of each of the SERC subregions; and
reports its findings to the SERC EC. The RRS
reviews and assesses the overall reliability
(adequacy and security) of the SERC bulk
electric systems, both existing and as planned, to
ensure that each SERC member conforms to
applicable NERC Reliability Standards, as well as
any related SERC criteria. The RRS is a
permanent subcommittee of the SERC
Engineering Committee. These reviews and
assessments: 1) consider trends in planning,operations, and external influences as they affect
reliability, both overall and subregion specific; 2)
are conducted annually and as requested by the
NERC Planning Committee; and 3) consider
seasonal variations, near-term ears one
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There is no regional criteria specified. Resource
planning and criteria are left to the members and
their respective state or other jurisdictions. The
RRS determines if resource information
submitted represents a reasonable and attainable
plan. The transmission systems within SERC areplanned, designed, and operated such that the
regions generating resources with an obligation
to serve load or have firm contracts to serve load
are not constrained. Typical resource adequacy
studies (LOLE studies) do not consider
transmission constraints
Some SERC members perform some sort of
probabilistic studies. Others consider their
approach deterministic. Some consider their
approach a combination of deterministic and
probabilistic methods. At least one member uses
Loss of load expectation and percent reserves.
The RELY model is used by at least one
member.
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Determining resource adequacy in each
capability period (summer/winter). Results are
used to determine if additional capacity and
energy need to be procured. State and local
regulators generally rely on company specific
studies for those companies within theirrespective jurisdictions.
The data used is the data gathered through a
twice yearly survey of SERC members in support
of NERC LTRA, Winter and SummerAssessments along with EIA data filings. Within
member companies expected forced outage
rates for all generation units are provided by , i.e.
nuclear, fossil, hydro, etc.
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The transmission systems within SERC are
planned, designed, and operated such that the
regions generating resources with an obligation
to serve load or have firm contracts to serve load
are not constrained. Typical resource adequacy
studies (LOLE studies) do not considertransmission constraints. But limits are modeled
by some members indirectly through limits on
amount of off-system purchases.
Summation of non-coincident peaks on a monthly
or annual basis.
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Load uncertainty related to many factors
including economic conditions and weather is
generally considered by SERC's members. Most
produce a 50/50 forecast, Some use a 90/10
forecast.
SERC members are questioned and asked to
quantify load forecast uncertainty. Information
received is used in assessments. Memberstypically consider short term load uncertainty as
including the impacts of extreme weather. Long
term uncertainties include high and low economic
scenarios, high and low electric prices, high and
low gas prices, and outlook for large industrial
customers.None to the best of our ability to determine.
SERC staff extensively test the data received to
determine if any data is missing.
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All load serving entities within SERC report
existing and future resources through the EIA-
411 reporting process. This includes owned
resources as well as merchant resources with a
contractual arrangement. Only capacity reported
through the EIA-411 is used in capacity margincalculations. Because significant capacity exist
within SERC with no obligation to serve or firm
contractual arrangement, there will continue to be
additional generation above that which is
reported in the capacity margin trend. Capacity
margin calculations also assume the use of load
management and interruptible contracts at the
time of the annual peak. Market based
mechanisms for capacity assurance are generally
not applicable to SERC except in a few areasthat are part of organized markets (MISO, SPP,
PJM). All resources reported in the region are
tabulated as being a portion of the resource mix.
Resources are being categorized consistent with
the NERC LTRA guidelines. The load serving
entities (LSE) may have their own selection
process, including RFPs, to evaluate the capacity
options. Capacity resources included in reliability
assessments are generally proven technologies.
See answer above. For the purposes of NERC
Reliability Assessment reporting, SERC members
are generally using the NERC Planning
Committee and RAS guidance from the
December 2007 meeting: "Planned" means
construction has started with at least one of the
following regulatory permits approved: Site
permit, Construction permit, Environmental
permit
Or: Corporate management has approved atleast one of the following: Included in a capital
budget BOD approved. All other resources are
considered Uncertain
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SERC members have been instructed to follow
the NERC definitions for resource certainty in the
current year's (2008) reporting.
We do not have a recommendation at this time,
but note that very few SERC members reported
any "uncertain" capacity for the Summer 2008
and the 2008 LTRA reporting cycle.
Yes. SERC members monitor and develop
contingency plans as needed to address these
operational issues.
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SERC members are aware of energy-limited
resources that could impact resource availability
and use various tools and practices to develop
short-term operational and long-term plans to
address these issues.
SERC is not specifically assessing transmission
limited resources as a result of the NERC
Planning Committee decision to not do so this
year. Some members may calculate accredited
capacity of 4-6 hours duration based on legacy
region (MAIN) criteria. At this time there is not
much wind resource in SERC although in some
portions of SERC it is expected to develop.
There is no SERC standard approach. Projectedwind (or any other fuel type plant) project output
is taken as reported by each SERC reporting
member. MISO is using a rating for capacity
determination set at 20% of the rated output of
wind plants. Wind resources should be
connected to the Ameren system in late 2008 or
earl 2009.
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Ratings for generating plants are reported based
on the seasonal ratings established based on
peak season ambient temperature, water, or
other constraining conditions. Based on recent
history, water temperatures and water availability
would be included.Yes, for instance we have developed a drought
study which examines the impact of the
Southeast US drought on hydro and thermal
plants (environmental permit related cooling
system impacts) in the region. The NERC 2007
LTRA reported for 2006 showing natural gas at
15%, Coal at 44% , Nuclear at 16% and Hydro at
6% of Summer peak demand. Also, some
members have conducted interdependency
studies between fuel delivery and resourceavailability. Specifically the RRS performed a
gas-electricity interdependence assessment two
years ago. No fuel supply problems are
anticipated except for the recent drought related
issues which may be abating.
Deliverability to load is generally assessed
through regional transmission assessmentstudies and studies carried out by Transmission
Planning entities within the SERC region. Some
sub areas have other approaches, for instance in
MISO, generators that pass a deliverability test
can be considered as a network resource for any
of the MISO loads that choose to designate
them. The load serving entities (LSE) may have
their own selection process, including RFPs, to
evaluate the capacity options.
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In general within the SERC region there are
significant demand response programs. These
programs allow demand to be reduced or
curtailed when needed to maintain reliability.
Traditional load management and interruptible
programs such as air conditioning load controland large industrial interruptible services are
utilized within the region.
EE is considered at the member level. SERC
does not generally obtain this information,
however for 2008 there are categories of
reporting which include such information.
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NDDR is considered at the member level.
DEDR is considered at the member level.
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DCDR is considered at the member level.
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Emergency Operating procedures vary by
member.
Some members rely on public appeals to reduce
load for capacity reserve deficiencies.
SERC takes the assessments of such
transactions as put forward by our SERC
members in the data survey process.
Import and export categories are considered
certain as reported
Yes- we strive to match up buyers and sellers
reporting transactions when reporting
transactions. These are reconciled at the regional
reporting level.
Past experience with import plans and
projections made by members through the twice
yearly surveys.
They are not
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There is no process in place.
Probabilistic assessments are not performed by
SERC, although some members perform such
assessments at the member level. They are
typically performed on an annual basis by
members10,15, or 20 years depending on the member.
Some members use probability methods others
use deterministic methods. Some use LOLP
others LOLE, others use a capacity or reserve
margin approach not driven by a probabilistic
assessment.Answer not available at this time for those
members performing such assessments.
Scenarios are modeled from time to time
depending on the issue. For instance for Summer
2008 SERC has prepared a Drought
Assessment. SERC is also at the time of this
submittal considering participating in arenewables assessment.
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In general, operating procedures seek voluntary
load reduction through public appeals, reactive
power dispatch and generation redispatch are
tools that are available to operators in the SERC
region. We would not be pursuing operating
remedies if peak demands are higher thanexpected. Typically, only if operating reserves are
at risk would there be implementation of DSM or
public appeals, or voltage reduction, etc.
Not Applicable in the SERC region.
SERC members have generally adopted the
NERC 2008 LTRA definitions which identifies this
component separately
SERC members are generally applying the
NERC 2008 LTRA model definition which
identifies this component separately
Yes, by each reporting member company
consistent with their respective experience.
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resource adequacy is assessed on a state
jurisdictional basis by each member company
and generally not through organized markets,
ISOs, RTOs except where such exist (MISO,
SPP, PJM) in parts of the SERC footprint
No there are no benchmarks or established
metrics but, depending on the company, state
and subregion; for the SERC region as a whole
one can say that there is general acceptance ofcapacity margins in the range of 10-15%
Yes, the state of Georgia.
Not generally applicable in the SERC region
except for portions of SERC in SPP, MISO andPJM.
No response
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Response to SurveySPP
The lastest study is under progress. It will bemade available at a later date.
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SPP uses a 12% reserve margin which based on
historical LOLE studies(approximately a 1 day in
ten years)
To verify LOLE, a 3-5 year out case is used, with
Monte Carlo simulations.
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To inform resource planners who are SPP
members.
Data is used from member data submissions
annually relevant to forecast and historical figures
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Interface limits are modeled as well as significant
OTDF flowgates. Binding transmission forces
local generation to serve load, if none is available
then load is shed
Each SPP member annually provides a tenyear
forecast of peak demand and net energy
requirements. The forecasts are developed in
accordance with generally recognizedmethodologies.The resultant SPP forecast is the
total of the member forecasts. High and
lowgrowth rates and unusual weather scenario
bands are then produced for the SPP regional
and subregional demand and energy forecasts
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Based on weather, economic trends, etc.
Changes over time
No
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EIA-411,LTRA,Supply Adequacy Audit
EIA-411 data submitted by members
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Existing Capacity includes Certain and Uncertain
Capacities. Planned Capacity is a resouce that is
already under construction or has a signed
interconnection agreement in place. Proposed
Capacity is a resource that has been announced
but does not have a signed interconnectionagreement.
No suggestion at this time
Studies show LOLP problems throughout the
year based on standard FOR and results of the
simulation. Maintenance is done on SPP
generating units in the off peak season, whereenough generation is present in the surrounding
system to cover any unexpected system
conditions based on the reserve sharing
re uirements.
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They are included with a uncertainty distribution
in the program
These resources are currenly being derated
appropriately for resource adequacy assessment.
Wind is rated based on historical data, and astandard uncertainty distribution
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Units that have a specific derating for peak load
conditions are modeled as such on an individual
basis.
SPP consults its generation owners and
contolling members each year to monitor fuel
supplies. SPP criteria requires members to keep
a sufficient amount of standby fuel on hand to
help if there are any deliveribilty concerns. There
are no concerns known to SPP at this time.Coal-
fired plants make approx. 48% and natural gas
power plants make up approx. 44% of SPP total
generation.
SPP defines firm deliverability as electric power
intended to be continuously available to the buyereven under adverse conditions; i.e., power for
which the seller assumes the obligation to
provide capacity (including SPP defined capacity
margin) and energy. Such power must meet
standards of reliability and availability as that
delivered to native load customers. Power
purchased can be considered to be firm power
only if firm transmission service is in place to the
load serving member for delivery of such power.
SPP does not include financial firm contractstowards this category
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