RRO Adequacy Assessment Practices-Survey Responses 08-14-08 2

7/29/2019 RRO Adequacy Assessment Practices-Survey Responses 08-14-08 2

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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?


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?


component of DEDR?


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38 Are the DEDR-associated peak demand


adequacy assessments?

39 How are the certainties/uncertainties of DEDR


diversity modeled?40 What criteria do you use to include future DEDR


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?


component of DCDR?

44 Are the DCDR-associated peak demand


adequacy assessments?45 How are the certainties/uncertainties of DCDR


diversity modeled?

46 What criteria do you use to include future DCDR


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


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


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


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


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


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 PlanningCoordinators within the MRO geographical area



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Coordinators within the MRO geographical area(MISO, MAPP, MHEB, ATC, SaskPower)


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MISO, MAPP, MHEB, ATC, SaskPowerSee the responses from the Planning


(MISO, MAPP, MHEB, ATC, SaskPower)See the responses from the Planning

















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See MRO standard (RES-501-MRO-01)







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MRO standard is applicable to the LSE or its

delegate. Midwest PRSG, MAPP PRSG,

SaskPower will be performing the studies




state of Wisconsin



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







e.aspx


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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






e.aspx

Development of NPCC guidelines for ratingintermittent resources (wind) for resource

adequacy assessments is a NPCC 2009

Corporate Goal.


73/144

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


74/144

No response

Refer to the individual NPCC Area responses for

more detail or the latest NPCC Review of Area



e.aspx

See above

See above

See above

See above


75/144

See above

See above





e.as x

See above

See above

See above

See above

See above





e.aspx

See above

See above


76/144

See above

See above

See above

See above

See above

See above

See above

See above

See above


77/144





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


78/144

See:


s.aspx

See:


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


e.aspx (interim and comprehensive reviews of

resource adequacy)

Yes - scenarios are modeled with separate multi-

area probabilistic assessment

assumptions/simulations


79/144













e.as x







e.as xSee above

NPCC does not have a reserve margin

requirement

NPCC does not have a reserve margin

requirement

See above


80/144

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




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.


81/144

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


82/144

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.


83/144

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.


84/144

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.


85/144

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.


86/144

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.


87/144

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.


88/144

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.


89/144

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.


90/144

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


91/144

See response to #22

See response to #22

No

No

Not applicable

No

Not applicable

Not applicable

Unknown

No

Not applicable


92/144

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.


93/144

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


No.

Whatever criteria the RTOs use for firm imports

and exports.

Tie benefits are not included in the assessments.


94/144

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.


95/144

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.


96/144

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.


97/144

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


98/144

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.


99/144

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.


100/144

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.


101/144

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.


102/144

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


103/144

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.


104/144

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.


105/144

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.


106/144

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.


107/144

NDDR is considered at the member level.

DEDR is considered at the member level.


108/144

DCDR is considered at the member level.


109/144

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


110/144

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.


111/144

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.


112/144

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


113/144

Response to SurveySPP

The lastest study is under progress. It will bemade available at a later date.


114/144

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.


115/144

To inform resource planners who are SPP

members.

Data is used from member data submissions

annually relevant to forecast and historical figures


116/144

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


117/144

Based on weather, economic trends, etc.

Changes over time

No


118/144

EIA-411,LTRA,Supply Adequacy Audit

EIA-411 data submitted by members


119/144

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.


120/144

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


121/144

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
http://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+Interconnectionhttp://www.midwestmarket.org/page/Generator+In

Documents

RRO Adequacy Assessment Practices-Survey Responses 08-14-08 2