2008 Long-Term 

Reliability Assessment

2008-2017

116-390 Village Blvd., Princeton, NJ 08540

609.452.8060 | 609.452.9550 fax

www.nerc.com

the reliability of the

to ensure

bulk power system

October 2008
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Table of Contents 

i 2008 Long-Term Reliability Assessment 

Table of Contents

NERC’S MISSION........................................................................................................... 1

INTRODUCTION............................................................................................................. 2

PROGRESS SINCE 2007............................................................................................... 5

KEY FINDINGS FOR 2008-2017 .................................................................................... 7

KEY FINDINGS FOR 2008-2017 .................................................................................... 8

1. Capacity Margins Improved, though Resources still Required .............................................................................8

2. Wind Capacity Projected to Significantly Increase.............................................................................................12

3. More Transmission Needed to Maintain Bulk System Reliability and Integrate New Generation .....................15

4. Demand Response Increasingly Used to Meet Resource Adequacy Requirements ............................................18

5. Bulk Power System Adequacy Trends Emphasize Maintenance, Tools and Training........................................22

EMERGING ISSUE ASSESSMENT & SCENARIO ANALYSIS................................... 25

Emerging Issue Risk Assessment .............................................................................................................................25

Potential Environmental Regulation could Impact Resource Adequacy..............................................................28

Greenhouse Gas Reductions....................................................................................................................................28

U.S. Clean Water Act: Cooling-Water Intake Structures........................................................................................29

U.S. Clean Air Interstate Rule (CAIR) and Clean Air Mercury Rule (CAMR)......................................................31

Fuel Transportation & Storage ................................................................................................................................33

Rising Global Demand Impacts for Electric Power Equipment............................................................................39

Increased Adoption of Distributed Generation and Demand-Side Resources .....................................................41

Transmission of the 21st Century.............................................................................................................................44

Water Availability and Use.......................................................................................................................................46

2009 Scenario Analysis Summary ............................................................................................................................48

RELIABILITY HISTORICAL TRENDS.......................................................................... 50

REGIONAL RELIABILITY ASSESSMENTS ................................................................ 62

Background..............................................................................................................................................................62

Regional Demand & Resource Projections 2008-2017 .................................................................................63

Table 13a: Estimated 2008 Summer Margins (%), Resources and Demands (MW) .............................68
Table of Contents 

ii 2008 Long-Term Reliability Assessment 

Table 13b: Estimated 2008/09 Winter Margins (%), Resources and Demands (MW) ...........................69

Table 13c: Estimated 2012 Summer Margins (%), Resources and Demands (MW) .............................70

Table 13d: Estimated 2012/13 Winter Margins (%), Resources and Demands (MW) ...........................71

Table 13e: Estimated 2017 Summer Margins (%), Resources and Demands (MW) .............................72

Table 13f: Estimated 2017/18 Winter Margins (%), Resources and Demands (MW) ............................73

ERCOT Highlights...................................................................................................................................................75

ERCOT Self-Assessment......................................................................................................................................77

FRCC Highlights .....................................................................................................................................................83

FRCC Self-Assessment.........................................................................................................................................86

MRO Highlights .......................................................................................................................................................93

MRO Self-Assessment...........................................................................................................................................97

NPCC Highlights ...................................................................................................................................................111

NPCC Self-Assessment.......................................................................................................................................118

Maritimes Area......................................................................................................................................................123

New England.........................................................................................................................................................128

New York..............................................................................................................................................................139

Ontario ..................................................................................................................................................................148

Québec ..................................................................................................................................................................157

RFC Highlights ......................................................................................................................................................162

RFC Self-Assessment..........................................................................................................................................165

SERC Highlights ...................................................................................................................................................177

SERC Self-Assessment.......................................................................................................................................182

Central...................................................................................................................................................................193

Delta......................................................................................................................................................................197

Gateway ................................................................................................................................................................201

Southeastern ..........................................................................................................................................................206

VACAR.................................................................................................................................................................209

SPP Highlights.......................................................................................................................................................215

SPP Self Assessment..........................................................................................................................................218

WECC Highlights ..................................................................................................................................................225

WECC Self-Assessment......................................................................................................................................233

Northwest Power Pool Area..................................................................................................................................250

Rocky Mountain Power Area................................................................................................................................256

Arizona-New Mexico-Southern Nevada Power Area ...........................................................................................258

California-Mexico Power Area .............................................................................................................................261
Table of Contents 

iii 2008 Long-Term Reliability Assessment 

ABBREVIATIONS USED IN THIS REPORT .............................................................. 265

CAPACITY, DEMAND & EVENT DEFINITIONS ........................................................ 267

a) Demand Definitions ..........................................................................................................................................267

b) Demand Forecast Bandwidths ..........................................................................................................................267

c) Demand Response Categorization ....................................................................................................................270

d) Capacity, Transaction and Margin Categories ..................................................................................................272

e) How NERC Defines Bulk Power System Reliability........................................................................................273

f) Event Classifications .........................................................................................................................................274

MAJOR TRANSMISSION PROJECTS > 200 KV....................................................... 276

REPORT CONTENT RESPONSIBILITY .................................................................... 294

RELIABILITY ASSESSMENT SUBCOMMITTEE ...................................................... 295
NERC’s Mission 

1 2008 Long-Term Reliability Assessment 

NERC’s Mission

The North American Electric Reliability Corporation’s (NERC) mission is to ensure the 

reliability of the bulk power system in North America. To achieve this objective, NERC 

develops and enforces reliability standards; monitors the bulk power system; assesses and reports 

on future transmission and generation adequacy; and offers education and certification programs 

to industry personnel. NERC is a non-profit, self-regulatory organization that relies on the 

diverse and collective expertise of industry participants that comprise its various committees and 

sub-groups. It is subject to oversight by governmental authorities in Canada and the United 

States (U.S.).1 

NERC assesses and reports on the reliability and adequacy of the North American bulk power 

system according to eight regional areas as shown on the map below2

. The users, owners, and 

operators of the bulk power system within these areas account for virtually all the electricity 

supplied in the U.S., Canada, and a portion of Baja California Norte, Mexico. 

 

Note: The highlighted area between SPP and 

SERC denotes overlapping regional boundaries 

 

1

 As of June 18, 2007, the U.S. Federal Energy Regulatory Commission (FERC) granted NERC the legal authority to enforce 

reliability standards with all U.S. users, owners, and operators of the bulk power system, and made compliance with those 

standards mandatory and enforceable. Reliability standards are also mandatory and enforceable in Ontario and New 

Brunswick, and NERC is seeking to achieve comparable results in the other Canadian provinces. NERC will seek recognition 

in Mexico once the necessary legislation is adopted. 

2 Note ERCOT and SPP are tasked with performing reliability self-assessments as they are regional planning and operating 

organizations. SPP-RE (SPP – Regional Entity) and TRE (Texas Regional Entity) are functional entities to whom NERC 

delegates certain compliance monitoring and enforcement authorities. 

ERCOT 

Electric Reliability Council 

of Texas 

RFC

ReliabilityFirst 

Corporation 

FRCC 

Florida Reliability 

Coordinating Council 

SERC 

SERC Reliability 

Corporation 

MRO 

Midwest Reliability 

Organization 

SPP 

Southwest Power Pool, 

Incorporated 

NPCC 

Northeast Power 

Coordinating Council, Inc. 

WECC 

Western Electricity 

Coordinating Council 
Introduction 

2 2008 Long-Term Reliability Assessment 

Introduction 

The 2008 Long-Term Reliability Assessment represents NERC’s independent judgment of the 

reliability and adequacy of the bulk power system in North America for the coming ten years. 

NERC’s primary purpose in preparing this assessment is to identify areas of concern regarding 

the reliability of the North American bulk power system and to make recommendations for their 

remedy. The annual schedule for NERC’s reliability assessments is found in Table 1. 

This assessment is prepared by NERC in 

its capacity as the Electric Reliability 

Organization in the U.S. and parts of 

Canada.3 NERC cannot order construction 

of generation or transmission or adopt 

enforceable standards that require 

expansion of these facilities, as that 

authority is explicitly withheld in the U.S. 

by Section 215 of the U.S. Federal Power 

Act4

 and in Canada by various provisions. 

In addition, NERC does not make any 

projections or draw any conclusions 

regarding expected electricity prices or the 

efficiency of electricity markets. 

The potential long-term impacts of the recent unprecedented events in global financial markets 

could have a significant effect on future electricity supply and demand projections that are not 

reflected in this special report. NERC will monitor these impacts and reflect them in its future 

assessments. 

Assessment Preparation 

NERC prepared the 2008 Long-Term Reliability Assessment with support from the Reliability 

Assessment Subcommittee (RAS) under the direction of NERC’s Planning Committee (PC) with 

additional review from the Operating Committee (OC).5

 The report is based on data and 

information submitted by each of the eight Regional Entities in March 2008 and periodically 

updated throughout the report drafting process.6

 This data and information is carefully vetted to 

ensure accuracy and consistency by NERC staff and RAS. Other data sources consulted by 

NERC staff are identified in this report. 

 

3

 Section 39.11(b) of the U.S. FERC’s regulations provide that: “The Electric Reliability Organization shall conduct assessments 

of the adequacy of the Bulk-Power System in North America and report its findings to the Commission, the Secretary of 

Energy, each Regional Entity, and each Regional Advisory Body annually or more frequently if so ordered by the 

Commission.” 4

 http://frwebgate.access.gpo.gov/cgi-bin/getdoc.cgi?dbname=109_cong_bills&docid=f:h6enr.txt.pdf 5

 Unlike the Energy Information Administration’s (EIA) Annual Energy Outlook (for example the 2008 report can be found at 

http://www.eia.doe.gov/oiaf/aeo/pdf/0383(2008).pdf), NERC’s report focuses exclusively on bulk power system reliability 

with data and information provided by industry experts, representing a variety NERC stakeholders. 6

 See http://www.nerc.com/files/Adequate_Level_of_Reliability_Defintion_05052008.pdf for more background on reliability 

concepts used in this report. 

Table 1: 

NERC’s Annual Reliability Assessments 

Assessment Outlook Published 

Summer 

Assessment Upcoming season May 

Long-Term 

Assessment 10 years October 

Winter Assessment Upcoming season November 
Introduction 

3 2008 Long-Term Reliability Assessment 

NERC uses an active peer review process in developing reliability assessments. The peer review 

process takes full advantage of industry subject matter expertise from many sectors of the 

industry. This process also provides an essential check and balance for ensuring the validity of 

the information provided by the Regional Entities. 

Each region prepares its data and a self assessment. Each of the regional self-assessments is 

assigned to two to four RAS members from other regions for an in-depth and comprehensive 

review of the data and information. Reviewer comments are discussed with the regional entity’s 

representative and refinements and adjustments are made as necessary. The regional selfassessments and data are then subjected to scrutiny and review by the entire subcommittee. This 

review ensures members of the subcommittee are fully convinced that each regional selfassessment and data is accurate, thorough, and complete. The Reliability Trends section is 

reviewed by the OC, while the entire document, including the regional self-assessments, is then 

reviewed in detail by the Member Representatives Committee (MRC) and NERC management. 

The report is endorsed by the PC before being submitted to NERC’s Board of Trustees for final 

approval. 

To further increase the transparency of the process and conclusions, NERC sponsored a public 

workshop designed to discuss preliminary findings with industry experts and participants, 

identify industry concerns, and solicit improvements. Key suggestions from this workshop are 

reflected in this final report. The presentations and notes from the workshop are posted on the 

NERC Web site.7

In the 2008 Long-Term Reliability Assessment, the baseline information on future electricity 

supply and demand is based on several assumptions:8

• Supply and demand projections are based on industry forecasts submitted in March 2008. 

Regions were given an opportunity to reflect significant changes through the summer, but 

any subsequent demand forecast or resource plan changes may not be fully represented. 

• Peak demand and capacity margins are based on average weather conditions and assumed 

forecast economic activity at the time of submittal. Weather variability is discussed in 

each regional self-assessment. 

• Generating and transmission equipment will perform at historical availability levels. 

 

7

 http://www.nerc.com/filez/ltra_workshop.html 8

 Forecasts cannot precisely predict the future. Instead, many forecasts report probabilities with a range of possible outcomes. 

For example, each regional demand projection is assumed to represent the expected midpoint of possible future outcomes. This 

means that a future year’s actual demand may deviate from the projection due to the inherent variability of the key factors that 

drive electrical use, such as weather. In the case of the NERC regional projections, there is a 50 percent probability that actual 

demand will be higher than the forecast midpoint and a 50 percent probability that it will be lower. 

For planning and analytical purposes, it is useful to have an estimate not only of the expected of possible future outcomes, but 

also of the distribution of probabilities around the projection. Accordingly, the Load Forecasting Working Group (LFWG) 

develops for each an upper and lower ten percent confidence band around the NERC regional demand and energy projections. 

This means there is an 80 percent probability that future demand and energy will occur within these bands. Concurrently, there 

is a ten percent chance future outcomes could be less than the lower band and a ten percent chance future outcomes could be 

higher than the upper band. The high and low bands around the demand forecasts are depicted in the charts with each region's 

self assessment 
Introduction 

4 2008 Long-Term Reliability Assessment 

• Planned outages and future generation and transmission facilities are commissioned and 

in-service as scheduled and planned. 

• Demand reductions expected from demand response programs will yield the forecast 

results, if and when they are called on. 

• Other peak demand-side management programs are reflected in the forecasts of net 

internal demand. 

• Firm electricity transfers between regions are contractually arranged and occur as 

projected. 

Enhancements to the 2008 Reliability Assessment 

In light of the guidance in FERC’s Order 672 and comments received from other authorities and 

industry representatives, NERC’s Planning Committee (PC) concluded the Seasonal and LongTerm Reliability Assessment processes required improvement. To achieve this goal, the PC 

formed a task force and directed it to develop recommendations and a plan for improvement. A 

number of the task force’s recommendations9 were incorporated into the 2008 Long-Term 

Reliability Assessment, including: 

1. Supply-side resource categories were enhanced to better assess and measure the 

certainty and risk of resource acquisition strategies and adequacy. 

2. Collection of Demand-side Management data was expanded to include both projected 

Energy Efficiency and Dispatchable Demand Response.10

3. Both wind nameplate and on-peak capacity projections were collected. 

4. Emerging issues and scenario analysis sections were added to identify risks and 

document risk assessment results. The scenarios for the 2009 LTRA are currently under 

development. 

5. Reliability trends were compiled to provide indications of system use and the need for 

further investigations in future reliability assessments. 

 

9

 For the full report, see http://www.nerc.com/files/Reliability%20Improvement%20Report%20RAITF%20100208.pdf, entitled, 

“Data Collection for Demand-Side Management for Quantifying its Influence on Reliability: Results and Recommendations.” 10 ftp://ftp.nerc.com/pub/sys/all_updl/docs/pubs/NERC_DSMTF_Report_040308.pdf 
Key Findings 2008-2017 

5 2008 Long-Term Reliability Assessment 

Progress Since 2007

In its 2007 Long-Term Reliability Assessment,

11 NERC identified five “Key Findings” that could 

critically impact long-term reliability unless prompt actions were taken. NERC’s key findings 

are based on observations and analyses of supply and demand projections submitted by the 

regions as part of the Long-Term Reliability Assessment, NERC staff independent assessment of 

the results as well as industry trends, and other stakeholder input and comments.12

The magnitude of these issues necessitates complex planning and execution strategies whose 

impacts may not be realized for several years. As shown in Table 2, while some progress has 

been made, action is still needed on all of the issues identified in last year’s report to ensure a 

reliable bulk electric system for the future. Based on industry progress made on 2007 Key 

Findings, NERC will either continue to highlight them through the Key Findings or Emerging 

Issues sections of this report, or will continue to monitor advancement. 

Table 2: Progress on 2007 Key Findings 

2007 Key Finding Progress in 2008 2008 Status 

1. Long-Term Capacity Margins 

are still Inadequate 

 4.2% improvement over 2007 

 Demand response decreases peak 1% by 2016 

 More resources required in some areas 

 Key Finding 

2. Integration of Wind, Solar and 

Nuclear Resource Require 

Special Consideration in 

Planning, Design and 

Operation 

 Wind plant nameplate increased (145,000 MW 

of Proposed installed nameplate capacity) 

 Nuclear plant projections increase 9,000 MW 

by 2017 

 Transmission vital for integration of resources 

in various planning stages across NERC. 

 Key Finding 

3. High Reliance on Natural Gas 

in Some Areas of the U.S. Must 

Be Properly Managed to 

Reduce the Risk of Supply & 

Delivery Interruptions 

 Natural gas delivery remains a concern 

 Regional measures taken 

 Emerging Issue 

4. Transmission Situation 

Improves, But More Still 

Required 

 Projected mileage increase of 14% from last 

year 

 More transmission needed to maintain bulk 

power system reliability and integrate new 

generation 

 Key Finding 

5. Aging Workforce Still a 

Growing Challenge 

 Increased industry recognition and response 

 NERC continues to support action and monitor 

industry progress 

 Monitoring 

 

11 http://www.nerc.com/files/LTRA2007.pdf 12 Additional significant findings also appear in the Regional Reliability Assessments, Operational Reliability and Emerging 

Issues Assessment and Scenario Analysis sections of the report. 
Key Findings 2008-2017 

6 2008 Long-Term Reliability Assessment 

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Key Findings 2008-2017 

7 2008 Long-Term Reliability Assessment 

Total Internal Demand (MW) — Total amount of electricity projected to be used at time of peak within a given 

system area 

Net Internal Demand (MW) —Total Internal Demand reduced by dispatchable controllable (capacity) demand 

response. 

Existing-Certain Capacity — Existing generation resources anticipated to be available, operable and deliverable 

to or into the region at the time of peak demand.

Existing-Uncertain Capacity — Existing generation resources which may be available, operable, and 

deliverable to or into the region at the time of peak demand. This category includes “mothballed” units and the 

“de-rated” portion of intermittent resources not included in Existing Certain. 

Planned Capacity — Generation that has achieved certain regulatory and approval milestones (see pg. 273). 

Proposed Capacity — Generation that is not in any of the above categories, but has passed certain planning 

milestones (see pg. 273). 

Net Firm Transactions (MW) — Net of contracted firm interregional purchases (positive value) and sales 

(negative value). 

Total Internal Capacity — Sum of Existing (both Certain and Uncertain) and Planned Capacity.

Net Capacity Resources (MW) — Total Internal Capacity, less Transmission-Limited Resources, all Derates, 

Energy Only, and Inoperable resources; including Net Firm, Expected and Provisional Purchases/Sales (does not 

include Non-Firm Purchases/Sales).

Total Potential Resources (MW) — Total Internal Capacity, less Transmission-Limited Resources, plus all 

Purchases/Sales.

Adjusted Potential Resources (MW) —Total Proposed Resources reduced (multiplied) by a confidence factor; 

plus Net Non-Firm Transactions. 

Existing-Certain Capacity and Net Firm Transactions Margin (%) — Existing-Certain Capacity and Net Firm 

Transactions less Net Internal Demand; as a percent of Existing-Certain Capacity and Net Firm Transactions.

Net Capacity Resource Margin (%) — Net Capacity Resources reduced by the Net Internal Demand; as a 

percent of Net Capacity Resources.

Total Potential Resources Margin (%) — Total Potential Resources reduced by the Net Internal Demand; as a 

percent of Total Potential Resources 

. 

Adjusted Potential Resources Margin (%) — Capacity margin using the Total Potential Resources reduced 

(multiplied) by the confidence factor (percentage). 

Target Capacity Margin (%) — Established target for capacity margin by the region or sub-region. 

NERC Reference Margin Level (%) — Either the Target Capacity Margin provided by the region/sub-region or 

NERC assigned based on capacity mix (i.e. thermal/hydro).

Capacity Resources & Margins Quick Reference Guide 
Key Findings 2008-2017 

8 2008 Long-Term Reliability Assessment 

Key Findings for 2008-2017 

1. Capacity Margins Improved, though Resources still Required 

Capacity margins in many regions are improved compared to 2007 figures, due in part to significant 

increases in demand response and supply-side resources. Nevertheless more resources will be required to 

maintain reliability in Western Canada and the Desert Southwest areas in the coming years. 

Many areas have shown improvement in projected capacity margins, due to changes in resource 

categorization, the establishment of forward capacity markets, or the addition of new resources. 

These areas include New England, California, the Rocky Mountain sub-region, Texas, and the 

Midwest. Figure 1 provides the 2008-2017 summer capacity margins in North America (unless 

noted as winter) to NERC’s Reference Margin Level.13

Figure 1: Net Capacity and Adjusted Potential Resources compared to NERC’s Reference 

Margin Level14

* Substantial amounts of existing capacity in SERC-Delta subregion are categorized as “uncertain” under NERC’s 

2008 capacity categories. Under this year’s method, existing-uncertain generation is not counted towards Net 

Capacity Margin. Rather, it is included in the Adjusted Potential Capacity Margin. This generation is expected 

to be available to meet peak demand in the region despite its classification as “uncertain”. We expect that 

clarification of definitions for 2009 will correct this issue 

** Areas that may need more resources to meet their Target Margin Level or NERC Reference Margin Level.

 

13 The colors shown in this map serve to show the regional boundaries of reporting entities. 

14 Each region/subregion may have their own specific margin level based on load, generation, and transmission characteristics as 

well as regulatory requirements. If provided in the data submittals, the regional/subregional Target Capacity Margin level is 

adopted as the NERC Reference Margin Level. If not, NERC assigned 13 percent capacity margin for predominately thermal 

systems and for predominately hydro systems, 9 percent. 

ERCOT 

2013/>2017 

New England

2013/2013 

AZ/NM/SNV** 

2010/2010

California 

2014/2014 

Rocky Mtn 

2015/2015 SPP

2013/>2017

MRO-US 

2010/>2017 

RFC

2013/2017 

WECC-CAN** 

2009/2009 

(Winter) 

Ontario

2015/>2017 

Central

2011/2015

VACAR

2013/2014

Southeastern

2010/>2017

Delta*

2008/>2017

When Net Capacity Resources 

drop below the NERC 

Reference Margin Level 

...including Adjusted 

Potential Resources 
Key Findings 2008-2017 

9 2008 Long-Term Reliability Assessment 

Certain areas (See Figure 1), however, may still need additional resources in the near-term to 

ensure adequate capacity margins when comparing Net Capacity Resources margins to the 

NERC Reference Margin Level. Areas of most concern include: Western Canada (in winter) and 

the Desert Southwest. The outlook improves somewhat when including Adjusted Potential 

Resources, but Western Canada and the Desert Southwest margins are still a cause for concern. 

Winter Net Capacity Resource Margins in Canada are projected to decrease. Offsetting 

additional supplies throughout the rest of Canada, Ontario’s Net Capacity Resources for the 

2017/18 Winter peak are 4,800 MW lower than 2008/2009 Winter, reflecting the planned 

retirements of 6,400 MW of coal-fired generation by the end of 2014. Much of this reduction is 

balanced with demand response and energy efficiency coupled with new renewable, gas-fired, 

refurbished and new-build nuclear resources.

Drivers 

A number of factors have combined to affect resource adequacy for 2008. Marked improvement 

from 2007 in New England, for example, is directly due to newly operational mechanisms 

designed to add greater long-term planning visibility. Dubbed “forward capacity markets,” these 

and similar mechanisms are being implemented in some parts of North America. 

Supply-side additions have also contributed to improved margins, though substantial uncertainty 

exists for new resource construction. These additions are predominately gas-fired generating 

units (50%), but also include nearly 25,000 MW of coal plants still slated for construction 

despite recent trends in coal plant deferrals and cancellations,15 145,000 MW of nameplate wind, 

and 9,000 MW of new nuclear generation beginning to appear in the outer years. 

Recent rulemaking activities of the U.S. Environmental Protection Agency (EPA) on the Clean 

Air and Water Acts and federal climate change legislative deliberations in the U.S., each 

discussed in the Emerging Issues section of this report,16 could adversely affect both existing 

capacity (earlier retirements) and these planned capacity additions (deferrals and cancellations), 

which will, in turn, result in lower future capacity margins. 

A significant decrease in projected demand growth in the U.S. also contributes to higher capacity 

margins over the ten year period. This is primarily due to an increase in projected demand-side 

management (DSM) which plays a key role in improving capacity margins over the ten years.

Summer peak demand growth is projected to increase 16.6 percent for 2008-2017, compared to 

17.7 percent forecast last year through the 2007-2016 period. This represents a reduction of 1.1 

percent or almost one full year of growth (see Figure 2). An increase in projected dispatchable 

demand response is responsible for most of this reduction. Comparing last year’s projections to 

this year for the summer of 2016, demand response accounts for 3.4 percent of Total Internal 

Demand in this year’s report compared with 2.5 percent for last year (See Figure 2 below). 

 

15 OE NETL: http://www.netl.doe.gov/coal/refshelf/ncp.pdf 16 See www.nerc.com for more information on the potential impacts on reliability of Climate Change Initiatives 
Key Findings 2008-2017 

10 2008 Long-Term Reliability Assessment 

In Canada, winter peak demand is forecast to increase by over 6,500 MW or 7.2 percent during 

the next ten years, which is higher than the 6.5 percent growth forecast in last year’s assessment. 

However, the total winter peak demand for both 2008/2009 and 2017/2018 are lower than last 

year’s projections, due to lowered demand forecasts in Ontario and The Maritimes. Ontario17

forecasts a 2008/09 winter demand decrease of 1,200 MW compared to the 2007/2008 winter 

peak demand and a decrease of 2,326 MW when comparing this year’s ten-year forecast 

(2017/2018 winter) with last year’s (2016/2017 winter). These reductions result from 

conservation and energy efficiency18 programs, countering the expected 0.7 percent average 

annual growth. 

Figure 2: Dispatchable Capacity Demand Response Resources for the U.S. 

(2016 Summer peak) and Canada (2016/17 Winter peak) 

NERC US - 2016 Summer On-Peak 

Total Internal Demand 

3.4%

2.5%

860,000

870,000

880,000

890,000

900,000

910,000

920,000

930,000

2007 LTRA 2008 LTRA

MW

0.0%

1.0%

2.0%

3.0%

4.0%

5.0%

Demand Response

Net Internal Demand

% of Demand Response to Internal Demand

11,468 MW 

NERC CAN - 2016/17 Winter On-Peak 

Total Internal Demand 

2.7% 2.8%

95,000

96,000

97,000

98,000

99,000

100,000

101,000

102,000

103,000

2007 LTRA 2008 LTRA

MW

0.0%

1.0%

2.0%

3.0%

4.0%

5.0%

Demand Response

Net Internal Demand

% of Demand Response to Internal Demand

New energy efficiency is also projected to increase in both the U.S. and Canada. For example, 

for the summer peak, NERC-US grows over 6,000 MW during 2008-2017. During this same 

period, in Canada, Energy Efficiency is projected to grow by 3,000 MW for the winter peak (See 

Figure 3). 

 

17 Ontario is summer peaking. The 2017 Peak Summer forecast is 1,226 MW less than 2008 Summer peak.

18 http://www.powerauthority.on.ca/Page.asp?PageID=924&SiteNodeID=320 
Key Findings 2008-2017 

11 2008 Long-Term Reliability Assessment 

Figure 3: 2008-2017 Project New Energy Efficiency in 

the U.S. and Canada

0

2,000

4,000

6,000

8,000

2008 2017

MW

NERC-US (Summer Peak)

NERC-CAN (Winter Peak)

Reliability Impacts 

Capacity margins are measurements of the bulk power system’s ability to supply the aggregate 

electric power and energy requirements of electricity consumers. Higher capacity margins 

indicate that the system is more capable of withstanding extreme weather, forecasting errors, 

system events, and unscheduled resource outages. Lower capacity margins can lead to reduced 

reliability. Those regions and sub-regions whose capacity margins are projected to fall below 

NERC’s Reference Margin Levels in the next few years need to add resources quickly in order to 

maintain bulk power system reliability. 

The electric industry is projected to increase its reliance on Energy Efficiency and Dispatchable 

Capacity Demand Response programs. To consistently validate and measure the results of the 

demand response programs, NERC is inaugurating a demand response event analysis system 

(Demand Response Data Task Force), expected to be launched in 2010.19

Conclusions and Recommendations20

• Regulators need to continue their support for the development of additional cost effective 

transmission resources, including equitable cost allocation guidelines for such resources. 

Further, they should revise their existing processes to expedite the licensing of cost 

effective transmission resources needed to maintain reliability. 

• Formal markets should continue to pursue mechanisms to establish longer-range visibility 

of their resource needs. 

NERC Actions 

• Monitor the conditions in Western Canada and the Desert Southwest which may require 

additional resources in the near future. 

• Improve categorization of projected supply-side and demand-side resources to enhance 

the analysis of capacity margin certainty and risk. 

 

19 See http://www.nerc.com/filez/drdtf.html for ongoing progress. 20 The “Recommendations” for each of the Key Findings do not represent mandatory requirements, but rather NERC’s 

independent judgment of those steps that will help improve reliability of the bulk power system of North America 
Key Findings 2008-2017 

12 2008 Long-Term Reliability Assessment 

2. Wind Capacity Projected to Significantly Increase 

Wind resources are growing in importance in many areas of North America as new facilities 

come online. With growing dependence on wind generation, it is vital to ensure that these 

variable resources are reliably integrated into the bulk power system. 

As shown in Figure 4, 145,000 MW of nameplate new wind resources are Planned or Proposed 

over the next ten years. Though the bulk of these additions are categorized as Proposed resources 

raising the possibility that a number of these projects may be cancelled or reduced as developers 

make their final decisions, this projection still represents a dramatic increase in wind energy 

resources when compared to data received last year. 

While other renewable resources are beginning to appear in forecasts (800 MW of ExistingCertain and 280 MW of Planned solar capacity resources were reported in WECC), wind 

generation has become the primary reported focus of renewable resource development in North 

America. 

Figure 4: Projected Increase in Summer Wind 

Nameplate/Installed Capacity

0

10,000

20,000

30,000

40,000

50,000

60,000

2008201720082017200820172008201720082017200820172008201720082017

ERCOT FRCC MRO NPCC RFC SERC SPP WECC

MW

Existing Planned Proposed

Availability of capacity during times of peak demand (capacity on peak) is an important issue 

facing wind power when discussing reliability. Figure 5 shows the projected wind capacity 

during summer peak presented in megawatts (bars in Figure 5) and as a percentage of nameplate 

capacity (diamonds in Figure 5). These values vary significantly between regions (from 8.7 

percent in ERCOT to 26.4 percent in NPCC) due in part to varying forecasting and planning 

methodologies currently under development. 
Key Findings 2008-2017 

13 2008 Long-Term Reliability Assessment 

Figure 5: Projected Increase in Existing, Planned & Proposed Summer OnPeak Wind Capacity

11.5%

17.2%

13.4%

19.6%

13.1%

26.4%

19.9%19.9%

8.7% 8.7% 9.1%

15.0%

0

2,000

4,000

6,000

8,000

10,000

12,000

2008201720082017200820172008201720082017200820172008201720082017

ERCOT FRCC MRO NPCC RFC SERC SPP WECC

MW

0%

5%

10%

15%

20%

25%

30%

Existing Planned Proposed % of Expected-Peak Wind Capacity to Nameplate Capacity

Drivers

Policy and regulations aimed at energy independence, climate change and green house gas 

emissions, whether already in place or still under consideration, seem to be the most significant 

drivers for development of new renewable resources. Renewable Portfolio Standards (RPS) 

currently in place in over 30 U.S. states, for example, require many utilities to acquire new 

renewable resources to meet up to 30% of their total energy portfolio over the next five to 15 

years.

21 Supported by federal tax credits in the U.S., wind power has become the fuel of choice 

for these requirements due to the maturity of the technology and availability of suitable sites for 

development. 

Reliability Impacts 

The proposed level of commitment to renewable resources offers many benefits including a more 

diversified fuel mix and reduced emissions. But, just as with any new technology, certain 

challenges to reliably integrating wind into the system must be addressed. 

Numerous studies have been conducted to study wind integration, notably the recently released 

report by the Department of Energy which suggests wind energy could provide for 20 percent of 

the U.S. electricity needs by 2030.22 Though the level of penetration is the most studied factor, 

reliability considerations also include the size of balancing areas, improved system flexibility, 

ancillary service requirements, wind forecasting and transmission requirements. 

NERC’s Integration of Variable Generation Task Force has been studying the influence on 

reliability of accommodating large amounts of wind generation.23 Preliminary conclusions of 

 

21 See Emerging Issues Section for more detail. 22 http://www.20percentwind.org/ 23 http://www.nerc.com/filez/ivgtf.html 
Key Findings 2008-2017 

14 2008 Long-Term Reliability Assessment 

this NERC Task Force, concentrating on accommodate large amounts of variable generation (i.e. 

predominately wind) are: 

• Forecasting of resources must be improved to manage wind uncertainty 

• Flexibility of the bulk power system must be expanded to manage wind variability 

• Transmission must be constructed to enable management of both the uncertainty 

and variability of wind resources. 

Power system planners and operators are already familiar with a certain amount of variability 

and uncertainty, particularly as it relates to system demand and, to a lesser extent, with 

conventional generation. Output from wind generation, however, is not as dispatchable as 

conventional resources. With limited operating history, planners and operators are adjusting their 

activities to accommodate large amounts of wind while maintaining bulk power system 

reliability. 

Consistent methods are needed, for example, to determine wind on-peak capacity to ensure 

uniform measurement of its contribution to capacity margins. Three approaches are in current 

use: 1) Effective Load Carrying Capability (ERCOT), historical performance (i.e. SPP) and 

deploying a flat percentage (i.e. Midwest ISO predominately located in MRO and RFC areas). 

These different approaches provide widely different results seen in Figure 5. 

Conclusions and Recommendations 

• Regulators and policy makers must support the development of cost effective 

transmission resources, including equitable cost allocation guidelines for the delivery of 

both remotely located wind resources and ancillary services (such as spinning reserve and 

frequency response) to demand centers where such resources and/or services are deemed 

necessary and beneficial. 

• Coordinated effort is needed to better determine appropriate calculations for measuring 

the availability of wind on peak. 

NERC Actions 

• Assist the Integration of Variable Generation Task Force in the completion of its report 

incorporating specific, actionable recommendations. 

• Review the regions’ renewable resource scenario analyses to be incorporated in the 2009 

Long-Term Reliability Assessment.
Key Findings 2008-2017 

15 2008 Long-Term Reliability Assessment 

3. More Transmission Needed to Maintain Bulk System Reliability and Integrate 

New Generation 

Though total miles of transmission additions have increased when compared to last year’s 

assessment, much more transmission will be required to reliably integrate projected locationconstrained resources such as wind, nuclear, clean coal, and others into the bulk power system. 

The total number of transmission 

miles is projected to increase by 9.5 

percent (15,700 circuit-miles) in the 

U.S. and 7.4 percent (3,400 circuitmiles) in Canada over the next ten 

years (See Table 3). 

This represents 1,700 more circuitmiles projected to be added in the 

U.S. and 1,000 more circuit-miles in 

Canada over the coming ten-year 

period when compared to projections 

in last year’s report. 

More resources and investment will 

be needed, however, to maintain 

reliability and integrate new resources 

as aging infrastructure is replaced and 

changes are needed to the 

transmission system topology. New 

generation supply is projected to 

outpace transmission development by 

nearly two times – with Total 

Potential Resources projected to grow 

by 21 percent.24 

Further, many new supply resources 

are likely to be located remote from 

demand centers (i.e. wind generation) 

and location-constrained to those 

areas. The amount of transmission 

required to integrate these resources is 

significant. In Texas alone, for 

example, over 2,300 miles of new 

bulk transmission was recently 

approved for construction to transport 

power from new wind resources in 

West Texas to population centers like 

 

24 NERC does not collect transmission additions with the same granularity as supply-side resources. This comparison assumes 

the mileage reported includes Proposed transmission additions which is compared to Proposed Capacity additions. 

2007 2008-2012 2013-2017 2017 Total

Existing Additions Additions Projection

United States

ERCOT - 8,792 269 623 9,684 

FRCC - 7,201 349 239 7,789 

MRO - 15,939 1,075 1,258 18,273 

NPCC - 6,805 252 16 7,073 

NPCC New England 2,660 242 16 2,918 

NPCC New York 4,145 10 - 4,155 

RFC - 26,203 1,471 154 27,828 

RFC-MISO 7,229 687 21 7,937 

RFC-PJM 18,209 784 133 19,126 

SERC - 32,295 1,676 753 34,724 

Central 3,270 257 - 3,527 

Delta 5,065 253 73 5,391 

Gateway 1,952 57 - 2,009 

Southeastern 9,503 459 448 10,410 

VACAR 12,505 650 232 13,387 

SPP - 7,683 672 21 8,376 

WECC - 59,061 5,305 1,591 65,957 

AZ-NM-SNV 10,418 1,310 713 12,441 

CA-MX US 14,437 1,587 119 16,143 

NWPP 24,875 1,669 663 27,207 

RMPA 6,122 739 96 6,957 

Total-U.S. 163,979 11,069 4,655 179,704 

Canada

MRO - 6,693 392 931 8,016 

NPCC - 29,106 933 285 30,324 

Maritimes 2,174 - 103 2,277 

Ontario 11,316 420 - 11,736 

Quebec 15,616 513 182 16,311 

WECC - 10,700 703 153 11,556 

Total-Canada 46,499 2,028 1,369 49,896 

Mexico

WECC CA-MX Mex 674 238 102 1,014 

Total-NERC 211,152 13,335 6,126 230,614 

Table 3: Planned Transmission Circuit Miles > 200 kV 
Key Findings 2008-2017 

16 2008 Long-Term Reliability Assessment 

Dallas, Houston, Austin, and San Antonio in the eastern part of the state.25 This increase in 345 

kV facilities is not reflected in this report’s ERCOT data as it was submitted in March, 2008 

which was prior to regulatory approval of these facilities. 

The Major Transmission Projects > 200 kV section includes examples of potentially significant 

transmission additions, which are projected to improve reliability and/or system efficiencies. The

projects were identified on a regional basis as vital to regional reliability during and beyond 

2008–2017. 

In order to provide another view of the breadth of investment requirements and capacity 

installation under consideration, the collective capacity of existing and planned regional 

transmission was weighted by their total miles and average MVA capacity by operating voltage 

in Figure 6. Though this comparative does not entirely measure the bulk power system reliability 

benefits and increased capability of individual facility additions,26 it provides insights into 

transmission capacity additions. 

Figure 6: NERC-Wide Total Existing and Planned Lines: MVA-1000 

Miles

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

100,000

2007201720072017200720172007201720072017200720172007201720072017

ERCOT FRCC MRO NPCC RFC SERC SPP WECC

MVA-Miles (Thousands)

All DC

AC765kV

AC500kV

AC345kV

AC230kV

 Assumed MVA Capacity 

 230 kV = 700 MVA

 345 kV = 1,300 MVA

 500 kV = 2,000 MVA

 765 kV = 3,000 MVA

 ALL DC = 2,000 MVA

Perhaps most notable are the 765kV additions planned in RFC. This approximately 240 mile 

project, expected to be in-service in 2012, will bring a strong source of power into Maryland area 

by reducing the west-to-east power flow on the existing PJM 500 kV transmission paths while 

providing significant benefits to the constrained area of Washington, DC and Baltimore. 

Drivers

Lagging investment in transmission resources has been an ongoing concern for a number of 

years. More investment is required, as each peak season puts more and more strain on the 

transmission system, especially in constrained areas such as California and Desert Southwest of 

the U.S. 

 

25 ERCOT’s CREZ analysis (http://www.ercot.com/news/presentations/2006/ATTCH_A_CREZ_Analysis_Report.pdf Data not 

included in the submittal as this approval for transmission occurred after March 31, 2008. 26 For example, short lines in parallel may add more capability than long lines in series. 
Key Findings 2008-2017 

17 2008 Long-Term Reliability Assessment 

The process to site new transmission continues to be difficult, time consuming and expensive 

due to local opposition and environmental concerns especially when lines are planned to cross 

state borders. Negotiations still delay and, in some cases, stop needed projects from being built. 

As a result, transmission permitting, siting, and construction can take significantly longer (i.e. 7-

10 years) than permitting, siting, and construction of generation. 

Positive steps are being taken in some states and provinces to expedite certain key projects, and 

the U.S. federal government now has back-stop authority for lines planned within DOE defined 

National Interest Electric Transmission Corridors (NIETC). A number of studies are also 

ongoing to provide advanced planning for facilities.27

Reliability Impacts 

Transmission lines are the critical link between generation and customers. As demand grows and 

generation is built in areas remote from the demand, more capacity on the transmission system is 

needed to meet demand. Congestion on transmission lines, as more and more power is moved 

over them, can have a significant impact on reliability. As these lines reach their capacity, for 

example, they are less able to make up the difference when neighboring lines are forced out of 

service due to equipment failure, severe weather, or maintenance. Under-investment in 

transmission puts additional strain on existing resources, raising the risk of system disturbances, 

lengthening restoration time when outages do occur, and limiting access to remote generation. 

Reflecting this importance, NERC should expand its understanding of projected transmission 

resource acquisition strategies being employed throughout North America. Therefore, the 

categorization of transmission additions should be considered to fully appreciate transmission 

resource requirements. 

Conclusions and Recommendations 

• Regulators need to continue their support for additional transmission resources. Further, they 

should revise their existing processes to expedite the licensing of transmission projected 

needed to maintain reliability. 

• The projects identified in the Major Transmission Projects > 200 kV section and their 

associated in-service dates are vital to maintain regional bulk power system reliability and/or 

system efficiencies. 

NERC Actions 

• Continue to assess and report on the reliability impacts of integrating new variable generation 

and nuclear resources into the bulk power system.28

• Enhance data collection to increase the granularity and gradation of certainty of planned and 

proposed transmission projects. 

• Provide information and support to NERC’s stakeholders on the need for new transmission in 

North America. 

 

27 For example, Joint Coordinated System Plan Study (JCSG) 

(http://www.spp.org/publications/2007%2011%2001%20JCSP%20Stakeholder%20Meeting%20Presentation.pdf), the EHV Overlay 

Study (http://www.nerc.com/docs/pc/ras/EHV_Overlay_Overview_NERC_FERC_LTRA_Workshop_FINAL_81007.pdf), A Vision 

of The Next Interstate (www.nerc.com/docs/pc/ras/NERC_2008_LTRA_WS_30-31July08_presentations.zip ), and WECC’s 

Transmission Expansion Planning Policy Committee (http://www.wecc.biz/documents/library/board/TEPPC/TEPPC%20Charter.pdf) 28 NERC expects to issue a special report in December 2008 on the reliability requirements for integrating variable generation 

into the bulk power system. 
Key Findings 2008-2017 

18 2008 Long-Term Reliability Assessment 

4. Demand Response Increasingly Used to Meet Resource Adequacy 

Requirements 

Demand response programs increased significantly in this year's projections. The long-term 

sustainability of these impacts will need to be monitored closely as these programs are used to 

meet reliability requirements more frequently. 

Significant increases in demand response programs over the next ten years are projected to 

reduce growth in demand and provide ancillary services across North America. As shown in 

Figure 7, Capacity Demand Response,29 as a percentage of demand, is increasing in FRCC (over 

6% of demand) and NPCC (up to 4% of demand). In other regions, the ratio of demand response 

to demand declines somewhat, as demand response additions do not quite keep pace with 

demand growth. Though a suitable comparison to last year’s report measuring relative gains is 

not possible due to improvements in NERC’s data collection, these figures are both significant 

and encouraging. 

Figure 7: Capacity Demand Response as a % of Summer Peak Demand 

0.0%

1.0%

2.0%

3.0%

4.0%

5.0%

6.0%

7.0%

2008 2017 2008 2017 2008 2017 2008 2017 2008 2017 2008 2017 2008 2017 2008 2017

ERCOT FRCC MRO NPCC RFC SERC SPP WECC

% of Total Internal Demand

0.0%

1.0%

2.0%

3.0%

4.0%

5.0%

6.0%

7.0%

Total Capacity Demand Response Direct Control Load Management

Contractually Interruptible (Curtailable) Critical Peak-Pricing with Control

Load as a Capacity Resource

The total NERC-wide Capacity Demand Response for summer peak demand reduction grows 

from 29,000 MW in the summer of 2008 to 32,500 MW in the summer of 2017. Figure 8 shows 

the projected increases in dispatchable demand response by region. 

 

 

29 See the Capacity, Demand and Event Definitions Section of this report for detailed definitions of demand response. 
Key Findings 2008-2017 

19 2008 Long-Term Reliability Assessment 

Figure 8: Capacity Demand Response (MW) - 10 Year Projection 

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

2008 2017 2008 2017 2008 2017 2008 2017 2008 2017 2008 2017 2008 2017 2008 2017

ERCOT FRCC MRO NPCC RFC SERC SPP WECC

MW

Total Capacity Demand Response Direct Control Load Management

Contractually Interruptible (Curtailable) Critical Peak-Pricing with Control

Load as a Capacity Resource

The total NERC-wide demand response used for Ancillary Demand Response during the summer 

peak remains about constant at 4,400 MW. NERC regional comparison is shown in Figure 9. 

Figure 9: Ancillary Demand Response (MW) - 10 Year Projection

0

200

400

600

800

1,000

1,200

1,400

2008 2017 2008 2017 2008 2017 2008 2017 2008 2017 2008 2017 2008 2017 2008 2017

ERCOT FRCC MRO NPCC RFC SERC SPP WECC

MW

Spinning Reserves Non-Spinning Reserves Emergency Regulation
Key Findings 2008-2017 

20 2008 Long-Term Reliability Assessment Dr

Drivers

Federal, state, and provincial policy makers and regulators are increasingly interested in 

improving the overall availability and efficiency of demand response resources to help address 

climate change issues.

30 In addition, the electric industry is increasingly using demand response 

as an effective and efficient capacity resource, on equal footing with generation. In areas with 

structured markets, for example, demand response resources are now allowed to enter capacity 

markets, either through curtailment service providers or directly from individual customers. 

Several state commissions are also considering ways to earn a rate of return on demand response 

investments similar to new build generation. Florida’s commission, for example, has had such a 

mechanism in place for a number of years which has supported the high adoption of the resource 

in the state.

Reliability Impacts 

Demand response will become a critical resource for maintaining system reliability over the next 

ten years. Though demand continues to grow, new development of supply-side options are 

becoming increasingly limited – many coal plants have been deferred or cancelled, nuclear plants 

are becoming more and more expensive, and transmission lines increasingly difficult to site. 

Further, demand response also has an important role to play as more variable resources (such as 

wind) are added to the system. Variable resources, for example wind generation, often need a 

“dance partner” which can provide operational flexibility to maintain reliability during resource 

down-ramps that can be associated with them. Demand response can provide all or a portion of 

the flexibility required for this integration. 

 As demand response is relied upon more heavily to meet firm demand in these capacities, 

however, more coordination between demand response programs, system operators, and system 

planners is needed to fully assess the resource’s availability, characteristics, and constraints. For 

example, as dispatchable demand response programs are increasingly used as non-emergency 

resources, the probability and frequency of their dispatch will also likely increase. Voluntary 

participation in these programs may decline as a result of this higher usage, causing the program 

to suffer “response fatigue.” If this occurs, system reliability could be affected as other resources 

may not be built or available in time to provide the ancillary services or energy required. In many 

cases, dispatchable demand response resources have not yet been tested to meet system 

reliability requirements at these potentially higher dispatch frequencies. 

Conclusions and Recommendations 

• Additional demand-side resources could be an effective option to preserve system reliability 

over the next ten years. In addition, they may facilitate the integration of renewable and 

variable resources. 

• Potential reliability impacts of broad-scale use of demand response resources must be better 

understood by industry and regulators. 

• Better measurement and verification techniques will be needed to measure and track actual 

availability of demand response under various system conditions. 

 

30 Some examples of Federal, State and Provincial activities can be found in the following reports: 

http://www.ferc.gov/legal/staff-reports/demand-response.pdf, http://www.ferc.gov/legal/staff-reports/09-07-demand-response.pdf, 

http://www.powerauthority.on.ca/Page.asp?PageID=924&SiteNodeID=320 & 

http://www.narucmeetings.org/Presentations/National%20Action%20Plan%20on%20Demand%20Response%20-%20NARUCR3.pdf 
Key Findings 2008-2017 

21 2008 Long-Term Reliability Assessment ΝΕΡΧ

NERC Actions

Anticipating the growth in demand response as part of the seasonal and long-term reliability 

assessments, the NERC Planning Committee, in coordination with the North American 

Energy Standards Board (NAESB), initiated two activities: 

1. Develop and maintain a categorization scheme while collecting projected information.31

2. Design and implement a demand response event analysis system.32

The recommendations from the first activity were approved by the NERC Planning 

Committee and results included in this report. The Demand Response Data Task Force was 

formed by the Planning Committee in order to measure and validate demand response event 

data and evaluate potential reliability concerns. The demand response event data collection 

scheme and report are to be completed in early 2009.

 

31 http://www.nerc.com/docs/pc/drdtf/NERC_DSMTF_Report_040308.pdf 32 http://www.nerc.com/filez/drdtf.html 
Key Findings 2008-2017 

22 2008 Long-Term Reliability Assessment 

5. Bulk Power System Adequacy Trends Emphasize Maintenance, Tools and 

Training 

NERC performed its initial analysis of reliability metrics from the last six years and concluded 

that the drive towards suitable maintenance, operating tools and training must continue. It is 

vital that these metrics be further refined and the trends analyzed so that root causes can be 

addressed. 

There are two basic, functional components of bulk power system reliability: operating reliability 

and adequacy.33 NERC has developed preliminary metrics measuring bulk power system 

reliability and, though these metrics require further refinement for future reliability assessments 

and are primarily limited to the Eastern Interconnection34, they can provide valuable insights for 

root cause analysis and bulk power system planning goals. 35 

For example, Energy Emergency Alerts, shown in Figure 10, are issued when electricity supplies 

in a given area become insufficient to serve demand, remain high in the Eastern Interconnection 

during the last six years. In 2007, there were 20 occasions when firm customer load interruption 

was imminent or in progress (Category A3).36

Figure 10: Number of Energy Emergency Alerts by Year (2002-2007) 

 

Figure 26: Number of Energy Emergency Alerts 

by Year (2002-2007)

0

20

40

60

80

100

120

140

2002 2003 2004 2005 2006 2007

A1

A2

A3

 

33 See the Capacity, Demand and Event Definitions Section 34 http://en.wikipedia.org/wiki/Eastern_Interconnection 35 This is the inaugural year for incorporating reliability metrics in the Long-Term Reliability Assessment. Available data for this 

assessment is solely from the Eastern Interconnection. 36 The current definition for Category A2 includes the operation of demand-side resources as a capacity and emergency event, 

while current industry practice includes the resource as part of normal, non-emergency operations. The categories for capacity 

and emergency events based on Standard EOP-002-0, therefore, require revision to account for higher use of demand response 

as a capacity and ancillary resource. See http://www.nerc.com/docs/pc/drdtf/NERC_DSMTF_Report_040308.pdf, entitled, 

“Data Collection for Demand-Side Management for Quantifying its Influence on Reliability: Results and Recommendation” as 

well as the Capacity Demand and Event Definitions section of this report for NERC’s demand-side management definitions 

and categorization. 

Category A1: No disturbance 

events and all available resources 

in use. 

a. Required Operating Reserves 

can not be sustained. 

b. Non-firm wholesale energy 

sales have been curtailed. 

Category A2: Load management 

procedures in effect. 

a. Public appeals to reduce 

demand. 

b. Voltage reduction. 

c. Interruption of non-firm end 

use loads per contracts. 

d. Demand-side management. 

e. Utility load conservation 

measures. 

Category A3: Firm load 

interruption imminent or in 

progress.
Key Findings 2008-2017 

23 2008 Long-Term Reliability Assessment 

One measure of bulk transmission congestion, used in parts of the Eastern Interconnection of 

North America, is Transmission Loading Relief (TLR) requests, which have increased during the 

last six years. In some cases, the over-scheduling of electricity transactions requires the issuance 

of TLRs, which is how system operators maintain system loadings within reliability limits. 

Reallocation and curtailment of bulk transmission service to meet System Operating Limits and 

Interconnection Reliability Operating Limits are increasing (See Figure 11).37

38

 Figure 11: TLR's Level 5b: 2002 - Sep 2008 

0

10

20

30

40

50

60

70

2002

2003

2004

2005

2006

2007

2008(Jan-Sep)

# of Incidents

SWPP

TVA

PJM

MISO

ICTE

38

While TLR actions in and of themselves do not directly indicate a lowering of reliability, their 

higher use of these requests by some regional coordinators such as Interdependent Coordinator 

of Transmission for Entergy (ICTE), Southwest Power Pool (SWPP) and the Midwest 

Independent Service Operator (MISO) requires further investigation. It is necessary to 

understand the drivers behind this perceived transmission congestion to determine if it represents 

a reliability or economic issue. If it is increasing because the transmission system is being fully 

used to optimize economic dispatch, congestion may not impact bulk power system reliability. If 

congestion is occurring because needed transmission capacity is not available to serve firm load, 

then this may be an indicator of reliability concerns. 

Application of TLR represents one method used in the Eastern Interconnection to relieve 

potential or actual loading. However, differences exist on how areas approach congestion 

management. For example, WECC uses an Unscheduled Flow Mitigation Plan as an equivalent 

load relief procedure for use in the Western Interconnection.39 In market structures, redispatch is 

 

37 See the Operational Reliability Section 38 SPP implemented its Energy Imbalance Market (EIS) on February 1, 2007. Since the implementation of the EIS Market, SPP 

has experienced an increase in the number of TLR events primarily due to its operating protocols. SPP’s market protocols 

require that the SPP Reliability Coordinator issue a TLR event every time congestion is experienced in the market footprint. 39 This procedure has been accepted by FERC and adopted by NERC Standards: http://www.nerc.com/files/IRO-STD-006-0.pdf. 

WECC USFMP: http://www.wecc.biz/documents/library/UFAS/UFAS_mitigation_plan_rev_2001-clean_8-8-03.pdf 
Key Findings 2008-2017 

24 2008 Long-Term Reliability Assessment 

commonly used as an efficient measure to reduce congestion in transmission systems. MISO40

and PJM41 have Locational Marginal Pricing (LMP) markets which run a security constrained 

dispatch models to determine the lowest cost generation dispatch without exceeding transmission 

limitations. Similarly, ERCOT employs a flow-based/zonal approach to manage forward markets 

and congestion.42

Drivers 

Building and operating infrastructure to meet growing demand remains a challenge. Therefore, 

the industry has developed new operational approaches to effectively use existing bulk power 

system assets. These actions can reduce the bulk power system’s ability to withstand unexpected 

system outages. To maintain reliability, the industry has improved maintenance practices, 

developed new operational tools and reinforced operator training. 

Recognizing the need to measure reliability trends, NERC’s Planning and Operating Committees 

jointly organized the Reliability Metrics Working Group (RMWG) to develop and improve 

reliability metrics. Specific activities will include: 

o Development of general metrics for the characteristics of an Adequate Level of 

Reliability 

o Definition of reliability measures, including formulae or methods for their calculation 

o Identification of data collection and reporting guidelines 

o Recommend root cause analysis 

Conclusions and Recommendations 

• Industry must continue to emphasize the importance of bulk power system maintenance, new 

tools and well-trained operators. 

NERC Actions 

• Support the RWMG’s activities to study and improve upon historical reliability metrics and 

trends. Specifically, this group should focus on expanding this analysis beyond the Eastern 

Interconnection. In addition, support root cause analysis of trends in the number of TLRs and 

other similar mechanisms. 

• NERC should revise its Emergency Preparedness and Operations Standard EOP-002-0 

removing demand-side management as a characteristic for identifying an Energy Emergency 

Event (i.e. Category A2). 

 

40 More information on MISO’s congestion management procedures can be found in the 2007 STATE OF THE MARKET 

REPORT FOR THE MIDWEST ISO at: http://www.midwestiso.org/publish/Document/24743f_11ad9f8f05b_-

7b890a48324a/2007%20MISO%20SOM%20Report_Final%20Text.pdf?action=download&_property=Attachment 41 PJM’s congestion management procedures can be found in the 2007 STATE OF THE MARKET REPORT FOR THE PJM 

INTERCONNECTION at http://www2.pjm.com/markets/market-monitor/downloads/mmu-reports/2007-som-volume2-sec7.pdf 42 ERCOT’s congestion management procedures, entitled 2007 STATE OF THE MARKET REPORT FOR THE ERCOT 

WHOLESALE ELECTRICITY MARKETS http://www.puc.state.tx.us/wmo/documents/annual_reports/2007annualreport.pdf 
Emerging Issues & Scenario Analysis 

25 2008 Long-Term Reliability Assessment 

Emerging Issue Assessment & Scenario Analysis 

Each year, the 10-year Long-Term Reliability Assessment (LTRA) forms the basis for the NERC

reference case. This reference case incorporates known policy/regulation changes expected to 

take effect throughout the ten-year timeframe assuming a variety of factors such as economic 

growth, weather patterns and system equipment behavior. Risk assessment and study of 

emerging reliability issues can identify a set of scenarios which may require deeper analysis. 

Once complete, these scenarios can then be compared to the reference case to measure any 

significant changes in bulk power system reliability. 

Emerging Issue Risk Assessment 

Background - Risk assessment of emerging issues measures their perceived likelihood and 

potential consequences. To qualify for consideration, emerging issues must affect bulk power 

system reliability based on the following criteria: 1) Exists for more than a single year in the 

LTRA ten-year study period, 2) Impacts reliability no sooner than three years into the future to 

allow sufficient time for analysis, and 3) Impacts the reliability across at least one regional 

footprint and is not a local or sub-regional reliability issue. 

NERC’s Reliability Assessment Subcommittee and staff identified seven emerging issues for use 

in the Planning Committee’s (PC) Risk Assessment: 

1. Greenhouse gas reductions 

2. Fuel storage and transportation 

3. Rising global demand for energy and equipment, increased off-shore manufacturing of raw 

and finished materials 

4. Increased adoption of demand-side and distributed generation resources 

5. Replacing, upgrading and adding transmission infrastructure for the 21st century, including 

enhance cyber security protections 

6. Water availability and use 

7. Mercury emissions regulations 

Risk Assessment – After endorsing the aforementioned emerging issues, the PC prioritized the 

resulting emerging issues based on risk, defined as their likelihood and consequence, and 

categorized each issue as high, medium, or low. This risk assessment was performed for two 

timeframes: 1-5 years and 6-10 years. 
Emerging Issues & Scenario Analysis 

26 2008 Long-Term Reliability Assessment 

Ranking and Risk Evolution - The risk assessment survey was completed by industry 

stakeholders represented on the NERC Planning Committee. Figure 12 below provides the risk 

vectors for the seven emerging issues for the 1-5 year and 6-10 year timeframe. 

Three emerging issues show increased acceleration into the high likelihood and the high 

consequence quadrants: 1) Greenhouse Gas Reductions, 2) Rising Global Demand for Energy & 

Equipment, and 3) Transmission of the 21st Century. None of the seven emerging issues showed 

a decrease in probability or impact in the 6-10 year timeframe. The risk assessment confirmed 

the sentiment of the Reliability Assessment Subcommittee that all seven emerging issues are 

important to NERC and the industry 

Finally, PC members individually identified potential emerging issue gaps, naming seven 

additional concerns not ranked: 1) Plug-in Hybrid Vehicles, 2) Impact of wide-scale transmission 

‘back-bone’ infrastructure, 3) Major Transmission Improvements for new Nuclear Plants, 4) 

Increasing Use of Special Protection Systems to avoid transmission construction, 5) Once 

through cooling limitations, 6) Hydroelectric dam removal, and 7) Air emissions and offset 

regulations. These issues may be explored in more detail in future reliability assessments. 

Figure 12: Emerging Issues Risk Evolution: 

1-5 Year & 6-10 Years 

Greenhouse Gas 

Reductions

Fuel Storage & 

Transport

Rising Global 

Demand for Energy 

& Equipment

Increasing 

adoption of 

demand-side and 

distributed 

generation 

resources

Transmission of the 

21st century

Limited Water 

Availability

Mercury Regulation

Consequence

Likelihood

High

High Low

1-5 Years

 6-10 Years
Emerging Issues & Scenario Analysis 

27 2008 Long-Term Reliability Assessment 

Descriptions and reliability considerations for each of the emerging issues are discussed below. 

A broader view of environmental regulation impacts was added to place the air and water issues 

into perspective. 

They are grouped as: 

• Potential Environmental Regulation Could Impact Resource Adequacy 

- Greenhouse Gas Reductions 

- U.S. Clean Water Act: Cooling-Water Intake Structures 

- U.S. Clean Air Act: Interstate Rule and Mercury Rule 

• Fuel Transportation and Storage 

• Rising global demand for energy & equipment, increased off-shore manufacturing of raw & 

finished materials 

• Increased adoption of demand-side and distributed generation resources 

• Replacing, upgrading and adding transmission infrastructure for the 21st century, including 

enhanced cyber security protections 

• Water availability and use 

Finally, a status report of the Scenario Analysis for the 2009 LTRA is discussed in this section. 
Emerging Issues & Scenario Analysis 

28 2008 Long-Term Reliability Assessment 

Figure 13: Snapshot of Renewable Portfolio 

Standards (RPS) in the U.S. 

Potential Environmental Regulation could Impact Resource Adequacy 

A number of ongoing environmentally-driven regulatory issues could, in sum, have a significant 

effect on resource adequacy in the U.S., namely Greenhouse Gas Reductions and climate change 

initiatives, the U.S. Clean Water Act: Cooling Water Intake Structures43 and the U.S. Clean Air 

Act: Interstate and Mercury Rules. Understanding the reliability implications of potential 

legislation and regulations is vital to ensuring that the bulk power system remains reliable 

during and after implementation. 

Greenhouse Gas Reductions 

Background: The drive to reduce 

greenhouse gas emissions is gaining 

momentum throughout North America. 

Regulations such as Renewable Portfolio 

Standards are being promulgated by 

individual states and provinces, with 

over thirty states adopting similar 

regulations44 (Figure 1345). 

In 2006, coal provided almost 50% of 

the electric energy production46 in the 

US and approximately 20% in Canada47

in 2003. Natural gas is the cleanest fossil 

fuel in terms of air quality and carbon 

emissions, emitting up to 60 percent less 

carbon dioxide than coal. However, the 

magnitude of these benefits depends on the source of the natural gas and other factors, such as 

plant efficiency. Burning natural gas instead of coal at electricity-generating units to reduce 

greenhouse gas emissions involves important tradeoffs related to economic, environmental, 

infrastructure, and fuel supply considerations. Converting existing capacity to natural gas poses 

substantial challenges due to fuel supply constraints, changes to infrastructure, and economic 

considerations. 48

The prospect for federal regulation in the U.S. continues to grow as numerous climate change 

bills are proposed in the House and Senate. A recent United States Supreme Court decision49

determined that greenhouse gases regulation could fall under the purview of the U.S. 

Environmental Protection Agency (EPA). The U.S. EPA is inviting comment from all interested 

parties on options and questions to be considered for possible greenhouse gas regulations under 

 

43 http://www.catf.us/advocacy/legal/CWIS/RiverkeepervEPA%20P2%2004-6692-ag_opn.pdf 44 http://www.pewclimate.org/what_s_being_done/in_the_states/rps.cfm or more detailed resource maps at: 

http://www.pewclimate.org/what_s_being_done/in_the_states/nrel_renewables_maps.cfm 45 The Florida Public Service Commission (FPSC) Renewable Portfolio Standard is currently under development 46 http://www.eia.doe.gov/cneaf/electricity/epa/epat1p1.html 47 http://www.canelect.ca/en/Pdfs/HandBook.pdf 48 http://www.gao.gov/new.items/d08601r.pdf 49 http://www.supremecourtus.gov/opinions/06pdf/05-1120.pdf 
Emerging Issues & Scenario Analysis 

29 2008 Long-Term Reliability Assessment 

the Clean Air Act. EPA has issued an advance notice of proposed rulemaking (ANOPR) to 

gather information and determine how to proceed.50

To lay the foundation for future action, NERC gathered stakeholder perspectives on this issue, 

asking them to identify potential impacts climate change initiatives may have on bulk power 

system reliability. NERC will be issuing a special report on these findings in the coming 

weeks.51

U.S. Clean Water Act: Cooling-Water Intake Structures 

Background: Some thermal (coal, nuclear and gas) generation plants use substantial volumes of 

cooling water and are located on large water bodies or high flow-rate rivers. Many of these 

facilities currently use once-through cooling systems: drawing large volumes of water from the 

ocean, lake, or river to cool plant equipment and returning the used, warmer water back into the 

body of water immediately after use. 

 

Section 316(b) of the Federal Water Pollution Control Act (FWPCA), more commonly known as 

the Clean Water Act, regulates thermal discharges to the surface waters in the U.S. The 

temperature of the water discharged to the receiving water body must be kept at a level such that 

thermal discharges do not adversely affect wildlife in and on that water body, commonly 

accomplished by dilution. 

Thermal generation is impacted by two of the three phases promulgated by EPA 316(b): 

• Phase I set standards for cooling water intake structures at new facilities. 

• Phase II set standards for existing power plants.52 

Phase II regulations required that large existing power plants withdrawing 50 million gallons per 

day or more and using at least 25 percent of the water withdrawn for cooling purposes must 

comply with requirements to minimize impingement and entrainment of aquatic life in the water 

intake structures. In 2004, the final rule provided several compliance alternatives. Based on a 

January 2007 decision by the Second U.S. Circuit Court of Appeals, EPA suspended its Phase II 

implementation53 and is considering a new rulemaking. Those units with once-through cooling 

systems may be required to retrofit with closed loop cooling systems. The cost of such retrofits 

may result in some units retiring earlier than expected. Further, for plant retrofitting, there is an 

ancillary load required to serve the closed-loop cooling equipment, resulting in a de-rating of the 

unit’s net output capability. 

 

 

50 http://www.epa.gov/climatechange/anpr.html 51 See www.nerc.com 52 http://www.epa.gov/waterscience/316b/phase2/devdoc/ 53 http://www.epa.gov/waterscience/316b/phase2/implementation-200703.pdf

†

 Adjusted Potential Resource Margins are subject to change, as updated capacity information is expected. 

‡ Adjusted Potential Resources for WECC US include the AZ-NM-SNV subregion (approx. 37,000 MW). However, this 

subregion was unaffected in the NERC Special Reliability Assessment. 
Emerging Issues & Scenario Analysis 

30 2008 Long-Term Reliability Assessment 

Reliability Considerations: 

In conjunction with the U.S. 

Department of Energy’s 

(DOE) Office of Electricity 

Delivery and Energy 

Reliability and Office of 

Fossil Energy, NERC 

completed a Special 

Reliability Assessment 

measuring the Adjusted 

Potential Resource Capacity 

Margin implications of 

Section 316(b) Phase II 

rules.54 DOE provided 

NERC a listing of vulnerable 

units (totaling approximately 

240 Gigawatts). This 

information was 

supplemented by identifying 

those units that were expected to retire during the study time frame, along with permitting dates. 

Summer peak capacity margins and demand data from the 2008-2017 Long-Term Reliability 

Assessment were used to establish a Reference Case. To reflect the potential EPA rulemaking 

timeframe, the summer peak Adjusted Potential Resource Capacity Margins for 2012 through 

2015 were compared to the capacity margin impacts with assumed unit retirements and ancillary 

load increases. 

NERC reviewed the impact of 

either retrofitting units with 

existing once-through-cooling 

systems to closed-loop cooling 

systems (4% reduction in 

nameplate capacity) or unit 

retirements (capacity factors less 

than 35 percent) on NERC-US 

and regional capacity margins for 

2012-2015. Based on a worst 

case view, NERC-U.S. Adjusted 

Potential Resources may be 

reduced by over 48,000 MW, 

approximately 39,000 MW due 

to retirements and 9,000 MW 

due to increased unit auxiliary 

loads. This reduction has the 

effect of lowering the Adjusted 

Potential Resource Capacity Margin by 4.3 percent (see Figures 14 & 15). 

 

54 See http://www.nerc.com/files/NERC_SRA-Retrofit_of_Once-Through_Generation_090908.pdf for details and assumptions 

Figure 14: NERC US - Cooling Tower Retrofit Effects

Change in Adjusted Potential Resource Margin

Summer Peak Demand

0%

5%

10%

15%

20%

25%

2013 2014 2015

Margin (%)

Adjusted Potential Resources Margin

Reduced Adjusted Potential Resource Margin

NERC Reference Margin Level

4.3 percent reduction 

in the Adjusted 

Potential Resources 

Capacity Margin

Figure 15: NERC US - Cooling Tower Retrofit Effects on 

Adjusted Potential Resources

Summer Peak Demand

0

10,000

20,000

30,000

40,000

50,000

60,000

2013 2014 2015

ΔMW

0.0%

1.0%

2.0%

3.0%

4.0%

5.0%

Reduction of

Adjusted Potential 

Resources Margin 

Derate Effects

Retirement Effects

Total Capacity Reduction

% of Margin Lost due to Retirements and Derate Effects
Emerging Issues & Scenario Analysis 

31 2008 Long-Term Reliability Assessment 

Figure 16: CAIR Coverage in the U.S. 

Table 4 indicates the 2015 

summer peak capacity 

margin reductions for each 

of the affected NERC-U.S. 

regions/subregions. The 

most significant reductions 

in capacity margin occur in 

California, ERCOT, New 

England, and the Delta 

Subregion of SERC, with 

each of these areas 

experiencing more than a 

10 percent reduction in 

their capacity margins. 

These regions may require 

additional resources to 

accommodate the potential 

retirements/retrofits from 

the Section 316(b) Phase II 

action. 

These capacity reductions 

could also result in 

additional transmission 

congestion. Detailed 

system transmission studies 

may be needed to 

determine the full extent of 

bulk power system 

reliability impacts resulting from the reduction of this significant amount of generating capacity. 

U.S. Clean Air Interstate Rule (CAIR) and Clean Air Mercury Rule (CAMR) 

Two Clean Air Rules have the potential to 

impact capacity margins in the U.S. It is 

vital to understand potential plant retirements, 

ancillary demands of retrofit equipment and 

impact on bulk power transmission to fully 

understand the potential reliability impacts. 

Background: The U.S. EPA issued the Clean 

Air Interstate Rule (CAIR) in March 2005. 

CAIR is meant to reduce ground-level ozone 

and/or fine particles that might migrate across 

state boundaries. The Clean Air Interstate 

Rule covered 28 eastern states and 

 Table 4: 2015 Summer Peak Capacity Margin Reductions

Adjusted 

Potential 

Resources 

(MW)

Reduction 

due to 

Retirement 

(MW) 

Derate 

due to 

Retrofit 

(MW) 

 NERC 

Reference 

Margin 

Level 

 Adjusted 

Potential 

Resources 

Margin 

 Margin 

Reduction 

Reduced 

Margin 

United States

WECC - CA-MX US† 72,293 10,137 289 13.2% 12.7% 14.7% -2.0%

NPCC - New England 31,673 2,827 428 13.0% 10.0% 10.3% -0.3%

ERCOT 86,436 10,919 542 11.1% 15.9% 12.9% 3.0%

NPCC US 72,750 6,481 990 13.0% 13.3% 9.9% 3.4%

WECC US† ‡ 176,944 10,177 314 12.3% 11.1% 5.6% 5.5%

NPCC - New York 41,077 3,654 561 13.0% 15.9% 9.6% 6.3%

SERC - VACAR 78,182 553 1,032 13.0% 11.0% 1.8% 9.2%

WECC - RMPA† 15,609 40 0 10.5% 10.2% 0.2% 10.0%

SERC - Central 54,548 0 949 13.0% 12.6% 1.5% 11.0%

SERC - Delta 41,259 4,266 466 13.0% 21.5% 10.2% 11.4%

RFC 230,062 3,339 2,863 12.8% 14.5% 2.4% 12.1%

SERC 269,599 6,054 3,307 13.0% 15.6% 3.0% 12.5%

SERC - Southeastern 66,675 675 357 13.0% 13.9% 1.4% 12.6%

MRO US 55,582 529 612 13.0% 15.1% 1.8% 13.3%

FRCC 63,170 1,267 454 13.0% 18.7% 2.3% 16.4%

WECC - NWPP† 51,861 0 25 11.9% 16.9% 0.0% 16.8%

SPP 63,700 817 257 12.0% 24.1% 1.3% 22.8%

SERC - Gatew ay 28,935 560 502 13.0% 28.8% 2.7% 26.1%

Total - NERC US 1,018,243 39,583 9,339 13.0% 14.7% 4.3% 10.4%
Emerging Issues & Scenario Analysis 

32 2008 Long-Term Reliability Assessment 

Washington D.C.55 (see Figure 16). CAIR permanently placed a cap on emissions of sulfur 

dioxide (SO2) and nitrogen oxides (NOx) in the eastern U.S. by using an interstate cap and trade 

program deployed only in those states covered by the interstate mechanism. 

In July, 2008, the U.S. Court of Appeals voided the current version of the CAIR and remanded it 

back to EPA56, noting that their approach – region wide caps with no state specific quantitative 

contribution determinations or emission requirements – was flawed and required EPA to redo its 

analysis. The court also agreed that EPA must tailor pollution cuts in upwind states with the level 

of impacts on downwind jurisdictions. EPA is reviewing the Court's decisions and evaluating its 

impacts. 

Closely related to CAIR, the EPA Clean Air Mercury Rule (CAMR) requires coal-fired plants to 

reduce their emissions of mercury. In December 2000, the U.S. EPA issued a “regulatory 

determination” under the 1990 Clean Air Act Amendments that regulation of mercury is 

“appropriate and necessary” for coal- and oil-fired power plants. Title III of the Amendments 

introduced the Maximum Achievable Control Technology (MACT) standard as a level of control. In 

March 2005, EPA issued its final Clean Air Mercury Rule (CAMR) for coal-based power plants. 

The CAMR used a market-based cap-and-trade approach to require emissions reductions in two 

phases: a cap of 38 tons in 2010, and 15 tons after 2018, for a total reduction of 70 percent from 

current levels. Facilities would have to demonstrate compliance with the standard by holding one 

"allowance" for each ounce of mercury emitted in any given year. In the final rule, EPA stated 

that regulation of nickel emissions from oil-based plants is not "appropriate and necessary." 

In February 2008, the U.S. Court of Appeals for the District of Columbia Circuit issued an 

opinion in a case, which was initiated by 15 states and other groups, challenging the CAMR and 

EPA's decision to "de-list" mercury as a hazardous air pollutant. The Court held that EPA's 

reversal of the December 2000 regulatory finding was unlawful57. The Court vacated both the 

reversal and the CAMR, and sent the CAMR back to EPA for reconsideration. As a result of the 

Court's decision, it is likely that EPA will develop a MACT standard, which would require every 

oil- and coal-based power plant to install mercury-specific controls. 

A new EPA rulemaking could take several years to finalize and might not require emission 

reductions for more than five years. In the meantime, states are also developing their own 

Mercury standards that are at least as stringent as the EPA MACT standard. 

Reliability Considerations: Much like meeting the requirements of Section 316(b) of the Clean 

Water Act mentioned above, compliance with CAIR and CAMR may require the owners of 

existing plants to face economic decisions to: 

- Retire plants earlier than expected. 

- Retrofit plants, which can increase ancillary loads

In either case, capacity margins would be reduced, increasing the need for more resources to 

meet resource adequacy requirements. 

 

55 http://www.epa.gov/cair/index.html 56 http://www.epa.gov/cair/pdfs/05-1244-1127017.pdf 57 http://pacer.cadc.uscourts.gov/docs/common/opinions/200802/05-1097a.pdf 
Emerging Issues & Scenario Analysis 

33 2008 Long-Term Reliability Assessment 

Fuel Transportation & Storage 

The interdependence of the electric, gas, coal, and – to an extent – oil industries will continue to 

play a role in the adequacy of electricity supply in North America. 

Background: The physical capacity for natural gas transportation and storage is emerging as an 

issue with greater potential implications for the adequacy of electricity supply than in recent 

years due to the increasing concerns regarding global warming and the increasing likelihood of 

legislation to reduce CO2 emissions. Such legislation could create incentives for the construction 

of more new natural gas-fired capacity as a “bridging” technology to displace energy from 

existing coal-fired generation until new low-carbon electricity production technologies become 

commercially viable. The drivers toward a carbon-constrained future focus this discussion on 

natural gas transportation and storage as a potential weak reliability link associated with 

significant increases in gas-fired generation. 

In 2006, natural gas-fired generation produced 20% of the electricity in the United States while 

representing 41% of the installed summer generating capacity. Coal-fired generation produced 

49% of the electrical energy in North America and represented 32% of the installed summer 

capacity. Heavy and light oil is primarily used as a back-up fuel for natural gas. Oil-only fired 

capacity is negligible and total oil generation represented less than 2% of the electricity produced 

in 2006.58

Transportation and storage for coal, residual oil and distillate fuel oils have not been, nor are 

expected to be, an electric power reliability concern, as explained below.

• One significant disruption in rail transportation occurred in 2005 for the delivery of coal 

from the Powder River Basin (PRB), a region in southeast Montana and northwest 

Wyoming. The coal in this region has low sulfur and low ash content, and about 40% of 

the coal used in power plants at that time came from the PRB. Coal from the region is 

moved on a single rail system comprising three tracks that are jointly owned by the 

Union Pacific and Burlington Northern Santa Fe railroads. In 2006, the joint owners of 

the PRB rail system received the required approvals to add a fourth track. 

• While fuel inventories at some coal plants reached extremely low levels in 2005, the PRB 

delivery disruptions did not impact electric reliability. Many utilities, however, did incur 

higher costs for the use of alternative fuels. 

• Despite the 2005 PRB coal delivery disruption, the reliability aspects of coal 

transportation and storage are generally excellent.59

Residual (heavy) and distillate (light) oil are typically delivered by barge to power plants located 

along the Atlantic and Pacific coasts. Supply disruptions have not occurred in recent decades 

and the reliance on these fuels has dropped significantly since the repeal of both the Natural Gas 

Policy Act of 1978 and the Power Plant and Industrial Fuel Use Act of 1979 which eliminated 

the prohibitions against the significant use of natural gas as an electricity sector fuel. 

 

58 http://www.eia.doe.gov/cneaf/electricity/epa/epat1p1.html 59 Note that Midwest U.S. experienced severe flooding in 2008, and this caused fuel transportation delays, primarily with 

delivery of coal by rail. This year’s floods are being compared to the 1993 floods. Both are either 100 or 500 year occurrences 

that have occurred within 15 years. It is too early to conclude that flooding is an emerging issue that needs to be considered.
Emerging Issues & Scenario Analysis 

34 2008 Long-Term Reliability Assessment 

Hydro is another primary energy source that can influence the adequacy of electricity supply. For 

areas that are heavily dependent upon hydro-electric generation, it has been observed that 

droughts can create severe strains on alternative fossil fuel resources and delivery infrastructure 

that may either not be robust or which atrophied during periods of favorable hydro conditions. 

The California Energy Crisis of 2001 was largely precipitated by the onset of 

drought conditions in the Pacific Northwest after a decade of relatively high 

hydro conditions. Since California depends on imports from the Northwest to 

satisfy some of its adequacy needs, these drought conditions exerted stress on the 

coal and gas markets and the physical generation and delivery infrastructure. 

The failure of a key natural gas compressor station exacerbated the crisis as did 

the lack of opportunities for maintenance on natural gas-fired facilities and the 

concerns of making and receiving payments for generation in a dysfunctional 

electricity market.60 

 

Natural Gas Transportation: 

The U.S. has several major natural gas production basins61, and an extensive natural gas pipeline 

network. There are also numerous pipeline connections between the United States and Canada, 

and almost 95 percent of U.S. natural gas imports come from Canada. Major connections join 

Texas and northeastern Mexico, with additional connections to Arizona and between Baja 

California, Mexico, and California, U.S. Infrastructure growth in the Baja California region is 

expected.62

A large portion of natural gas 

pipeline capacity within the 

United States is directed from 

major production areas of 

Texas and Louisiana to markets 

in the Western, Northeastern, 

and Midwestern regions of the 

country, as illustrated in Figure 

17. In the past ten years 

increasing levels of gas from 

Canada have targeted these 

markets as well. 

 

60 http://www.eia.doe.gov/pub/oil_gas/natural_gas/analysis_publications/ngpipeline/process.html 61 Excepted from http://www.eia.doe.gov/emeu/northamerica/enginfr2.htm#_VPID_1 62 http://www.eia.doe.gov/emeu/northamerica/fig35.jpg 

Figure 17: U.S. Natural Gas Pipeline 62 
Emerging Issues & Scenario Analysis 

35 2008 Long-Term Reliability Assessment 

Canada has an extensive natural gas pipeline network, including several major interconnections 

with the United States. Alberta is the dominant producer, though Nova Scotia is increasing its 

production. Canada is the world’s second largest natural gas exporter after Russia. Figure 18 

illustrates the pipeline system in Canada. 

Natural gas is delivered by Figure 18: Main Canadian Natural Pipelines63 

pipeline and, unlike electricity 

grids, natural gas pipelines do 

not demand the nearly 

instantaneous balancing of 

injections and withdrawals since 

the pipelines themselves have 

some storage capacity. While 

daily injections and withdrawals 

by customers are monitored by 

pipeline operators, pipelines 

typically have customers “trueup” their BTU injection and 

withdrawal differences 

(“imbalances”) on a monthly 

basis.64 

 

Additional gas storage facilities 

could potentiality mitigate 

electricity adequacy concerns 

due to gas supply or delivery disruptions; however, gas storage facilities are unevenly distributed 

and typically located remote from gas-fired generators. Nearly all of the gas storage facilities in 

the U.S. are in 13 states: Texas, Louisiana, Mississippi, Oklahoma, Kansas, eastern New York, 

eastern Pennsylvania, West Virginia, western Ohio, Illinois, Indiana, eastern Kentucky, and 

southern Michigan. The western U.S has only about 5% of the nearly 400 active storage 

facilities. 

Gas storage is primarily used for two reasons. First, storage is used to take 

advantage of differences in supply and demand for natural gas. Natural gas 

production capability is reduced if extraction is cycled across the seasonal swings 

in gas demand. Therefore, natural gas is largely extracted at a constant rate, and 

storage is used to balance the annual, and inter-annual, variations in natural gas 

consumption. This seasonal imbalance between constant supply and seasonal 

demand produces the seasonal gas price fluctuations which encourage gas to be 

injected into storage when prices are lower and withdrawn when prices are 

higher, as well as to supplement gas well withdrawals during peak use periods. 

Second, storage is used by pipelines as an operational tool to balance pipeline 

supplies and withdrawals and maintain gas pressure.65

 

63 http://www.eia.doe.gov/emeu/northamerica/enginfr2.htm#_VPID_1 64 Pipelines retain 2-3% of the gas injected for pipeline compressor operation. 

65http://www.eia.doe.gov/pub/oil_gas/natural_gas/analysis_publications/storagebasics/storagebasics.html
Emerging Issues & Scenario Analysis 

36 2008 Long-Term Reliability Assessment 

Natural gas is predominately stored at exhausted oil and gas fields, aquifers, or underground salt 

caverns generally distant from power plants. Since stored gas must still use the pipeline system 

for delivery, gas storage does not mitigate electricity supply concerns caused by pipeline 

disruptions. The pipelines and compressor stations are shown below in Figure 19.

Figure 19: Pipelines in the U.S.66

From an electricity supply adequacy perspective, a pipeline incident, whether an accidental break 

or the loss of gas compression, can disrupt the flow of fuel to power plants that are connected to 

that pipeline resulting in the near simultaneous loss of such power plants as line pack runs 

out.67,68 Such an incident could cause switching to alternative fuels, such as distillate fuel oil, 

which may not be available in the quantities needed for an extended timeframe to replace the lost 

natural gas, or may be limited by environmental restrictions. 

Reliability Considerations - Disruptions of gas flow from wells, as illustrated in the Sable 

Island incident described below, whether caused by severe weather or equipment failure, are also 

a potential electricity supply adequacy issue. Since the impact of the loss of gas wells can be the 

same as the loss of gas pipeline capacity, strategies that address the loss of pipeline capacity can 

also address the loss of supply from gas wells. 

 

66 http://www.eia.doe.gov/pub/oil_gas/natural_gas/analysis_publications/ngpipeline/images/compressorMap.gif 67 In the U.S, pipeline safety is regulated by the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety 

Administration (PHMSA). 68 Recently, a 5+ magnitude earthquake occurred in southern Illinois near the Indiana border. Many state and local government 

agencies began reviewing earthquake preparedness plans. Gas pipelines may be at risk of rupture due to a severe earthquake. 
Emerging Issues & Scenario Analysis 

37 2008 Long-Term Reliability Assessment 

On Friday, November 30, 2007, a mechanical component failure at the Sable 

Offshore Energy Project (Sable Island) located off the Nova Scotia coast resulted 

in a significant loss of natural gas supply injections into the Maritimes & 

Northeast (M&N)69 pipeline. By Saturday, December 1, this loss of gas supply 

finally impacted northern New England gas-fired generating resources. This 

event resulted in electric capacity deficiencies in the state of Maine. The capacity 

deficiency in Maine led to a Power Watch declaration of Emergency Operating 

Procedures (EOPs)70 and consumers of electricity were requested to reduce 

electricity use. During this event, both Central Maine Power and ISO-NE 

coordinated remedial efforts to ensure system reliability. No electric load was 

shed within the region and electric sector operations eventually returned to 

normal in two days. 

There are differences in the way fuel transportation and transmission services are sold. “Firm” 

and “non-firm” mean different things in the fuel transportation business when compared to the 

electric transmission business, and these differences need to be understood and considered.   As 

an example, no market or Balancing Authority would consider a supply as “firm” if its electric 

Transmission Service is contracted as “non-firm” under a Transmission Provider’s tariff. Yet 

many organized markets and Balancing Authorities would consider a supply as “firm” if it has 

Firm Transmission Service even though its natural gas fuel delivery is contracted as “non-firm” 

under a natural gas pipeline’s tariff and it has no back-up oil fuel. The reliability aspects of such 

gas transportation arrangements are more definitive than the distinction implied by “firm” or 

“non-firm” delivery categories. Several factors could make non-firm gas deliveries acceptable 

from a reliability perspective. These include: 

1. Generation with dual-fuel capability that could switch to an alternate fuel without 

disrupting its production of power if its non-firm natural gas delivery was curtailed.71

2. Generation with multiple non-firm pipeline sources, such that the interruption of natural 

gas deliveries by one pipeline would not disrupt its power production. 

Generators with firm gas transmission capacity may not have the ability to withdraw their 

maximum hourly demand because of how they contracted for their deliveries. Most pipeline 

tariffs contract for gas capacity based on the contracted maximum daily energy withdrawals 

specified by the generator. These same tariffs typically limit the hourly withdrawal rate to 1/24th

of the contracted maximum daily energy withdrawals.72 

There are some contractual refinements that supplement the discussion above. Each plant with a 

firm transportation nomination is considered a “primary “delivery point. A Generation Owner 

(GO) who contracts for gas transportation for a number of generators at different locations from 

the same pipeline may not be able to produce 100% of its capacity based upon the contracted 

firm pipeline capacity for each plant. In this case, a GO may be relying upon its ability to 

 

69 http://www.iroquois.com/new-Internet/igts/PipelineSvs/ps_sysmp.asp 70 ISO-NE implemented up to Action 12 of Operating Procedure No. 4 – Action During a Capacity Deficiency (OP4). 71 Curtailments of non-firm gas deliveries require one to two hours of notice under most gas pipeline tariffs, allowing a generator 

to switch fuels in a controlled manner. 72 A “uniform withdrawal rate” is the typical pipeline tariff terminology that requires that hourly withdrawal rates to not exceed 

1/24th (or 4.17%) of the contracted daily deliveries. Other pipelines have more flexible hourly scheduling requirements; some,

for example, may allow hourly deliveries to be up to 6% of the contracted daily deliveries. 
Emerging Issues & Scenario Analysis 

38 2008 Long-Term Reliability Assessment 

nominate some of its contracted capacity at other generator locations (i.e., other “primary” 

delivery points) to the locations of the generators that will be operating. The operating 

generators that receive such supplemental nominations are “alternate” delivery points. 

Pipelines allow customers to switch their total firm gas capacity to different locations, provided 

that (i) the sum of the customer’s primary and alternate delivery nominations do not exceed their 

total gas capacity under contract and (ii) the deliveries to alternate delivery points do not impede 

the deliveries to the primary delivery points of any other pipeline customers. This strategy 

recognizes the low probability that all generators will be at their simultaneous maximum 

capacities, as one or more generators may be out of service due to planned or unplanned 

outages. Therefore, a generation owner may have 90% of the gas needed at a particular location 

under a firm transportation contract and assume that it could nominate the additional 10% from 

locations that will not be operating at full capacity. As described above, the nominated 10% 

capacity to the alternate delivery point is not 100% guaranteed. However, once granted, 

pipelines will interrupt non-firm transportation if needed to maintain service to alternate 

delivery points. 

Questions have also been raised regarding the potential impacts from compositional variability 

within natural gas streams by gas-fired generators. Gas interchangeability and/or quality are of 

greatest concern to large frame combustion turbines because their NOx combustion systems are 

particularly sensitive to its composition. Varying fuel characteristics are strongly impacted by 

the natural gas origin. 

Two NERC regions – NPCC73 and FRCC74 – have already performed an analysis on natural gas 

transportation and its potential impact on reliability. In addition, other areas (for example, ISONE) continue to monitor the impact of fuel quality on the reliability of combustion turbines. 

Their analyses can be used as a starting point by others. 

 

73For NPCC, see http://www.npcc.org/documents/regStandards/Guide.aspx, B-08 “Guidelines for Area Review of Resource 

Adequacy,” 74 For FRCC see pages P6:2-32 of https://www.frcc.com/Reliability/Shared%20Documents/FRCC%20Handbook%200208.pdf 

entitled “FRCC Generating Capacity Shortage Plan.”
Emerging Issues & Scenario Analysis 

39 2008 Long-Term Reliability Assessment 

Range of 8.3 - 7.6% 9.5 - 7.6% 3.4 - 3.7% 4.9 - 4.6% 

Forecast GDP 

Growth (2007-

2011)

Nuclear 

Coal-fired plants 

 Hydroelectric/ 

thermal 

 Nuclear 

resources

Coal 

Nuclear sources 

 Nuclear 

 Renewable 

energy 

Types of 

Investments in 

Generation 

Major $100 billion $75 billion $40 billion $15 billion 

Investment 

Initiatives next 5 

years

Surplus 

Excess 

generating 

capacity; deficit 

expected in near 

future 

Adequate 

Net importer of 

electricity: long 

term contract to 

import power from 

Itaipu hydro station 

located in 

Paraguay 

Adequate but 

moving towards 

deficit

10% of annual 

growth required for 

future demand 

 Deficit 

Shortage 11-

13%; 43% with 

power 

Power Supply 

Situation 

India China Brazil S. Africa 

Country

Table 5: Global Demand for Power Equipment is Rising. 

Rising Global Demand Impacts for Electric Power Equipment 

High growth in global demand for energy, including electricity, has led to increased demand for 

both transmission and generation electric power equipment Much of the equipment is 

manufactured overseas and shipped to the U.S. Further, global manufacturing capacity for 

equipment has not kept pace with demand. Therefore, expected delivery times have recently 

lengthened considerably, a trend expected to continue through 2017. 

Background: Much of the equipment required by the electric utility industry represents 

specialized orders, and large inventories of such equipment are not maintained by manufacturers. 

Without equipment standardization, there is little surplus capacity for electric power equipment, 

and delivery times will always be sensitive to external pressures. Global demand for power 

equipment is rising significantly, especially in countries whose economies are accelerating. The 

Table 5 provides a perspective from a sampling of countries experiencing high growth.75

 

75 TSC Research 
Emerging Issues & Scenario Analysis 

40 2008 Long-Term Reliability Assessment 

The extended expected delivery times for equipment leads to three issues that can impact future 

reliability: 

1. Generation and transmission projects must be planned farther in advance. 

2. Lack of flexibility to respond to unexpected or quickly changing conditions. 

3. Longer times to replace depleted inventories resulting from catastrophic events. 

Meanwhile, there is a significant worldwide focus on renewable resources to provide the 

growing requirements for electric energy. The demand for renewable energy in the United States 

exceeds supply. Further exacerbating this situation is the fact that legislation is in place in over 

twenty-five states that mandates renewable portfolios of up to 30% of renewable energy to be in 

place over a time period from fifteen years to as short as five years. It is estimated that, absent 

accelerated construction, the demand for renewable resources could exceed the available supply 

by more than 30% by 2010. This pressure will particularly strain the ability of the United States 

to produce wind turbines. Currently, only two manufacturers in the U. S. account for more than 

three-fourths of the market. 

Additional and reinforced transmission infrastructure will be required to connect these renewable 

resources to load centers. In the U.S. 30% to 50% of the transmission and distribution network is 

40-50 years old and may require repair or replacement in the coming years.76 These factors, 

along with the transmission infrastructure necessary to meet increased global energy demand, 

strains manufacturers’ ability to supply the needed transmission system equipment, with the net 

result being longer delivery times. 

Reliability Considerations: With the substantial increase in projected wind and nuclear 

generation, it is vital that the associated equipment be available. For example, there are fifteen 

applications pending for new nuclear facilities in eight states, almost 145 GW of new wind 

generation across North America (Proposed), as well as the requisite bulk power transmission 

additions to reliably integrate these new resources into the bulk power system. The impact of 

equipment delays on the timely completion of these facilities can significantly impact future bulk 

power system reliability. 

Delayed equipment and depleted inventories can cause near term and event-related shortages of 

transmission or resources. Over time, these extended delivery times should be factored into the 

lead times for planned projects as well as equipment inventory strategies. However, many 

organizations may experience an adjustment period during which there will be some reliability 

risks. To manage these risks, organizations should: 

• Build supply chain reliability; 

• Transition to industry specification standards; 

• Diversify supply portfolios; and 

• Solidify service partnerships and redefine alliance relationships. 

 

76 http://www.weidmann-acti.com/u/library/2006bartleypaperyes.pdf 
Emerging Issues & Scenario Analysis 

41 2008 Long-Term Reliability Assessment 

Increased Adoption of Distributed Generation and Demand-Side Resources 

Distributed generation, demand-side management (demand response and energy efficiency) and 

new technologies will become critical to meeting increasing demands for electricity in North 

America. 

Background: The potential benefits that demand-side and distributed generation resources bring 

to bulk power system reliability must be balanced with the operational and forecasting 

challenges being faced as the penetration of these resources increases. 

Demand-side and distributed generation resources can be categorized into a number of sub 

groupings: 

• Distributed generation (DG) is a term used to describe the small scale production of 

power, typically located close to demand or connected to distribution systems. In certain 

cases, the plants may often be located “behind the meter” at sites such as hospitals and 

industrial facilities. DG is also known as on-site generation, dispersed generation or 

embedded generation. Typical system reliability benefits attributed to DG may include: 

1) Reduced energy losses and upstream congestion on transmission lines; 2) Improved 

local reliability; and 3) Faster permitting than transmission line upgrades. 

• Demand-side management (DSM) is often understood to include two components77: 

energy efficiency (EE) and demand response (DR). DSM resources can lead to reductions 

in supply-side and transmission requirements to meet total internal demand. Planners and 

Operators have already integrated demand-response programs: 1) Capacity resources; 2) 

Ancillary Services; and 3) Energy reductions. Long-term reliability benefits include 

reduced supply-side and transmission requirements as well as augmentation of 

operational and long-term planning margins. DR is also considered as an effective tool in 

responding to system events, such as sudden loss of supply, and can be included in UFLS 

and UVLS schemes. These resources can offset or defer the need for large scale 

generation investment (i.e. large individual grid-connected generation facilities). EE 

generally refers to projects which reduce energy use at all times – such as compact 

fluorescent lighting – but which cannot be controlled at the time of peak. 

Reliability Considerations: To realize the potential benefits of DG and DSM outlined above, 

planners and operators must integrate them reliably into the bulk power system. 

Distributed Generation - Increased DG integration must support: 1) Reliability – DG must not 

degrade the quality and reliability of supply to distribution-connected consumers, 2) Visibility – 

DG must be visible to the system operators to allow real time decisions for the reliable operation 

of the grid, and 3) Requirements – Technical requirements for DG must support the reliable 

operation of the bulk power system. 

As the penetration of DR resources grows, the frequency and duration of their dispatch will also 

grow. If DR performance diminishes in response to a higher frequency and duration of dispatch, 

 

77 http://www.nerc.com/docs/pc/drdtf/NERC_DSMTF_Report_040308.pdf 
Emerging Issues & Scenario Analysis 

42 2008 Long-Term Reliability Assessment 

electricity supply adequacy could be impacted. Current resource planning methods often fail to 

fully address the unique characteristics of DR resources. 

As more distributed generation is contemplated and deployed, the question begins to arise as to 

how planners and operators can best utilize these resources for reliability purposes. Several 

challenges remain that complicate how distributed generation is “counted on” for reliability. First 

and foremost, unlike with larger generating units, system operators do not typically have the 

same kind of visibility and control over these distributed assets – especially those connected to 

the distribution network as opposed to the bulk transmission system. 

Additionally, the performance of generation connected to the distribution system currently is not 

covered by NERC Standards. While the loss of a single unit connected to the distribution system 

may not materially impact reliability on the rest of the system, the collective loss of many 

distributed generators – as may occur during a system disturbance – could have a significant 

impact to reliability in the area. For example, based on the current interconnection standards 

from the IEEE Power and Energy Society,78 distributed generation resources may disconnect 

from the power grid when short-term low voltage events occur either to prevent damage to the 

equipment or to meet anti-islanding voltage drop-out requirements on the distribution system. 

Bulk power system reliability requirements, however, may require the units to “ride through” the 

excursions to support the grid, prevent cascading outages, and aid in restoration. Failure of 

generation to meet these requirements could lead to system instability and/or voltage collapse, 

especially if the demand being served by the distributed generation stays connected when the 

resources drop off-line. In this scenario, distributed generation could, in fact, negatively impact 

reliability in a region. 

Distributed generation can support reactive performance of the bulk power systems due to close 

proximity of the grid to generators. However, more studies are needed to measure the potential 

reactive benefits. 

Therefore, NERC Standards may be required reconciling potential conflicts between the need to 

maintain bulk power system reliability and existing IEEE-PES standards for the distribution 

network. Industry investigation into the potential impacts of distribution connected generation on 

bulk power system reliability could reveal needs and required NERC Standard activity. 

Demand Response and Energy Efficiency - As dispatchable demand response is used as a nonemergency resource more often, the frequency of dispatch will increase. If the performance 

diminishes in reaction to the higher frequency of dispatch, system reliability could be affected as 

other resources may not be available in time to provide the ancillary services or energy required. 

In many cases, dispatchable demand response resources have not yet been tested to meet system 

reliability requirements at higher dispatch frequencies. To best measure the potential reliability 

benefits of DR, it is vital to collect event data for Dispatchable, Controllable, Dispatchable 

Economic DR and Non-Dispatchable DR. Please refer to the Capacity, Demand and Event 

Definition section for further discussion of these categories. 

To incorporate EE into resource planning, the energy efficiency peak demand reduction must be 

defined so resource planners can evaluate it along with capacity resources. Care must be 

exercised to ensure that the estimates are not misused for other applications. Successful 

 

78 IEEE 1547, “IEEE Standard on Interconnection Distributed Resources with Electric Power Systems.” 
Emerging Issues & Scenario Analysis 

43 2008 Long-Term Reliability Assessment 

integration of energy efficiency into resource planning requires close coordination between those 

responsible for energy efficiency and those in bulk system planning to ensure appropriate 

capacity values are estimated while meeting reliability objectives. A recent NERC report 

stated79: “For NERC to seriously consider the reliability benefits of EE, the resources promised 

by energy efficiency programs must be reconciled (measurement/validation) on a historical basis 

with projections. Once this validation occurs, DSMTF proposes to modify Total Internal 

Demand with projections.” To best measure the potential reliability benefits of DR, it is vital to 

collect event data for Dispatchable, Controllable, Dispatchable Economic DR and NonDispatchable DR. 

Plug-in hybrid electric vehicles (PHEV), which can act both as load and mobile storage devices 

(demand and supply), have the potential to become critical reliability resources – theoretically 

supporting capacity during times of peak usage and drawing charging power from the grid in the 

evening hours when, for example, more wind generated energy may be available due to wind 

patterns. This Grid-to-Vehicle (G2V) and Vehicle-to-Grid (V2G) technology may provide a 

more efficient use of generation capacity. Recent studies identified the impact of PHEV on 

system capacity requirements and energy use.80 DR initiatives will support PHEV integration, 

thereby playing an integral part in the development of future “Smart Grids.” The potential 

reliability benefits of “Smart Grid” technologies on bulk power systems require more study. 

 

79 http://www.nerc.com/docs/pc/drdtf/NERC_DSMTF_Report_040308.pdf 80 http://my.epri.com/portal/server.pt?open=512&objID=243&PageID=223132&cached=true&mode=2. 
Emerging Issues & Scenario Analysis 

44 2008 Long-Term Reliability Assessment 

Transmission of the 21st Century 

The 21st century brings new challenges to managing the bulk transmission system that affects the 

entire electric industry. Change in transmission line design, network reinforcements and 

communications required to accommodate new technologies can have an impact on the 

reliability of the bulk power system. 

Background: The development of new transmission infrastructure and technologies will be 

critical to North America’s energy future. As these resources are developed, vast improvements 

to the way operators currently manage and operate the system are beginning to emerge, along 

with new technologies that will allow planners to more fully utilize existing assets and right-ofways. 

New Technologies - Innovative technologies such as Flexible Alternating Current Transmission 

Systems (FACTS), for example, are making it possible increase the amount of power that can be 

transferred over existing lines by managing voltage support along the line. In addition, planners 

are now able to optimize the use of right-of-way corridors by converting existing transmission 

lines to higher voltages such as 500 kV and 765 kV using conventional as well as compact 

transmission line and High Surge Impedance Loading (HSIL) designs. Because High Voltage 

Direct Current (HVdc) lines typically require less right-of-way acquisition than AC lines of 

similar capacity and with advances in technology, they are also becoming ever more economic 

for shorter distance power transfers than before. These designs and technologies can minimize 

the amount of property required to route new facilities.

In addition to these innovations, advancing “Smart Grid”81 technology for the bulk power system 

will enable better visualization of the grid, allowing operators to quickly diagnose system events 

and respond with greater speed, accuracy, and confidence than ever before. For example, 

Synchro-phasor technology already installed across much of the grid is already beginning to 

show marked results, allowing disturbances to be analyzed in much greater detail than in the 

past. This increased information and control has the potential to significantly improve reliability. 

Infrastructure Additions - As new, location-constrained resources (such as wind, wave, nuclear, 

solar, and clean coal with carbon capture and sequestration) are proposed and built, new 

transmission infrastructure may be needed to bring energy generated by these resources to 

demand centers. Transmission may also be needed to support variable resources by providing 

access to requisite system flexibility, such as ancillary services (i.e. spinning reserves, etc.).

Reliability Considerations: For both new bulk power transmission facilities and existing aging 

transmission equipment for which rejuvenation may be required due to failures, new 

transmission technologies and designs can improve bulk power system reliability if they are 

properly integrated. These technologies can (1) increase the transfer capability of existing 

transmission facilities and (2) improve the operating flexibility of the bulk power system. 

The integration of intermittent resources will pose many challenges including transmission 

access and use of ancillary services. The large scale addition of demand resources will also 

impact the transmission system. 

 

81 http://en.wikipedia.org/wiki/Smart_grid 
Emerging Issues & Scenario Analysis 

45 2008 Long-Term Reliability Assessment 

Controllers and facilities such as Flexible AC Transmission System (FACTS) and HVdc that can 

respond dynamically to system emergencies will require additional training of system operators. 

In addition, as part of system rejuvenation, new system capabilities can be installed, such as 

advanced diagnostics and control, to maintain bulk power system reliability. Future coordinated 

transmission studies can identify potential locations where this 21st century technology can be 

reliably implemented. Improvements resulting from the deployment of diagnostics, protection 

and control technologies, including “Smart Grid” equipment, have the potential to measurably 

improve the reliability of the bulk power system. 

“Smart Grid” technology includes not only the application of advanced meter infrastructure 

(AMI), but also supports advanced asset management addressing bulk power system reliability. 

Use of diagnostics and communications will provide more information about the status of the 

grid and its components. Increased information and control generated from the smart grid 

infrastructure increases grid effectiveness and provides more tools for operators tasked with 

maintaining bulk power system reliability. Diagnostics can help monitor the condition of a 

variety of equipment and warn of potential failures a priori. Operators can then, with advanced 

warning, position the bulk power system and schedule maintenance as required. 

For example, the use of phasor measurements units (PMUs) on the bulk power system not only 

provides a priori information on the grid for proactive measures, it also supports 

advanced adaptive relaying vital to power the “smart grid.” In addition, studies are under way to 

determine if phasor measurement could resolve uncertainties surrounding zone 3 relaying 

through real time analysis of sequence quantities from the phasor vectors. 

As new technologies are integrated and the operation of the bulk power system becomes more 

heavily reliant on communications and cyber technology, the vulnerability of the system to cyber 

attack and intrusion may increase. New technologies must be designed and deployed with close 

attention paid to these issues and ongoing testing and security updating must become routine for 

system and plant operators. System planners should also begin to consider whether potential 

cyber criteria have a place in contingency planning or models. 

Cyber security and critical infrastructure protection are two of the key issues facing the reliability 

of the bulk power system today. Adequately addressing these challenges will be critical to the 

industry’s success over the coming years.
Emerging Issues & Scenario Analysis 

46 2008 Long-Term Reliability Assessment 

Water Availability and Use 

Demand for water is increasing in North America and it is a vital resource requiring careful 

management. Thermal power plants require sufficient levels and quantities of water for cooling. 

Understanding the industry’s role in water use and the implications of reduced water availability 

on bulk power system reliability requires careful study. 

Background: Direct human uses of water for drinking or sanitation takes priority over utility 

and other industrial uses. Most Canadian,82 and northern WECC utilities have significant reliance 

on hydro power, and fossil-fueled generating plants depend on water in both the U.S.83 and 

Canada for cooling the steam in their condensers. Substantial changes in on-peak capacity of 

generating plants caused by water restrictions will influence electricity supply adequacy. 

Transmission requirements will significantly change if replacement power sources are remote 

from traditional sources serving a given region. The strains on transmission are often only 

revealed through special drought oriented studies of the transmission system. 

Fossil plants may need to consider cooling towers instead of once-through cooling water sources. 

Auxiliary loads for these new cooling towers is often greater than that used for traditional water 

sources and can reduce overall plant output. 

Reliability Considerations: Hydro plants require a minimum head (the difference between the 

height of the water behind the dam and the height of the turbines) to function. If water flow into 

a fore bay above the dam is lessened, it may be necessary to pond (limit outflow) water to build 

up enough head. 

In the U.S. most of the attractive hydro generation sites have already been fully developed and 

site new plants is unlikely because of environmental concerns and restrictions. For existing 

plants, environmental minimum flow restrictions may require water releases that bypass hydro 

turbines to maintain river levels below the dam, essentially rendering the hydro plant useless. 

Hydro site licenses specify the conditions for the operation of the hydro plant and must be 

strictly adhered to when operating such plants. In Canada, there is a considerable amount of 

hydro still potentially available for development.84 Because of the size, cost and negative 

environmental impacts of large dam projects, however, hydro development has been increasingly 

focused on small-scale projects (i.e., those with less than 10 MW of generating capacity).

Low levels or flow in rivers, lakes and other bodies of water used for the cooling of plant thermal 

systems may affect the thermal cycle of electric generating plants using such water bodies. 

Lower flow can affect cooling in two ways. First, generator output may be limited because of 

lower water levels at water intakes or intakes being exposed, limiting their effectiveness or even 

requiring plant shut down. Second, lower water flow can result in higher water temperatures 

reducing the cooling system’s efficiency and possibly violating environmental thermal 

restrictions. Without sufficient water use and thermal discharge rights, large fossil and nuclear 

plants are also often hard to site. Many plants in recent years have been forced to move to “dry-

 

82 http://www.ec.gc.ca/Water/en/manage/use/e_use.htm 83 http://water.usgs.gov/watuse/ 84 http://www.nwri.ca/threats2full/ch2-2-e.html 
Emerging Issues & Scenario Analysis 

47 2008 Long-Term Reliability Assessment 

cooling” concepts dependent on heat exchange with the atmosphere and minimal water use in 

order to obtain site permission. 

NERC will continue to monitor water use issues along with the ongoing research & 

development. NERC has worked with the Department of Energy National Energy Technology 

Laboratory (NETL)85 on water use86(See U.S. Clean Water Act: Cooling-Water Intake Structure

subsection in this section). In addition, substantial amount of research and development on this 

topic is being performed by the Electric Power Research Institute (EPRI).87

 

85 http://www.netl.doe.gov/technologies/coalpower/ewr/water/power-gen.html 86 http://www.nerc.com/files/NERC_SRA-Retrofit_of_Once-Through_Generation_090908.pdf 87 http://my.epri.com/portal/server.pt?open=512&objID=240&&PageID=350&mode=2&in_hi_userid=2&cached=true 
Emerging Issues & Scenario Analysis 

48 2008 Long-Term Reliability Assessment 

2009 Scenario Analysis Summary 

Background: The LTRA preparation includes data and information on projected summer and 

winter electricity supply and demand conditions for the coming ten-year period, along with 

reliability self-assessments prepared by each regional entity. These data, information, and 

assessments form the basis of the NERC reference case presented in the Long-Term Reliability 

Assessment, for which detailed analysis and discussion follows. The reference case incorporates 

known policy/regulation changes expected to take effect throughout the studied timeframe 

assuming that a variety of economic growth, weather patterns and system equipment behaviors 

are as expected, usually based on historic performance trends.

Regional Scenario Analysis Plans for 2009: To commence scenario analysis development, in 

December 2007 the NERC Planning Committee (PC) identified and prioritized various resource 

and transmission impact scenarios for regional and NERC-wide evaluation, based on input from 

its subcommittees. Regions proposed study outlines to be submitted for next year’s 2009 LongTerm Reliability Assessment in conjunction with the regions’ normal 2009 – 2018 reference case 

self-assessment and data submittals. Each region was required to examine one of the following 

two scenarios: 

Scenario #1: Study accelerated integration of renewable resources: Around the 

world, renewable resources have become a significant portion of the generation mix. The 

available technologies have matured to the point generation owners and system operators 

can generally meet federal, state and provincial renewable energy mandates, although 

penetration may be limited by system integration issues, often due to these resources 

being variable or intermittent in nature. For example, weather patterns of the 

region/subregion, the variety of renewable sources, the existing generation mix, and the 

bulk power system transfer capability with neighboring areas all influence the level of 

penetration that can be achieved. Another consideration is ancillary services and system 

re-dispatch needed to support reliable operation to support the level of renewables. 

Scenario Item Specifics Expected Response 

For this scenario, the regions will assess accommodating a minimum of an additional 

15% of total energy from new renewable resources, above the reference case values, with 

no more than 5% made up from energy efficiency. The base year for calculating the 

energy was set as 2008 to provide a common reference value. The addition of renewable 

resources may be ramped at a rate that can be integrated into the system while sustaining 

bulk power system reliability until the end of ten year period. 

As part of the data submittal, NERC will be looking for narratives and data similar to the 

LTRA reference data submittal, including: 

− Tabulations of potential capacity (gross and derated) 

− Resource adequacy needs (contribution towards capacity margin with or without the 

additional resources) 

− Renewables/energy efficiency needed to meet the 15% scenario. 

− Impacts on reliability, e.g. new transmission lines, back-up capacity, impact on load, 

etc., and 

− Fuel outlook, transmission operational issues and reserves (resource adequacy) 
Emerging Issues & Scenario Analysis 

49 2008 Long-Term Reliability Assessment 

Scenario #2: Scenario selected by the region/sub-region for study in 2009: If there is 

little or no impact of Scenario #1 on a region/subregion, then Scenario #2 will be 

evaluated. The regions are expected to select a scenario that significantly impacts supply 

mix, electricity purchases or sales in the studied region. The emerging issues identified in 

the 2007 LTRA are potential candidates for this alternate scenario analysis. The 

assessment and detail required in the analysis will be consistent with the framework 

provided for Scenario #1. 

Each region’s scenario analysis identifies the impact on reliability and what needs to happen to 

keep the resulting system reliable. The scenario results, when presented in 2009 will distinguish 

the key regional challenges arising from the scenario which are different from the reference case. 

Analytical studies which have already been or can be performed before May 2009 will be used to 

bolster this scenario assessment. 

Summary of Regional Scenarios: The outlines submitted to NERC were generally consistent 

with what was requested. Because of the significant effort expected to be required in 2009 to 

produce these scenario analyses along with a reference case, the regions will build their scenario 

analyses on existing studies or studies that are already underway. In most instances, this means 

examining a single point in time ten years in the future rather than year-by-year analysis. Several 

regions will be building their scenarios from the Joint Coordination Study Group (JCSG). 

Outlines of scenario study plans proposed by regions were approved by the PC at their June 2008 

meeting.88 

Table 6 summarizes each region’s plans for the 2009 scenario analysis. 

Table 6: Regional plans for the 2009 Scenario Analysis 

Region Scenario 

Compare 

to 

Reference 

Case 

Annual 

Peak or 

Point in 

Time 

Peak 

capacity Energy Fuel Mix Miles of Transmission 

Operational 

Challenges 

ERCOT 

Wind resources for 

15% of new 

energy 

Yes 

Annual 

peak to 

2018 

Yes Yes Yes Yes 

FRCC 

Renewable 

resources for 15% 

of new energy 

Yes 

Annual 

Peak to 

2018 

Yes Yes Yes Yes 

SERC 

Southeast 

Generation Fuel 

Shift 

Yes 

Point in 

Time 

2019 

Yes No Yes Yes 

WECC 

Renewable 

resources for 15% 

of new energy 

Will 

compare 

capacity 

mix 

Point in 

Time 

2017 

Yes 

Yes, but can’t 

compare energy 

to reference case, 

will compare by 

fuel 

Approximate Yes 

MRO Yes Yes Yes Yes Yes 

NPCC Yes Yes Yes Yes Yes 

RFC Yes Yes Yes Yes Yes 

SPP 

Joint Coordinated 

Study Group: 

Wind resources 

for at least 15% of 

new energy 

Yes 

Point in 

Time 

2018 Yes Yes Yes Yes 

 

88 The draft proposals can be found as Item 5.b Reliability Assessment Subcommittee Report, Appendix I of the Planning 

Committee’s June 4-5, 2008 Draft Agenda at http://www.nerc.com/docs/pc/Update_2_PC_Agenda_June%204-5-2008.pdf 
Reliability Historical Trends 

50 2008 Long-Term Reliability Assessment 

Table 7: Bulk Power System Event 

Classification Scale 

Category 1: An event results in any or combination of: 

a. The loss of a bulk power transmission component 

beyond recognized criteria, e.g. single-phase line-toground fault with delayed clearing, line tripping due 

to growing trees, etc. 

b. Frequency below the Low Frequency Trigger Limit 

(FTL) more than 5 minutes. 

c. Frequency above the High FTL more than 5 

minutes. 

d. Partial loss of dc converter station (mono-polar 

operation) 

e. Inter-area oscillations 

Category 2: An event results in any or combination of: 

a. The loss of multiple bulk power transmission 

components 

b. System separation with no loss of load or generation 

c. Special Protection Scheme or Remedial Action 

Scheme misoperation 

d.The loss of generation (between 1,000 and 2,000 

MW in the Eastern Interconnection or Western 

Interconnection and between 500 MW and 1,000 

MW in the ERCOT Interconnection). 

e. The loss of an entire generation station or 5 or more 

generators 

f. The loss of an entire switching station (all lines, 100 

kV or above) 

g.Complete loss of dc converter station 

Category 3: An event results in any or combination of: 

a. The loss of generation (2,000 MW or more in the 

Eastern Interconnection or Western Interconnection 

and 1,000 MW or more in the ERCOT 

Interconnection). 

b.The loss of load (less than 1,000 MW) 

c. System separation or islanding with loss of load or 

generation (less than 1,000 MW). 

d. UFLS or UVLS operation. 

Category 4: An event results in any or combination of: 

a. System separation or islanding of more than 1,000 

MW of load 

b.The loss of load (1,000 to 9,999 MW) 

Category 5: An event results in any or combination of: 

a. The occurrence of an uncontrolled or cascading 

blackout 

b.The loss of load (10,000 MW or more) 

Reliability Historical Trends 

Introduction 

Historical trends of reliability are provided for 

the first time in NERC’s 2008 Long-Term 

Reliability Assessment. Understanding these 

trends can lead to improved bulk power system 

reliability. For example, indication of ongoing 

threats to reliability can stimulate pre-emptive 

action in future designs towards maintain bulk 

power system reliability. 

There are two basic, functional components of 

reliability: operating reliability and adequacy. 

• Operating reliability is the ability of the 

interconnected electric system to withstand 

sudden disturbances such as electric short 

circuits or unanticipated loss of system 

components89. 

• Adequacy is the ability of the electric 

system to supply the aggregate electrical 

demand and energy requirements of the enduse customers at all times, taking into 

account scheduled and reasonably expected 

unscheduled outages of system elements.90

The purpose of this section is to report historic 

trends in operating reliability and adequacy for 

the Eastern Interconnection.91 

Trends in Operating Reliability 

Disturbance Event Trends - NERC classifies 

system events according to five categories with 

Category 5 being the most severe (See Table 7). 

Based on data from NERC’s Disturbance 

Analysis database, Figure 20 depicts all 

Category 2 through 5 system events for 2002-

2007.92 The events caused by factors other than 

the performance of the transmission system are 

not included. 

 

89 Definition of operating reliability http://www.nerc.com/~members/OC_PC/ALR/ as of December 12, 2007 90 NERC Glossary of Terms ftp://www.nerc.com/pub/sys/all_updl/standards/rs/Glossary_02May07.pdf 91 This is the inaugural year for incorporating reliability metrics in the Long-Term Reliability Assessment. Available data for this 

assessment is solely from the Eastern Interconnection. 92 See http://www.nerc.com/page.php?cid=5%7C63%7C252 for detailed definitions 
Reliability Historical Trends 

51 2008 Long-Term Reliability Assessment 

Though the performance is mixed, with no discernable trends, a number of observations can be 

made form this data: 1) While the number of Category 2 events increased in 2005, the number of 

events in Category 3 has continued a steady decline between 2002 and 2006, 2) Category 4 

events were up in 2005 and 2007, after declining in 2004 and 2006. 

These data clearly indicate that gaps exist between actual performance and expected system 

behavior under actual operating conditions. Ultimately the most important measure of operating 

reliability is that the number of events declines towards zero. 

Figure 20: Annual Number of Disturbance Events by

Severity 

0

10

20

30

40

50

Category 5 0100000

Category 4 4203121

Category 3 22 20 19 12 11 13 10

Category 2 17 16 8 22 17 15 15

2002 2003 2004 2005 2006 2007 2008 

(Jan-Jul)

Figure 21 summarizes the contribution of leading causes to the total number of events in 2006. 

Of the 29 events in 2006, over half were caused by equipment failures, nine by system protection 

misoperations, and four by personnel errors. Definitions of these cause codes are in Table 8. In 

addition, the 2008 disturbances have added for comparative purposes. 

Equipment Failure

Events caused by the failure of equipment. Use this code only when the equipment failed even though it was 

operated within design specifications. The failed equipment could be (i) a component of an Element (such as a 

failed insulator), or (ii) part of an AC Substation (such as a failed circuit breaker), 

Protection Misoperation 

Events caused by relay and/or control initiated operations when not desired or the failure to operate when 

desired. This category also includes incorrect relay or control settings that do not coordinate with other 

protective devices. 

Human Error 

Events caused by any incorrect action traceable to employees and/or contractors for companies operating, 

maintaining, and/or providing assistance to the Transmission Owner will be identified and reported in this 

category. Also, any human failure or interpretation of standard industry practices and guidelines that cause an 

outage will be reported. 

Table 8: Definition of Cause Codes 
Reliability Historical Trends 

52 2008 Long-Term Reliability Assessment 

More work is required to examine the root causes of these events, including the significance of 

protection system misoperations, the effects of human activities (both by utility workers and the 

public), as well as the influence of equipment failures on the reliability performance. The 

objective is to recognize and eliminate unreliable actions and at-risk conditions.93 

Figure 21: Reported Events by Cause Codes

0

10

20

30

40

50

60

Equipment Failure Protection

Misoperations

Human Error Others

Cause Codes

Percent (%) 

2006

2007

As is evident in Figure 21, one of the key categories identified as a major cause of system 

disturbances under analysis has been protection system misoperations. Every major system 

disturbance since the 1965 Northeast Blackout has been caused or exacerbated by protection 

system performance ranging from protection system coordination to relay loadability. 

NERC’s efforts in the Protection System Review Program, launched in 2005 following the 2003 

Blackout, have materially reduced relay loadability as a causal or contributory factor in system 

disturbances; only three loadability instances have occurred since the program was initiated, and 

only one of those was on the bulk power system 

That program’s success led to the development a new initiative in 2007 focused on improving 

more aspects of protection system performance and, thereby, overall system reliability. The 

initiative continues the work in relay loadability through the development of Standard PRC-023 

– Transmission Relay Loadability (awaiting FERC approval), and includes efforts in protection 

system reliability (redundancy), relay coordination, maintenance, and the coordination of system 

protection with generator protection and controls. 

Analyses of system disturbances over the last year show a trend of generation turbine controls 

and voltage sensitivity of generator auxiliary systems that caused unexpected loss of generation 

or runbacks of output. In seven disturbances, the output of 28 generators was lost due to 

unexpected turbine control action, and an additional 13 generators tripped due to voltage 

sensitivity. For instance, in the February 2008 south Florida disturbance, after the fault had been 

 

93 The 2007 event root cause trend is not yet available. A number of 2007 disturbance events are still being analyzed
Reliability Historical Trends 

53 2008 Long-Term Reliability Assessment 

cleared, an additional 11 generators (1,500 MW) tripped off line due to these problems, further 

exacerbating the disturbance.94 

NERC is in the process of expanding the protection system performance initiative to address 

these issues in conjunction with the IEEE. This enhanced initiative will involve a number of 

NERC standards projects and increased efforts to raise the profile and priority of protection 

system performance in the industry 

Frequency Excursion Occurrence for the Eastern Interconnection- The ability to maintain 

load-generation balance within acceptable limits is a key performance indicator to measure real 

power balancing control performance. Prolonged system recovery from a disturbance or normal 

operating frequency excursions (either high or low) could indicate the need for new methods of 

system management. Decline in frequency response or degradation of regulation and reserve 

sharing capability are performance issues worthy of attention, and NERC is currently developing 

a Standard Authorization Request.95 For example, for every 0.1 Hz reduction in frequency 

response, represent 70 MW of reduction in automatic generation control (AGC). Frequency 

excursions on the grid led to the unexpected loss of over 20 generating units in eight separate 

disturbances since August 1, 2007. 

Figures 22 and 23 present low frequency excursion trends in the Eastern Interconnection 

indicating significant changes have been taking place during the last six years. From 2002 to 

2007, the number of on-peak low frequency events has more than tripled, growing from 186 in 

2002 to 675 in 2007; the number of off-peak low frequency events increased from 67 in 2002 to 

426 in 2007. 

While there is no apparent trend in the longer term (> 2 minute AGC-related) events, the bulk of 

the excursions identified are short-term step changes in frequency that are an indicator of a 

decline in primary control (governor response). While these trends do not directly suggest a 

deterioration of system performance, it is a reliability indicator that bears close monitoring. The 

NERC Operating Committee’s Resources Subcommittee plans to analyze Interconnection real 

time balancing control performance and identify root cause of out-of-limit operation in 2008. 

 

94As a result of this finding, NERC issued an industry advisory to all registered Generation Owners, Generation 

Operators, Planning Authorities, Planning Coordinators, Transmission Operators, and Reliability Coordinators 

outlining the issue and urging further coordination. NERC’s advisory is available at:

http://www.nerc.com/fileUploads/File/Events%20Analysis/A-2008-06-26-01(1).pdf and 

http://www.nerc.com/fileUploads/File/Events%20Analysis/A-2008-06-26-02.pdf 95 http://www.nerc.com/docs/standards/sar/SAR_Frequency_Response_Final_Draft3_30Jun07.pdf 
Reliability Historical Trends 

54 2008 Long-Term Reliability Assessment 

Figure 22– Low Frequency Events 

Figure 23 – Low Frequency vs. Duration by Year 
Reliability Historical Trends 

55 2008 Long-Term Reliability Assessment 

The majority of the low frequency events are coincident with Time Error Corrections. Over half 

of the events occur during Time Error Corrections even though the eastern interconnection is in 

correction only about 15% of the time. The events also occur just after the primary scheduling 

periods (06:00 to 22:00). 

Figures 24 and 25 present high frequency excursion trends in the Eastern Interconnection. From 

2002 to 2007, the number of on-peak high frequency events has increased from 199 to 315; the 

number of off-peak high frequency events has varied over the years and remained stable through 

2006 and 2007. The frequency data from the Western Interconnection did not indicate any 

significant changes within the last few years. 

Figure 24 –High Frequency Events
Reliability Historical Trends 

56 2008 Long-Term Reliability Assessment 

Figure 25 – High Frequency vs. Duration by Year 

Improvements to frequency event analysis include analyzing 

outlier days using statistical process control theory. Generally 

very noisy days are an indication of something identifiable that 

is impacting reliability. Significant changes in weekly 

frequency variation may indicate wide-area or sustained 

balancing issues. Highly variable frequency often occurs 

during grid upsets or when operators initiate rapid generation 

changes to correct congestion. Measuring noise around a target 

frequency therefore can be a valuable indicator of potential 

reliability considerations.96

Trends in Adequacy 

Capacity and Energy Emergency Events - The total number 

of capacity and energy emergency events between 2002 and 

2007 in NERC’s Reliability Coordinator Information System 

(RCIS) database are grouped into three categories (A1, A2 and 

A3) based on Standard EOP-002-0 (Capacity and Energy 

Emergencies). Note that Categories A1 and A2 are, in effect, 

operating procedures used to avoid the interruption of firm 

customer load97 as defined in Category A3 (See Tables 9 and 

10 along with Figure 26). 

 

96 http://www.asq.org/quality-progress/2008/08/statistical-process-control-spc/bright-idea.html 97 The categories for capacity and emergency events based on Standard EOP-002-0, require revision to specifically account for 

higher, more regular use of demand response as a capacity resource. For example, the current definitions for Category A2 

Category A1: No disturbance 

events and all available resources in 

use. 

a. Required Operating Reserves 

can not be sustained. 

b. Non-firm wholesale energy 

sales have been curtailed. 

Category A2: Load management 

procedures in effect. 

a. Public appeals to reduce 

demand. 

b. Voltage reduction. 

c. Interruption of non-firm end 

use loads per contracts. 

d. Demand-side management. 

e. Utility load conservation 

measures. 

Category A3: Firm load 

interruption imminent or in 

progress.

Table 9: 

Categories for Capacity 

and Emergency Events 
Reliability Historical Trends 

57 2008 Long-Term Reliability Assessment 

Table 10 – Capacity and Energy Emergency Event Trend 

Categories 2002 2003 2004 2005 2006 2007 

A3 18 36 15 21 5 20 

A2 123 29 20 62 5 50 

A1 130 43 31 102 14 103 

The categories for capacity and emergency events based on Standard EOP-002-0, however, 

require revision to specifically account for higher, more regular use of demand response as a 

capacity resource. Current definitions for Category A2 include the operation of demand-side 

resources as a capacity and emergency event, while, in some areas, current industry practice also 

includes the resource as part of normal, non-emergency operations. 

Figure 26: Number of Energy Emergency Alerts 

by Year (2002-2007)

0

20

40

60

80

100

120

140

2002 2003 2004 2005 2006 2007

A1

A2

A3

The 2002 – 2007 quarterly plots are provided in Figure 27. There is a seasonal pattern to the 

events over the year, with the 2006 summer weather particularly mild compared to other years. 

A clear periodicity is evident between the summer months in the third quarter (Q3) and winter 

months represented in the first quarter and fourth quarter (Q1 and Q4) of each year. The 

monthly annual breakdown of quarters is defined as: 

• Q1 – Winter (January, February, March) 

• Q2 – Spring (April, May, June) 

 

include the operation of demand-side resources as a capacity and emergency event, while current industry practice includes the 

resource as part of normal, non-emergency operations. 
Reliability Historical Trends 

58 2008 Long-Term Reliability Assessment 

• Q3 – Summer (July, August, September) 

• Q4 – Fall/Early Winter (October, November, December) 

Analysis has indicated that extreme weather, short-term load forecast errors and unplanned 

generation outages are the main causes of the emergency events. 

Figure 27 – Quarterly Capacity and Energy Emergency Event Trend 

Number of Energy Emergency Alerts by Quarter (2002-2007)

0

10

20

30

40

50

60

70

80

90

100

Q1

02

Q2

02

Q3

02

Q4

02

Q1

03

Q2

03

Q3

03

Q4

03

Q1

04

Q2

04

Q3

04

Q4

04

Q1

05

Q2

05

Q3

05

Q4

05

Q1

06

Q2

06

Q3

06

Q4

06

Q1

07

Q2

07

Q3

07

Q4

07

A1

A2

A3

Transmission Loading Relief (TLR) - The TLR98 process allows reliability coordinators to 

operate the system within real-time reliability limits while respecting transmission service 

reservation priorities.99 Bulk power system customer requests for transactions on Firm Point-toPoint Transmission Service paths that exceed the amount that the system can transfer without 

violating operating limits is an indication that more transmission may be needed for economic 

purposes. Reliability Coordinators issue Transmission Loading Relief (TLR) directives in which 

transaction rights for specific transactions are revoked until system conditions allow their 

resumption. These TLRs have different levels with Level 6 being the most severe (See Table 

11). Trends towards increasing number of TLR Level 5100 or higher indicate that certain parts 

of the system are at their limit to supply requested transfers within reliability constraints (see 

Figure 28). 

 

98 TLRs are not used in a number of systems where centralized security constrained economic dispatch is employed. 99 TLR procedure http://www.nerc.com/files/IRO-006-3.pdf 100 All transactions as prescribed by TLR Level 5b are considered point-to-point across the interface and they can include native 

load, network service and point-to-point. Hence there is no differentiation and they are comparably treated when it comes to 

curtailment as stated by FERC pro-forma tariff in Section 13.6 (which starts on sheet no. 47). 
Reliability Historical Trends 

59 2008 Long-Term Reliability Assessment 

Number of Level Five & Higher TLRs by Year (2002 - 2007)

0

20

40

60

80

100

120

140

160

180

2002 2003 2004 2005 2006 2007

It is necessary to understand the drivers behind 

congestion to determine if it represents a reliability 

or economic issue. If congestion is increasing 

because the transmission system is being fully used 

to optimize economic dispatch they are not a 

reliability concern. If congestion is occurring 

because transfers are needed to serve load, then this 

variety of congestion is an indicator of reliability 

concerns. TLR can indicate enforcing the 

boundaries of economic market activity or they can 

suggest reliability concerns. TLR below level 5 

suggest that non-firm transactions are encountering 

system limits. While the network limits are rooted 

in reliability the drivers behind them are economic 

in nature. 

Figure 28 shows that the number of Level 5 and 

higher TLRs has continued to increase from 2004 

to 2007 at a rate more than 15% each year. In 2007 

the number of Level 5 TLRs more than doubled 

over the 2006 figures. The duration of Level 5 

TLRs increased from 348 hours in 2006 to 990 

hours in 2007. 

 

101 TLR procedures shown apply only to the Eastern Interconnection (http://www.nerc.com/page.php?cid=5%7C67%7C205) 

Table 11: Transmission Loading 

Relief (TLR) Procedure: TLR 

Levels101

TLR 

Level Reliability Coordinator Action

1 

Notify Reliability Coordinators of 

potential System Operating Limit 

(SOL) or Interconnection Reliability 

Limit (IROL) violations. 

2 

Hold Transfers at present level to 

prevent SOL or IROL violations. 

3a 

Reallocation of Transmission 

Service by curtailing Interchange 

Transactions using Non-firm Pointto-Point Transmission Service to 

allow Interchange Transactions 

using higher priority Transmission 

Service. 

3b 

Curtail Interchange Transactions 

using Non-firm Point-to-Point 

Transmission Service to mitigate an 

SOL or IROL violation. 

4 

Reconfigure transmission system 

to allow Transactions using Firm 

Point-to-Point Transmission Service 

to continue. 

5a 

Reallocation of Transmission 

Service by curtailing Interchange 

Transactions using Firm Point-toPoint Transmission Service on a pro 

rata basis to allow additional 

Interchange Transactions using 

Firm Point-to-Point. 

5b 

Curtail Interchange Transactions 

using Firm Point-to-Point 

Transmission Service to mitigate an 

SOL or IROL Violation 

6 Emergency Procedures

0 TLR Concluded

For information about the TLR procedure and 

transmission service priorities, please refer to 

NERC reliability standard. Standard IRO-006-3 

— Reliability Coordination — Transmission 

Loading Relief http://www.nerc.com/files/IRO006-3.pdf 

 Figure 28 – Trends of Level 5 & Higher TLRs 
Reliability Historical Trends 

60 2008 Long-Term Reliability Assessment 

Reliability Coordinators (RCs) also reported forced generation and transmission outages 

significantly increased in 2007 which may have triggered increased use of Level 5 TLR 

procedures. To show the progressive use of TLR Level 5, they are further divided into Level 5a 

and Level 5b. 

Figure 29 indicates the number of Level 5 TLRs issued by three RCs (SPP, MISO and ICTE) 

increased significantly from 2005 to 2007.102 The higher number of TLR events in the SPP 

market demonstrates a greater use of the transmission capacity while maintaining reliability (See 

Table 12). Where other markets may allow re-dispatch without a TLR to maintain reliability of 

the transmission system, SPP’s market protocols require calling a TLR for each congestion 

situation 

Figure 29: Level 5 TLRs for the years 2002- Sep 2008

0

10

20

30

40

50

60

70

80

90

100

2002

2003

2004

2005

2006

2007

2008(Jan-Sep)

# of Incidents

VACS

SWPP

TVA

PJM

MISO

ONT

ICTE

5a

5b

Note not all regions use TLRs to manage their electricity delivery systems and markets, and their 

use is neither an absolute nor a broadly applicable indicator of the need for transmission 

reinforcements. 

 

102 Note that those RCs not mentioned in the Eastern Interconnection did not issue TLRs during the 2002-2007 timeframe 
Reliability Historical Trends 

61 2008 Long-Term Reliability Assessment 

Much of the Level 5 TLRs increased in the Southwest Power Pool 

(SPP), which includes SWPP and ICTE RCs. SPP implemented its 

Energy Imbalance Market (EIS) on February 1, 2007. Since the 

implementation of the EIS Market, SPP has experienced an increase 

in the number of TLR events primarily due to its operating 

protocols. SPP’s market protocols require that the SPP Reliability 

Coordinator issue a TLR event in accordance with NERC TLR 

requirements every time congestion is experienced in the market 

footprint. First, SPP’s market protocols require calling a TLR to 

publicize the fact that SPP is experiencing congestion. Second, it 

ensures that the other parties contributing to the congestion 

equitably share in achieving the necessary relief. 

Prior to implementation of the market, many constrained flowgates 

were resolved with generation re-dispatch internal to a Balancing 

Authority and in many of those instances, TLR was not declared. 

Now with the EIS Market operational, the same flowgates are 

reliably managed through TLR and market re-dispatch. 

Additionally, the structure of the market greatly facilitates more 

efficient and effective use of the network. Because the market more 

fully uses transmission capacity, more TLRs are experienced now 

than under the previous pre-market structure which only allowed 

bilateral and network transactions to use transmission capacity. 

Table 12: SPP’s Use of TLRs 

Application of TLR represent is one 

method to relieve potential or actual 

loading. Differences exist on how 

regions approach congestion 

management. For example, WECC 

uses an Unscheduled Flow 

Mitigation Plan as an equivalent load 

relief procedure for use in the 

Western Interconnection103. In 

market structures, redispatch is 

commonly used as an efficient 

measure to reduce congestion in 

transmission systems. MISO104 and 

PJM105 have LMP markets run a 

security constrained dispatch model 

which determines the lowest cost 

generation dispatch without 

exceeding any transmission 

limitations, thereby significantly 

reducing the number of TLRs called. 

Similarly, ERCOT employs a flowbased/zonal approach to manage 

forward markets and congestion.106

Potential Reliability Metric Enhancements 

While TLRs and EEAs were initially developed to help manage/ensure adequacy, they are being 

used more and more as triggering events for individual entity market decision points. This blurs 

the lines between reliability tools and market drivers. It also blurs the link between the state of 

reliability and the use of TLR Level 5 and EEA. Therefore, TLR and the EEA metrics may need 

improvement for adequacy trends analysis. 

Further, the RMWG may also study the correlation between A1/A2, CPS1/CPS2, and balancing 

area ACE limits (BAAL) with frequency performance and inadvertent interchange performance 

Frequency is also linked to schedule ramp performance, frequency bias performance, ACE 

management, and contingency response. Also, Time Error does provide an indication of 

operational discipline along with inadvertent interchange and Area Interchange Error. The 

RMWG should evaluate these and other potential metrics to measure operating reliability trends. 

 

103 This procedure has been accepted by FERC and adopted by NERC Standards http://www.nerc.com/files/IRO-STD-006-0.pdf. 

WECC USFMP: http://www.wecc.biz/documents/library/UFAS/UFAS_mitigation_plan_rev_2001-clean_8-8-03.pdf 104 More information on MISO’s congestion management procedures can be found in the 2007 STATE OF THE MARKET 

REPORT FOR THE MIDWEST ISO at: http://www.midwestiso.org/publish/Document/24743f_11ad9f8f05b_-

7b890a48324a/2007%20MISO%20SOM%20Report_Final%20Text.pdf?action=download&_property=Attachment 105 PJM’s congestion management procedures can be found in the 2007 STATE OF THE MARKET REPORT 

 FOR THE PJM INTERCONNECTION at http://www2.pjm.com/markets/market-monitor/downloads/mmu-reports/2007-somvolume2-sec7.pdf 106 ERCOT’s congestion management procedures, entitled 2007 STATE OF THE MARKET REPORT FOR THE ERCOT 

WHOLESALE ELECTRICITY MARKETS http://www.puc.state.tx.us/wmo/documents/annual_reports/2007annualreport.pdf
Regional Reliability Assessments 

62 2008 Long-Term Reliability Assessment 

Regional Reliability Assessments 

Background 

Regional Resource and Demand Projections - The figures in the regional self-assessment pages 

show the regional historical demand, projected demand growth, capacity margin projections, and 

generation expansion projections reported by the regions for the coming ten-year period. 

Capacity Fuel Mix - The regional 

capacity fuel mix charts show each 

region’s relative reliance on specific 

fuels107 for its reported generating 

capacity. The charts for each region in 

the regional self-assessments are based 

on the most recent data available in 

NERC’s Electricity Supply and 

Demand database. 

Capacity fuel mix evolution in the 

U.S. for peak Net Capacity Resources 

during the 2008-2017 timeframe show 

increased coal, gas, wind and nuclear 

plant (See Figure 30). 

Nuclear new-build Net Capacity 

Resources represented in the U.S. 10-

year fuel-mix comparison includes 1) 

FRCC: 2,900 MW,108 2) RFC: 5,000 

MW,109 and 3) SERC: 1,200 MW.110

In addition, a number of new-build 

nuclear plants have been identified in 

regional reliability assessments (see 

Regional Reliability Assessment

section), though their capacity is not 

represented in the fuel mix of Net 

Capacity Resources. Regions 

considered the following nuclear 

capacity as part of their Total Potential 

Resources: 1) SERC: 6,800 MW,111

and 2) ERCOT: 8,400 MW.112 

 

107 Note: The category “Other” may include capacity for which a fuel type has yet to be determined. 108 Levy 1 & 2 (1,173 MW each 2016-2017) 109 1,600 MW (PPL Corporation, 2013), 1,640 (Constellation Energy, 2015) and 1,563 MW (DTE Energy, 2017) 110 1,182 MW (Central in 2012) 111 3,102 MW (Delta in 2015), 1,650 MW (Gateway, 2017), 1,100 MW (Southeastern, 2017) & 1,100 MW (VACAR, 2016) 112 Comanche Peak 3 & 4 at 3,200 MW, STP 3 & 4 at 2,700 MW & Victoria City Nuclear at 3,200 MW 

NERC-US Projected Fuel-Mix Change for Net Capacity Resources 

2008-2017

0

10,000

20,000

30,000

40,000

50,000

Gas

Coal

Nuclear

Wind

Dual Fuel

Other

ΔMW

NERC-CAN Projected Change for Net Capacity Reources FuelMix 2008-2017

-8,000

-6,000

-4,000

-2,000

0

2,000

4,000

6,000

8,000

Gas Coal Hydro Nuclear Wind Other

ΔMW
Regional Reliability Assessments 

63 2008 Long-Term Reliability Assessment 

Canada shows a substantial drop in coal-fired and nuclear resources (see Figure 31). Ontario 

expects to retire 6,400 MW of coal-fired resources across four facilities and 15 units by 2014, 

fulfilling the commitments called for in the Ontario Power Authority’s Integrated Power Supply 

Plan.113 In addition, the Ontario sub-region forecasts nuclear reductions resulting from of the 

removal of one unit in 2015 (797 MW) and two units in 2016 (1,364 MW total). Decisions have 

not been made at this time about refurbishment or replacement of these nuclear units. Increases 

in Canada of Net Capacity Resources from gas, hydro and wind plant round off the remainder of 

the fuel mix during the ten-year assessment. 

The NERC-wide fuel mix is found in Figure 32. 

NERC - Projected On-Peak Capacity by Fuel-Mix

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

Coal

Gas

Hydro

Nuclear

Dual Fuel

Oil

Pumped Storage

Wind

Other

MW

2008

2017

Regional Demand & Resource Projections 2008-2017 

Resources and Fuel Mix- To improve consistency and increase the granularity and transparency 

of how regional resource projections are represented in NERC assessment reports, NERC’s 

Planning Committee approved new categories for capacity resources and capacity purchases and 

sales. The previously-used categories of “committed” and “uncommitted” resource designations 

used in the 2007 Long-Term Reliability Assessment were replaced with enhanced categories: 1) 

Existing; 2) Planned; 3) Proposed Capacity; and 4) Capacity Purchases & Sales. 114

To better understand the resource acquisition strategy and the relative resource certainty, a 

layered resource graph, deploying the more detailed resource categorization, can show the risk 

profile for future resources to meet capacity margins. These graphs can be used to trend capacity 

margins for comparative assessment against reference margin levels to identify areas where and 

when additional resources may be required. 

 

113 http://www.powerauthority.on.ca/Page.asp?PageID=924&SiteNodeID=320 114 See the Capacity, Demand & Event Definitions section for detailed definitions.
Regional Reliability Assessments 

64 2008 Long-Term Reliability Assessment 

Figure 33 shows the NERC-wide 2008-2017 summer peak demand capacity margins. The 

NERC Reference Margin Level capacity margin level of 13 percent is used to identify 

approximately when additional resources may be needed. While the overall NERC-wide capacity 

margins appear adequate for most resource scenarios, the results for individual 

regions/subregions vary widely, discussed in the regional self-assessment sections. 

 

NERC - Summer Capacity Margin Comparison

-5%

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%

55%

60%

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Margin (%)

NERC Reference Margin Level Existing Certain

Net Capacity Resources Adjusted Potential Resources

Total Potential Resources

Figure 33 shows NERC-wide the existing capacity sufficiently meets the NERC Target Margin 

Level through 2015. However, this includes the combination of a predominately summer 

peaking system (NERC-US) and one that, with the exclusion of Ontario, is a winter peaking 

system (NERC-Canada). Figures 35 and 35 shown below show NERC-US and NERC-Canada 

for their respective peaking season. The NERC Reference Margin Level is different for the U.S. 

(13%) a predominately thermal system, and Canada (9%), a predominately hydro system. 115

 

115 Each region/subregion may have their own specific margin level based on load, generation, and transmission characteristics 

or regulatory requirements. No NERC-wide minimum margin standard or criteria exits. If provided in the data submittals, 

the regional/subregional Target Capacity Margin level is reflected as the NERC Reference Margin Level. If not, NERC 

assigned a 13 percent capacity margin for predominately thermal systems and for predominately hydro systems, 9 percent. 

Figure 33: NERC Summer Capacity Margin 2008-2017 Comparison 
Regional Reliability Assessments 

65 2008 Long-Term Reliability Assessment 

NERC CAN - Winter Capacity Margin Comparison

-20%

-10%

0%

10%

20%

30%

40%

50%

60%

2008/09

2009/10

2010/11

2011/12

2012/13

2013/14

2014/15

2015/16

2016/17

2017/18

Margin (%)

NERC Reference Margin Level Existing Certain

Net Capacity Resources Adjusted Potential Resources

Total Potential Resources

Figure 34: NERC-US Summer Capacity Margin 2008-2017 Comparison 

Figure 35: NERC Canada Winter Capacity Margin 2008-2017 Comparison 

NERC US - Summer Capacity Margin Comparison

-5%

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Margin (%)

NERC Reference Margin Level Existing Certain

Net Capacity Resources Adjusted Potential Resources

Total Potential Resources
Regional Reliability Assessments 

66 2008 Long-Term Reliability Assessment 

Figure 36: NERC US Capacity vs. Total Internal Demand – Summer Peak

Demand - The peak demand projections shown in this report’s tables and charts represent an 

aggregate of weather-normalized projections reported by the regions. In some cases, these 

regional aggregations do not take into account the regional diversity among the various regional 

participants’ peak demands, which, depending on the geographical size, could significantly 

influence the capacity margin comparisons. However, in other cases, as regions can be widespread, resources would not be deliverable, and sub-regional analysis is more meaningful.

The NERC Load Forecasting Working Group (LFWG) develops bandwidths around the 

aggregate U.S. and Canadian demand projections to account for uncertainties inherent in demand 

forecasting (see the Capacity, Demand & Event Definitions section)116. 

For the high demand projection, NERC-wide capacity margin appears adequate through the 

study timeframe when considering Adjusted Potential Resources. However, Net Capacity 

Resources fall short for this high demand forecast in 2013 when considering Net Capacity 

Resources. 

The Total Internal Demand117 growth equates to a ten-year average annual peak demand growth 

in the U.S. for 2008–2017 (See Figure 36) of 1.7 percent in the summer and 1.7 percent in the 

winter, representing a 0.2% increase compared to last year’s report. 

NERC US Capacity vs Demand - Summer

500

600

700

800

900

1,000

1,100

1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016

Thousands of MW

Historic

Demand

High

Demand

Projection

Low

Demand

Projection

Adjusted

Potential

Resources

Net Capacity

Resources

In Canada, the ten-year average annual peak demand growth is 0.8 percent in the summer and 

0.9 percent in the winter or 0.1% higher than last year’s report (see Figure 37). The average 

annual growth in the “high” and “low” band U.S. summer peak demands are 2.8 percent and 0.4 

percent, and in Canada winter peak demand bands are 1.8 percent and -0.1 percent, respectively. 

 

116 For the full report, see http://www.nerc.com/docs/pc/lfwg/NERC_2008-2017_Regional_Bandwidths.pdf 117 Note that Total Internal Demand includes the affect of energy efficiency, but does not include demand response, the impacts 

of both are included in Net Internal Demand 
Regional Reliability Assessments 

67 2008 Long-Term Reliability Assessment 

For the high demand projections, Canada appears adequate for either the Adjusted Potential or 

Net Capacity Resources. 

Figure 37: NERC-Canada Capacity vs. Total Internal Demand – Winter Peak 

Net Capacity

Resources

Tables 13a through 13f are the estimated Resources, Demands and Margins representing a subset 

of the data submitted to NERC. Key years of 2008 summer, 2008/2009 Winter, 2012 summer, 

2012/2013 Winter and 2017 summer and 2017/2018 winter for peak conditions are provided.

Year-to-year actual demand growth rates can vary due to variations in economic conditions and 

weather. Also, actual demands are not corrected for weather or other conditions that deviate from 

the forecast assumptions. 

NERC CANADA Capacity vs Demand - Winter

60

70

80

90

100

110

120

130

1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016

Thousands of MW

Historic

Demand

High

Demand

Projection

Low

Demand

Projection

Adjusted

Potential

Resources
Regional Reliability Assessments 

68 2008 Long-Term Reliability Assessment 

Table 13a: Estimated 2008 Summer Margins (%), Resources and Demands (MW) 

 Net Internal 

Demand 

 Existing 

Certain and 

Net Firm 

Transactions 

 Net 

Capacity 

Resources 

 Adjusted 

Potential 

Resources 

 Total 

Potential 

Resources 

 Existing 

Certain and 

Net Firm 

Transactions 

Margin 

 Net 

Capacity 

Resources 

Margin 

 Adjusted 

Potential 

Resources 

Margin 

 Total 

Potential 

Resources 

Margin 

 NERC 

Reference 

Margin 

Level 

(MW) (MW) (MW) (MW) (MW) (%) (%) (%) (%) (%)

United States

ERCOT 63,725 71,639 72,503 72,503 72,503 11.0% 12.1% 12.1% 12.1% 11.1%

FRCC 44,417 53,077 53,552 53,553 53,552 16.3% 17.1% 17.1% 17.1% 13.0%

MRO 41,260 46,363 47,875 48,083 48,378 11.0% 13.8% 14.2% 14.7% 13.0%

NPCC 58,371 69,740 72,105 72,105 72,275 16.3% 19.0% 19.0% 19.2%

New England 26,150 30,950 31,131 31,131 31,301 15.5% 16.0% 16.0% 16.5% 13.0%

New York 32,221 38,790 40,974 40,974 40,974 16.9% 21.4% 21.4% 21.4% 13.0%

RFC 177,200 213,787 213,787 213,806 213,806 17.1% 17.1% 17.1% 17.1%

RFC-MISO 61,200 70,076 70,076 70,095 70,095 12.7% 12.7% 12.7% 12.7% 12.8%

RFC-PJM 119,700 141,542 141,542 141,542 141,542 15.4% 15.4% 15.4% 15.4% 12.8%

SERC 198,522 235,136 235,485 263,476 264,659 15.6% 15.7% 24.7% 25.0%

Central 42,163 49,725 49,725 54,332 55,515 15.2% 15.2% 22.4% 24.1% 13.0%

Delta 27,936 30,012 30,012 41,616 41,616 6.9% 6.9% 32.9% 32.9% 13.0%

Gateway 19,105 23,711 23,711 27,751 27,751 19.4% 19.4% 31.2% 31.2% 13.0%

Southeastern 48,215 57,466 57,466 63,266 63,266 16.1% 16.1% 23.8% 23.8% 13.0%

VACAR 61,103 74,222 74,571 76,511 76,511 17.7% 18.1% 20.1% 20.1% 13.0%

SPP 43,056 48,993 50,109 58,514 58,514 12.1% 14.1% 26.4% 26.4% 13.0%

WECC 137,925 166,508 169,876 169,880 171,184 17.2% 18.8% 18.8% 19.4% 12.1%

AZ-NM-SNV 30,996 35,135 36,903 36,907 36,907 11.8% 16.0% 16.0% 16.0% 11.7%

CA-MX US 57,507 64,847 69,714 69,714 71,438 11.3% 17.5% 17.5% 19.5% 13.3%

NWPP 37,778 53,376 50,505 50,505 50,518 29.2% 25.2% 25.2% 25.2% 11.9%

RMPA 12,043 13,302 13,702 13,702 13,702 9.5% 12.1% 12.1% 12.1% 10.5%

Total - US 764,476 905,243 915,292 951,920 954,872 15.6% 16.5% 19.7% 19.9% 13.0%

Canada

MRO 5,886 7,594 7,600 7,600 7,600 22.5% 22.6% 22.6% 22.6% 13.0%

NPCC 48,706 65,118 65,417 65,406 65,406 25.2% 25.5% 25.5% 25.5%

Maritimes 3,137 5,827 5,827 5,816 5,816 46.2% 46.2% 46.1% 46.1% 13.0%

Ontario 24,351 28,194 28,493 28,493 28,493 13.6% 14.5% 14.5% 14.5% 14.5%

Quebec 21,218 31,097 31,097 31,097 31,097 31.8% 31.8% 31.8% 31.8% 9.1%

WECC 17,907 21,687 21,995 21,995 21,995 17.4% 18.6% 18.6% 18.6% 10.2%

Total - CAN 72,499 94,399 95,012 95,001 95,001 23.2% 23.7% 23.7% 23.7% 13.0%

Mexico

WECC CA-MX Mex 2,223 2,789 2,540 2,540 2,540 20.3% 12.5% 12.5% 12.5% 12.5%

Total - NERC 1,002,431 839,198 1,012,844 1,049,461 1,052,413 16.3% 17.1% 20.0% 20.3% 13.0%

* MISO and PJM information does not sum to the RFC total due to the handling of OVEC data. RFC information is only for 

demand and capacity within its region.
Regional Reliability Assessments 

69 2008 Long-Term Reliability Assessment 

Table 13b: Estimated 2008/09 Winter Margins (%), Resources and Demands (MW) 

 Net Internal 

Demand 

 Existing 

Certain and 

Net Firm 

Transactions 

 Net 

Capacity 

Resources 

 Adjusted 

Potential 

Resources 

 Total 

Potential 

Resources 

 Existing 

Certain and 

Net Firm 

Transactions 

Margin 

 Net 

Capacity 

Resources 

Margin 

 Adjusted 

Potential 

Resources 

Margin 

 Total 

Potential 

Resources 

Margin 

 NERC 

Reference 

Margin 

Level 

(MW) (MW) (MW) (MW) (MW) (%) (%) (%) (%) (%)

United States

ERCOT 74,640 75,504 75,508 75,508 46,068 38.3% 39.0% 39.0% 39.0% 11.1%

FRCC 56,818 57,510 57,510 57,510 46,093 18.9% 19.9% 19.9% 19.9% 13.0%

MRO 43,400 44,987 45,702 46,034 34,358 20.8% 23.6% 24.8% 25.4% 13.0%

NPCC 74,920 75,772 75,772 76,644 46,185 38.4% 39.0% 39.0% 39.7%

New England 20,892 33,678 34,009 34,009 34,881 38.0% 38.6% 38.6% 40.1% 13.0%

New York 41,242 41,763 41,763 41,763 25,293 38.7% 39.4% 39.4% 39.4% 13.0%

RFC 212,123 141,200 212,257 216,200 217,784 33.4% 33.5% 34.7% 35.2%

RFC-MISO 47,700 67,307 67,307 70,769 70,845 29.1% 29.1% 32.6% 32.7% 12.8%

RFC-PJM 142,561 96,400 142,695 143,093 144,684 32.4% 32.4% 32.6% 33.4% 12.8%

SERC 228,615 176,766 229,627 257,619 258,987 22.7% 23.0% 31.4% 31.7%

Central 46,452 46,454 51,061 52,429 41,908 9.8% 9.8% 17.9% 20.1% 13.0%

Delta 23,877 23,918 35,522 35,522 24,140 -1.1% -0.9% 32.0% 32.0% 13.0%

Gateway 23,631 23,631 27,671 27,671 14,912 36.9% 36.9% 46.1% 46.1% 13.0%

Southeastern 40,506 59,335 59,335 65,135 65,135 31.7% 31.7% 37.8% 37.8% 13.0%

VACAR 75,321 76,290 78,230 78,230 55,299 26.6% 27.5% 29.3% 29.3% 13.0%

SPP 49,107 50,223 59,218 59,218 31,455 35.9% 37.4% 46.9% 46.9% 13.0%

WECC 164,787 113,504 167,770 167,822 168,458 31.1% 32.3% 32.4% 32.6% 12.1%

AZ-NM-SNV 19,468 34,687 37,973 38,025 38,025 43.9% 48.7% 48.8% 48.8% 11.7%

CA-MX US 42,929 62,175 60,387 60,387 60,990 31.0% 28.9% 28.9% 29.6% 13.3%

NWPP 54,620 55,857 55,857 55,921 41,205 24.6% 26.2% 26.2% 26.3% 11.9%

RMPA 13,335 13,377 13,377 13,377 10,398 22.0% 22.3% 22.3% 22.3% 10.5%

Total - US 904,410 635,629 913,650 955,351 960,143 29.7% 30.4% 33.5% 33.8% 13.0%

Canada

MRO 9,074 9,091 9,091 9,091 19.4% 19.5% 19.5% 19.5% 13.0% 7,316

NPCC 74,410 76,036 76,593 76,593 63,170 15.1% 16.9% 17.5% 17.5%

Maritimes 6,314 6,353 6,342 6,342 17.3% 17.8% 17.7% 17.7% 13.0% 5,220

Ontario 27,993 29,398 29,966 29,966 22,900 18.2% 22.1% 23.6% 23.6% 14.5%

Quebec 40,103 40,285 40,285 40,285 35,049 12.6% 13.0% 13.0% 13.0% 9.1%

WECC 23,247 24,532 24,532 24,732 21,664 6.8% 11.7% 11.7% 12.4% 10.2%

Total - CAN 106,731 92,150 109,659 110,216 110,416 13.7% 16.0% 16.4% 16.5% 13.0%

Mexico

WECC CA-MX Mex 1,641 1,951 2,358 2,358 2,358 15.9% 30.4% 30.4% 30.4% 12.5%

Total - NERC 1,013,092 729,420 1,025,667 1,067,925 1,072,917 28.0% 28.9% 31.7% 32.0% 13.0%

* MISO and PJM information does not sum to the RFC total due to the handling of OVEC data. RFC information is only for 

demand and capacity within its region.
Regional Reliability Assessments 

70 2008 Long-Term Reliability Assessment 

Table 13c: Estimated 2012 Summer Margins (%), Resources and Demands (MW) 

 Net Internal 

Demand 

 Existing 

Certain and 

Net Firm 

Transactions 

 Net 

Capacity 

Resources 

 Adjusted 

Potential 

Resources 

 Total 

Potential 

Resources 

 Existing 

Certain and 

Net Firm 

Transactions 

Margin 

 Net 

Capacity 

Resources 

Margin 

 Adjusted 

Potential 

Resources 

Margin 

 Total 

Potential 

Resources 

Margin 

 NERC 

Reference 

Margin 

Level 

(MW) (MW) (MW) (MW) (MW) (%) (%) (%) (%) (%)

United States

ERCOT 72,486 78,843 86,397 116,615 68,833 5.0% 12.7% 20.3% 41.0% 11.1%

FRCC 52,817 59,979 59,979 59,979 48,212 8.7% 19.6% 19.6% 19.6% 13.0%

MRO 45,221 49,529 54,029 61,324 44,993 0.5% 9.2% 16.7% 26.6% 13.0%

NPCC 69,585 72,923 72,923 84,901 61,065 12.2% 16.3% 16.3% 28.1%

New England 27,541 31,246 31,673 31,673 43,651 11.9% 13.0% 13.0% 36.9% 13.0%

New York 38,339 41,250 41,250 41,250 33,524 12.6% 18.7% 18.7% 18.7% 13.0%

RFC 213,787 188,900 219,492 227,911 255,072 11.6% 13.9% 17.1% 25.9%

RFC-MISO 65,200 70,076 72,540 74,493 77,322 7.0% 10.1% 12.5% 15.7% 12.8%

RFC-PJM 127,600 141,542 144,783 150,943 175,581 9.9% 11.9% 15.5% 27.3% 12.8%

SERC 233,581 214,834 240,273 268,712 276,703 8.0% 10.6% 20.1% 22.4%

Central 48,848 50,304 54,774 56,778 44,732 8.4% 11.1% 18.3% 21.2% 13.0%

Delta 29,655 29,655 41,259 43,391 30,352 -2.4% -2.4% 26.4% 30.1% 13.0%

Gateway 23,787 24,332 28,839 28,839 20,000 15.9% 17.8% 30.6% 30.6% 13.0%

Southeastern 53,896 57,736 59,418 65,218 67,833 6.7% 9.3% 17.4% 20.5% 13.0%

VACAR 73,556 76,565 78,622 79,862 65,854 10.5% 14.0% 16.2% 17.5% 13.0%

SPP 48,628 54,328 62,975 67,981 46,248 4.9% 14.9% 26.6% 32.0% 13.0%

WECC 166,578 149,137 175,431 175,435 184,342 10.5% 15.0% 15.0% 19.1% 12.1%

AZ-NM-SNV 34,802 35,026 37,087 37,091 38,399 0.6% 6.2% 6.2% 9.4% 11.7%

CA-MX US 60,731 64,899 72,021 72,021 77,521 6.4% 15.7% 15.7% 21.7% 13.3%

NWPP 53,809 52,123 52,123 54,472 41,004 23.8% 21.3% 21.3% 24.7% 11.9%

RMPA 12,852 14,744 14,744 14,744 13,047 -1.5% 11.5% 11.5% 11.5% 10.5%

Total - US 902,683 822,222 950,798 1,008,361 1,106,917 8.9% 13.5% 18.5% 25.7% 13.0%

Canada

MRO 7,613 8,048 8,048 8,048 16.0% 20.6% 20.6% 20.6% 13.0% 6,394

NPCC 62,761 69,586 71,976 72,444 49,143 21.7% 29.4% 31.7% 32.2%

Maritimes 6,526 6,526 6,580 6,723 49.6% 49.6% 50.0% 51.1% 13.0% 3,289

Ontario 24,504 30,473 32,809 33,135 23,788 2.9% 21.9% 27.5% 28.2% 14.5%

Quebec 31,731 32,587 32,587 32,587 22,065 30.5% 32.3% 32.3% 32.3% 9.1%

WECC 21,889 22,912 22,912 25,196 19,984 8.7% 12.8% 12.8% 20.7% 10.2%

Total - CAN 92,263 100,546 102,936 75,521 105,688 18.1% 24.9% 26.6% 28.5% 13.0%

Mexico

WECC CA-MX Mex 2,769 2,356 2,722 2,722 3,233 -17.5% -1.7% -1.7% 14.4% 12.5%

Total - NERC 997,302 900,512 1,054,066 1,114,019 1,215,838 9.7% 14.6% 19.2% 25.9% 13.0%

* MISO and PJM information does not sum to the RFC total due to the handling of OVEC data. RFC information is only for 

demand and capacity within its region.
Regional Reliability Assessments 

71 2008 Long-Term Reliability Assessment 

Table 13d: Estimated 2012/13 Winter Margins (%), Resources and Demands (MW) 

 Net Internal 

Demand 

 Existing 

Certain and 

Net Firm 

Transactions 

 Net 

Capacity 

Resources 

 Adjusted 

Potential 

Resources 

 Total 

Potential 

Resources 

 Existing 

Certain and 

Net Firm 

Transactions 

Margin 

 Net 

Capacity 

Resources 

Margin 

 Adjusted 

Potential 

Resources 

Margin 

 Total 

Potential 

Resources 

Margin 

 NERC 

Reference 

Margin 

Level 

(MW) (MW) (MW) (MW) (MW) (%) (%) (%) (%) (%)

United States

ERCOT 75,015 81,372 88,926 119,144 49,371 34.2% 39.3% 44.5% 58.6% 11.1%

FRCC 56,458 65,107 65,107 65,107 50,104 11.3% 23.0% 23.0% 23.0% 13.0%

MRO 43,030 47,292 52,426 59,984 37,436 13.0% 20.8% 28.6% 37.6% 13.0%

NPCC 72,041 73,759 73,759 86,424 48,258 33.0% 34.6% 34.6% 44.2%

New England 21,786 31,246 31,673 31,673 44,331 30.3% 31.2% 31.2% 50.9% 13.0%

New York 40,795 42,086 42,086 42,092 26,472 35.1% 37.1% 37.1% 37.1% 13.0%

RFC 212,123 149,100 217,827 229,321 257,729 29.7% 31.6% 35.0% 42.1%

RFC-MISO 51,000 67,307 69,771 74,471 77,300 24.2% 26.9% 31.5% 34.0% 12.8%

RFC-PJM 101,200 142,561 145,801 152,276 178,174 29.0% 30.6% 33.5% 43.2% 12.8%

SERC 227,231 188,972 235,730 264,120 273,164 16.8% 19.8% 28.5% 30.8%

Central 46,197 48,881 53,355 55,632 42,995 6.9% 12.0% 19.4% 22.7% 13.0%

Delta 23,725 24,102 35,706 37,856 25,752 -8.5% -6.8% 27.9% 32.0% 13.0%

Gateway 23,778 24,525 28,675 28,675 15,897 33.1% 35.2% 44.6% 44.6% 13.0%

Southeastern 45,086 58,803 60,485 66,285 68,934 23.3% 25.5% 32.0% 34.6% 13.0%

VACAR 74,729 77,738 80,099 82,067 59,241 20.7% 23.8% 26.0% 27.8% 13.0%

SPP 48,754 53,730 62,916 64,388 34,021 30.2% 36.7% 45.9% 47.2% 13.0%

WECC 165,001 121,657 171,862 171,914 179,603 26.3% 29.2% 29.2% 32.3% 12.1%

AZ-NM-SNV 21,709 34,997 40,134 40,186 41,170 38.0% 45.9% 46.0% 47.3% 11.7%

CA-MX US 45,318 62,097 60,682 60,682 65,008 27.0% 25.3% 25.3% 30.3% 13.3%

NWPP 54,594 55,912 55,912 58,291 43,890 19.6% 21.5% 21.5% 24.7% 11.9%

RMPA 13,334 14,426 14,426 14,426 11,265 15.5% 21.9% 21.9% 21.9% 10.5%

Total - US 899,653 678,919 946,679 1,008,489 1,105,542 24.5% 28.3% 32.7% 38.6% 13.0%

Canada

MRO 9,044 9,415 9,415 9,415 12.5% 16.0% 16.0% 16.0% 13.0% 7,909

NPCC 71,695 79,018 81,640 81,782 62,985 12.1% 20.3% 22.9% 23.0%

Maritimes 6,813 7,038 7,059 7,171 19.2% 21.8% 22.1% 23.3% 13.0% 5,502

Ontario 24,602 30,571 33,172 33,202 20,952 14.8% 31.5% 36.8% 36.9% 14.5%

Quebec 40,280 41,409 41,409 41,409 36,531 9.3% 11.8% 11.8% 11.8% 9.1%

WECC 23,297 25,622 25,622 27,802 24,104 -3.5% 5.9% 5.9% 13.3% 10.2%

Total - CAN 104,036 94,998 114,055 116,677 118,999 8.7% 16.7% 18.6% 20.2% 13.0%

Mexico

WECC CA-MX Mex 2,045 1,830 2,257 2,257 2,768 -11.7% 9.4% 9.4% 26.1% 12.5%

Total - NERC 1,005,519 775,962 1,062,991 1,127,423 1,227,309 22.8% 27.0% 31.2% 36.8% 13.0%

* MISO and PJM information does not sum to the RFC total due to the handling of OVEC data. RFC information is only for 

demand and capacity within its region.
Regional Reliability Assessments 

72 2008 Long-Term Reliability Assessment 

Table 13e: Estimated 2017 Summer Margins (%), Resources and Demands (MW) 

 Net Internal 

Demand 

 Existing 

Certain and 

Net Firm 

Transactions 

 Net 

Capacity 

Resources 

 Adjusted 

Potential 

Resources 

 Total 

Potential 

Resources 

 Existing 

Certain and 

Net Firm 

Transactions 

Margin 

 Net 

Capacity 

Resources 

Margin 

 Adjusted 

Potential 

Resources 

Margin 

 Total 

Potential 

Resources 

Margin 

 NERC 

Reference 

Margin 

Level 

(MW) (MW) (MW) (MW) (MW) (%) (%) (%) (%) (%)

United States

ERCOT 72,486 78,843 86,436 116,811 75,201 -3.7% 4.6% 13.0% 35.6% 11.1%

FRCC 51,475 67,434 67,434 67,434 53,733 -4.4% 20.3% 20.3% 20.3% 13.0%

MRO 45,220 50,126 55,984 65,335 48,625 -7.5% 3.0% 13.1% 25.6% 13.0%

NPCC 69,411 72,750 72,750 85,672 64,145 7.6% 11.8% 11.8% 25.1%

New England 28,971 31,246 31,673 31,673 44,596 7.3% 8.5% 8.5% 35.0% 13.0%

New York 38,165 41,077 41,077 41,077 35,174 7.8% 14.4% 14.4% 14.4% 13.0%

RFC 213,787 201,700 219,632 230,875 267,513 5.7% 8.2% 12.6% 24.6%

RFC-MISO 68,900 70,076 72,540 75,428 80,338 1.7% 5.0% 8.7% 14.2% 12.8%

RFC-PJM 137,000 141,542 144,923 152,940 185,006 3.2% 5.5% 10.4% 25.9% 12.8%

SERC 234,638 236,070 242,498 271,830 302,558 -0.6% 2.7% 13.2% 22.0%

Central 47,379 49,983 54,574 67,518 49,673 -4.8% 0.6% 9.0% 26.4% 13.0%

Delta 29,647 29,647 41,251 46,485 33,144 -11.8% -11.8% 19.7% 28.7% 13.0%

Gateway 23,749 24,314 28,957 28,957 20,997 11.6% 13.6% 27.5% 27.5% 13.0%

Southeastern 60,156 61,905 63,587 69,387 78,640 2.8% 5.4% 13.3% 23.5% 13.0%

VACAR 71,959 74,968 77,661 80,959 72,100 -0.2% 3.8% 7.2% 10.9% 13.0%

SPP 48,390 55,781 64,428 74,354 49,853 -3.0% 10.6% 22.6% 33.0% 13.0%

WECC 166,571 162,763 175,838 175,842 187,512 2.3% 7.4% 7.4% 13.2% 12.1%

AZ-NM-SNV 39,442 35,066 37,336 37,340 39,060 -12.5% -5.6% -5.6% -1.0% 11.7%

CA-MX US 64,598 64,515 71,799 71,799 77,976 -0.1% 10.0% 10.0% 17.2% 13.3%

NWPP 54,127 51,788 51,788 54,861 44,484 17.8% 14.1% 14.1% 18.9% 11.9%

RMPA 12,880 15,418 15,418 16,118 14,747 -14.5% 4.4% 4.4% 8.5% 10.5%

Total - US 901,978 892,090 962,902 1,025,579 1,167,189 1.1% 7.4% 13.0% 23.6% 13.0%

Canada

MRO 7,689 8,297 8,297 8,297 14.0% 20.3% 20.3% 20.3% 13.0% 6,613

NPCC 56,810 64,353 70,123 70,606 49,349 13.1% 23.3% 29.6% 30.1%

Maritimes 6,526 6,526 6,598 6,756 47.5% 47.5% 48.1% 49.3% 13.0% 3,423

Ontario 18,553 24,522 30,220 30,545 23,125 -24.6% 5.7% 23.5% 24.3% 14.5%

Quebec 31,731 33,305 33,305 33,305 22,802 28.1% 31.5% 31.5% 31.5% 9.1%

WECC 21,889 23,402 23,402 25,686 22,489 -2.7% 3.9% 3.9% 12.4% 10.2%

Total - CAN 86,388 96,052 101,822 78,451 104,589 9.2% 18.3% 23.0% 25.0% 13.0%

Mexico

WECC CA-MX Mex 3,598 2,356 2,722 2,722 3,521 -52.7% -32.2% -32.2% -2.2% 12.5%

Total - NERC 990,722 974,139 1,061,676 1,130,123 1,275,299 1.7% 8.2% 13.8% 23.6% 13.0%

* MISO and PJM information does not sum to the RFC total due to the handling of OVEC data. RFC information is only for 

demand and capacity within its region.
Regional Reliability Assessments 

73 2008 Long-Term Reliability Assessment 

Table 13f: Estimated 2017/18 Winter Margins (%), Resources and Demands (MW) 

 Net Internal 

Demand 

 Existing 

Certain and 

Net Firm 

Transactions 

 Net 

Capacity 

Resources 

 Adjusted 

Potential 

Resources 

 Total 

Potential 

Resources 

 Existing 

Certain and 

Net Firm 

Transactions 

Margin 

 Net 

Capacity 

Resources 

Margin 

 Adjusted 

Potential 

Resources 

Margin 

 Total 

Potential 

Resources 

Margin 

 NERC 

Reference 

Margin 

Level 

(MW) (MW) (MW) (MW) (MW) (%) (%) (%) (%) (%)

United States

ERCOT 75,015 81,372 88,965 119,340 54,085 27.9% 33.5% 39.2% 54.7% 11.1%

FRCC 55,116 72,725 72,725 72,725 55,516 -0.7% 23.7% 23.7% 23.7% 13.0%

MRO 42,848 48,019 54,436 63,883 40,067 6.5% 16.6% 26.4% 37.3% 13.0%

NPCC 71,830 73,549 73,549 87,264 50,760 29.3% 31.0% 31.0% 41.8%

New England 22,671 31,246 31,673 31,673 45,382 27.4% 28.4% 28.4% 50.0% 13.0%

New York 40,584 41,876 41,876 41,882 28,089 30.8% 32.9% 32.9% 32.9% 13.0%

RFC 212,123 157,900 217,967 231,959 268,595 25.6% 27.6% 31.9% 41.2%

RFC-MISO 54,300 67,307 69,771 75,406 80,316 19.3% 22.2% 28.0% 32.4% 12.8%

RFC-PJM 106,800 142,561 145,941 153,958 186,024 25.1% 26.8% 30.6% 42.6% 12.8%

SERC 229,454 203,698 237,973 266,885 298,910 11.2% 14.4% 23.7% 31.9%

Central 46,102 48,786 53,343 67,268 46,444 -0.7% 4.8% 12.9% 31.0% 13.0%

Delta 23,717 24,094 35,698 41,036 26,456 -11.5% -9.8% 25.9% 35.5% 13.0%

Gateway 23,825 24,592 28,768 28,768 16,835 29.3% 31.5% 41.5% 41.5% 13.0%

Southeastern 49,625 62,542 64,224 70,024 79,311 20.7% 22.7% 29.1% 37.4% 13.0%

VACAR 73,269 76,278 79,052 82,527 64,338 12.2% 15.7% 18.6% 22.0% 13.0%

SPP 48,563 54,464 63,650 66,528 37,592 22.6% 31.0% 40.9% 43.5% 13.0%

WECC 164,545 131,752 171,100 171,152 181,617 19.9% 23.0% 23.0% 27.5% 12.1%

AZ-NM-SNV 24,525 34,829 40,266 40,318 42,016 29.6% 39.1% 39.2% 41.6% 11.7%

CA-MX US 48,151 61,629 59,063 59,063 64,043 21.9% 18.5% 18.5% 24.8% 13.3%

NWPP 54,739 56,312 56,312 59,399 46,858 14.4% 16.8% 16.8% 21.1% 11.9%

RMPA 13,363 15,164 15,164 15,864 12,634 5.5% 16.7% 16.7% 20.4% 10.5%

Total - US 899,494 731,370 957,169 1,023,321 1,158,862 18.7% 23.6% 28.5% 36.9% 13.0%

Canada

MRO 9,044 9,509 9,509 9,509 8,179 9.6% 14.0% 14.0% 14.0% 13.0%

NPCC 65,713 73,918 79,957 80,122 63,827 2.9% 13.7% 20.2% 20.3%

Maritimes 6,813 7,038 7,083 7,219 15.6% 18.3% 18.8% 20.4% 13.0% 5,749

Ontario 18,620 24,589 30,583 30,612 20,264 -8.8% 17.6% 33.7% 33.8% 14.5%

Quebec 40,280 42,291 42,291 42,291 37,814 6.1% 10.6% 10.6% 10.6% 9.1%

WECC 23,284 26,303 26,303 28,483 26,796 -15.1% -1.9% -1.9% 5.9% 10.2%

Total - CAN 98,041 109,730 115,769 98,802 118,114 -0.8% 10.0% 14.7% 16.4% 13.0%

Mexico

WECC CA-MX Mex 2,648 1,830 2,922 2,922 3,721 -44.7% 9.4% 9.4% 28.8% 12.5%

Total - NERC 999,365 832,820 1,069,821 1,142,012 1,280,697 16.7% 22.2% 27.1% 35.0% 13.0%

* MISO and PJM information does not sum to the RFC total due to the handling of OVEC data. RFC information is only for 

demand and capacity within its region.
Regional Reliability Assessments 

74 2008 Long-Term Reliability Assessment 

Notes for Table 13a through 13f 

Note 1: Existing-Certain and Net Firm Transactions and Net Capacity Resources are reported to be deliverable by 

the regions. 

Note 2: The Inoperable portion of Total Potential Resources may not be deliverable. 

Note 3: The WECC-U.S. peak demands or resources do not necessarily equal the sums of the non-coincident 

WECC-U.S. subregional peak demands or resources because of subregional monthly peak demand diversity. 

Similarly, the Western Interconnection peak demands or resources do not necessarily equal the sums of the noncoincident WECC-U.S., Canada, and Mexico peak demands or resources. Also, the subregional resource numbers 

include utilization of seasonal demand diversity between the winter peaking northwest and the summer peaking 

portions of the Western Interconnection. 

Note 4: The demand side management resources are not necessarily sharable between the WECC subregions and 

are not necessarily sharable within subregions. 

Note 5: WECC CA-MX represents only the northern portion of the Baja California Norte, Mexico electric system 

interconnected with the U.S. 

Note 6: MISO and PJM information does not sum to the RFC total due to the handling of OVEC data. RFC 

information is only for demand and capacity within its region. 

Note 7: These demand and supply forecasts are as of March 31, 2008. 

Note 8: Each region/subregion may have their own specific margin level based on load, generation, and 

transmission characteristics as well as regulatory requirements. If provided in the data submittals, the 

regional/subregional Target Capacity Margin level is adopted as the NERC Reference Margin Level. If not, NERC 

assigned 13 percent capacity margin for predominately thermal systems and for predominately hydro systems, 9 

percent. 
Regional Reliability Assessments 

75 2008 Long-Term Reliability Assessment 

ERCOT Highlights 

This year’s long-term assessment for resource adequacy in 

the ERCOT Region is improved over last year’s outlook. 

With additional generating units that have gone into service 

or have signed interconnection agreements and a lower 

expectation of load growth due to economic expectations, the 

annual reserve margin for the region does not drop below the 

minimum target level of 12.5% until 2013. In addition, there 

are significant amounts of additional generation that are 

being considered for addition in the region, but have not yet 

been developed to the point of meeting the criteria for 

inclusion in this reserve margin calculation. 

The number of planned transmission circuit miles and autotransformer additions over the first 

five years has increased since last year’s long term assessment. The rapid increase in installation 

of new wind generation is expected to result in congestion on multiple constraints until new 

transmission lines are added between West Texas and the rest of the ERCOT system. Later this 

year, the Public Utility Commission of Texas will be completing its Competitive Renewable 

Energy Zone (CREZ) process, which is expected to result in significant additional bulk 

transmission that is not reflected in the current assessment. From an operational perspective, the 

increasing reliance on wind generation is expected to increase operating challenges. Several 

initiatives are underway, at varying stages of resolution, to ensure the appropriate procedures and 

requirements are in place to meet these challenges. 

ERCOT - Summer Capacity Margin Comparison

-5%

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Margin (%)

Region/Subregion Target Margin Existing Certain

Net Capacity Resources Adjusted Potential Resources

Total Potential Resources
Regional Reliability Assessments 

76 2008 Long-Term Reliability Assessment 

ERCOT - Projected On-Peak Capacity by Fuel-Mix

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

Gas

Dual Fuel

Coal

Nuclear

Hydro

Wind

Other

MW

2008

2017

ERCOT Capacity vs Demand - Summer

40

50

60

70

80

90

1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016

Thousands of MW

Historic

Demand

High

Demand

Projection

Low

Demand

Projection

Adjusted

Potential

Resources

Net

Capacity

Resources
Regional Reliability Assessments 

77 2008 Long-Term Reliability Assessment 

ERCOT Self-Assessment 

Demand 

The 2008 long-term forecast for the ERCOT Region is generally lower than last year’s forecast 

due to the slowdown in the forecasted economic conditions. This is reflected in the average 

annual growth rate of this year’s projected annual growth for 2008-2017 of 1.97% which is lower 

in comparison to last year’s forecasted growth rate for 2007-2016 of 2.25%. 

The lower peak demands reflect the expected state of the economy as represented by economic 

indicators that have been found to drive electricity use in the ERCOT Region’s eight weather 

zones, including real per capita personal income, population, gross domestic product, and various 

employment measures including non-farm employment and total employment. 

In the long-term, real personal per-capita income is expected to level-off or decline in a slight to 

medium fashion due to wage rates experiencing modest growth, only slightly faster than 

inflation, due to lower productivity growth. Texas non-farm employment continues to grow 

faster than the U.S. The gross domestic product (GDP) also shows a lower level and growth rate 

from 2008 to 2018 when compared to last year’s forecast. 

Given the net effects of the economic indicators used in the 2008 LTDF forecast, they indicate 

slowdown of the economy in the long-run. The long-run impact on the forecast due to economic 

slowdown is projected to start around 2010. Its effects are projected to translate into a 4.50% 

decline in energy and a 3.31% decline in peak demand by 2018, when compared to last year’s 

forecast. 

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. The weather assumptions 

on which the forecasts are based represent an average weather profile (50/50). An average 

weather profile is calculated for each of the eight weather zones in the ERCOT grid, which are 

used in developing the forecast. These average weather profiles are based on a Rank-Median 

method. This method ranks the yearly temperatures from highest to lowest for all years in the 

database and assigns the ranked temperatures to a calendar. The calendar is selected using a 

minimum squared error criterion. Median temperatures are preferred as they are not affected as 

much by outliers as the average. 

The actual demands used for forecasting purposes are coincident hourly values across the 

ERCOT Region. The data used in the forecast is by weather zones. 

Two programs are available that explicitly modify the forecasted peak demand for the region. 

The LaaRs program (Load Acting as a Resource) which amounts to approximately 1059 MW. 

The LaaR capacity is available through ERCOT’s ancillary services market. In addition, the 

Texas Legislature increased the mandatory amount of energy efficiency reduction in demand that 

each investor-owned utility in ERCOT must achieve. The effect of this increase on system peak 

demand is expected to be 143MW in 2008 and 160MW in 2009 and thereafter. 

To assess the impact of weather variability on the peak demand for ERCOT, alternative weather 

scenarios are used to develop extreme MW forecasts. A high demand scenario is produced using 
Regional Reliability Assessments 

78 2008 Long-Term Reliability Assessment 

the 90th percentile of the temperatures in the database spanning the last fourteen years available. 

The lower temperatures that rank in the bottom 10th percentile of the database are also used to 

produce a lower range forecast. 

The extreme temperatures are input into the load-shape and energy models to obtain the 

forecasts. The higher temperature assumptions consistently produce MW forecasts that are 

approximately 5.5% higher than the base forecasts (50/50). Together the forecasts from these 

temperature scenarios are usually referred to as 90/10 MW forecasts. 

Generation 

The amount of Existing Certain capacity is 70,886 MW for the summer periods. Of this amount, 

480 MW is from wind generation and 53MW is from biomass. Existing Uncertain118 capacity is 

9,231 MW, of which 4,979 MW is from wind generation. Planned capacity119 additions range 

from 864 MW in 2008/2009 to 6,357 MW starting in 2011 / 2012 and continuing through the 

assessment period. Wind generation accounts for 371 MW of this Planned amount. Proposed 

capacity120 resources expected to be in-service amount to 5,787 MW in 2009 / 2010 and 

increasing to 37,968 MW in 2013 / 2014 through the rest of the study period. Wind capacity 

accounts for 3,728 MW of this Proposed amount 

Purchases and Sales on Peak 

ERCOT has only limited planned purchases and sales with other regions. There is 

approximately 50 MW tied to a long term contract for purchase from the SPP region of firm 

power and transmission (on SPP side) from specific generation. There are no other known 

purchases existing or under study. 

SPP members’ ownership of 247 MW of a power plant located in ERCOT results in a transfer of 

this amount from ERCOT to SPP. There are no other known firm sales from the ERCOT Region 

existing or under study. ERCOT does not share reserves with entities outside the region but does 

have emergency support agreements with both CFE and SPP. 

Fuel

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 seven 

day 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. . 

 

118 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 119 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. Planned capacity additions are included in reserves. 120 Proposed capacity additions include all other generation that has requested interconnection agreement, with wind generation 

counted at its effective load carrying capability. Proposed capacity additions are not included in reserves. 
Regional Reliability Assessments 

79 2008 Long-Term Reliability Assessment 

ERCOT will initiate its Emergency Electric Curtailment Plan (EECP)121 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. 

Transmission – 

Planned Improvements identified for the first time in this year’s assessment include a new 345 

kV transmission line in the East weather zone to alleviate the need for a special protection 

system (SPS), a new 345 kV switching station in northwest Houston to increase North to 

Houston transfer capability, and additional autotransformer and 138 kV line upgrades in the 

Dallas-Fort Worth metropolitan area. In addition, two new 345 kV transmission lines and a new 

345 kV switching station were included in the West region due to the additional wind generation 

in the West region. Additional findings of the assessment are: 

• The numbers of planned transmission circuit miles and autotransformer additions for the 

next five years have increased from the level included in last year’s five year plan. 

• Continued rapid increase in the installation of new wind generation in West Texas is 

expected to result in congestion on multiple constraints and West to North transfers until 

new bulk transmission lines are added between West Texas and the rest of the ERCOT 

system. 

The Public Utility Commission of Texas will be completing its Competitive Renewable Energy 

Zone (CREZ) process this summer. This process may result in significant additional plans for 

bulk transmission. 

Operational Issues 

No major facility outages, regulatory restrictions, or environmental requirements are currently 

expected during the assessment period that would significantly impact reliable operations. 

Ongoing operational challenges during the assessment period are expected to center around 

transmission congestion management and operating with reduced capacity reserve margins. 

The continued increase in installed wind generation has the potential to increase operating 

challenges. ERCOT has recently implemented a wind power forecasting system to allow 

operators to take appropriate actions when changes or increased uncertainty in wind power 

output are forecasted. In addition, congestion management associated with the increased wind 

generation is likely to require increased attention. Finally, ERCOT recently completed a study of 

the impact of increased wind generation in ancillary services requirements, which are expected to 

increase at the projected levels of installed wind generation. 

Reserve margins will likely be at minimum levels over the assessment period. This, coupled with 

resource vulnerability to winter gas curtailments, could increase the likelihood that operators will 

need to initiate emergency procedures such as the EECP in the future. 

The major market redesign, approved by the Public Utility Commission of Texas (PUCT) will 

change current congestion management procedures from a zonal to a nodal-based system. This 

transition, which will occur during the assessment period, may present challenges in 

implementing new operating computing systems but should also improve the efficiency of 

transmission congestion management. 

 

121 See ERCOT Protocols Section 5.6.6.1 at http://www.ercot.com/mktrules/protocols/current.html
Regional Reliability Assessments 

80 2008 Long-Term Reliability Assessment 

Reliability Assessment Analysis 

ERCOT has an adequate reserve margin through 2012 but the reserve margin falls below the 

12.5 percent minimum level used throughout the assessment period starting in 2013, based on 

new generation with signed interconnection agreements and existing resources. The minimum 

reserve margin target of 12.5 percent is applied to each year of the ten year assessment period 

and is based on a Loss-of-Load Expectation (LOLE) analysis, resulting in no more than one day 

in ten years loss of load, performed in 2005. 

ERCOT almost entirely uses internal resources to serve its load and reserves, with the exception 

of a 50 MW purchases from SPP and emergency support agreements with SPP and CFE. 

ERCOT has 71,750 MW of installed generation (summer), with additional signed 

interconnection agreements for 5,987 MW of new fossil fuel generation and 371 MW of wind 

generation over the next ten years. 

Reserve margins for the Region have improved since last year’s assessment, due to the lower 

demand forecast and several additional wind and gas-fired generating units that have signed 

interconnection agreements. 

ERCOT should have sufficient capacity even for a peak demand that is as high as the 90th

percentile of the weather sensitivity in the load forecast, which could result in a peak demand 

5.5% higher than the expected peak demand. An extremely hot summer that results in load 

levels significantly above forecast, higher than normal unit forced outage rates, or financial 

difficulties of some generation owners that may make it difficult for them to obtain fuel from 

suppliers are all risk factors that alone or in combination could result in inadequate supply. In 

the event that occurs, ERCOT will implement its Emergency Electric Curtailment Plan (EECP) 

(See Section 5.6.6.1 of the ERCOT Protocols)122. The EECP includes procedures for use of 

interruptible load, voltage reductions, procuring emergency energy over the DC ties, ISOinstructed demand response procedures and are in place and are described in the ERCOT 

Operating Guides Section 4.5 Emergency Electric Curtailment Plan (EECP). 123

Only 8.7% of existing wind generation nameplate capacity is counted on for Certain generation, 

based on an analysis of the effective load carrying capability of wind generation in the region. 

The remaining existing wind capacity amount is included in the Uncertain generation amount. 

There are no currently-known unit retirements which have significant impact on reliability. 

ERCOT does not have a formal definition of generation deliverability. However, in the planning 

horizon, ERCOT performs a security-constrained unit commitment and economic dispatch 

analysis for the upcoming year. This analysis is performed on an hourly basis for a variety of 

conditions to ensure deliverability of sufficient resources to meet a load level that is 

approximately 10 percent higher than the expected coincident system peak demand plus 

operating reserves. Load data for this analysis is based on the non-coincident demands projected 

by the transmission owners. Operationally, transmission operating limits are adhered to through 

market-based generation redispatch directed by ERCOT as the balancing authority and reliability 

coordinator. Operational resource adequacy is also maintained by ERCOT through market-based 

procurement processes (See Sections six and seven of the ERCOT Protocols124). 

 

122 http://www.ercot.com/mktrules/protocols/current.html 123 http://www.ercot.com/mktrules/guides/operating/current.html. 124 http://www.ercot.com/mktrules/protocols/current.html
Regional Reliability Assessments 

81 2008 Long-Term Reliability Assessment 

ERCOT has interconnections through DC ties with the Eastern Interconnect and with Mexico. 

The maximum imports/export over these ties is 1,106 MW. These ties can be operated at a 

maximum import and export provided there are no area transmission elements out of service. In 

the event of a transmission outage in the area of these ties, studies will be run during the outage 

coordination period for the outages to see if any import/export limits are needed. 

The Public Utility Commission of Texas will be completing its Competitive Renewable Energy 

Zone (CREZ) process this summer. This process may result in significant additional plans for 

bulk transmission to enable wind generation in West Texas to be able to serve load in the rest of 

the ERCOT Region. 

The continued rapid installation of new wind generation in West Texas is expected to result in 

congestion on multiple constraints within and out of West Texas for the next several years until 

new bulk transmission lines are added between West Texas and the rest of the ERCOT system. 

This is not expected to limit deliverability during peak periods, since only 8.7% of the installed 

wind capacity is counted for reserve purposes. 

 

ERCOT regularly performs transient dynamics and voltage studies. Small signal stability studies 

were performed as part of the West-North stability study. There are no anticipated stability 

issues that could affect reliability, however ERCOT closely monitors a west-north stability limit 

and a Rio Grande valley voltage limit. 

In the operations planning horizon, ERCOT performs off-line transient stability studies for 

specific areas of the region as needed. The results of these studies are used in real-time and near 

real-time monitoring of the grid. 

 Operating Procedure 2.4.3 VSAT (Voltage Stability Analysis Tool) describes the procedure to 

monitor the system and to prevent voltage collapse using the online voltage stability analysis 

tool. Different scenarios along with the MW safety margins are described and mitigation 

procedures are prescribed based on VSAT results. Once the prescribed action is communicated, 

taken and verified VSAT will be rerun with the new topology. 

No explicit minimum dynamic reactive criteria exist, however reactive margins are maintained in 

the major metropolitan areas. Areas of dynamic and static reactive power limitations are Corpus 

Christi, Houston, Dallas/Ft. Worth, Rio Grande Valley, South to Houston generation, South to 

Houston load, North to Houston Generation and North to Houston load. These areas and 

mitigation procedures are found in Operating Procedure 2.4.3.125 ERCOT plans for a 5% voltage 

stability margin for category A and category B contingencies and a 2.5% margin for category C 

contingencies126. ERCOT planning criteria are intended to maintain sufficient dynamic reactive 

capability to maintain system voltages within the range for which generators are expected to 

remain online. 

UVLS schemes are deployed in the following areas: Houston ~ 4500 MW, DFW ~ 3500 MW, 

Rio Grande Valley ~ 650 MW. Additional UVLS deployments in other areas have been 

considered, but at this time there are no implementation plans. The Houston and DFW 

 

125 http://www.ercot.com/mktrules/guides/procedures/TransmissionSecurity_V3R89.doc 126 http://www.ercot.com/mktrules/guides/operating/2007/07/05/05-070107.doc 
Regional Reliability Assessments 

82 2008 Long-Term Reliability Assessment 

deployments are intended to provide a “safety net” and are not targeted to specific events. 

UVLS are not generally relied upon to survive NERC Category B & C events and system 

reinforcements may be made to limit the amount of load shed that is necessary under certain 

extreme contingencies (NERC Category D events). The Valley deployment is intended to 

prevent (local) voltage collapse that may result following certain Category C contingencies. 

ERCOT is not generally reliant on single gas pipelines or import paths such that the long term 

outage of one of these types of systems would lead to loss of significant amounts of generating 

capacity. ERCOT is not currently experiencing drought conditions and reservoir levels are 

currently at or near full capacity nor does it expect significant capacity reduction implications 

due to low water levels. 

Transmission Service Providers (TSPs) and ERCOT perform a full battery of steady-state and 

dynamic contingency analyses on an on-going basis to test the performance of the planned 

system against the standards of TPL-001 through TPL-004. The TSPs are responsible for 

resolving unacceptable results through the provision of Transmission Facilities, etc. in 

accordance with Op. Guide 5.1.4. Additional transmission system upgrades are planned to 

resolve any future problems, resulting in the planned transmission discussed in the Transmission 

section. . 

ERCOT has recently implemented a wind power forecasting system to allow operators to assess 

differences with the resource plans submitted by scheduling entities for wind generation and take 

appropriate actions. 

Aging infrastructure is not expected to result in significant reliability impacts. Many of the older 

gas-fired generating units in the ERCOT Region have been mothballed or retired. Fault currents 

in the region have not yet exceeded the levels for which for which applications using 

commercially available 345kV breakers can be designed. The ERCOT region does not have 

guidelines for on-site, spare generator step-up (GSU) and auto transformers. Individual 

transmission owners may participate in programs to share spare transformers, but the region as a 

whole does not. 

Other region-specific issues that were not mentioned above 

ERCOT will be implementing a new market design and related systems during the assessment 

period which should allow for more efficient management of congestion. Entities in the ERCOT 

Region are handling workforce retention and recruitment issues independently. 

Region Description 

The ERCOT Region is a separate electric interconnection located entirely in the state of 

Texas and operated as a single balancing authority. Texas RE, a functionally 

independent division of ERCOT, performs the regional entity functions described in the 

Energy Policy Act of 2005 for the ERCOT region. ERCOT has 251 members that 

represent independent retail electric providers; generators, and power marketers; 

investor-owned, municipal, and cooperative utilities; and retail consumers. It is a 

summer-peaking region responsible for about 85 percent of the electric load in Texas 

with a 2006 peak demand of 62,339 megawatts. ERCOT serves a population of more than 

20 million in a geographic area of about 200,000 square miles. Additional information is 

available on the ERCOT web site.
Regional Reliability Assessments 

83 2008 Long-Term Reliability Assessment 

FRCC Highlights 

All Florida utilities are required to meet the Florida Public 

Service Commission (FPSC) reserve margin. Therefore, much of 

the resources in the 6-10 year timeframe are not sited, rather 

represent industry’s obligation to meet this reserve margin. 

While FRCC reports adequate resources through 2017, not sited 

plants are included in the data provided in the self assessment. 

Much of these planned generation resources are not sited but are 

considered committed by FRCC and deemed to be deliverable. 

Based on the aforementioned, the Florida Reliability Coordinating Council (FRCC) expects to 

have an adequate generating reserve margin with transmission system deliverability throughout 

the 2008-2017 reliability assessment to meet the forecasted growth in peak demand and energy 

through the same time frame. The FRCC Region expects to serve the forecasted firm peak 

demand and energy requirements reliably through 2017 by adding a net 15,959 MW of 

resources. In addition, existing uncertain merchant plant capability of 1966 MW is available by 

2017 as potential future resources of FRCC members and others. 

The transmission capability within the FRCC is expected to be adequate to supply firm customer 

demand and to provide planned firm transmission service. In order to maintain an adequate 

transmission system, the FRCC members plan to construct 508 miles of 230 kV and 80 miles of 

500 kV transmission lines through 2017. Operational issues in the Central Florida area are 

expected through the summer of 2010. Unplanned outages of generating units may aggravate the 

transmission system serving the Central Florida area. However, it is anticipated that existing 

operational procedures, pre-planning and training will adequately manage and mitigate the 

impacts to the bulk transmission system in the Central Florida area. After 2010, planned 

transmission improvements in the Central Florida area are expected to mitigate these operational 

issues. 

The FRCC Region meets the NERC’s TPL Standards by performing the required transmission 

assessments representing the 10 year planning horizon. The FRCC Region develops detailed 

transmission assessments for the 1-5 year time frame recognizing the fact that generation 

expansion plans are known with a higher degree of confidence and most planned transmission 

projects and corresponding in-service dates are known. 

The FRCC Region performs transmission assessments representing the 6-10 year time frame 

recognizing the uncertainties related to future generation siting and corresponding transmission 

expansion to support future generation and load growth. All Florida utilities are required to meet 

the Florida Public Service Commission (FPSC) reserve margin. Therefore, even if future 

generation plans are not firm, the utilities must show that they plan to maintain these reserve 

margin levels throughout the planning horizon. Approximately half of the generation planned in 

the 6-10 year time frame us not sited and may require additional transmission sensitivity 

assessments. The transmission system is evaluated in the 6-10 year time frame to identify 

possible emerging concerns, monitor known concerns, monitor the effects of planned projects 

and identify major projects that may require long lead times. In addition, the transmission 

expansion plans representing the years 6-10 are typically under review by most transmission 

owners still considering multiple alternatives for each project.
Regional Reliability Assessments 

84 2008 Long-Term Reliability Assessment 

FRCC - Summer Capacity Margin Comparison

-5%

0%

5%

10%

15%

20%

25%

30%

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Margin (%)

Region/Subregion Target Margin Existing Certain

Net Capacity Resources Adjusted Potential Resources

Total Potential Resources

FRCC - Projected On-Peak Capacity by Fuel-Mix

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

Gas

Oil

Coal

Nuclear

Other

MW

2008

2017
Regional Reliability Assessments 

85 2008 Long-Term Reliability Assessment 

FRCC Capacity vs Demand - Summer

30

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86 2008 Long-Term Reliability Assessment 

FRCC Self-Assessment 

Introduction 

FRCC expects to have adequate generating capacity reserves with transmission system 

deliverability throughout the 10 year period. In addition, existing uncertain merchant plant 

capability raging from 1,054 MW to 1966 MW is available as potential future resources of 

FRCC members and others. 

The transmission capability within the FRCC region is expected to be adequate to supply firm 

customer demand and to provide planned firm transmission service. Operational issues can 

develop due to unplanned outages of generating units within the FRCC Region. However, it is 

anticipated that existing operational procedures, pre-planning, and training will adequately 

manage and mitigate the impacts to the bulk transmission system. 

Demand 

FRCC uses historical weather databases consisting of as much as 58 years of data for the weather 

assumptions used in their forecasting models. Historically, the FRCC has high-demand days in 

both the summer and winter seasons. However, because the region is geographically a 

subtropical area, a greater number of high-demand days normally occur in the summer. As such, 

this report will address the summer load values. 

The aggregated peak demand in the FRCC region for 2007 was 46,676 MW as compared to a 

peak demand forecast of 46,878 MW. The 2008 ten year demand forecast for the FRCC region 

exhibits a compounded average annual growth rate of 2.1 percent over the next ten years 

compared to last year’s compounded average annual growth rate of 2.2 percent. The decrease in 

peak demand forecast growth rate is attributed to an increase in demand side management 

participation as well as higher electricity costs and a decrease in economic development in 

Florida. The 2008 ten year net internal demand forecast includes the effects of 3,613 MW of 

potential demand reductions from the use of load management (1,834 MW of residential & 1,073 

MW of commercial/industrial) and interruptible demand (706 MW) by 2017. 

FRCC employs two different techniques to assess the peak demand uncertainty and variability. 

First, FRCC develops regional bandwidths or 80 percent confidence intervals on the projected 

demand. The 80 percent confidence intervals on peak demand can be interpreted to mean that 

there is a 10 percent probability that in any year of the forecast horizon that actual observed load 

could exceed the high band. Likewise, there is a 10 percent probability that the actual observed 

load in any year could be less than the low band in the confidence interval. The purpose of 

developing bandwidths on peak demand is to quantify uncertainties of demand at the regional 

level. This would include weather and non-weather demand variability such as demographics, 

economics, and price of fuel and electricity. 

Monte Carlo simulations on peak demands are performed to arrive at a probabilistic distribution 

as to range and likelihood of this range of outcomes of peak demand. Factors that determine the 

level of demand for electricity are assessed in terms of their own variability and this variability is 

incorporated into the simulations. The regional aggregated peak demand for the FRCC is 

established using these simulations. 
Regional Reliability Assessments 

87 2008 Long-Term Reliability Assessment 

Generation 

FRCC supply-side resources considered for this 10 year assessment are categorized as Existing 

Certain, Existing Uncertain and Planned. The FRCC Region counts on 50,629 MW of Existing 

Certain resources of which 55 MW are hydro and 462 MW are Biomass.127 There are a total of 

1,054 MW of Existing Uncertain resources identified for 2008 and increasing to 1,966 MW by 

2017. In addition, there are a total of 476 MW of Planned resources for 2008 of which 11 MW 

are Biomass. Planned resources by 2017 are expected to be 15,959 MW of which 201 MW are 

categorized as Biomass 

FRCC entities have an obligation to serve and this obligation is reflected within each entity’s 10-

Year Site Plan file annually with the Florida Public Service Commission. Therefore, FRCC 

entities consider all future capacity resources as “Planned” and included in Reserve Margin 

calculations. 

Purchases and Sales 

The FRCC Region does not consider non-firm, expected or provisional purchases and sales as 

capacity resources in the determination of the Region’s Reserve Margin. The expected firm 

interregional purchases for 2008 are 2,448 MW and expected to decrease by 2017 to 846 MW. 

The FRCC Region does not rely on external resources for emergency imports and reserve 

sharing. However, there are emergency power contracts (as available) in place between SERC 

and FRCC members 

Fuel 

Although the FRCC has reviewed various types of fuel supply vulnerability issues in the past, the 

increased reliance of generating capacity on natural gas has caused the FRCC to address this fuel 

type specifically. The FRCC continues coordination efforts among natural gas suppliers and 

generators within the region. The recently revised FRCC Generating Capacity Shortage Plan128

includes specific actions to address capacity constraints due to natural gas availability constraints 

and includes close coordination with the pipeline operators serving the Region. The FRCC 

Operating Committee has also developed the procedure, FRCC Communications Protocols – 

Reliability Coordinator, Generator Operators and Natural Gas Transportation Service 

Providers129, to enhance the existing coordination between the FRCC Reliability Coordinator and 

the natural gas pipeline operators and in response to FERC Order 698. 

Currently, the expected percentage of generation capacity whose primary fuel is natural gas is 

58% and that whose primary fuel is coal-fired is 14% within the FRCC Region by 2017. 

Presently, the FRCC Region is not anticipating any fuel supply and/or delivery problems for 

either natural gas or coal. 

Transmission 

Currently, individual transmission owners plan to construct 508 miles of 230 kV and 80 miles of 

500 kV transmission lines during the 2008-2017 planning horizon. The existing transmission 

system of the FRCC Region consists of 1,350 miles of 500 kV transmission lines and 

approximately 5,850 miles of 230 kV transmission lines. 

 

127 The FRCC Region categorizes the following fuels as Biomass: Agricultural by-products, biogases, straw, energy crops, 

municipal solid waste, sludge waste, peat, railroad ties, utility poles, wood chips and other solids. 128 See pages P6:2-32 of the document: 

https://www.frcc.com/Reliability/Shared%20Documents/FRCC%20Handbook%200208.pdf 129 https://www.frcc.com/Reliability/Shared%20Documents/FRCC%20Communications%20Protocols%20102207.pdf 
Regional Reliability Assessments 

88 2008 Long-Term Reliability Assessment 

Operational Issues 

No transmission maintenance outages of any significance are scheduled during seasonal peak 

periods over the forecast horizon. Scheduled transmission outages are typically performed 

during off seasonal peak periods to minimize any impact to the bulk power system. In addition, 

there are no foreseen environmental and/or regulatory restrictions that can potentially impact 

reliability in the FRCC region throughout the assessment period. 

Reliability Assessment Analysis 

The Florida Public Service Commission (FPSC) requires all Florida utilities to file an annual Ten 

Year Site Plan130 that details how each utility will manage growth for the next decade. The data 

from the individual plans is aggregated into the FRCC Load and Resource Plan131 that is 

produced each year and filed with the Florida Public Service Commission. The FRCC 2008 

Load and Resource Plan shows the average FRCC Reserve Margin of 29% over the winter peaks 

and a 24% Reserve Margin over the summer peaks for the next ten years. The 15% (20% for 

Investor Owned Utilities) Reserve Margin criteria required by the FPSC applies to all 10 years of 

the planning horizon. The calculation of reserve margin includes firm imports into the region 

and does not include excess merchant generating capacity (energy only) that is not under a firm 

contract with a load serving entity. 

The FRCC has historically used the Loss-Of-Load-Probability (LOLP) analysis to confirm the 

adequacy of reserve levels for peninsular Florida. The LOLP analysis incorporates system 

generating unit information (e.g., Availability Factors and Forced Outage Rates) to determine the 

probability that existing and planned resource additions will not be sufficient to serve forecasted 

loads. The objective of this study is to establish resource levels such that the specific resource 

adequacy criterion of a maximum LOLP of 0.1 day in a given year is not exceeded. The results 

of the most recent LOLP analysis conducted in 2006 indicated that for the “most likely” and 

extreme scenarios (e.g., extreme seasonal demands; no availability of firm and non-firm imports 

into the region; and the non-availability of load control programs), the peninsular Florida electric 

system maintains a LOLP well below the 0.1 day per year criterion. The FRCC is planning to 

conduct the next LOLP analysis by 2009. 

The amount of resources internal to the region or subregion that are relied on to meet the 

minimum 15% Reserve Margin throughout the assessment period varies from 51,104 MW to 

66,588 MW. The amount of resources external to the region/subregion that are relied on to meet 

the Reserve Margin for the assessment period vary from 2,448 MW to 846 MW by 2017. 

FRCC is projecting a net increase (i.e., additions less removals) of 15,959 MW of new installed 

capacity over the next decade, compared to the 14,792 MW projected by last year’s ten-year 

forecast. Of this net increase, 12,842 MW are designated for gas-fired operation in either 

simple-cycle or combined-cycle configurations, 738 MW132 are anticipated for coal-fired 

operation, 2,927 MW designated as new and upgraded nuclear, 201 MW are designated as 

Biomass, and 749 MW are related to oil-fired units that have been de-rated, retired and/or 

 

130https://www.frcc.com/Planning/default.aspx?RootFolder=%2fPlanning%2fShared%20Documents%2fTen%20Year%20Site%

20Plans%2f2008&FolderCTID=&View=%7bFBDE89E4%2dE66F%2d40EE%2d999D%2dCFF06CF2A726%7d 131 https://www.frcc.com/Planning/Shared%20Documents/Load%20and%20Resource%20Plan/2008%20LRP_Web.pdf 132 The expected coal-fired generation decreased by 3889 MW since 2007 primary due to environmental concerns at the State 

level. The majority of this decrease in planned coal-fired generation was replaced with gas-fired units. 
Regional Reliability Assessments 

89 2008 Long-Term Reliability Assessment 

converted to another fuel type. Gas-fired generation continues to dominate a high percentage of 

new generation. It is forecast that electrical energy produced from natural gas generators will 

increase from 40 percent in 2007 to 55 percent in 2017. 

For capacity constraints due to inadequate fuel supply, the FRCC State Capacity Emergency 

Coordinator (SCEC) along with the Reliability Coordinator (RC) have been provided with an 

enhanced ability to assess Regional fuel supply status by initiating Fuel Data Status reporting by 

Regional utilities. This process relies on utilities to report their actual and projected fuel 

availability along with alternate fuel capabilities, to serve their projected system loads. This is 

typically provided by type of fuel and expressed in terms relative to forecast loads or generic 

terms of unit output, depending on the event initiating the reporting process. Data is aggregated 

at the FRCC and is provided, from a Regional perspective, to the RC, SCEC and governing 

agencies as requested. Fuel Data Status reporting is typically performed when threats to Regional 

fuel availability have been identified and is quickly integrated into an enhanced Regional Daily 

Capacity Assessment Process along with various other coordination protocols to ensure accurate 

reliability assessments of the Region and also ensure optimal coordination to minimize impacts 

of Regional fuel supply issues and/or disruptions. 

Fuel supplies continue to be adequate for the region and these supplies are not expected to be 

impacted by extreme weather during peak load conditions. There are no identified fuel 

availability or supply issues at this time. Based on current fuel diversity, alternate fuel capability 

and preliminary study results, the FRCC does not anticipate any fuel transportation issues 

affecting capability during peak periods and/or extreme weather conditions. 

The FRCC ensures resource adequacy by maintaining a minimum 15% Reserve Margin to 

account for higher than expected peak demand due to weather or other uncertainties. In addition, 

there are operational measures available to reduce the peak demand such as the use of 

Interruptible/Curtailable load, DLC (HVAC, Water Heater, and Pool Pump), Voltage Reduction, 

customer stand-by generation, emergency contracts and unit emergency capability. 

The FRCC Region has not identified any unit retirements that could have a significant impact on 

reliability. The majority of the units in the FRCC Region that are classified to be retired are 

typically converted and re-powered to run on natural gas. 

The FRCC Region does not have an official definition for deliverability. However, the FRCC 

Transmission Working Group (composed of transmission planners from FRCC member utilities) 

conducts regional studies 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 

Bulk Electric System (BES). In addition, the FRCC Transmission Working Group evaluates 

planned generator additions to ensure the proposed interconnection and/or integration is 

acceptable to maintain the reliability for the BES within the FRCC Region. Presently, the FRCC 

has not identified any deliverability concerns with regards to firm resources. 

Availability and deliverability of external resources are ensured by firm transmission service, 

purchase power contracts and transmission assessments. These external resources were included 

in the “FRCC Long Range Study (2009 – 2017)” demonstrating the deliverability of these 

resources and no deliverability concerns identified. 
Regional Reliability Assessments 

90 2008 Long-Term Reliability Assessment 

Major transmission additions required to support the addition of new resources in the 2013 – 

2017 time frame include, but not limited to, major 500 kV (~80 miles) and 230 kV (~160 miles) 

transmission lines. Construction of 500 kV transmission lines is considered to be a long lead 

time project. 

The FRCC Region is planned and operated such that NERC Reliability Standards are met 

without the need to identify any specific criteria for minimum dynamic reactive reserve 

requirements or transient voltage-dip criteria. Transient and dynamic stability studies are 

performed by the FRCC and no issues have been identified that would impact years 1-5 of the 

time period. Small signal analysis is performed when damping issues are identified during 

transient and/or dynamic stability studies. Voltage security assessments performed in the Region 

involve identifying the worst case conditions such as the unavailability of multiple units. In 

addition, the FRCC has performed load sensitivity analyses in the short term time frame using 

available load models representing induction motors and no issues have been identified. 

Under firm transactions, reactive power-limited areas can be identified during transmission 

assessments performed by the FRCC. These reactive power-limited areas are typically localized 

pockets that do not affect the bulk power system. The “FRCC Long Range Study (2009 – 

2017)” did not identify any reactive power-limited areas that would impact the bulk electric 

system during the entire planning horizon time period. The FRCC Region has not identified the 

need to develop specific criteria to establish a voltage stability margin. 

The FRCC Region has approximately 700 MW of load set for Under Voltage Load-Shedding 

(UVLS) in localized areas to prevent voltage collapse as a result of a contingency event. The 

UVLS system is designed with multiple steps and time delays to shed only the necessary load to 

allow for voltage recovery. At this time no additional load is targeted by UVLS throughout the 

planning horizon time period. 

Based on past operating experience with hurricane impacts to the fuel supply infrastructure 

within the Region, the FRCC revised its Generating Capacity Shortage Plan133 in 2007. This 

plan can distinguish between generating capacity shortages caused by abnormally high system 

loads and unavailable generating facilities from those caused by short-term, generating fuel or 

availability constraints. Since a significant portion of electric generation within Florida uses 

remotely supplied natural gas, the plan specifically distinguishes generating capacity shortages 

by primary causes (e.g., hurricanes and abnormally high loads) in order to provide a more 

effective Regional coordination. 

Currently, the FRCC Region is not experiencing a drought and therefore, no reliability impacts 

due to a drought are anticipated over the next few years. 

The FRCC Region participants perform various transmission planning studies addressing NERC 

Reliability Standards TPL-001 through TPL-004. These studies include long range transmission 

studies and assessments, sensitivity studies addressing specific issues (e.g., Extreme summer 

weather, Off-peak conditions), interconnection and integration studies and interregional 

assessments. 

 

133 https://www.frcc.com/Reliability/Shared%20Documents/FRCC%20Handbook%200208.pdf, pages P6:2-32 
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91 2008 Long-Term Reliability Assessment 

The results of the short-term (first five years) study for normal, single and multiple contingency 

analysis of the FRCC region show that the thermal and voltage violations occurring in Florida 

are capable of being managed successfully by operator intervention. Such operator intervention 

can include generation re-dispatch, system reconfiguration; reactive device control and 

transformer tap adjustments. Major additions or changes to the FRCC transmission system are 

mostly related to expansion in order to serve new demand and therefore, none of these additions 

or changes would have a significant impact on the reliability of the transmission system. 

Transmission constraints in the Central Florida area may require remedial actions depending on 

system conditions creating increased west-to-east flow levels across the Central Florida 

metropolitan load areas. Based on the committed projects and expected generation dispatch, it is 

expected that these remedial actions will continue in this area through 2010. Permanent 

solutions consisting of new proposed facilities and the rebuilding of existing facilities have been 

identified and implementation of these solutions is underway. Some of these proposed facilities 

include constructing a new 230kV transmission line from West Lake Wales to Intercession City 

and rebuilding the existing transmission line from West Lake Wales to Intercession City. 

The long-range (remaining five years) study results reveal developing thermal and voltage issues 

in several areas in the FRCC region which the responsible utilities have studied in more detail. 

These areas include northwest Florida around Tallahassee and the Avon Park area northwest of 

Lake Okeechobee. The northwest Florida issues are being addressed by interregional 

coordination and proposed projects expected to be in-service beginning in the summer of 2009 

and extending through 2013. The Avon Park area issues are being addressed by implementing a 

Special Protection Scheme and converting an existing 115 kV transmission line to 230 kV. 

FRCC transmission owners evaluate new technologies such as FACTS devices and high 

temperature conductors to address specific transmission conditions or issues. Presently, there are 

several transmission lines constructed with high temperature conductors within the FRCC 

Region. However, at this time there are no FACTS devices installed with the Region. FRCC 

transmission owners consider enhancements to existing transmission planning tools (e.g., 

enhancements to existing software, new software, etc.) to address the expected planning needs of 

the future. 

Transmission owners within the FRCC Region have the responsibility to address short circuit 

levels within their system. Any potential short circuit concerns identified by interconnection 

studies or other studies are addressed by the individual transmission owner. Resolution of short 

circuit concerns is typically addressed by replacing existing equipment, adding equipment and/or 

reconfiguring the system. Presently, the FRCC Region has not identified any short circuit 

mitigation techniques that are projected to impact reliability. 

FRCC transmission owners have not identified any reliability impacts due to aging 

infrastructure. Generally, maintenance programs developed and performed by the transmission 

owners can extend the life of equipment. 

Guidelines for on-site spare generator step-up (GSU) and auto transformers are developed by 

generator and transmission owners to address specific needs. The FRCC Region does not 

coordinate or develop spare transformer programs. 
Regional Reliability Assessments 

92 2008 Long-Term Reliability Assessment 

Other Region-Specific Issues that were not mentioned above 

The FRCC is not anticipating any other reliability concerns throughout the 10 year study period. 

Unexpected potential reliability real-time issues identified by the Reliability Coordinator can be 

resolved with existing operational procedures. 

Industry entities within the FRCC Region address workforce retention and recruitment issues by 

providing various monetary and non-monetary compensation strategies. Some of these strategies 

may include higher base pay, end of year bonus, stock options with a vested time frame, signing 

bonus, additional vacation, work from home options and improved health, medical and dental 

benefits. 

Region Description 

FRCC’s membership includes 26 members, which is composed of investor-owned utilities, 

cooperative systems, municipal utilities, power marketers, and independent power producers. 

Historically, the region has been divided into 11 Balancing Authorities. As part of the transition 

to the ERO, FRCC has registered 79 entities (both members and non-members) performing the 

functions identified in the NERC Reliability Functional Model and defined in the NERC 

Reliability Standards glossary. The region contains a population of more than 16 million 

people, and has a geographic coverage of about 50,000 square miles over peninsular Florida. 

Additional details are available on the FRCC website (https://www.frcc.com/default.aspx). 
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93 2008 Long-Term Reliability Assessment 

MRO Highlights 

Sufficient generating capacity is expected within the Midwest 

Reliability Organization to maintain adequate capacity margins 

through 2017. Through the 2017 planning horizon, the MRO 

expects its transmission system to perform adequately, assuming 

proposed reinforcements are completed on schedule. The MRO 

Transmission Owners estimate that 833 miles of 500 kV DC, 

1,068 miles of 345 kV, and 996 miles of 230 kV transmission 

will be installed in the MRO region over the next ten years. 

The next ten years will see a very rapid load growth in the oil fields and coal bed methane fields 

at the Bakken Formation in western North Dakota and eastern Montana. Constructing adequate 

facilities to handle this growth is on a fast tract. Also during the 2008-2017 period, a very large 

amount of wind generation will be expected to be added in the MRO footprint. In 2017, the 

existing wind generation plus the planned and proposed wind generation would be serving about 

16% of the projected MRO net internal demand at summer peak. Operating the system with the 

wind generation additions in the MRO region will be a challenge. 

MRO - Summer Capacity Margin Comparison

-5%

0%

5%

10%

15%

20%

25%

30%

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Margin (%)

Region/Subregion Target Margin Existing Certain

Net Capacity Resources Adjusted Potential Resources

Total Potential Resources
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94 2008 Long-Term Reliability Assessment 

MRO - Projected On-Peak Capacity by Fuel-Mix

0

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Coal

Hydro

Gas

Dual Fuel

Nuclear

Oil

Wind

Other

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2008

2017

MRO US - Summer Capacity Margin Comparison

-10%

-5%

0%

5%

10%

15%

20%

25%

30%

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Margin (%)

Region/Subregion Target Margin Existing Certain

Net Capacity Resources Adjusted Potential Resources

Total Potential Resources
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95 2008 Long-Term Reliability Assessment 

MRO US Capacity vs Demand - Summer

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MRO CA - Winter Capacity Margin Comparison

0%

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30%

2008/09

2009/10

2010/11

2011/12

2012/13

2013/14

2014/15

2015/16

2016/17

2017/18

Margin (%)

Region/Subregion Target Margin Existing Certain

Net Capacity Resources Adjusted Potential Resources

Total Potential Resources
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96 2008 Long-Term Reliability Assessment 

MRO CANADA Capacity vs Demand - Winter

5

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Adjusted

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Resources
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97 2008 Long-Term Reliability Assessment 

MRO Self-Assessment 

Introduction 

Sufficient generating capacity is expected within the Midwest Reliability Organization to 

maintain adequate capacity margins through 2017. Through the 2017 planning horizon, the 

MRO expects its transmission system to perform adequately, assuming proposed reinforcements 

are completed on schedule. The MRO Transmission Owners estimate that 833 miles of 500 kV 

DC, 1,068 miles of 345 kV, and 996 miles of 230 kV transmission will be installed in the MRO 

region over the next ten years. 

The next ten years will see a very rapid load growth in the oil fields and coal bed methane fields 

at the Bakken Formation in western North Dakota and eastern Montana. Constructing adequate 

facilities to handle this growth is on a fast tract. Also during the 2008-2017 period, a very large 

amount of wind generation will be expected to be added in the MRO footprint. In 2017, the 

existing wind generation plus the planned and proposed wind generation would be serving about 

16% of the projected MRO net internal demand at summer peak. Operating the system with the 

wind generation additions in the MRO region will be a challenge. 

The MRO is a Cross-Border Regional Entity representing the upper Midwest of the United States 

and Canada. MRO is organized consistent with the Energy Policy Act of 2005 and the bilateral 

principles between the United States and Canada. The MRO membership consists of the former 

and existing members of the MAPP Generation Reserve Sharing Pool (GRSP), members from 

the former Mid-America Interconnected Network, Inc. (MAIN),134 and Saskatchewan Power 

Corporation (SaskPower), one of the two Canadian members.135 The new bulk power system 

transmission facilities are, however, described by geographical areas in the MRO footprint: 

Minnesota, Nebraska, Dakotas, Iowa, and Wisconsin in the MRO-U.S., and Manitoba and 

Saskatchewan in the MRO-Canada. 

Demand 

Each MRO member’s peak demand forecast includes factors involving expected economic 

trends (industrial, commercial, agricultural, residential) and normal weather patterns. From a 

regional perspective, there were no significant changes in this year’s forecast assumptions in 

comparison to last year’s assumptions. 

. 

The MRO region as a whole is summer-peaking. The MRO-U.S. summer peak net internal 

demand is expected to increase at an average rate of 1.8% per year during the 2008–2017 period, 

as compared to 2.3% predicted last year for the 2007–2016 period. This year's projection of 

1.8% compares closely with the 1.9% predicted two years ago for the 2006–2015 period. The 

 

134 The former MAIN members are Alliant Energy, Wisconsin Public Service Corp., Upper Peninsula Power Co., Wisconsin 

Public Power Inc., and Madison Gas and Electric. The American Transmission Company (ATCLLC) is the transmission 

owner which encompasses the last four former MAIN members and Alliant Energy-Wisconsin Power & Light, which is the 

Wisconsin portion of Alliant Energy. The ITC Midwest is the transmission provider for the Iowa and Minnesota portion of 

Alliant Energy. 135 The other Canadian member is Manitoba Hydro which, for the purpose of this assessment, is included in the MAPP GRSP 

group. 
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98 2008 Long-Term Reliability Assessment 

higher growth rate predicted last year can be attributed to higher trending resulting from actual 

2006 demands that occurred within the region. Factors that can influence higher trending from 

year to year are weather extremes and economic assumptions. 

The MRO-Canada summer peak net internal demand is expected to increase at an average rate of 

1.3% per year during the 2008–2017 period, as compared to 1.1% predicted last year for the 

2007–2016 period. While the MRO region as a whole is summer-peaking, the MRO-Canada is a 

winter-peaking sub-region. The MRO-Canada winter peak demand is expected to increase at an 

average rate of 1.2% per year during the 2008–2017 period, as compared to 1.0% predicted last 

year for the 2007–2016 period. The higher winter peak growth rate predicted this year stems 

from the new loads (mining, chemical plants, pipelines, and ethanol plants) requesting 

connections that were committed in the last forecast.

MRO staff sent the NERC spreadsheets to each Load Serving Entity within the MRO region and 

collected individual member’s load forecast data. MRO staff then combined the individual 

inputs from these spreadsheets to calculate the MRO regional totals without applying a diversity 

factor to the regional demand. 

Interruptible Demand and Demand Side Management (DSM) programs, presently amounting to 

approximately 6.2% of the MRO’s Projected Total Internal Peak Demand, are used by a number 

of MRO members. A wide variety of programs, including direct load control (such as electric 

appliance cycling) and interruptible load are used to reduce peak demand. 

Generation 

Existing resources considered as “Certain” amount to 52,900 MW for 2008. Existing 

“Uncertain” resources amount to 3,397 MW for 2008. The “Planned” resources for the MRO 

region amount to 1,518 MW starting in 2008 and are estimated to increase to 5,514 MW by 

2017. The “Proposed” resources for the MRO region amount to 591 MW starting in 2008 and 

are estimated to increase to 14,727 MW by 2017. All these capacity numbers are net expected 

on-peak values. 

Existing wind generation amounts to 3,997 MW of nameplate capacity for summer 2008. 

Assuming a 20% capacity value,136 799 MW of the nameplate amount is expected to be 

“Certain” (available at peak load). Wind generation that is “Planned” for the next 10 years 

amounts to 1,028 MW nameplate, with an expected on-peak value of 213 MW. 

A significant portion of the “Proposed” resources consists of wind generation. This is based on 

generation within the Midwest ISO interconnection queue that is in the MRO Region. 

“Proposed” on-peak wind resources are expected to be 467 MW starting in 2008 and increasing 

to 7,895 MW by 2017. The “Proposed” nameplate wind generation for the MRO Region 

amounts to 2,336 MW in 2008 and increasing to 39,713 MW in 2017. 

 

136 This assumption is based on the fact that the Midwest ISO allows a capacity credit of 20 percent of nameplate capacity for 

wind generation. That would account for most, but not all of the wind capacity within the MRO region. MRO members, like 

those who are MAPP members, also submitted data for their existing wind facility, as well as future planned facilities. As the

result, the MRO overall on-peak value may not necessarily equal 20 percent of nameplate capacity. 
Regional Reliability Assessment

99 2008 Long-Term Reliability Assessment 

Existing Biomass generation amounts to 275 MW and is estimated to increase by only 76 MW 

over the next 10 years. This generation is typically expected to be available on peak. 

For this year’s assessment, NERC has re-defined how resources are reported. Existing resources 

are categorized as either “Certain” or “Uncertain.” Future resources are categorized as either 

“Planned” or “Proposed.” Three capacity margins are calculated for the 10-year period: 

• Existing Certain + Planned 

• Existing Certain + Planned + 100% of Proposed 

• Existing Certain + Planned + (Proposed x Confidence Factor) 

Since the “Proposed” generation was primarily determined from the MISO generation 

interconnection queue, a confidence factor was applied by MRO staff to reduce the proposed 

amount to a realistic expected value. Confidence factors were higher in the earlier years since 

these resources were assumed to be more likely to be built. In later years, a 20% confidence 

factor was applied, which is consistent with actual generation realized historically from 

interconnection queues. 

There are uncertainties involved when using a generation interconnection queue. In-service 

dates can be deferred or slip. Similarly, some generation that is expected within the next several 

years may in fact qualify as “Planned” resources. MRO staff worked with generation owners to 

verify/update in-service dates of key future generation (i.e., large coal units) and to establish 

reasonable confidence factors. In establishing these confidence factors, MRO staff also 

considered that the LSEs within the MRO region have an obligation to serve. 

The confidence factors applied for each year are: 

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 

50% 45% 40% 35% 35% 35% 20% 20% 20% 20% 

For the purposes of this assessment, capacity margins using adjusted proposed resources will be 

compared to target margin levels. 

Purchases and Sales 

For 2008, the MRO is projecting total firm purchases of 1,787 MW from sources external to the 

MRO region. The MRO has projected 731 MW of total sales to load outside the MRO region. 

Both purchases and sales become progressively lower in future years. This is typical and 

purchases/sales will likely increase as each year approaches. By NERC definition, capacity 

margins are to be calculated using the net firm interchange. However, the net import/export of 

the MRO region can vary at peak load, depending on system conditions and economic 

conditions. For example, firm exports may not necessarily be scheduled on during internal peak 

load periods. 

Firm transactions from the MRO-Canada (Saskatchewan and Manitoba) into the MRO-U.S. are 

limited to 2,415 MW due to the operating security limits of the two interfaces between the two 

provinces and the United States. Firm transactions from MRO-Canada into the MRO –U.S. 

reflex existing and future long term contractual transactions. For example, for summer 2008, 
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100 2008 Long-Term Reliability Assessment 

approximately 1,400 MW of firm transactions from Manitoba Hydro into the MRO-U.S. is 

expected. These long-term firm sale transactions are based on dependable energy expected to be 

available under the lowest recorded historic water flow (drought) conditions in Manitoba.

Throughout the MRO region, firm transmission service is required for all generation resources 

that are used to provide firm capacity, which also means that these firm generation resources are 

fully deliverable to the load. The MRO is expected to meet the various reserve margin targets 

without needing to include energy-only, uncertain, or transmission-limited resources. 

Transmission providers within the MRO region treat Liquidated Damage Contracts according to 

their individual tariff policies. Most MRO members are within non-retail access jurisdictions 

(except for Upper Michigan), and therefore liquidated damages products are not typically used. 

Most MRO members count on firm capacity from outside of the region for emergency and 

reserve sharing requirements. However, Saskatchewan does not rely on outside resources. It 

self-supplies all planning and operating reserves. 

Fuel 

49% of existing MRO generation is coal-fired, and 13% is natural gas-fired. The MRO 

considers known and anticipated fuel supply or delivery issues in its assessment. Because there 

is a large diversity in fuel supply, inventory management, and delivery methods throughout the 

region, the MRO does not have a specific mitigation procedure in place should fuel delivery 

problems occur. The MRO and its members closely monitor the delivery of Powder River Basin 

coal to ensure adequate supply. The MRO does not foresee any significant fuel supply and/or 

fuel delivery issues in the near future.

In Saskatchewan in particular, fuel-supply vulnerability is generally not considered an issue due 

to system design and operating practices: 

• Coal resources (approximately 47% of generating capacity) have firm contracts and are 

mine mouth, and also stock is maintained in the event that mine operations are unable to 

meet the required demand of the generating facility. SaskPower has 20 days of on-site 

stockpile for each of its coal facilities. Strip coal reserves are also available and only need 

to be loaded and hauled from the mine. These reserves are either 30 or 65 days 

depending on the coal facility. 

• Natural gas resources (approximately 25% of generating capacity) have firm 

transportation contracts with large natural gas storage facilities located within the 

province backing those contracts up. 

• Hydro facilities and reservoirs are fully controlled by SaskPower. 

Transmission 

Minnesota 

Transmission companies in the Minnesota Area are jointly pursuing major transmission 

infrastructure investment through the CapX 2020 (CapX) effort. This coalition of utilities is 

seeking to enhance the 345 kV grid for load serving purposes with facilities available by 2016. 
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101 2008 Long-Term Reliability Assessment 

The proposed lines will impact multiple flowgates. The proposed Fargo - St. Cloud 345 kV line 

will impact the North Dakota Export flowgate. 

The CapX proposed Brookings, SD - Twin Cities 345 kV line may benefit the flowgate of North 

Dakota Export, and may impact the Lakefield - Lakefield Generation 345 kV line, Fox Lake - 

Rutland 161 kV line, Rutland - Winnebago 161 kV line, and the Lakefield - Fox Lake 161 kV 

line. Further wind farm development in this region will continue to recreate the flowgate issues 

unless continued transmission investment is made in the region. 

The CapX proposed Twin Cities - North Rochester - La Crosse 345 kV line may impact several 

flowgates, such as the Minnesota - Wisconsin Export Interface, Prairie Island - Byron 345kV, 

and other lower voltage flowgates that exist in the Minnesota/western Wisconsin areas. It is 

expected that this line will redefine the Minnesota - Wisconsin Export Interface. 

Nebraska 

Western Area Power Administration and Nebraska Public Power District plan to install a third 

250 MVA 345/230 kV transformer at the Grand Island substation by the summer of 2009. Both 

187 MVA 230/115 kV transformers at the North Platte substation will be replaced with new 336 

MVA 230/115 kV transformers by 2009. 

Due to rapid load growth in the east central Nebraska region, a Columbus/Norfolk Transmission 

Expansion Plan, targeted for completion by the summer of 2010, was developed. 

The Public Power Generation Agency plans to construct a second coal-fired generating unit at 

the existing Whelan Energy Center Site near Hastings, Nebraska, which is expected to begin 

commercial operation in the spring of 2011 with a net output of 220 MW. 

The Omaha Public Power District (OPPD) is constructing a second coal-fired generating unit at 

the Nebraska City Power Station, which is expected to begin commercial operation in the spring 

of 2009 with a net output of 700 MW. 

Lincoln Electric System plans to install a second 345/115 kV transformer at the NW68th & 

Holdrege substation, with an in-service date of 2010. LES will construct a 26-mile 345 kV line 

from the Wagener substation to the NW68th & Holdrege substation, around the northern 

perimeter of Lincoln, with an in-service date of 2009. 

Dakotas 

About 50 facility additions are scheduled between 2008 and 2014. Facility additions range from 

new substation equipment such as capacitor bank additions and transformers to new transmission 

line additions. Unexpected load growth in the oil fields and coal bed methane fields at the 

Bakken Formation in western North Dakota and eastern Montana has led to a large increase in 

load in some isolated areas. This unexpected load growth has resulted in individual substation 

loads that were less than 10 MW at the start of the decade to those projected to be approaching 

100 MW now. Facilities to handle this growth are on a fast track. 
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102 2008 Long-Term Reliability Assessment 

Near-term major transmission projects under construction include two 230 kV transmission lines, 

one from Belfield to a new tap of the Little Missouri - Bowman line called Rhame, and the other 

from Williston to Tioga. Both are planned for completion by fall 2009. 

Out-year projects planned include 230 kV transmission additions in the Huron-Storla area in 

South Dakota scheduled for 2014. 

Iowa 

The Iowa system is beginning to experience several regional forces including an increase in 

installed wind power in Minnesota, northern Iowa, and central Illinois, recent base load 

generation near Council Bluffs followed by Nebraska City (2009), and the development of 

several new spot loads from ethanol plants. Power from wind and coal in western Iowa (and 

Nebraska) should decrease east – west transfers, while future additional Illinois wind power 

could again increase east – west and possibly south – north transfers. New large spot loads from 

ethanol plants should absorb some of the new generation. The combination of wind and coal 

generation along with new load will continue to require new transmission to adequately meet 

transmission planning criteria.

The Iowa companies have several 115 kV, 161 kV, and 345 kV projects planned over the next 

several years to reinforce Iowa.

Wisconsin 

Significant transmission and transformer additions planned to be in-service during 2008-2017 

will strengthen the reliability of the Wisconsin-Upper Michigan Systems (WUMS) for summer 

2008 and subsequent years. 

The WUMS southern interface contains four 345 kV lines and one 138 kV tie line. This interface 

is thermally limited for critical N-1 contingencies and voltage stability limited for critical N-2 

contingencies during periods of heavy transfers across the interface. Operating guides are used to 

monitor and manage the constraints during high imports into WUMS across the southern 

interface. The American Transmission Company (ATCLLC) has plans to add a new 345 kV 

transmission line between the Rockdale and Paddock 345 kV substations that will help to 

alleviate the southern interface constraints. This 345 kV line is expected to be in-service in 2010. 

Heavy power flows into Michigan’s Upper Peninsula (UP) from northeast Wisconsin is expected 

to continue. The corridor consisting of the three 138 kV lines south of the Morgan and Stiles 

substations continues to be a potential constraint that could lead to thermal and voltage violations 

under contingencies during periods of high flows towards the UP. This constraint is monitored 

and managed by following an operating guide. Completion of new Werner West – Highway 22 – 

Morgan and Gardner Park – Highway 22 345 kV lines in late 2009 will help to alleviate this 

constraint. 

Manitoba 

For normal operations with all facilities in service, the Manitoba Hydro system demonstrates 

adequate performance in terms of facility loading and voltages with various operating conditions 

for the 2008-2017 period. There are no existing constraints from a system planning perspective. 
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103 2008 Long-Term Reliability Assessment 

The projects listed below are now underway or planned in the next decade and will keep the 

Manitoba Hydro transmission system operating satisfactorily in the future. Most of the projects 

are dictated by the need to expand the transmission system to reliably serve growing loads in 

Manitoba and transmit generation to the export market. Other drivers of expansion are to 

improve safety, increase efficiency, and connect new generation. The following are the major 

projects in the Manitoba area: 

• Wuskwatim Generation Outlet Facilities consist of 296 miles of 230 kV transmission to 

interconnect the new 223 MW hydro generating plant into the Manitoba northern AC 

grid, including: 

o Two Wuskwatim-Herblet Lake lines – 2009 

o Herblet Lake-The Pas Ralls Islands line – 2010 

o Thompson Birchtree static VAR compensator – 2011 

• Dorsey Bus Enhancement consists of the Dorsey 230 kV bus being improved with the 

addition of four 230 kV circuit breakers and a new connecting bus. 

• New 500/230 kV Reil Station consists of establishing a new station which will include: 

o Installing a 500/230 kV transformer bank 

o Sectionalizing the existing Dorsey – Forbes 500 kV line 

o Sectionalizing two existing parallel 230 kV lines from Ridgeway to St. Vital 

• Bipole III transmission line runs from Conawapa Station in the north to Riel Station near 

Winnipeg. The Bipole III scheme with a west side of the province routing includes: 

o ±500 kV HVDC transmission line, about 833 miles long, from Conawapa 

Converter Station to Riel Converter Station 

o 2,000 MW converter station at Conawapa 

o Five AC transmission lines approximately 19 miles in length each to connect the 

Conawapa Converter Station to the northern collector system 

o 2,000 MW converter station at Riel, including four synchronous compensators

• Winnipeg Area Transmission Refurbishments consist of an estimated 114 miles of 230 

kV transmission lines that will be upgraded to carry higher loading. 

• Part of the Winnipeg to Brandon improvements includes the addition of a new 43.5 mile 

230 kV line from Dorsey to Portage South. 

• Several new 230/115 kV and 230/66 kV transformers are being added to the system. The 

sites include the Rosser, Transcona, Stanley, and Neepawa stations. 

Saskatchewan 

Addition of a 99 mile 230 kV transmission line and a 350 MVA 230/138 kV autotransformer in 

south central Saskatchewan in 2010 is planned to mitigate post-contingency overloads and 

provide voltage support in the area. 

Operational Issues 

No significant operational concerns are expected. Operating studies and guides have been or will 

be performed for all scheduled transmission or generation outages. When necessary, temporary 

operating guides will be developed for managing the scheduled outages to ensure transmission 

reliability. 
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104 2008 Long-Term Reliability Assessment 

Completion of the Arrowhead – Stone Lake – Gardner Park 345 kV line provides the needed 

transmission reinforcement on the Wisconsin-Upper Michigan System (WUMS) western 

interface with Minnesota and improves both the WUMS and MRO transmission reliability and 

transfer capability. Studies have demonstrated that with high imports into WUMS from 

Minnesota, there is potential transient voltage recovery violation and voltage instability and 

therefore determined the need for a new interface flowgate comprised of Arrowhead-Stone Lake 

345 kV line and King-Eau Claire 345 kV line, called the Minnesota Wisconsin Export (MWEX) 

Interface. This interface is managed as a reciprocal Interconnection Reliability Operating Limit 

Flowgate of Midwest ISO and MAPP. The existing Minnesota Wisconsin Stability Interface will 

be retained for prior outage conditions and to gain operational experience with MWEX. The 

existing operating guides for the King – Eau Claire – Arpin 345 kV line and the Arpin – Rocky 

Run 345 kV line will be revised accordingly. 

The onset of CO2 regulations as well as the requirement to reduce Critical Air Contaminants 

such as SO2 and NOX could cause restrictions to high emitting technologies. The magnitude of 

these potential impacts, however, is unknown at this time. 

Reliability Assessment Analysis 

For the purpose of this assessment, the MRO used a 15% region-wide reserve margin as a proxy 

measure of resource adequacy, which is representative of the range of reserve margin targets for 

the various groups within the MRO, as described below: 

• For the MAPP GRSP members, resource adequacy is measured through the accreditation 

rules and procedures. The MAPP GRSP requires a 15% reserve capacity obligation 

(RCO) for predominantly thermal systems, and a 10% RCO for predominantly hydro 

systems.137 The RCO is established by the MAPP Restated Agreement and its governing 

authorities, i.e. MAPP Executive Committee and MAPP Pool Committee. This level of 

reserve requirements is subject to periodic review based on reserve requirements studies 

conducted regularly by MAPP.138 The RCO requires the MAPP GRSP members to 

maintain their respective minimum reserve based on after-the-fact peak demand; i.e., the 

members are responsible for maintaining adequate generation to account for load forecast 

uncertainty. When a new peak occurs, the member will be required to maintain the 

minimum reserve based on that peak for the next 11 months, or until a new, higher peak 

takes place. For summer 2008, approximately 8,850 MW of generation in the MAPP 

GRSP (15.7% of MRO net internal capacity) is associated with predominantly hydro 

systems and only requires a 10% RCO. 

• For the former MAIN members, generation resource adequacy is assessed based on 

LOLE studies previously conducted by the MAIN region.139 Although conducted on a 

 

137The MAPP GRSP Handbook, http://www.mappcor.org/assets/pdf/GRSP_Handbook_20070116.pdf. 138The previous MAPP reserve requirements study was conducted in 2003 by the MAPP Composite System Reliability Working 

Group. This study is not posted on the MAPP website, but it is available upon request from Brian Glover, MAPPCOR (651-

855-1715 or bp.glover@mappcor.org). The MAPP 2008 LOLE Study is ongoing and is expected to be completed by October 

1, 2008.

139In the former MAIN region, MAIN Guide 6 adopted a resource adequacy criterion of 0.1 days/year,

http://www.maininc.org/bg/guide6.pdf. Studies concerning LOLE calculations for the former MAIN Region are available. 

The 2005 study is located at http://www.maininc.org/files/MG6GenerationReliabilityStudy2005_14.pdf. Other studies are 

found by navigating through http://www.maininc.org/files/files.htm.
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105 2008 Long-Term Reliability Assessment 

yearly basis, MAIN’s LOLE studies consistently recommended a minimum long-term 

planning reserve margin of 16%. 

• Saskatchewan's reliability criterion is based on annual expected unserved energy (EUE) 

analysis and equates to an approximate 15% reserve margin requirement.140

Since NERC requests that capacity margins be used, a 13% region-wide capacity margin is used 

as a proxy measure of resource adequacy (target level) in the MRO region. A 15% planning 

reserve margin equates to a 13.04% capacity margin. Using the “Proposed” resources after they 

have been appropriately adjusted by the confidence factors, the projected capacity margins for 

the MRO region, MRO-U.S., and MRO-Canada are as follows: 

 

• MRO-Total: The summer peak capacity margins for the full MRO region range from 

17.2% to 14.1% for the 2008-2017 period. 

• MRO-U.S.: The summer peak capacity margins for the MRO-U.S. sub-region range 

from 16.8% to 13.1% for the 2008-2017 period. 

• MRO-Canada: The summer peak capacity margins for the MRO-Canada subregion 

range from 22.6% to 18.7% for the 2008-2017 period. For winter peak, the MROCanada capacity margins range from 19.5% to 14.0% for the 2008-2017 period. 

The graph below shows these projected capacity margins graphically, which all exceed the target 

capacity margin of 13%. 

Capacity Margin Comparison

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Margin (%)

MRO - Summer US - Summer Canada - Summer Canada - Winter Target

 

140Saskatchewan Power's generation adequacy studies for the province of Saskatchewan are not publicly posted or released. 

Information regarding these studies may be obtained by contacting SaskPower.
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106 2008 Long-Term Reliability Assessment 

The former MAIN members now within MRO use a minimum long-term planning reserve 

margin of 16% and a minimum short-term planning reserve margin of 14%. For the remainder 

of the MRO, reserve margin requirements do not vary based on short term vs. long term. 

This year’s assessment cannot be readily compared with last year’s assessment due to the 

significant changes in how resources were defined and accounted for. Last year’s assessment 

only included “Committed” future resources when calculating capacity margins. Consequently 

capacity margins did not meet target levels for most of 10 year period for most regions. This 

year, a portion of “Proposed” resources are being included from generation interconnection 

queues. The projected capacity margins based on this year’s resource definitions should more 

accurately capture future generation than last year’s assessment. 

The MRO members accounted for resource unavailability being higher than expected due to fuel 

interruptions or other conditions such as extended drought or forced outages, and peak demands 

being higher than expected due to extreme weather (e.g., 90/10 forecast) or other conditions 

within the determination of adequate generation reserve margin levels, as follows: 

• Both the MAPP Generation Reserve Sharing Pool members and the former MAIN 

members within MRO consider generator forced outage rate increase and load forecast 

uncertainty within their Loss of Load Expectation (LOLE) studies to determine the target 

reserve margin levels that satisfy the LOLE criteria of 0.1 day per year or 1 day in 10 

years. 

• For Saskatchewan, a winter-peaking system, winter peak load is forecasted on a heating 

season basis and represents the highest level of demand placed on the supply system. 

The winter forecast is normalized to account for cold weather based on a 30-year average 

weather pattern. Forecasts are developed for Saskatchewan to cover possible ranges in 

economic variations and other uncertainties such as weather using a Monte Carlo 

simulation model to reflect those uncertainties. This model considers each variable to be 

independent from other variables and assumes the distribution curve of a probability of 

occurrence of a given result to be normal. Results are based on an 80 percent confidence 

interval. This means that a probability of 80% is attached to the likelihood of the load 

falling within the bounds created by the high and low forecasts. 

The MRO region does not count on energy-only, existing-uncertain wind and transmissionlimited resources for reliability purposes. 

None of the planned unit retirements within the MRO Region will have a significant impact on 

reliability. 

Generation deliverability is performed by Transmission Providers within the MRO region. Links 

to deliverability criteria within the MRO region are: 

• http://www.midwestiso.org/page/Generator+Interconnection

• http://www.mappcor.org/content/policies.shtml

• https://www.oatioasis.com/spc/
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107 2008 Long-Term Reliability Assessment 

Throughout the MRO region, firm transmission service is required for all generation resources 

that are used to provide firm capacity; therefore, these firm generation resources are fully 

deliverable to the load. 

No specific analysis was performed by MRO to evaluate whether external resources are available 

and deliverable. However, the MAPP GRSP, former MAIN utilities, and Saskatchewan require 

external purchases to have a firm contract and firm transmission service to be counted as firm 

capacity. 

The major transmission additions required to support the addition of new resources and new 

loads in the MRO in the 6-10 year period include the following: 

• The network upgrades identified for the addition of a 280 MW generating unit at Nelson 

Dewey include a new 161 kV transmission line approximately 15 miles long from 

ATCLLC’s Nelson Dewey substation in Wisconsin to a new ITC Midwest’s switching 

station located between the existing Liberty and Lore 161 kV substations in.141 The 

expected in-service year for the generation and the required network upgrades is 2013. 

• The new 230 kV transmission facilities in the western Minnesota area will be required for 

the proposed Big Stone II generation project planned to be on-line in 2013. Some of this 

new transmission may be designed for operation at 345 kV. 

• The CAPX 345 kV line from Brookings, SD to the Twin Cities, MN is in the Minnesota 

certificate of need process and is being constructed to support additional wind generation 

and other potential resources and also to support load serving needs. The expected 

service date is 2014. 

There are no stability issues that could impact the reliability anticipated during the reported 

period. The following is information on stability-related criteria used within the MRO: 

• For MAPP members, the specific MAPP bulk transmission reliability criteria and study 

methods, assumptions, and procedures are outlined in the MAPP Member Reliability 

Criteria and Study Procedure142 and the MAPP Design Reliability Subcommittee Policies 

and Procedures.

143 Those criteria are to be used for MAPP planning and operating 

studies. 

• For the former MAIN members, dynamic reactive margin is part of the ATCLLC 

Planning Criteria, which is determined using a reduction to the reported reactive 

capability of synchronous machines. A 10 percent dynamic reactive margin is required in 

the intact system and a 5 percent dynamic reactive margin is required under NERC 

Category B contingencies. ATCLLC has transient voltage dip criteria. Voltage recovery 

is required to be within 70 percent and 120 percent of nominal immediately following the 

clearing of a disturbance. Voltage recovery is required to be within 80 percent and 120 

percent of nominal between 2.0 and 20 seconds following the clearance of a disturbance. 

Due to many years of coordinated planning as a MAPP member in the past, ITC Midwest 

retains the MAPP criteria. 

 

141 G527 Interconnection Facilities Study Report available at http://oasis.midwestiso.org/documents/ATC/Cluster_8_Queue.html 142 http://www.mapp.org/assets/pdf/Reliability%20Criteria%20Studies%20Manual/As%20of%20November%202004.pdf 143 http://www.mapp.org/assets/policies/DRS%20Policies%20and%20Procedures_February%202008.pdf
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108 2008 Long-Term Reliability Assessment 

• Saskatchewan addresses dynamic reactive requirements through operating guides and 

planning studies. No stability issues are anticipated that will impact reliability in 

Saskatchewan. Saskatchewan's guideline for post-disturbance transient voltage dip is 0.7 

p.u. and 1.2 p.u. 

A voltage stability study was done for the majority of the MRO region (excluding Saskatchewan 

and WUMS) and was published in 2005. The study found no single contingency that resulted in 

system collapse or cascading. 

Voltage stability margin is part of the ATCLLC Planning Criteria. Under NERC Category B 

contingencies, the steady state system operating point of selected areas for evaluation is required 

to be at least 10 percent away from the nose of the P-V curve. 

Several members within the MRO region have localized UVLS programs to prevent localized 

low voltage conditions. These programs are not required to protect the bulk power system. 

Emergency conditions within the MRO region would be managed through the Reliability 

Coordinators. Resource and/or transmission deficiencies would be offset by planning reserves 

and external markets. Operational measures, which would include emergency plans, 

interruptible load contracts, public appeals, and rotating outages, would be implemented as 

necessary. 

The MRO region as a whole is not experiencing a drought. However, reservoir water levels 

continue to remain low in Montana, North Dakota, and South Dakota, and will reduce the 

magnitude and duration of power transfers out of the Dakotas. As a result, there will likely be 

non-firm imports of power from south and east of the MRO region into the MRO region to 

replace the energy reduction associated with these low water levels. The Manitoba water 

condition is normal. Therefore, normal Manitoba-US exports are likely. 

TPL001 – TPL004 planning studies are performed in the MRO region by the various groups, as 

follows: 

• For MAPP and ITC Midwest, a Reliability Assessment Study is performed annually by 

the MAPP Transmission Planning Subcommittee and its Transmission Reliability 

Assessment Working Group. NERC Category A (system intact), NERC Category B, and 

some NERC Category C and known multiple element single contingencies outages (such 

as common tower) are performed according to NERC criteria. A number of NERC 

Category D contingencies were also evaluated. Assessments are conducted on model 

years 2008, 2012 and 2017 for winter peak, summer peak, and summer off-peak with 

high transfer conditions. Dynamic analysis was conducted on 2011 and 2012 summer 

off-peak with high transfer models. 

• Based on the TPL-001 - TPL-004 planning studies performed by ATCLLC,144 reliable 

operation of the WUMS transmission system is expected during the 2008-2017 

assessment period. 

 

1442007 – ATCLLC 10-Year Transmission System Assessment Update, http://www.atc10yearplan.com. Also refer to Reliability 

First Corporation (RFC) Long Term Transmission Assessment Studies (on-going), https://www.rfirst.org, 

http://www.maininc.org/
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109 2008 Long-Term Reliability Assessment 

• Saskatchewan performs ongoing system assessments as part of its planning process to 

integrate new generation and load. 

The MRO region uses special protection systems (SPS) to enhance reliability and currently has 

53 SPSs in place. These systems allow the owners to meet TPL-001 through TPL-003 Standards 

per NERC Standard PRC-012. Certain MRO members also use SPSs to meet TPL-004. 

New technologies, systems, and tools that are expected to be deployed (or continue to be 

deployed) to improve bulk power system reliability within the MRO region includes: 

• Distributed Superconducting Magnetic Energy Storage Devices, 

• Certain High Temperature Low Sag conductors, and 

• Software tools such as Physical and Operational Margins/Optimum Mitigation, 

Production Cost Modeling, Voltage Stability Analysis Tool, and Power World. 

In addition, MRO members participate in the review and development of new technologies, 

systems, and tools through the research activities of the Electric Power Research Institute, Power 

System Engineering Research Center, and CEATI International Inc. 

The MRO region Transmission Owners evaluate short circuit levels on an on-going basis, and 

forecasted short circuit levels are currently well below available nameplate interrupting ratings. 

Companies within the MRO have asset renewal programs to invest in transmission infrastructure 

and replace aging infrastructure before it degrades reliability. Several companies have 

reliability-centered maintenance programs. 

Policies or guidelines for on-site, spare generator step-up (GSU) transformers and 

autotransformers in the MRO region are, as follows: 

• ATCLLC does not own any spare GSU transformers but owns many medium and large 

spare autotransformers. Many sites have dedicated spare units, and system spares are 

stored at strategic locations. On-site spares are determined on a case by case basis. 

ATCLLC participates in the EEI STEP program. 

• Saskatchewan does not have a guideline for GSU transformers; however it does have a 

spare GSU transformer for major base load units. The planning guideline for 

autotransformers is to have enough installed capacity so that one may be used as a system 

spare. Saskatchewan does not share spare transformers with other companies. 

• For the rest of the MRO region, the need for spare transformers is decided on a case-bycase basis. 

Other Region-Specific Issues that were not mentioned above 

Because wind generation is a variable resource, the operational impacts of the large amount of 

proposed wind generation in the MRO region will need to be closely monitored for any 

reliability impacts. The impact of wind generation will be reported in more detail in the MRO 

Scenario Assessment. This report will be provided to NERC in May 2009. 

 
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110 2008 Long-Term Reliability Assessment 

In 1992, conventional base load generation (coal, hydro, nuclear) amounted to 90% of the total 

generation in the former MAPP Region, which is now a major portion of the MRO. In 2008, 

conventional base load generation amounts to about 73% of the total generation within the MRO. 

Over the next ten years, planned and proposed wind generation on a nameplate basis makes up 

about 77% (40,740 MW out of 52,873 MW) of the resource additions within the MRO Region, 

based on the Midwest ISO generation interconnection queue. Assuming that all of the planned 

and proposed wind generation will be built, and assuming that the expected on-peak value of the 

wind nameplate capacity (8,108 MW) is available and deliverable at peak load, this would 

amount to about 40% of the projected 20,240 MW total for new resources expected to be 

available during peak load in 2017. Therefore, the existing wind generation (799 MW) plus the 

planned and proposed wind generation would be serving about 16% of the projected MRO net 

internal demand of 55,238 MW at peak load in 2017. 

As part of the preparation of this assessment, MRO staff attempted to collect information on how 

the workforce retention and recruitment issues are dealt with, from Planning Authorities (PA) 

within the MRO region. The responses from the PAs did not provide sufficient information to 

formulate a clear description of the subject. 

Assessment Process 

To prepare this MRO regional self-assessment, MRO staff sent the NERC spreadsheets to the 

registered entities within the MRO and collected individual entity’s load forecast, generation, 

and demand-side management data. The staff then combined the individual inputs from these 

spreadsheets to calculate the MRO regional totals. The staff also sought responses to the 

questions included in the NERC LTRA request letter, from Planning Authorities within the MRO 

region – MAPP, ATCLLC, and SaskPower. The MAPP Transmission Planning Subcommittee 

and its Transmission Reliability Assessment Working Group also provided detail on the various 

MAPP planning studies. Using the information gathered from this process, the MRO Resource 

Assessment Subcommittee prepared the resource assessment portions, while the Transmission 

Assessment Subcommittee prepared the transmission assessment and operational issues portions. 

Finally, the MRO Reliability Assessment Committee, which is ultimately responsible for the 

long-term reliability assessments, reviewed and approved the final draft before it was submitted 

to NERC. 

Region Description 

The Midwest Reliability Organization (MRO) has 48 members which include Cooperative, 

Canadian Utility, Federal Power Marketing Agency, Generator and/or Power Marketer, Small 

Investor Owned Utility, Large Investor Owned Utility, Municipal Utility, Regulatory Participant 

and Transmission System Operator. The MRO has 19 Balancing Authorities and 115 registered 

entities. The MRO Region as a whole is a summer peaking region. The MRO Region covers all 

or portions of Iowa, Illinois, Minnesota, Nebraska, North and South Dakota, Michigan, 

Montana, Wisconsin, and the provinces of Manitoba and Saskatchewan. The total geographic 

area is approximately 1,000,000 square miles with an approximate population of 20 million 
Regional Reliability Assessment

111 2008 Long-Term Reliability Assessment 

NPCC Highlights 

For the ten year study period of the 2008 Long-Term 

Reliability Assessment, the resource plans of each of the 

five Areas (subregions) of NPCC meet the NPCC resource 

adequacy criterion which obligates each Area to ensure that 

its probability (or risk) of disconnecting any firm load due 

to resource deficiencies shall be, on average, not more than 

once in ten years. When compared with the RAS LongTerm Reliability Assessment conducted in 2007 for the 2007-2016 time frame, margins have 

improved overall. The projected rate of load growth has decreased in four of the five Areas due 

to slowing economic activity. In Ontario, there is an active commitment to energy conservation 

and a reduction in customer load which is also reflected in its decline in load growth. Only the 

province of Québec forecasts a slight increase in load growth over its projections for 2007. The 

currently planned transmission system over the ten-year period is expected to perform reliably 

for a range of contingencies and conditions. 

The Maritimes Area has demonstrated compliance with the NPCC reliability criterion of less 

than 0.1 days of firm load disconnections per year, and the Maritimes Area requires no support 

from its interconnections to meet the criterion. Reserve levels will vary between 22% and 40%. 

The most significant change since the 2007 RAS Long-Term Reliability Assessment is a lower 

demand forecast and demand growth rate currently projected for the Maritimes. Contributing 

significantly to this lower forecast is a projection of slowing economy, particularly the 

announced mill closures in the pulp and paper and wood processing sectors, along with limited 

growth expectations in these sectors due to a high Canadian dollar and rising energy costs. 

In New England, the capacity needs to meet the NPCC resource adequacy criterion are 

purchased through annual auctions for a period of time three years in advance of the year of 

interest. After this primary annual auction, there are annual reconfiguration auctions prior to the 

commencement year in order to readjust installed capacity purchases and further ensure that 

adequate capacity will be purchased to meet system needs. 

For the New York Area, the New York Independent System Operator conducts an annual 

Reliability Needs Assessment (RNA) that examines both resource and transmission needs over a 

ten-year period. Resources totaling approximately 455 MW, as well as transmission upgrades 

that are under construction or otherwise have met the screening criteria, were included in the 

base case for the current RNA. This assessment has determined that sufficient statewide 

resources are available to meet the NPCC LOLE criteria through the year 2011. For 2012, the 

RNA indicates that sufficient resources will exist if 500 MW were added to New York City 

(NYC), or if 750 MW were added in the lower Hudson River valley, or if transfer limits into 

NYC were increased. Beyond 2012, additional resources of approximately 2,750 MW would be 

needed to meet the criteria through 2017; a majority of those resources would be required for the 

New York City zone to meet the NYC zonal requirements. 
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112 2008 Long-Term Reliability Assessment 

Ontario will eliminate its coal-fired fleet with the retirement of the Nanticoke station, currently 

scheduled for 2014. Although energy supplies available within Ontario are expected to be 

adequate overall, energy deficiencies could arise as a result of higher than forecast forced outage 

situations, prolonged extreme weather conditions and other influencing factors. Interconnection 

capability and available market and operational measures have been evaluated as sufficient to 

ensure summer energy demands can be met for a wide variety of conditions. 

To comply with the NPCC resource adequacy criterion, the Québec Area requires a reserve 

margin of about 11 % of the peak load for the year of analysis. In Québec, large multi-years 

water reservoirs allow hydro generation to be available on peak, and non-hydraulic resources 

account only for a small portion of total resources. Assessments for both NPCC and the Québec 

Energy Board are conducted annually. 

NPCC - Summer Capacity Margin Comparison

-5%

0%

5%

10%

15%

20%

25%

30%

35%

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Margin (%)

Region/Subregion Target Margin Existing Certain

Net Capacity Resources Adjusted Potential Resources

Total Potential Resources
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113 2008 Long-Term Reliability Assessment 

NPCC - Projected On-Peak Capacity by Fuel-Mix

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

50,000

Hydro

Dual Fuel

Nuclear

Gas

Coal

Oil

Pumped Storage

Wind

Other

MW

2008

2017

NPCC US - Summer Capacity Margin Comparison

-5%

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%

55%

60%

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Margin (%)

Region/Subregion Target Margin Existing Certain

Net Capacity Resources Adjusted Potential Resources

Total Potential Resources
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114 2008 Long-Term Reliability Assessment 

NPCC US Capacity vs Demand - Summer

40

45

50

55

60

65

70

75

80

85

1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016

Thousands of MW

Historic

Demand

High

Demand

Projection

Low

Demand

Projection

Adjusted

Potential

Resources

Net

Capacity

Resources

NPCC CA - Winter Capacity Margin Comparison

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

2008/09

2009/10

2010/11

2011/12

2012/13

2013/14

2014/15

2015/16

2016/17

2017/18

Margin (%)

Region/Subregion Target Margin Existing Certain

Net Capacity Resources Adjusted Potential Resources

Total Potential Resources
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115 2008 Long-Term Reliability Assessment 

NPCC CANADA Capacity vs Demand - Winter

55

60

65

70

75

80

85

90

1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016

Thousands of MW

Historic

Demand

High

Demand

Projection

Low

Demand

Projection

Adjusted

Potential

Resources

Net

Capacity

Resources

NPCC-New England - Summer Capacity Margin Comparison

-5%

0%

5%

10%

15%

20%

25%

30%

35%

40%

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Margin (%)

Region/Subregion Target Margin Existing Certain

Net Capacity Resources Adjusted Potential Resources

Total Potential Resources
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116 2008 Long-Term Reliability Assessment 

NPCC-New York - Summer Capacity Margin Comparison

-5%

0%

5%

10%

15%

20%

25%

30%

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Margin (%)

Region/Subregion Target Margin Existing Certain

Net Capacity Resources Adjusted Potential Resources

Total Potential Resources

NPCC-Maritimes - Winter Capacity Margin Comparison

0%

10%

20%

30%

40%

50%

60%

70%

2008/09

2009/10

2010/11

2011/12

2012/13

2013/14

2014/15

2015/16

2016/17

2017/18

Margin (%)

Region/Subregion Target Margin Existing Certain

Net Capacity Resources Adjusted Potential Resources

Total Potential Resources
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117 2008 Long-Term Reliability Assessment 

NPCC-Ontario - Winter Capacity Margin Comparison

-10%

0%

10%

20%

30%

40%

50%

2008/09

2009/10

2010/11

2011/12

2012/13

2013/14

2014/15

2015/16

2016/17

2017/18

Margin (%)

Region/Subregion Target Margin Existing Certain

Net Capacity Resources Adjusted Potential Resources

Total Potential Resources

NPCC-Quebec - Winter Capacity Margin Comparison

0%

5%

10%

15%

20%

25%

30%

2008/09

2009/10

2010/11

2011/12

2012/13

2013/14

2014/15

2015/16

2016/17

2017/18

Margin (%)

Region/Subregion Target Margin Existing Certain

Net Capacity Resources Adjusted Potential Resources

Total Potential Resources
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118 2008 Long-Term Reliability Assessment 

NPCC Self-Assessment 

Overview 

The resource plans of each of the five Areas (subregions) of NPCC meet the NPCC resource 

adequacy criterion which states that probability of disconnecting firm load shall be not more than 

once in ten years. Further, the currently planned transmission system over the ten-year period is 

expected to perform reliably for a range of contingencies and conditions. 

The following discussions document the extensive processes in place within NPCC to ensure that 

both resource and transmission plans remain adequate for the study period. 

NPCC Resource Adequacy Assessment Process 

The Northeast Power Coordinating Council, Inc. has in place a comprehensive resource 

assessment program directed through NPCC Document B-08, “Guidelines for Area Review of 

Resource Adequacy.”145 This document charges the NPCC Task Force on Coordination of 

Planning (TFCP) to assess periodic reviews of resource adequacy for the five NPCC Areas, or 

subregions, defined by the following footprints: 

● Maritimes Area (the New Brunswick System Operator, Nova Scotia Power Inc., the 

Maritime Electric Company Ltd. and the Northern Maine Independent System 

Administrator, Inc); 

● New England (the ISO New England Inc.); 

● New York (New York ISO); 

● Ontario (Independent Electricity System Operator); and 

● Québec (Hydro-Québec TransÉnergie). 

In assessing each review, the TFCP will ensure that the proposed resources of each NPCC Area 

will comply with NPCC Document A-02, “Basic Criteria for Design and Operation of 

Interconnected Power Systems.”146 Section 3.0 of Document A-02 defines the criterion for 

resource adequacy for each Area as follows: 

Resource Adequacy - Design Criteria

Each Area’s 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 criterion shall be 

evaluated probabilistically, such that the loss of load expectation [LOLE] of disconnecting firm 

load due to resource deficiencies shall be, on average, no more than 0.1 day per year. This 

evaluation shall make due allowance for demand uncertainty, scheduled outages and deratings, 

forced outages and deratings, assistance over interconnections with neighboring Areas and 

 

145 http://www.npcc.org/documents/regStandards/Guide.aspx 146 http://www.npcc.org/documents/regStandards/Criteria.aspx 
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119 2008 Long-Term Reliability Assessment 

Regions, transmission transfer capabilities, and capacity and/or load relief from available 

operating procedures. 

The primary objective of the NPCC Area resource review is to ensure that plans are in place 

within the Area for the timely acquisition of resources sufficient to meet this resource adequacy 

criterion and to identify those instances in which a failure to comply with the NPCC “Basic 

Criteria for Design and Operation of Interconnected Power Systems,” or other NPCC criteria, 

could result in adverse consequences to another NPCC Area or Areas. If, in the course of the 

study, such problems of an inter-Area nature are determined, NPCC informs the affected systems 

and Areas, works with the Area to develop mechanisms to mitigate potential reliability impacts 

and monitors the resolution of the concern. 

For the purposes of the Area resource adequacy review, resources are defined as the sum of 

supply-side and demand-side contributions. Supply-side facilities may include all generation 

sources within an Area as well as purchases from neighboring systems. Demand-side facilities 

may include measures for reducing and/or shifting load, such as conservation, load management, 

interruptible loads, dispatchable loads and unmetered, but identifiable small capacity generation. 

Document B-08 requires each Area resource assessment to include an evaluation and / or 

discussion of the: 

• Load model and critical assumptions on which the review is based; 

• Procedures used by the Area for verifying generator ratings and identifying deratings 

and forced outages; 

• Ability of the Area to reliably meet projected electricity demand, assuming the most 

likely load forecast for the Area and the proposed resource scenario; 

• Ability of the Area to reliably meet projected electricity demand, assuming a high 

growth load forecast for the Area and the proposed resource scenario; 

• Impact of load and resource uncertainties on projected Area reliability, discussing any 

available mechanisms to mitigate potential reliability impacts; 

• Proposed resource capacity mix and the potential for reliability impacts due to the 

transportation infrastructure to supply the fuel; 

• Internal transmission limitations; and 

• The impact of any possible environmental restrictions. 

The resource adequacy review must describe the basic load model on which the review is based 

together with its inherent assumptions, and variations on the model must consider load forecast 

uncertainty. The anticipated impact on load and energy of demand-side management programs 

must also be addressed. If the Area load model includes pockets of demand for entities which 

are not members of NPCC, the Area must discuss how it incorporates the electricity demand and 

energy projections of such entities. 

Each Area resource adequacy review will be conducted for a window of five years, and a 

detailed, “Comprehensive Review,” is conducted triennially. For those years when the 

Comprehensive Review is not required, the Area is charged to continue to evaluate its resource 

projections on an annual basis. The Area will conduct an “Annual Interim Review” that will 
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120 2008 Long-Term Reliability Assessment 

reassess the remaining years studied in its most recent Comprehensive Review. Based on the 

results of the Annual Interim Review, the Area may be asked to advance its next regularly 

scheduled Comprehensive Review. 

These resource assessments are complemented by the efforts of the Working Group on the 

Review of Resource and Transmission Adequacy (Working Group CP-08), which assesses the 

interconnection benefits assumed by each NPCC Area in demonstrating compliance with the 

NPCC resource reliability. The Working Group conducts such studies at least triennially for a 

window of five years, and the Working Group judges if the outside assistance assumed by each 

Area is reasonable. 

NPCC Transmission Assessment Process 

In parallel with the NPCC Area resource review, the NPCC Task Force on System Studies 

(TFSS) is charged with conducting periodic reviews of the reliability of the planned bulk power 

transmission systems of each Area of NPCC, the conduct of which is directed through NPCC 

Document B-04, “Guidelines for NPCC AREA Transmission Reviews.”147 Each Area is 

required to present an annual transmission review to the TFSS, assessing its planned 

transmission network four to six years in the future. Depending on the extent of the expected 

changes to the system studied, the review presented each year by the Area may be one of the 

following three types: 

• Comprehensive Review 

A detailed analysis of the complete bulk power system of the Area is presented every 

five years at a minimum. The TFSS will charge the Area to conduct such a review 

more frequently as changes may dictate. 

• Intermediate Review 

An Intermediate Review is conducted with the same level of detail as a 

Comprehensive Review, but, in those instances in which the significant transmission 

enhancements are confined to a segment of the Area, the review will focus only on 

that portion of the system. Or, if the changes to the overall system are intermediate in 

nature, the analysis will focus only on the newly planned facilities. 

• Interim Review 

If the changes in the planned transmission system are minimal, the Area will 

summarize these changes, assess the impact of the changes on the bulk power system 

of the Area and reference the most recently conducted Intermediate Review or 

Comprehensive Review. 

In the years between Comprehensive Reviews, an Area will annually conduct either an Interim 

Review, or an Intermediate Review, depending on the extent of the system changes projected for 

 

147 http://www.npcc.org/documents/regStandards/Guide.aspx
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121 2008 Long-Term Reliability Assessment 

the Area since its last Comprehensive Review. The TFSS will judge the significance of the 

proposed system changes planned by the Area and direct an Intermediate Review or an Interim 

Review. If the TFSS agrees that revisions to the planned system are major, it will charge a 

Comprehensive Review in advance of the normal five-year schedule. 

Both the Comprehensive Review and the Intermediate Review analyze: 

• Steady state performance of the system; 

• Dynamic performance of the system; 

• Response of the system to selected extreme contingencies; and 

• Response of the system to extreme system conditions. 

Each review will also discuss special protection systems and / or dynamic control systems within 

the Area, the failure or misoperation of which could impact neighboring Areas or Regions. 

The depth of the analysis required in the NPCC transmission review fully complies with, or 

exceeds, the obligations of NERC Reliability Standards TPL-001 through TPL-004: 

• TPL-001-0, “System Performance Under Normal Conditions” 

• TPL-002-0, “System Performance Following Loss of a Single BES Element” 

• TPL-003-0, “System Performance Following Loss of Two or More BES 

Elements” 

• TPL-004-0, “System Performance Following Extreme BES Events” 

Coordinated Operations

Reliable operations within NPCC are directed through the five Reliability Coordinators of 

NPCC. Each of the NPCC Areas also serves as a NERC Reliability Coordinator for its 

respective footprint as follows: 

Entity Serving as NERC Reliability 

Coordinator 

Reliability Coordinator Footprint 

New Brunswick System Operator (NBSO) Provinces of New Brunswick, Nova Scotia 

and Prince Edward Island; the Northern 

Maine Independent System Administrator, 

Inc 

ISO New England Inc. States of Connecticut, Maine, 

Massachusetts, New Hampshire, Rhode 

Island and Vermont, 

New York ISO State of New York 

Independent Electricity System Operator 

(IESO) 

Province of Ontario 

Hydro-Québec TransÉnergie Province of Québec 

Within each Area, the respective Reliability Coordinator assumes the authority and responsibility 

to immediately direct the redispatch of generation, the reconfiguration of transmission, or, if 
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122 2008 Long-Term Reliability Assessment 

necessary to return the system to a secure state, the shedding of firm load. Coordination in the 

daily operation of the bulk electric system is assisted through enhanced communications and 

heightened awareness of system conditions and mutual assistance during an emergency or a 

potentially evolving emergency. The Reliability Coordinators of the five NPCC Areas conduct 

conference calls daily and weekly to identify and assess emerging system conditions, and 

procedures are in place to initiate emergency conference calls whenever one or more Areas 

anticipates a shortfall of capacity or anticipates the implementation of operating measures in 

response to a system emergency. 

The NERC Standards, together with the Regional Criteria, Guides, and Procedures, establish the 

fundamental principles of interconnected operations among the NPCC Areas. 

NPCC Document A-03, “Emergency Operation Criteria,”148 presents the basic factors to be 

considered in formulating plans and procedures to be followed in an emergency or during 

conditions which could lead to an emergency, in order to facilitate mutual assistance and 

coordination among the Areas The Criterion establishes seven basic objectives in formulating 

plans related to emergency operating conditions, including the avoidance of interruption of 

service to firm load, minimizing the occurrence of system disturbances, containing any system 

disturbance and limiting its effects to the Area initially impacted, minimizing the effects of any 

system disturbances on the customer, avoiding damage to system elements, avoiding potential 

hazard to the public and ensuring Area readiness to restore its system in the event of a major or 

partial blackout. 

NPCC Document A-06, “Operating Reserve Criteria,”149 defines the necessary operating 

capacity required to meet forecast load, to accommodate load forecasting error, to provide 

protection against equipment failure which has a reasonably high probability of occurrence and 

to provide adequate regulation of frequency and tie line power flow. The NPCC “Operating 

Reserve Criteria” require two components of operating reserve. The ten-minute operating 

reserve available to each Area shall at least equal its most severe first contingency loss. The 

thirty-minute operating reserve available to each Area shall at least equal one-half its most severe 

second contingency loss. 

Various operating Guidelines and Procedures complement the NPCC Criteria by providing the 

system operator with detailed instructions to address such topics as the depletion of operating 

reserve, capacity shortfalls, the sharing of operating reserve, line loading relief, declining 

voltage, measures to contain the spread of an emergency, light load conditions, the rating of 

generating capability, the consequences of a solar magnetic disturbance, procedures for 

communications during an emergency and the coordinated restoration of the systems following a 

partial or total blackout. 

Area Assessments

Among the five NPCC Areas, the Maritimes Area and Québec are predominantly winter peaking 

systems. The Ontario, the New York and the New England Areas are summer peaking systems. 

 

148 http://www.npcc.org/documents/regStandards/Criteria.aspx 149 http://www.npcc.org/documents/regStandards/Criteria.aspx
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123 2008 Long-Term Reliability Assessment 

Consequently, the mix of winter and summer peaking areas would make a NPCC-wide 

comparison of year to year peaks misleading. Comparisons for the individual subregions are 

below. The expected growth, together with the overall reliability assessment of the projected 

transmission and resources, follows individually for the Maritimes Area, New England, New 

York, Ontario and Québec. 

Maritimes Area 

Introduction 

The footprint of the Maritimes Area is comprised of the Canadian provinces of New Brunswick 

(served by the New Brunswick System Operator), Nova Scotia (served by Nova Scotia Power 

Inc.), Prince Edward Island (served by the Maritime Electric Company Ltd.) and the Northern 

Maine Independent System Administrator, Inc (NMISA). The NMISA serves approximately 

40,000 customers in northern Maine and is radially connected to the New Brunswick power 

system. The Maritimes Area is a winter peaking region. 

On October 1, 2004, New Brunswick’s Electricity Act restructured the electric utility industry in 

New Brunswick (NB) and created the New Brunswick System Operator (NBSO). It is an 

independent not-for-profit statutory corporation separate from the NB Power group of 

companies. The Electricity Act transferred the responsibility for the security and reliability of 

the integrated New Brunswick electricity system from NB Power to NBSO, and also made 

NBSO responsible for facilitating the development and operation of the New Brunswick 

Electricity Market. These responsibilities take the form of operation of the NBSO controlled 

grid and administration of the NBSO Open Access Transmission Tariff (OATT) and the New 

Brunswick Market Rules. On February 1, 2007, the Nova Scotia Electricity Act came into 

effect, enabling wholesale market access with the implementation of the Nova Scotia Market 

Rules. The Nova Scotia Power System Operator (NSPSO) is that function of NSPI that is 

responsible for the reliable operation of the integrated power system in Nova Scotia (NS), as well 

as administration of the NS Market Rules and the Nova Scotia OATT which has been in effect 

since November 1, 2005. 

By contractual agreement, the NBSO acts as the Reliability Coordinator for the Maritimes Area. 

Demand 

Separate demand and energy forecasts are prepared by each of the Maritimes Area jurisdictions, 

as there is no regulatory requirement for a single authority to produce a forecast for the whole 

Maritimes Area. For Area studies, the individual forecasts are combined using the load shape of 

each jurisdiction. 

The NBSO load forecast for New Brunswick is based on 30-year average temperatures (1971-

2000) with the annual peak hour demand determined for a design temperature of -24°C over a 

sustained eight-hour period. It is prepared based on a cause and effect analysis of past loads, 

combined with data gathered through customer surveys, and an assessment of economic, 

demographic, technological and other factors that affect the use of electrical energy. 
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124 2008 Long-Term Reliability Assessment 

The NSPI load forecast for Nova Scotia is based on 30-year historical climate normalization for 

the major load centers, along with analyses of sales history, economic indicators, customer 

surveys, technological and demographic changes in the market, and the price and availability of 

other energy sources. 

The MECL load forecast for PEI uses an econometric model that factors in the historical 

relationship between electricity use and economic factors such as gross domestic product, 

electricity prices, and personal disposable income. 

The NMISA load forecast for northern Maine is based on historic average peak hour demand 

patterns inflated at a nominal rate and normalized to 30-year average historical weather patterns. 

Economic and other factors may also affect the forecast. 

The 2008/09 peak demand forecast, representing the summation of the forecasts of each 

Maritimes Area jurisdiction, is 5,705 MW, 269 MW lower than last year. The forecast average 

annual peak demand growth rate is 0.9% over the next ten years, and this is lower than the 1.7% 

growth rate forecast last year. Contributing significantly to this lower forecast are announced 

mill closures in the pulp & paper and wood processing sectors, along with limited growth 

expectations in these sectors due to a high Canadian dollar and rising energy costs. 

Monthly peak forecasts for the Maritimes Area are summations of the individual jurisdiction 

forecasts. For Area studies, the individual forecasts are combined using the load shape of each 

jurisdiction. 

The only demand response program currently used in the Maritimes Area is interruptible 

demand. For 2008/09, the interruptible demand forecast for the peak month is 485 MW, which 

represents 8.5% of the peak demand forecast. 

In its comprehensive reviews of resource adequacy, the Maritimes Area uses a load forecast 

uncertainty representing the historical standard deviation of load forecast errors based upon the 

four year lead time required to add new resources. 

Generation 

The Maritimes Area capacity resources in 2008/09 amount to 6,312 MW of Existing Certain 

capacity resources, 663 MW of Existing Uncertain capacity resources, 39 MW of Planned 

capacity resources, and 0 MW of Proposed capacity resources. The largest portion of the 

Existing Uncertain capacity resources is 558 MW of inoperable capacity at the Point Lepreau 

nuclear station due to an 18-month refurbishment between April 2008 and October 2009. 

By 2009/10, the Planned capacity resources increase to 225 MW, consisting of 100 MW of 

incremental nuclear capability from the Point Lepreau refurbishment, and 125 MW of on-peak 

wind capacity. By 2017/18, the Proposed capacity resources increase to 272 MW, of which 196 

MW is on-peak wind capacity. 
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125 2008 Long-Term Reliability Assessment 

In 2008/09, the wind generation expected on-peak represents 61 MW of the Existing Certain 

capacity resources, 66 MW of the Existing Uncertain capacity resources, and 39 MW of the 

Planned capacity resources. 

In 2008/09, biomass capacity represents 153 MW of Existing Certain capacity resources, and 5 

MW of Existing Uncertain capacity resources. There is no Planned or Proposed biomass 

capacity for the Maritimes during the study period. 

Planned and Proposed capacity resources are based upon the most recent 10-year projections 

submitted to NBSO by the load serving utilities in the Maritimes Area. Planned resources are 

required to be in construction. Proposed resources include known project announcements and 

legislated renewable energy requirements for utilities. 

Purchases and Sales on Peak 

The capacity purchase for the Maritimes is a firm 200 MW purchase from Hydro Quebec during 

the 2008/09 winter peak season. 

The firm capacity purchase from Hydro Quebec is not tied to a specific generator. The purchase 

is backed by a transmission reservation. 

The capacity purchase from Hydro Quebec is not an LDC. 

For the period 2008 through October 2011, there is a firm capacity sale of 198 MW from the 

Maritimes to Hydro Quebec. This sale is tied to two 99 MW oil combustion turbines at 

Millbank, NB. This sale is also backed by a transmission reservation. 

For 2008, there are a total of non-firm capacity sales of 11 MW from the Maritimes to New 

England. These non-firm capacity sales rise to 91 MW between 2009 and 2017. These capacity 

sales are tied to renewable energy projects in the Maritimes, and are not backed by transmission 

reservations. 

None of the capacity sales from the Maritimes are LDCs. 

The Maritimes Area participates in a regional reserve sharing program with New England, New 

York, and Ontario for 100 MW of ten-minute reserve. This reserve is counted as 25% spinning 

and 75% supplemental. 

Fuel 

Due to the diversity of the Maritimes Area fuel supply mix, its relatively low reliance on natural 

gas, and its fuel storage facilities, the potential impact of fuel supply and/or delivery 

interruptions in the Maritimes Area is very low, and thus it is not explicitly modeled in resource 

adequacy assessments. 

The percentage of natural gas in the Maritimes is less than 8%, and the percentage of coal-fired 

generation is about 27%. 
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126 2008 Long-Term Reliability Assessment 

Transmission 

Currently, the only new bulk power system transmission anticipated to be in-service during the 

ten year study period is a 103-mile, 345 kV line between Coleson Cove, NB and Salisbury, NB. 

The expected in-service date in sometime between 2009 and 2016. 

There are no transformer additions to the Maritimes bulk power system within this ten year study 

period. 

Operational Issues 

There are no significant anticipated generating unit outages, variable resource, transmission 

additions or temporary operating measures that are anticipated to impact the reliability of the 

Maritimes during the next ten years. 

There are no environmental or regulatory restrictions that are anticipated to impact the reliability

of the Maritimes during the next ten years. 

Reliability Assessment Analysis 

The Maritimes uses a reserve criterion of 20% for planning purposes and it was shown in the 

2007 Maritimes Comprehensive Review of Resource Adequacy150 that adherence to this criterion 

complies with the NPCC reliability criterion. The 20% reserve criterion is met in all ten years of 

the study period, with a minimum reserve of 22% occurring in 2008/09 due to the refurbishment 

of Point Lepreau. 

The Maritimes reserve criterion of 20% is set to a level which complies with the NPCC 

reliability criterion. 

Except for the 200 MW firm capacity purchase from Hydro Quebec during the peak winter 

months of 2008/09, all of the resources used to meet the reserve margin criterion are internal to 

the Maritimes. 

The Maritimes conducts resource adequacy studies to identify the resources needed to meet the 

NPCC resource adequacy criterion of less than 0.1 days per year of Loss of Load Expectation 

(LOLE). 

In its 2007 Maritimes “Comprehensive Review of Resource Adequacy,”151 it was shown that the 

NPCC reliability criterion of less than 0.1 days of firm load disconnections per year is not 

exceeded by the Maritimes Area for all years in the 2008-2012 study period, and varies between 

0.001 to 0.086 days/yr for the base load forecast with load forecast uncertainty. The Maritimes 

Area requires no support from its interconnections to meet the NPCC reliability criterion for all 

 

150 http://www.npcc.org/documents/reviews/Resource.aspx 151 http://www.npcc.org/documents/reviews/Resource.aspx
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127 2008 Long-Term Reliability Assessment 

years of the 2008-2012 study period. The Maritimes Area is also shown to adhere to its own 20% 

reserve planning criterion in all years for the base load forecast, with reserve levels varying 

between 22% and 40%. 

There is no difference in how the Maritimes treats short-term (i.e. 1-5 years) and long-term (i.e. 

6-10 years) reserve requirements. 

The most significant change since the last assessment is a lower demand forecast and demand 

growth rate for the Maritimes. Contributing significantly to this lower forecast are announced 

mill closures in the pulp & paper and wood processing sectors, along with limited growth 

expectations in these sectors due to a high Canadian dollar and rising energy costs. With this 

lower demand comes higher forecast reserve margins, and therefore less need to plan for any 

major new capacity in the Maritimes. 

In its 2007 Maritimes “Comprehensive Review of Resource Adequacy,” 152 scenarios of high 

load growth and zero wind availability were studied, with the result that the Maritimes Area was 

still able to meet its 20% reserve criterion in all cases with no more than 35 MW of necessary 

interconnection support. This level of interconnection support represents only 2.1% of the 

Maritimes Area tie benefits capability. 

As mentioned in part vii), the 2007 Maritimes Comprehensive Review of Resource Adequacy 

demonstrated compliance with the NPCC reliability criterion for the high load growth scenario. 

Wind project capacity for the Maritimes is modeled based upon results from the September 21, 

2005 NBSO report “Maritimes Wind Integration Study”.153 This report showed that the effective 

capacity from wind projects, and their contribution to Loss of Load Expectation was equal to or 

better than their seasonal capacity factors. Coincidence of high winter wind generation with the 

peak winter loads results in the Maritimes Area receiving a higher capacity benefit from wind 

projects versus a summer peaking area. The effective wind capacity calculation also assumes a 

good geographic dispersion of the wind projects in order to mitigate the occurrences of having 

zero wind production. 

There are no potential unit retirements having significant impact on the reliability of the 

Maritimes. 

Generation deliverability for the Maritimes is addressed through a combination of resource 

adequacy and transmission reliability studies. Resource adequacy studies use multi-area 

probabilistic analysis in order to verify that intra-area constraints do not compromise resource 

adequacy. Comprehensive transmission studies are performed for sub-areas to ensure that 

generation is sufficiently integrated with load. 

The Maritimes is studying an interconnection request from Newfoundland and Labrador Hydro 

involving an HVDC interconnection between Newfoundland and the Maritimes that would 

transmit up to 740 MW from the Lower Churchill hydro project to either New Brunswick or 

 

152 http://www.npcc.org/documents/reviews/Resource.aspx 153 http://www.nbso.ca/Public/_private/2005%20Maritime%20Wind%20Integration%20Study%20_Final_.pdf
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128 2008 Long-Term Reliability Assessment 

Nova Scotia, and then on down to New England. The target in-service date is January 1, 2015 

but due to its uncertainty it hasn’t been included as a proposed project. 

Currently, there are no specific deliverability problems in the Maritimes with the current 

portfolio of wind generation. Future proposed wind projects concentrated in certain areas may 

cause some congestion issues, and those issues are addressed in the System Impact Studies for 

those projects. 

System Impact Studies are mandatory for new generation interconnections, and may be required 

for changes/additions to the transmission grid. There are no anticipated stability issues 

impacting the reliability of the Maritimes during the study period. 

Under normal conditions, the Maritimes grid is to be designed and operated within a plus or 

minus 5% of nominal voltage. Both synchronous generators as well as wind projects have 

minimum voltage support requirements in the form of leading and lagging power factor 

capability. 

Generators in the Maritimes must not cause a voltage dip greater than 3% during start-up or 

shutdown. There are no known reactive power-limited areas in the Maritimes Area. At this time, 

there are no plans to install more UVLS in the Maritimes Area. 

The Maritimes Area addresses the loss of generation through its operating reserve requirements. 

Due to its diverse fuel mix and fuel storage, no long-term fuel disruptions are anticipated. The 

Maritimes Area has experienced above average levels of hydro power the last few years. 

Nuclear capacity will be increased by 100 MW due to the refurbishment of Point Lepreau. 

Bulk power system reliability has increased significantly with the commissioning of the second 

345 kV interconnection between New Brunswick and New England in December 2007. 

There are no reliability impacts to any specific aging infrastructure in the Maritimes area. The 

aging of the Point Lepreau nuclear station is being addressed through its refurbishment from 

April 2008 to October 2009. 

The Maritimes does not have any guidelines for on-site, spare generator step-up (GSU) or 

autotransformers. 

New England 

ISO New England’s reference case forecast is the 50/50 forecast (50% chance of being 

exceeded), corresponding to a New England three-day weighted temperature-humidity index 

(WTHI) of 80.1, which is equivalent to a dry bulb temperature of 90 degrees Fahrenheit and a 

dew point temperature of 70 degrees Fahrenheit. The reference demand forecast is based on the 
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129 2008 Long-Term Reliability Assessment 

reference economic forecast, which reflects the economic conditions that “most likely” would 

occur. 

This year’s summer peak forecast ten-year compound annual average growth rate has decreased 

to 1.2 percent from 1.7 percent, resulting in generally lower summer peak forecasts when 

compared with the 2007 long-term forecast. The key factor leading to the lower forecasts is a 

long-run forecast of lower personal income, which is an economic driver in the energy and peak 

load models. 

ISO New England develops an independent load forecast for the Balancing Authority area as a 

whole, and does not use individual members’ forecasts of peak load in its load forecast. 

It is expected that 1,820154 MW of demand resources will be available in summer 2008. These 

include resources in ISO New England’s Real-Time 30-minute, Real-Time 2-Hour, and Profiled 

Demand Response programs, which are instructed to interrupt their consumption during specific 

actions of Operating Procedure No. 4 (OP 4), Action During a Capacity Deficiency. Some of the 

assets in the Real-Time Demand Response programs are under direct control. The direct load 

control involves the interruption of central air conditioning systems in residential, commercial 

and industrial facilities. Also included in the total is 167 MW of energy efficiency. The 1,820 

MW of demand resources is expected to grow to 2,278 MW by 2010 because that is the amount 

of demand resources that has cleared ISO New England’s first Forward Capacity Auction (FCA), 

for the 2010-2011 commitment period. 

The 2,278 MW of demand resources that cleared the first FCA include new energy efficiency 

programs totaling 612 MW. The energy efficiency programs are also considered capacity 

resources in the New England capacity market. Under FCM, energy efficiency can be included 

in the category of on-peak demand resources155, which includes installed measures (e.g., 

products, equipment, systems, services, practices and/or strategies) on end-use customer facilities 

that result in additional and verifiable reductions in the total amount of electrical energy 

consumed during on-peak hours. As part of the qualification process to participate in an FCA, 

any new demand resource must submit detailed information about the project, including location, 

project description, estimated demand reduction values, and expected commercial operation date 

along with a project completion schedule. In addition, the new demand resource submits a 

Measurement and Verification (M&V) Plan, which must be approved by the ISO. The project 

sponsor is required to submit certification that the project complies with their ISO-approved 

M&V Plan. The ISO has the right to audit the records, data, or actual installations to ensure that 

the energy efficiency projects are providing the load reduction promised. The ISO tracks the 

project against their submitted schedule, thereby taking a proactive role in monitoring the 

progress of these resources to ensure that they are ready to reduce demand by the start of the 

FCM commitment period. 

 

154 This value is 137 MW higher than the demand resources assumed for the 2008 NERC RAS Summer Assessment due to 

updated information. 155 The rules addressing the treatment of demand resources in the Forward Capacity Market may be found in Section III.13.1.4 of 

ISO New England’s Market Rule 1, Standard Market Design, located at http://www.iso-ne.com/regulatory/tariff/sect_3/v8-7-

1-08_mr1_sect_13-14.pdf
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130 2008 Long-Term Reliability Assessment 

In addition to reliability-based programs, ISO-NE administers a voluntary price-response 

program where load interrupts based on the price of energy. As of March 31, 2008, there were 

approximately 97 MW enrolled in the price response program. These programs are not counted 

as capacity resources since their interruption is voluntary. 

ISO New England addresses peak demand uncertainty in two ways: 

• Weather – annual peak load distribution forecasts are made based on 37 years of historical 

weather which includes the reference forecast (50% chance of being exceeded), and 

extreme forecast (10% chance of being exceeded);156

• Economics – alternative forecasts are made using high and low economic scenarios. 

ISO New England reviews the summer conditions of the study period using the annual extreme, 

90/10 peak demand based on the reference economic forecast. 

Resources 

The ISO New England Balancing Authority capacity resources amount to 32,933157 MW in 

2008. That includes 30,892 MW of Existing Certain generating capacity, 1,820 MW of demand 

response resources, and 58 MW of net firm purchases and sales. Also included in the total 

capacity resources is 181 MW of Planned generating capacity, which is expected to become 

commercial by summer 2008. The total new generation expected to be in service by 2010 

amounts to 427 MW. In addition to the Planned capacity, ISO New England has a total of 13,028 

MW of Proposed projects in its Generator Interconnection Queue, with in-service dates ranging 

from 2008 to 2014. 

Approximately four MW of the Existing Certain capacity is wind generation expected on peak. 

The total nameplate capability of those wind facilities is 11 MW. The Planned capacity includes 

43 MW (124 MW nameplate) of new wind capacity, which is expected to be in service by 

summer 2009. Proposed wind capacity in New England amounts to 1,713 MW based on 

nameplate ratings, with target in-service dates of 2008 through 2011. 

Also included in the Existing Certain capacity is 765 MW of variable hydro resources expected 

on peak. 

Biomass capacity in the Existing Certain category totals 888 MW. Two additional Planned 

biomass facilities totaling 25 MW are expected to be in operation by summer 2009. A total of 

515 MW of biomass capacity is Proposed for installation in New England with target in-service 

dates of 2009 through 2014. 

ISO-NE’s capacity margin calculations include Planned capacity resources that are expected to 

begin commercial operation by the end of 2008. This information is based on either the date 

 

156 On an annual basis, the 50/50 reference peak has a 50% chance of being exceeded, and the 90/10 extreme peak has a 10% 

chance of being exceeded. 157 Due to differences in assumptions, the amount of existing and planned capacity in summer 2008 is different from that 

published in ISO New England’s 2008-2017 Forecast Report of Capacity, Energy, Loads, and Transmission (CELT Report). 
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131 2008 Long-Term Reliability Assessment 

specified in a signed Interconnection Agreement, or discussions with ISO-NE Customer Services 

indicating that the project is nearing completion and is preparing to become an ISO generator 

asset. Also included in the Planned capacity resources are new projects that have obligations in 

the ISO-NE Forward Capacity Market in 2010-2011. 

Purchases and Sales on Peak 

Firm purchases amount to approximately 400 MW through 2012 and then decrease to 334 MW 

in 2013 – 2014. Only firm, Installed Capacity (ICAP) purchases that are known in advance are 

included as capacity. A total of 934 MW of import capacity resources cleared in the first 

Forward Capacity Auction for the 2010-2011 commitment period. Although those are one-year 

contracts, they were assumed to extend through the end of the study period. If these particular 

imports do not clear in future FCM commitment periods, the capacity will be replaced by 

generator resources or other imports. 

The entire amount of ICAP purchases is backed by firm contracts for generation, and the imports 

under the Forward Capacity Market are import capacity resources with an obligation for the 

2010-2011 Capacity Commitment Period. Although there is no requirement for those purchases 

to have firm transmission service, it is specified that deliverability of firm purchases must meet 

the New England delivery requirement and should be consistent with the deliverability 

requirements of internal generators. The market participant is free to choose the type of 

transmission service it wishes to use for the delivery of firm energy, but the market participant 

bears the associated risk of market penalties if it chooses to use non-firm transmission. 

The 310 MW purchase from Hydro-Québec is a Liquidated Damage Contract (LDC) that is not a 

“make-whole” contract. The 91 MW purchase from New York is not an LDC. 

For the period 2008 through 2009, ISO New England is aware of a firm capacity sale to New 

York (Long Island) of 343 MW, anticipated to be delivered via the Cross Sound Cable. This sale 

will be reduced to 100 MW beginning in 2010. It should be noted that there is no firm 

transmission arrangement through the New England PTF system associated with this contract. 

This sale is backed by a firm contract for generation, but because the power has to go through the 

Connecticut import constrained interface, and there is no firm transmission arrangement, it can 

be cut earlier than non-recallable exports in the case of a transmission import constraint into 

Connecticut. 

The sale across the Cross Sound Cable is based on a make-whole contract. 

For resource adequacy studies, ISO New England assumes 2,000 MW of emergency assistance is 

available during 2008 and 2009, and 1,860 MW of emergency assistance from 2010 through 

2018. This assistance is also referred to as tie-line benefits that are available from other areas 

within the NPCC region, and is about 50% of New England’s total import capability. ISO New 

England also participates in a regional reserve sharing group with NPCC, and has a shared 

activation of reserves agreement with New York for up to 300 MW. 
Regional Reliability Assessment

132 2008 Long-Term Reliability Assessment 

Fuel 

Generation in New England is fueled primarily by natural gas (42.2%), followed by nuclear 

generation (28.3%), coal (15.1%), non-hydro renewables (6.0%), hydro (4.9%), oil (2.2%) and 

pumped storage (1.3%). Fuel supply vulnerability is not a concern for any of the fuels other than 

natural gas. Hydro capacity is not a concern because the New England region seldom 

experiences droughts, and because such resources make up a small percentage of the New 

England generation. Oil-fired plants, which also are only a small portion of generation in New 

England, typically have multiple days of fuel storage. 

Coal is primarily imported via ocean-going transport and is procured through a combination of 

spot-market, medium- and long-term contracts. Aside from weather-related shipping delays, coal 

can be readily stored and stockpiled within the region. There are no coal supply or delivery 

problems anticipated for New England for 2008 and beyond. 

During the winter, New England’s natural gas-fired generators continue to compete with the core 

natural gas demand (i.e., for space heating) for gas supply and finite transportation infrastructure. 

During winter peak load periods, regional natural gas pipeline capacity may not be sufficient to 

serve the coincident demands from both the gas and electricity sectors. During extreme cold 

winter weather, when the demand for natural gas and electricity peak coincidently, ISO-NE has 

developed a cold weather operating procedure that can be implemented to help mitigate the loss 

of operable generating capacity. ISO-NE has also implemented market incentives, such as those 

provided by the Forward Capacity Market, that encourage the conversion of single-fuel, gas-only 

units to dual-fuel capability in addition to promoting the procurement of firm gas supply and 

transportation contracts. 

The ongoing concern over the interruption of regional natural gas supply is mitigated through 

ISO New England’s regular monitoring of the gas supply situation, and communications with the 

natural gas sector. An Energy Emergency operating procedure can be implemented during any 

time of the year, to help mitigate the operational impacts of both short and long-term fuel supply 

shortages. 

One area of potential concern is with natural gas interchangeability. Two new Liquefied Natural 

Gas (LNG) import terminals (one onshore and one offshore) will soon be commercialized within 

the region. ISO-NE has and will continue to monitor the development of and revisions to natural 

gas quality standards within the regional gas pipelines tariffs. Questions regarding the potential 

impacts from compositional variability within natural gas streams have been raised by gas-fired 

generators. ISO-NE will continue to monitor these developments on both a regional and national 

scale. 
Regional Reliability Assessment

133 2008 Long-Term Reliability Assessment 

Transmission

ISO New England’s 2008 Regional System Plan158 will identify the region’s needed transmission 

improvements for this period. The New England region currently has over 250 transmission 

projects and components159 in various stages of planning, construction, and implementation. 

Operational Issues 

There are no significant anticipated generating unit outages, variable resource, transmission 

additions or temporary operating measures that are anticipated to impact reliability during the 

next ten years. Planned outages and the addition of new facilities is coordinated by the ISO and 

must pass through a rigorous operational review to ensure continued system reliability before 

allowing such system outages or additions to occur. 

During extremely hot days and low river flow conditions, there may be environmental 

restrictions on generating units due to water discharge temperatures. Such conditions could result 

in capacity reductions ranging from 150 MW to 200 MW. These reductions are reflected in the 

ISO’s forced outage assumptions. The ISO monitors the situation and expects adequate resources 

to cover such forced outages or generator reductions. 

Reliability Assessment Analysis 

The calculated installed capacity margins based on generator and demand resources is 17 percent 

of the reference load forecast in 2008, and will be 15 percent in 2009 assuming no changes in 

capacity. In 2010, the margin increases to 18 percent. The margin in 2010 reflects the resources 

that have obligations to serve the capacity needs of the ISO New England Balancing Authority 

area resulting from ISO New England’s first Forward Capacity Auction. It was assumed that 

resources with obligations for that year will remain in place through the end of the study period. 

Without any assumed additional resources, the capacity margin declines after 2010 to 10 percent 

by 2017. New England does not have a particular capacity margin requirement; rather it plans 

resources to meet the once in ten years loss of load expectation resource planning reliability 

criterion. The capacity needs to meet this criterion are purchased through annual auctions three 

years in advance of the year of interest. After this primary annual auction, there are annual 

reconfiguration auctions prior to the commencement year in order to readjust installed capacity 

purchases and ensure that adequate capacity will be purchased to meet system needs. Therefore, 

ISO New England does not expect to face any installed capacity shortages in the future. For 

reference purposes, the annual average percent capacity needed to meet the resource adequacy 

planning criterion based on a forecast of representative future installed capacity requirements is 

approximately 15 percent. 

To develop installed capacity requirements to meet the once in 10 years disconnection of firm 

load resource planning reliability criterion, ISO New England takes into account the random 

behavior of load and resources in a power system, and the potential load and capacity relief 

 

158 Summaries of transmission studies and projects can be found in the ISO New England 2008 Regional System Plan (final 

report expected to be posted by the end of 2008) at www.iso-ne.com/trans/rsp/index.html 159 The project listing can be found on the ISO New England web site at www.iso-ne.com/trans/rsp/index.html
Regional Reliability Assessment

134 2008 Long-Term Reliability Assessment 

obtainable through the use of ISO-NE Operating Procedure No. 4 – Action During a Capacity 

Deficiency (OP 4). 

The amount of internal generating and demand resource capacity assumed available to meet the 

installed capacity requirement is 32,586 MW in 2008 and 32,965 in 2009, increasing to 33,419 

for the remainder of the study period to reflect the resources procured for the 2010-2011 FCM. 

The total capacity to serve load, including net purchases and sales, is 32,644 MW in 2008 and 

34,077 in 2010. 

The amount of resources external to New England reflects capacity purchases of 401 MW per 

year in 2008 and 2009, increasing to 934 MW in 2010. 

ISO New England conducts resource adequacy studies to identify the resources needed to meet 

the NPCC resource adequacy criterion of once in ten years loss of load expectation. The ISO 

conducts such studies on an annual basis for the regional system plan (RSP). The study 

conducted for RSP08 shows that if there are no changes in the current generator and demand 

resource capacity of 32,644 MW, the New England system will need an additional 565 MW of 

physical capacity in 2012 to meet the resource adequacy planning criterion. By 2017, the 

additional capacity required will be 2,414 MW. However, 34,077 MW of generating, demand 

and import resources cleared in the first Forward Capacity Auction for 2010. Assuming that 

amount is in service and does not change, New England will need additional resources only by 

2015.160 As shown in the table below, under such assumed load and resource conditions, an 

additional 360 MW would be needed in 2015, increasing to a total of 981 MW by 2017. 

The following table shows ISO New England’s Installed Capacity Requirements and additional 

physical capacity resources possibly needed to meet the resources adequacy criterion. 

Year

Forecast 

50/50 Peak

Representative 

Future Net 

ICAP 

Requirement

Assumed 

Existing ICAP

Cumulative 

Additional 

Resources 

Needed Based 

on Existing 

ICAP

Amount of 

ICAP that 

Cleared in the 

First FCA

Cumulative 

Additional 

Resources 

Needed Based 

on the FCA 

Cleared 

Resources

2008 27,970 30,960 32,644 - N/A

2009 28,480 31,613 32,644 - N/A

2010 28,995 32,305 32,644 - 34,077 -

2011 29,405 32,671 32,644 - 34,077 -

2012 29,820 33,209 32,644 565 34,077 -

2013 30,190 33,702 32,644 1,058 34,077 -

2014 30,510 34,084 32,644 1,440 34,077 7

2015 30,790 34,437 32,644 1,793 34,077 360

2016 31,035 34,781 32,644 2,137 34,077 704

2017 31,250 35,058 32,644 2,414 34,077 981

 

160 The 7 MW of need shown for 2014 may be approximated as 0 
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135 2008 Long-Term Reliability Assessment 

ISO New England has 13,669 MW of projects in its Generator Interconnection Queue. These 

resources could help meet New England’s future Forward Capacity Auction needs. Historically, 

approximately 30 to 35 percent of projects in the Queue have gone into commercial operation. 

The capacity of projects in the Queue, by fuel type and in-service date, is illustrated in the chart 

below. 

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

2007 2008 2009 2010 2011 2012 2013 2014

Megawatts (MW)

Wind & Other

Renewables

Nuclear

Coal

Oil

Natural Gas/Oil

Natural Gas

There is no difference in how ISO New England treats short-term (i.e. 1-5 years) and long-term 

(i.e. 6-10 years) capacity margin requirements. 

The amount of demand resources (DR) has increased significantly since last year’s assessment, 

with the DR projection for 2008 more than doubling from 828 MW to 1,820 MW. New 

generation totaling approximately 427 MW is assumed to be in service by the 2010-2011 FCM. 

This is nearly 350 MW higher than last year’s projection for new generation. 

ISO New England uses operating procedures to address real-time problems with resource 

adequacy. Actual resource unavailability due to fuel interruptions or other conditions are used to 

formulate resource availability assumptions for long-range resource adequacy studies conducted 

on an annual basis. 

ISO New England also conducted an operable capacity analysis based on the 90/10 peak-load 

forecast for its 2008 Regional System Plan. That analysis is shown in the table below. The 2009 

capacity consists of both generating and demand resources, and the capacity of the remaining 

years is the installed capacity requirement for those years assuming that ISO New England 

purchases the exact amount of resources to meet the installed capacity requirements. A total of 

1,800 MW of operating reserves are assumed for 2009, which increases to 2,000 MW for all 

other years to reflect an assumed increase in import capability over the Hydro-Quebec Phase II 

interconnection from 1,200 MW to 1,400 MW. A total of 2,100 MW of supply-side resource 

outages were assumed on the basis of historical observations. The results do not reflect resource 

(generating unit and demand resource) additions, retirements, or deactivations that could 

potentially occur during the planning period. 
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136 2008 Long-Term Reliability Assessment 

Capacity Situation 

(Summer MW) 2009 2010 2011 2012 2013 2014 2015 2016 2017

Load (90/10 forecast) 30,475 31,015 31,525 31,995 32,410 32,775 33,085 33,360 33,595

Operating reserves 1,800 2,000 2,000 2,000 2,000 2,000 2,000 2,000 2,000

Total requirement 32,275 33,015 33,525 33,995 34,410 34,775 35,085 35,360 35,595

Capacity 32,644 32,305 32,671 33,209 33,702 34,084 34,437 34,781 35,058

Assumed unavailable capacity 2,100 2,100 2,100 2,100 2,100 2,100 2,100 2,100 2,100

Total net capacity 30,544 30,205 30,571 31,109 31,602 31,984 32,337 32,681 32,958

Operable capacity margin -1,731 -2,810 -2,954 -2,886 -2,808 -2,791 -2,748 -2,679 -2,637

As shown in the above table, negative operable capacity margins ranging from approximately -

1,730 MW to -2,950 MW were calculated for the period 2009 through 2017. When New England 

is short of operable capacity, ISO New England will implement Operating Procedure No. 4 — 

Action During a Capacity Deficiency161 (OP 4). OP 4 is designed to provide additional 

generation and load relief needed to balance electric demand and supply while striving to 

maintain appropriate operating reserves. Capacity available under OP 4 includes voltage 

reduction and emergency assistance from neighboring balancing authorities. For the purposes of 

the ISO New England operable capacity studies (not reflected in the table above), 2,000 MW of 

emergency assistance is assumed to be available through 2009. That number changes to 1,860 

MW beginning in 2010. 

ISO New England does not consider any energy-only, existing-uncertain wind or transmissionlimited resources in its resource adequacy assessment. 

ISO New England is not aware of any future unit retirements, and does not make projections 

about potential retirements. 

ISO New England currently addresses generation deliverability through a combination of 

transmission reliability and resource adequacy analyses. Detailed transmission reliability 

analyses of sub-areas of the New England bulk power system confirm that reliability 

requirements can be met with the existing combination of transmission and generation. Multiarea probabilistic analyses are conducted to verify that inter-sub-area constraints do not 

compromise resource adequacy. The ongoing transmission-planning efforts associated with the 

New England Regional System Plan support compliance with the NERC Transmission Planning 

requirements and assure that the transmission system is planned to sufficiently integrate 

generation with load. 

Currently, New England does not have interconnection requests for new resources in the 6-10 

year time frame. 

The New England methods for Installed Capacity Requirement analysis and the Forward 

Capacity Market are designed to recognize transmission constraints and to procure generation 

that is incrementally useful to serve new load. 

 

161 Operating Procedure No. 4 may be found on ISO-NE’s website at http://www.isone.com/rules_proceds/operating/isone/op4/index.html. 
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137 2008 Long-Term Reliability Assessment 

Transmission plans have been developed to serve load growth throughout the New England 

region. This includes service to load areas in Maine, New Hampshire, Vermont, Western 

Massachusetts, Southeastern Massachusetts, Northeastern Massachusetts, Greater Rhode Island 

and Connecticut. 

The impact of new generator interconnections or changes/additions to transmission system 

topology on transient performance and voltage or reactive performance of the bulk power system 

is routinely analyzed and plans are developed to mitigate concerns as part of the interconnection 

process. Operating studies to develop operating guides are generally performed under light load 

conditions to assess the impact on transient performance and under both peak and light load 

conditions to assess the impact on voltage/reactive performance. Therefore each and every 

change to the generation/transmission system is either implicitly or explicitly evaluated from a 

transient and voltage/reactive perspective. There is nothing during the study period which would 

introduce any new concerns in these areas. 

New England has specific criteria to manage minimum dynamic reactive reserve requirements. 

ISO Operating Procedure (OP #17) defines acceptable Load Power Factor requirements for 

various subregions within New England. The procedure is designed to ensure adequate reactive 

resources are available in the subregion by managing the reactive demand. Furthermore, when 

transfer limits are developed for voltage or reactive constrained subregions, the ISO will develop 

detailed operating guides that cover all relevant system conditions to ensure reliable operation of 

the bulk power system. In determining the acceptable transfer limits, a 100 MW reserve margin 

is typically added to each limit to ensure that adequate reactive reserves are maintained. In some 

areas, such as Boston and Connecticut, where specific reactive compensation concerns exist, 

specific operating guides have been developed to ensure that the areas are operated reliably. 

New England has a specific guideline for voltage sag which states that the minimum post-fault 

voltage sag must remain above 70% of nominal voltage. In addition, the voltage must not sag 

below 80% of normal voltage for a duration longer than 250 milliseconds within the 10 seconds 

following the fault. This guideline is applied when developing transfer limits for the bulk power 

system in New England. 

There are no known reactive power-limited areas in the New England transmission system. 

Transmission planning studies have ensured that adequate reactive resources are provided 

throughout New England. For instances where dynamic reactive power supplies are needed, 

devices such as STATCOMs, DVARs and additional generation commitment have been 

employed to meet the required need. Additionally the system is reviewed in the near-term via 

operating studies to develop operating guides to confirm adequate voltage/reactive performance. 

New England, in creating transfer limits based on the dynamic performance of the system, does 

apply a 100 MW margin to transfer limits. 

At this time, there are no plans to install more UVLS in New England. Currently, Northern New 

England has the potential to arm approximately 600 MW of load shedding as part of UVLS. 

However, it is important to recognize that a significant portion of this load shedding is normally 

not armed and is only armed under severe loading conditions with a facility already out of 

service. Presently, two significant projects which are anticipated being in service by 2012 will 
Regional Reliability Assessment

138 2008 Long-Term Reliability Assessment 

either completely eliminate the need for the UVLS or significantly reduce the likelihood of 

depending on such schemes. These projects are the Vermont Southern Loop and the Maine 

Power Reliability Program. 

ISO New England addresses the loss of a major import path by covering the possible loss with 

operating reserve requirement. 

ISO New England’s Operating Procedures 21 – Action During an Energy Emergency (OP 21) 

addresses energy emergencies, which may occur as a result of sustained national or regional 

shortages in fuel availability or deliverability to the New England region’s generation resources. 

Because fuel shortages may impact the New England region’s ability to fully meet system load 

and ten minute operating reserve for extended periods of time, actions may need to be taken in 

advance of a projected Energy Emergency. OP 21 specifies actions to commit, schedule, and 

dispatch the system in such a way as to preserve stored fuel resources in the region to minimize 

the loss of operable generating capability due to fuel shortages. 

The New England area is currently not experiencing a drought. 

As part of the New England Regional System Planning process, system needs have been 

identified in all six states of the New England region. The system needs assessments and 

resulting system solutions, which form the basis of the New England project listing,162 ensure 

conformance with TPL-001 through TPL-004.

New England already has a number of installations of new technology. These include two 

STATCOMs, voltage source converter based HVDC, variable reactors, a short section of gasinsulated transmission line (GITL) and D-VAR. Presently there are no specific plans for the 

additional use of such technologies in future projects, but they are always under consideration as 

tools for upcoming system concerns. 

For the most part, New England’s short circuit concerns occur at voltages less than 230 kV. In 

many instances, the short circuit concerns at these lower voltages are resolved through changing 

generator interconnections to be at higher voltages, system reconfigurations, or by operating 

equipment in a normally open state to increase the impedance between the network and the 

subject bus. New England has been meeting with various manufacturers over the years to 

acquire information on the possible application of “short circuit limiters” to resolve concerns. 

To date, such technologies have not been employed. 

The New England utilities have been working to upgrade and update their equipment over time 

on a case-by-case basis. While older equipment remains in service, there are no known risks to 

the continued operation of this equipment. Transmission system plans will often consider the 

potential retirement of older generation and determine the upgrades, if necessary, to allow for 

such retirements to occur. 

New England does not have any guidelines for on-site, spare generator step-up (GSU) or 

autotransformers. New England has been having numerous discussions on possible policies to 

address these concerns with respect to autotransformers. In addition, some of New England’s 

 

162 The project listing can be found on the ISO New England web site at www.iso-ne.com/trans/rsp/index.html 
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139 2008 Long-Term Reliability Assessment 

Transmission Owners have joined on to the EEI initiated Spare Transformer Equipment 

Program. 

Other region-specific issues that were not mentioned above 

ISO New England and the broader industry face challenges associated with retirement of a 

seasoned, technical workforce coupled with a shrinking pool of available talent. To address these 

issues, ISO New England has developed a comprehensive Succession Management Program 

designed to identify highest potential employees and build Retention Plans for them. In 

additions, to ensure ISO New England continues to attract and retain the best talent the industry 

has to offer, ISO-NE has adjusted compensation for engineering professionals, and is in the 

process of developing a technical career path for its Information Technology professionals to 

offer them the ability to continue career advancement. ISO New England has also expanded its 

recruiting strategy to include building relationships with key technical universities with the intent 

of facilitating campus hiring and further developing the technical skills of ISO-NE’s existing 

population. 

New York 

Demand — The New York area is a summer-peaking system, and summer peak demands are 

expected to grow at an average rate of 0.9 %, through 2017. This compares with 1.2 % growth 

projected in the 2007-2016 assessment conducted by the RAS in 2007. The forecast developed 

by the NYISO is based on historical weather-normalized loads provided by the transmissionowners of New York State. At peak load levels, a one-degree increase in the cumulative 

temperature-humidity index (CTHI) above the design value of 84.2 will result in about 610 MW 

of additional load. (The CTHI is a three-day heat index based on the dry bulb and wet bulb 

temperatures.) 

Energy consumption is forecast to grow at an average annual rate of 1.2 % through 2017. This 

compares with 1.4 % growth projected in the 2007-2016 assessment conducted by the RAS in 

2007. The decrease in demand and energy projections are the result of weaker long term 

economic growth projections, revisions to historical economic time series, and new planned 

energy conservation activities of local utilities. 

For Load Forecast Uncertainty, the New York ISO develops 90% confidence intervals about its 

long term energy and demand forecasts. In our Installed Reserve Margin Studies, we determine 

the load forecast uncertainty at seven separate load levels. The middle load level represents a 

50th percentile load forecast and is our base case forecast. The remaining six load levels are 

distributed at plus and minus 1, plus and minus 2, and plus and minus 3 standard deviations of 

the mean of the peak-producing weather index. 

Resources — New York’s Reliability Needs Assessment (RNA) provides a forecast of planned 

capacity resources over the study period. Table NYBA-1 below shows this projection with the 

wind and biomass portions of the total in-state capacity resource mix segregated out. The 
Regional Reliability Assessment

140 2008 Long-Term Reliability Assessment 

uncertainties for wind and hydro units are broken out, as well. Details of planned additions, reratings and retirements can be found in NYISO’s 2008 Load and Capacity Data Book163

 

Table NYBA -1 

NYBA Planned Resource Capacity Mix 

By Year 

Fuel Type 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Coal 3,105 2,803 2,803 2,803 2,803 2,803 2,803 2,803 2,803 2,803

Gas & Oil 14,515 14,746 14,746 14,515 14,515 14,515 14,515 14,515 14,515 14,515

Gas 6,467 6,467 6,467 6,467 6,467 6,467 6,467 6,467 6,467 6,467

Hydro 5,636 5,666 5,704 5,734 5,734 5,734 5,734 5,734 5,734 5,734

Nuclear 5,265 5,265 5,265 5,265 5,265 5,265 5,265 5,265 5,265 5,265

Oil 3,325 3,325 3,325 3,325 3,325 3,325 3,325 3,325 3,325 3,325

Biomass 357 364 370 370 370 370 370 370 370 370

Wind 424 443 449 449 449 449 449 449 449 449

w/recent 

Wind* 707 726 732 732 732 732 732 732 732 732

Total 39,378 39,362 39,412 39,211 39,211 39,211 39,212 39,212 39,212 39,212

Certain 38,269 38,237 38,282 38,081 38,081 38,081 38,081 38,081 38,081 38,081

Uncertain 1,108 1,125 1,130 1,130 1,130 1,130 1,131 1,131 1,131 1,131

* Three wind farms totaling an additional 283 MW have recently begun operation. 

The New York Independent System Operator (NYISO) applies a 45% derate factor for non-New 

York Power Authority (NYPA) hydro generation for the expected peak months of July and 

August. The 45% de-rate factor is applied to the total available non-NYPA hydro generators 

totaling 1,040 MW. The large NYPA projects (St. Lawrence and Niagara) have specific derate 

factors based on the probability the unit will be at certain percentages of its rated output. 

Wind and ambient readings taken near projected wind sites determine wind unit output over the 

course of a study year. This method has resulted in average availability rates of 10-11% during 

summer weekday peak periods (2 pm through 5 pm) with roughly 30% annual capacity factors. 

With 707 MW of wind generation capacity for this summer, the expected on-peak capacity 

counted is 71 MW from wind generators. 

Two load response programs for the New York Market were introduced in May 2001. The 

Special Case Resource (SCR) and Emergency Demand Response Program (EDRP) are programs 

in which Customers are paid to reduce their consumption by either interrupting load or switching 

to emergency standby generation when requested by the NYISO. 

The EDRP program is classified as load relief and the SCR program as capacity resources. 

These programs currently provide about 300 MW and 1,300 MW of load relief, respectively. 

 

163 NYISO’s 2008 Load and Capacity Data Book can be found at: 

http://www.nyiso.com/public/services/planning/planning_data_reference_documents.jsp 
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141 2008 Long-Term Reliability Assessment 

Purchases and Sales— For 2008, the NYISO projects capacity backed energy net purchases into 

the New York Balancing Authority area backed by 2,802 MW of generating capacity. 

Table NYBA-2 below shows the projection for firm contracts excluding the short term contracts 

mentioned above. 

Table NYBA-2

New York Purchases and Sales 

PURCHASE SOLD MEGAWATTS

FROM TO

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

PEAK - PURCHASES

ISO-NE NYISO 380.0 380.0 150.0 150.0 150.0 150.0 100.0 100.0 100.0 100.0 100.0

PJM NYISO 0.0 0.0 660.0 660.0 660.0 660.0 660.0 660.0 660.0 660.0 660.0

TOTALS 380.0 380.0 810.0 810.0 810.0 810.0 760.0 760.0 760.0 760.0 760.0

PEAK - SALES

NYISO ISO-NE 101.1 101.1 732.1 91.1 91.1 91.1 91.1 91.1 91.1 91.1 91.1

NYISO PJM 73.1 73.1 73.1 73.1 73.1 73.1 73.1 73.1 73.1 73.1 73.1

NYISO ECAR 129.0 129.0 129.0 129.0 129.0 129.0 129.0 129.0 129.0 129.0 129.0

TOTALS 303.2 303.2 934.2 293.2 293.2 293.2 293.2 293.2 293.2 293.2 293.2

Fuel — Traditionally, the New York Area generation mix has been dependent on fossil fuels for 

the largest portion of the installed capacity. Recent capacity additions or enhancements now 

available use natural gas as the primary fuel. While New York is clearly dependent on fossil 

fuels, the risk of interruption to a single source is mitigated by the large portion (37%) of units 

that can switch from natural gas to other fuel types such as residual or distillate oil. 

The following figure depicts New York’s resource capacity mix by fuel type for the year 2008 on 

an installed capacity basis. 
Regional Reliability Assessment

142 2008 Long-Term Reliability Assessment 

Figure NYBA-1: 

2008 NYBA Capacity by Fuel Type 

17%

9%

37%

8%

14%

13%

1%

1%

GAS - 6,467 (17%)

OIL - 3,325 (9%)

GAS & OIL - 14,514 (37%)

COAL - 3,105 (8%)

NUCLEAR - 5,265 (13%)

HYDRO - 5,636 (14%)

WIND (2) - 424 (1%)

OTHER (3) - 357 (1%)

MW (1)

50

Summer 2008 = 39,095 MW

(1) - All values are rounded to the nearest whole MW.

(2) - Wind is listed at full Nameplate Capacity.

(3) - Includes Methane, Refuse, Solar & Wood

Table NYBA-2 below shows how the Capacity fuel mix changes over the study period. 

TABLE164 NYBA-2 

Planned Resource Capacity Mix 

By Year 

Fuel Type

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 

Coal 7.9% 7.2% 7.2% 7.2% 7.2% 7.2% 7.2% 7.2% 7.2% 7.2% 

Gas & Oil 37.1% 37.7% 37.7% 37.3% 37.3% 37.3% 37.3% 37.3% 37.3% 37.3% 

Gas 16.5% 16.5% 16.5% 16.6% 16.6% 16.6% 16.6% 16.6% 16.6% 16.6% 

Hydro 14.4% 14.5% 14.6% 14.7% 14.7% 14.7% 14.7% 14.7% 14.7% 14.7% 

Nuclear 13.5% 13.5% 13.5% 13.5% 13.5% 13.5% 13.5% 13.5% 13.5% 13.5% 

Oil 8.5% 8.5% 8.5% 8.5% 8.5% 8.5% 8.5% 8.5% 8.5% 8.5% 

Biomass 0.9% 0.9% 0.9% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 

Wind 1.1% 1.1% 1.1% 1.2% 1.2% 1.2% 1.2% 1.2% 1.2% 1.2% 

 

164 Only proposed resource additions identified in the NYISO Load and Capacity Data book and included in the NYISO 

Reliability Needs Assessment (RNA), are considered. 
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143 2008 Long-Term Reliability Assessment 

The above table shows the projected installed capacity resource mix from 2008 through 2017. 

For the next ten years, resources fueled by natural gas, hydro, biomass, and wind will meet all of 

the growth in projected energy consumption. 

There is a potential for a natural gas shortage in New York State in the winter. This could cause 

natural gas fired units to burn other fuels or curtail operations. If unit operation curtailment due 

to fuel unavailability occurs in load pockets, generation from other areas would need to help 

meet demand, causing heavier loading on the existing transmission system. Many of the dual 

fired units are the larger older steam units located in load pockets and would impact reliability 

needs in a multiple ways if retired. The real challenge on a going forward basis will be to 

maintain the benefits that fuel diversity, in particular dual fired fuel capability, provides today. 

This will be especially critical in New York City and Long Island which are entirely dependent 

on oil and gas fired units many of which have interruptible gas transportation contracts. In terms 

of operational strategy, the NYSRC has adopted the following local reliability rule where a 

single gas facility refers to a pipeline or storage facility: 

I-R3. Loss of Generator Gas Supply (New York City & Long Island) 

“The NYS Bulk Power System shall be operated so that the loss of a single gas 

facility does not result in the loss of electric load within the New York City and Long 

Island zones.”

The NYSIO categorizes generation capacity fuel types into three supply risks: Low, Moderate 

and High 

The greatest risk to fuel supply interruption occurs during the winter months when both natural 

gas and heating fuel oils are competing to serve electrical and heating loads. Fortunately in New 

York, peak electrical loads occur during the summer months when demand is nearly 7,000 MWs 

greater than the winter peak. As such, New York can meet the winter peak of roughly 25,000 

MW with sufficient generation without exposure to significant fuel risks. Even with a forced 

outage rate of 10%, there is sufficient generation in the low to moderate fuel risk categories to 

meet the winter electrical peak of 25,500 MW. This would leave a margin of nearly 4,000 MW 

or 14% of the total capacity characterized by low to moderate fuel risk. 

The NYISO continues to work with regulators and other interested parties on a host of 

environmental initiatives aimed at encouraging the development of new cleaner generation and 

reducing emissions from existing generation. The four programs with the potential to have the 

most impact on the power sector are; The New York State Renewable Portfolio Standard (RPS), 

NOx Emission Reduction of the Ozone Transport Commission, New York State Consent Orders, 

and the Regional Greenhouse Gas Initiative. A more complete description of these initiatives 

can be found in the NYISO Power Trends document dated February 2008.165 

 

165 http://www.nyiso.com/public/webdocs/newsroom/press_releases/2008/nyiso_ptrendsfinal08.pdf
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144 2008 Long-Term Reliability Assessment 

The effects of the RPS and Consent orders are captured in the above forecasts for resources in 

new plants and retirements, respectively. Plans are currently being developed to address 

compliance in New York for the other two mentioned initiatives. 

Transmission —Upgrades in the Rochester vicinity have been completed in preparation of the 

Russell Station retirement this summer. A capacitor bank is scheduled to be added to the 

Millwood 345 kV substation by November 2008, for added voltage support in the lower Hudson 

Valley and Athens Special Protection System (SPS). Also planned for this summer (June or 

July) is the re-conductor of the Northport – Norwalk Harbor 138 kV cable. The new cable will 

have three circuits and operate at the same ratings as the current cable. 

Additional improvements over the study period are identified on the table appearing on the next 

page. 
Regional Reliability Assessment

145 2008 Long-Term Reliability Assessment 

Expected 

Line Service Nominal Voltage Thermal Ratings Type of

Transmission Length Date/Yr in kV # of in Amperes Construction &

Owner Terminals miles * Prior to ** Operating Design ckts Summer Winter Conductor Size 

Merchant

East Coast Power, LLC PSE&G 230 kV Linden Cogen 345kV 2010 345 345 Variable Frequency Transformer

Transmission Owner

Firm Plans

CHGE E. Fishkill E. Fishkill xfmr #2 2008 S 345/115 345/115 1 440MVA 560MVA Transformer #2 (Standby)

CHGE Hurley Ave Saugerties 11.11 2011 W 115 115 1 1114 1359 1-795 ACSR OH

CHGE E. Fishkill Wiccopee 3.320 2011 S 115 115 1 1114 1359 1-795 ACSR OH

CHGE Saugerties North Catskill 12.25 2011 W 115 115 1 1114 1359 1-795 ACSR OH

CHGE Hurley Ave North Catskill 23.36 2012 S 115 115 1 1114 1359 1-795 ACSR OH

CHGE Pleasant Valley Knapps Corners 17.7 2017 W 115 115 1 1114 1359 1-795 ACSR OH

ConEd Sprain Brook Sherman Creek 10 2011 S 345 345 1 872 1010 2000 CU UG

LIPA Riverhead Canal 16.4 2011 S 138 138 1 1056 1204 2500 MCM Cu Sol Dielect UG

LIPA (4) Pilgrim Brentwood 4.56 2012 S 138 138 1 2343 2506 1272 SSAC OH

LIPA (4) Pilgrim Brentwood 4.56 2012 S 138 138 2 2343 2506 1272 SSAC OH

LIPA (4) Pilgrim Brentwood 4.18 2012 S 138 138 3 2343 2506 1272 SSAC OH

LIPA New Brentwood Brentwood PS Phase Shifter 2012 S 138 138 1 - - Phase Shifter -

LIPA Brentwood PS Holtsville GT 12.4 2012 S 138 138 1 2343 2506 1272 SSAC OH

LIPA Barrett Bellmore PS Phase Shifter 2012 S 138 138 1 - - Phase Shifter -

LIPA Bellmore PS Bellmore 8.4 2012 S 138 138 1 1150 - 2000 mm2 Cu UG

LIPA (5)***** Northport Narwalk Harbor 11 2014 S 138 138 3 675 675 3/C XLPE Cu 800mm2 UW / UG

NYPA* Willis 1 Plattsburgh -33.700 2008/2009 W 230 230 1 426 545 1-795 ACSR OH

NYPA* Willis 2 Plattsburgh -33.700 2008/2009 W 230 230 2 426 545 1-795 ACSR OH

NYPA**** Willis 1 Patnode 9.100 2008/2009 W 230 230 1 426 545 1-795 ACSR OH

NYPA  Patnode Duley 15.270 2008/2009 W 230 230 1 426 545 1-795 ACSR OH

NYPA** ** Duley Plattsburgh 9.32 2008/2009 W 230 230 1 426 545 1-795 ACSR OH

NYPA  Willis 2 Ryan 6.460 2008/2009 W 230 230 2 426 545 1-795 ACSR OH

NYPA** ** Ryan Plattsburgh 27.24 2008/2009 W 230 230 2 426 545 1-795 ACSR OH

NYSEG (7) Wood Street Carmel 1.34 2009 S 115 115 1 775 945 477 ACSR OH

NYSEG (7) Wood Street Katonah 11.7 2009 S 115 115 1 775 945 477 ACSR OH

NYSEG *** Etna Lapeer 14.950 2010 W 115 115 1 1410 1725 1277 KCM ACAR OH

NYSEG Etna Lapeer 14.950 2010 W 115 115 1 1410 1725 1277 KCM ACAR OH

NYSEG Lapeer Lapeer xfrm 2010 W 345/115 345/115 1 200MVA 220MVA Transformer

NYSEG Lapeer Lapeer xfrm 2010 W 345/115 345/115 1 200MVA 220MVA Transformer

NGRID Paradise Ln 115 kV Paradise Ln 115 kV - 2010 S - - - - - 115 kV Switchyard -

O & R Ramapo Sugarloaf 16.000 2009 W 138 138 1 1089 1298 2-1590 ACSR OH

RGE Station 135 Station 424 4.98 2009 S 115 115 1 1135 1415 1033 AL OH

RGE Station 135 Station 424 4.977 2009/2010 W 115 115 1 1225 1495 1-1033.5 ACSR OH

Non-Firm Plans

NGRID South Saratoga (New Station) Luther Forest #W (New Station) 2.8 2009 S 115 115 1 TBD TBD New 115 kV line (2.8 miles new; 8.9 miles exist)

NGRID South Saratoga (New Station) Luther Forest #X (New Station) 2.8 2009 S 115 115 1 TBD TBD New 115 kV line (2.8 miles new; 8.9 miles exist)

NGRID North Troy Luther Forest #Y (New Station) 5.9 2009 S 115 115 1 TBD TBD New 115 kV line (5.9 miles new; 30.3 miles exist)

NGRID Mohican Luther Forest #Z (New Station) 5.9 2009 S 115 115 1 TBD TBD New 115 kV line (5.9 miles new; 12.1 miles exist)

NGRID Rotterdam South Saratoga #3 (New Station) 11 2009 S 115 345 1 TBD TBD New 115 kV line (to be converted to 345kV)

NGRID Gardenville Homer Hill 21 2010 S 115 115 2 TBD TBD 115 kV line Replacement -

NGRID Falconer Warren 19.4 2011 S 115 115 1 TBD TBD 115 kV line Replacement -

NGRID Mortimer Golah 9.6 2011 S 115 115 1 TBD TBD New 115 kV line -

NGRID Spier South Saratoga #3 (New Station) 21.7 2011 S 115 115 1 TBD TBD New 115 kV line

NGRID Rotterdam South Saratoga #4 (New Station) 11 2012 S 115 345 1 TBD TBD New 115 kV line (to be converted to 345kV)

NGRID Southwest 345 kV Southwest 115 kV - 2012 S - - - - - 345/115 kV Stepdown -

NGRID Packard Paradise 13.5 2013 S 115 115 1 TBD TBD 115 kV line Replacement -

NGRID Paradise Gardenville 13.5 2013 S 115 115 1 TBD TBD 115 kV line Replacement -

NGRID Packard Gardenville 27 2013 S 115 115 1 TBD TBD New 115 kV line -

NGRID Princetown (New Station) South Saratoga #3 (New Station) 17 2018 S 345 345 1 TBD TBD New 345kV Line reconfig/convert from 115kV above

NGRID Princetown (New Station) South Saratoga #4 (New Station) 17 2018 S 345 345 1 TBD TBD New 345kV Line reconfig/convert from 115kV above

O & R Lovett Lovett xfrm 2013 S 345/138 345/138 1 501 MVA 501 MVA Transformer

(7) '115 kv operation as opposed to previous 46 kv operation

(5) Cable replacement; LIPA owns 50% of the NUSCO cable

(4) 138 kv operation as opposed to previous 69 kv operation

***** Partial NUSCO upgrade will be done in 2008 and full NUSCO upgrade is scheduled for 2014 (including Northport-Pilgrim Upgrade)

  Lines resulting from tapping of Existing Circuit

** * Reconductoring of Existing Line

** S = Summer Peak Period W = Winter Peak Period

* Line Length Miles - negative values indicate removal of Existing Circuit being tapped
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146 2008 Long-Term Reliability Assessment 

Operational Issues — No unusual operational issues have been identified for the period 2008-

2017. 

Reliability Assessment Analysis — The NYISO conducts an annual Reliability Needs 

Assessment (RNA)166 that examines both resource and transmission needs over a ten year period. 

Resources totaling approximately 455 MW as well as transmission upgrades that are under 

construction or otherwise have met the screening criteria are included in the base case. The 

RNA determined that sufficient statewide resources are available to meet NPCC LOLE criteria 

through the year 2011. For 2012, the RNA indicates that sufficient resources would exist if 500 

MW were added to New York City (NYC) or 750 MW were added in the Lower Hudson Valley 

or if transfer limits into NYC were increased. Beyond 2012, additional resources of 

approximately 2,750 MW would be needed to meet the criteria through 2017; a majority of those 

resources would needed to be in the NYC zone to meet the NYC zonal requirements. 

Subsequent to the RNA, the NYISO solicits solutions to address the needs identified in the RNA. 

In response to this solicitation, market based solutions and regulated backstop solutions are 

proposed. Transmission Owner (TOs) plans subsequent to the RNA initiation are also evaluated 

by the NYISO and included in the assessment or evaluation of the proposed solutions. These TO 

plans will satisfy the reliability needs through 2012. Sufficient market based solutions have been 

proposed to more than meet the needs through 2017. If sufficient market solutions are not 

proposed or do not proceed, the responsible TOs are obligated, under the NYISO reliability 

planning process, to proceed with the implementation of the regulatory backstops and/or gap 

solutions when needed to meet any identified reliability needs. 

 

Although, deliverability of resources is evaluated in the NYISO’s resource adequacy and 

planning studies both on an inter-area, as well, as intra-zonal basis, the NYISO currently has 

under development a deliverability test for new resources. This test would become part of the 

NYISO’s interconnection process. Resources that were not fully deliverable based on the test 

would either need to upgrade the system to be eligible for full capacity payments or only would 

be eligible to receive capacity payments for the portion of the facility that is deliverable. 

NYISO conducts semi-annual and monthly Installed Capacity (ICAP) auctions. Based on the 

forecast load for 2008, the ICAP requirement is 38,879 MW based on a 15% Installed Reserve 

Margin (IRM) requirement. Last year the IRM requirement was 16.5%. On February 29, 2008, 

the Federal Electric Regulatory Commission issued an order accepting the New York State 

Reliability Council's filing of a 15% IRM for the State of New York. In addition to the 

generation resources within the New York Balancing Authority area, generation resources 

external to New York can also participate in the NYISO ICAP market. An external ICAP 

supplier must declare that the amount of generation that is accepted as ICAP in New York will 

not be sold elsewhere. The external Balancing Authority in which the supplier is located has to 

agree that the supplier will not be recalled or curtailed to support its own loads; or will treat the 

supplier using the same pro rata curtailment priority for resources within its Control Area. The 

energy that has been accepted as ICAP in New York must be demonstrated to be deliverable to 

 

166 NYISO Report titled “Comprehensive Reliability Planning Process (CRPP) – 2008 Reliability Needs Assessment”, December 

12, 2007 
Regional Reliability Assessment

147 2008 Long-Term Reliability Assessment 

the New York border. The NYISO sets a limit on the amount of ICAP that can be provided by 

suppliers external to New York. Resources within the New York Balancing Authority area that

provide firm capacity to an entity external to New York are not qualified to participate in the NYISO 

ICAP market. 

The NYISO performs a resource adequacy study to help the New York State Reliability Council 

determine the required Installed Reserve Margin for the upcoming capability year. This study 

specifies the margin required for the New York Balancing Authority area. The NYISO conducts 

the Locational Capacity Requirements study which determines the amount of capacity that must 

be physically located within specific zones such as New York City and Long Island. The 

NYISO currently requires that a value of capacity equal to 80% of the New York City peak load 

be secured from within its zone and capacity totaling 94 % of Long Island peak load be secured 

within that zone, for the 2008-2009 capability years. The NYISO also performs an LOLE 

analysis that determines the maximum amount of ICAP contracts that can originate from 

Balancing Authorities external to the New York Balancing Authority area. 

NPCC requires that New York perform a comprehensive resource adequacy assessment every 

three years. This assessment uses an LOLE analysis to determine resource needs five years out 

into the future. A report is required showing how the NYISO would act to meet any projected 

shortfalls. In the two intervening years between studies, the NYISO is required to conduct 

additional analysis in order to update the findings of the comprehensive review. 

Presently, the New York State Reliability Council (NYSRC) Reliability Rules are implemented 

such that the electric system has the ability "to supply the aggregate electrical demand and 

energy requirements of their customers at all times, taking into account scheduled and reasonably 

expected unscheduled outages of system elements.” Compliance is evaluated probabilistically, 

such that the loss of load expectation (LOLE) of disconnecting firm load due to resource 

deficiencies shall be no more than an average of 0.1 days per year. This evaluation gives 

allowance for NYS Transmission System transfer capability documented in NYSRC Rules, 

Installed Reserve Margin (IRM), and Locational Capacity Requirements (LCR) reports. 

Currently all known deliverability concerns are captured in the evaluation and there are none 

identified as needing mitigation. A multi area reliability simulation capturing the significant 

limitations of the NYS Transmission System is performed every year to demonstrate compliance. 

IRM Requirements are developed annually to satisfy resource adequacy requirements. The 

NYISO establishes installed capacity requirements (ICAP), including LCRs, recognizing internal 

and external transmission constraints. 

The Beck-Packard BP76 230kV line is out of service for this summer, currently scheduled to 

return to service by late in the summer of 2010. 

The NYISO performs transient dynamics and voltage studies. There is no stability issues 

anticipated that could impact reliability during the 2008 summer operating period. The NYISO 

does not have criteria for minimum dynamic reactive requirements. Transient voltage-dip 

criteria, practices or guidelines are determined by individual Transmission Owners in New York 

State. The NYISO does not use Under Voltage Load-Shedding (UVLS). 
Regional Reliability Assessment

148 2008 Long-Term Reliability Assessment 

The NYISO performs seasonal operating planning studies to calculated and analyze system 

limits and conditions for the upcoming operating period. The operating studies include 

calculations of thermal transfer limits of the internal and external interfaces of the New York 

Balancing Authority area. The studies are modeled under seasonal peak forecast load conditions. 

The operating studies also highlight and discuss operating conditions including topology changes 

to the system (generators, substations, transmission equipment or lines) and significant generator 

or transmission equipment outages. Load and capacity assessment are also discussed for 

forecasted peak conditions. 

Other Reliability Assessment Information — A number of issues that were indicated in the 

LTRA instructions have been addressed in the NERC Resource Issues Subcommittee Resource 

Adequacy Survey that was supplied by the NYISO to NERC on May 30, 2008. 

Ontario 

Demand - Ontario’s forecast of demand is based on Monthly Normal weather. The economic 

forecast is based on the most recent information and predicts a fairly neutral growth for Ontario 

in 2008 and 2009, followed by modest economic growth. The impacts of the high Canadian 

dollar, the current economic climate and particularly the considerable impacts from planned 

conservation and growing load-displacing generation is stabilizing Ontario’s load growth and 

moving it in the direction of gradual, intentional decline.

Due to the economic, conservation and load-displacing generation impacts, demand is expected 

to shrink over the course of the forecast. Peak demand is expected to average declines of 0.5% 

per year and annual energy demand is expected to average declines of 0.9% per annum. This is 

in contrast to last year’s forecast where peak demand had average annual decreases of 0.2% and 

energy demand was expected to grow by 0.4%. 

Ontario has a number of demand response programs that can reduce demand. A number of 

consumers within the province bid their load into the market and are responsive to price through 

IESO to dispatch instructions. Other consumers have been contracted by the Ontario Power 

Authority (OPA) to provide demand response under tight supply conditions. The combined 

amount of these demand measures has been steadily increasing and currently amounts to slightly 

more than 800 MW in total, of which two thirds is included for seasonal capacity planning 

purposes, with half of the included amount categorized as interruptible. This amount is expected 

to grow over time as more load is contracted to respond to tight supply conditions. By the end of 

the forecast, the interruptible component is expected to grow to more than 500 MW. 

The IESO quantifies the uncertainty in peak demand due to weather variation through the use of 

Load Forecast Uncertainty (LFU), which represents the impact on demand of one standard 

deviation in the underlying weather parameters. This is used with Monthly Normal weather 

demand to conduct probabilistic analysis. As well, the IESO uses an Extreme Weather scenario 

to study the impacts of adverse weather conditions on reliability of the IESO controlled grid. 

The IESO also studies the reliability of the system prior to the impact of planned conservation 

savings. The IESO did not look at alternate economic scenarios. 
Regional Reliability Assessment

149 2008 Long-Term Reliability Assessment 

Generation - The total capacity of existing installed resources connected to the IESO controlled 

grid is 31,297 MW, of which the amount of ‘certain’ capacity is 28,194 MW for summer 2008. 

The remainder, 3,103 MW, is ‘uncertain’ capacity for 2008 which includes on-peak resource 

deratings, planned outages and transmission-limited resources.

About 300 MW of dependable new supply (394 MW installed) is scheduled to come into service 

before the 2008 summer peak period. All of this new supply, with one exception, is gas-fired 

generation, including 340 MW of generation (250 MW under contract and considered 

dependable) in downtown Toronto from the first, simple cycle phase of a 550 MW combined 

cycle energy centre to be completed by summer 2009 and 31 MW of Combined Heat and Power 

projects in several locations around the province. A hydroelectric project with an installed 

capacity of 23 MW will, also, come into service before summer 2008. Eighty percent of this 

new installed hydroelectric capacity is assumed to be available at the time of weekly peak. 

The existing installed capacity of wind generation connected to the IESO controlled grid is 

471 MW. Ten percent of the installed wind capacity is assumed to be available at the time of 

weekday peak, thus, 47 MW of wind is considered certain for capacity planning purposes. Of 

the 75 MW of installed biomass generation in the province, 45 MW is assumed certain. The 

generation output of some biomass units has been reduced as a consequence of reductions in 

steam demand primarily from pulp and paper operations. 

The table below lists the certain and uncertain capacities for Existing, Planned and Proposed 

resources for summer 2008 to 2017. 

Projected

DESCRIPTION 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Existing Total Certain Capacity 28194 28123 26041 25072 24504 24593 24593 20230 18759 18553

Wind Expected On-Peak 47 47 94 94 94 94 94 94 94 94

Hydro Expected On-Peak 5869 5869 5869 5869 5869 5869 5869 5869 5869 5869

Biomass Expected On-Peak 45 45 45 45 45 45 45 45 45 45

Existing Total Installed Capacity 31297 31297 31297 29832 28156 27991 27991 24394 24287 24081

Existing Installed Wind Capacity 471 424 377 377 377 377 377 377 377 377

Existing Installed Hydro Capacity 7788 7788 7788 7788 7788 7788 7788 7788 7788 7788

Existing Installed Biomass Capacity 75 75 75 75 75 75 75 75 75 75

Planned Total Certain Capacity 299 4013 5954 5969 5969 5969 5969 5969 5969 5969

Wind Expected On-Peak 0 63 158 173 173 173 173 173 173 173

Hydro Expected On-Peak 18 22 29 29 29 29 29 29 29 29

Biomass Expected On-Peak 0000000000

Planned Total Maximum Capacity 304 4595 6599 6675 6675 6675 6675 6675 6675 6675

Planned Maximum Wind Capacity 0 631 789 865 865 865 865 865 865 865

Planned Maximum Hydro Capacity 23 36 43 43 43 43 43 43 43 43

Planned Maximum Biomass Capacity 0000000000

Proposed Total Certain Capacity 0 0 58 650 1380 3137 3925 4388 4735 4773

Wind Expected On-Peak 0 0 0 115 115 190 272 317 364 379

Hydro Expected On-Peak 0 0 58 185 404 446 558 604 743 753

Biomass Expected On-Peak 0 0 0 0 61 101 144 212 373 386

Proposed Total Maximum Capacity 0 0 81 1205 2060 4130 5286 5947 6533 6635

Proposed Maximum Wind Capacity 0 0 0 575 575 948 1359 1585 1820 1895

Proposed Maximum Hydro Capacity 0 0 81 280 624 680 832 895 1085 1099

Proposed Maximum Biomass Capacity 0 0 0 0 61 101 144 212 373 386

The process used to select Planned and Proposed capacity resources is the Ontario Power 

Authority’s Integrated Power System Plan. Established in 2005, the Ontario Power Authority 

(OPA) is the electricity system planner for the province of Ontario. 
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150 2008 Long-Term Reliability Assessment 

The OPA’s statutory objects require it to, among other things; ensure adequate, reliable and 

secure electricity supply and resources in Ontario and to conduct independent planning for 

electricity generation, demand management, conservation and transmission. 

One of the responsibilities of the OPA is to develop a 20-year Integrated Power System Plan 

(IPSP) and to submit the IPSP to the Ontario Energy Board for its review and approval. The 

IPSP is to be updated every three years. The IPSP must follow any directives issued by 

Ontario’s Minister of Energy relating to the government’s electricity goals. In addition, the IPSP 

must develop appropriate procurement processes for managing electricity supply, capacity and 

demand in accordance with the IPSP and apply to the Ontario Energy Board for approval of the 

IPSP’s proposed procurement processes. 

Ontario’s first IPSP was submitted to the Ontario Energy Board for review in August 2007, and 

is currently under regulatory review. The IPSP covers a period of twenty years, complies with 

the goals and requirements set out by the government of Ontario and proposes a procurement 

process for managing electricity supply, capacity and demand in accordance with the IPSP. 

Purchases and Sales - At present, there is no Firm, Non-Firm or Expected purchases from other 

regions. Transactions under study (i.e. provisional) are imports from Labrador and Manitoba. 

The IESO has agreements in place with neighbouring jurisdictions in NPCC, RFC and MRO for 

emergency imports and reserve sharing, should they be required in day to day operations. 

Fuel - The Ontario fuel supply infrastructure is judged to be adequate, and there are no fuel 

delivery problems anticipated. Nine per cent of the existing generation capacity in Ontario is 

gas-fired. The percentage of gas generation will increase to 26% by 2017 as coal generation is 

retired. Gas pipeline capacity, historically, has not limited the summer energy or capacity 

capability of Ontario generation fuelled solely by natural gas and is not expected to be a problem 

for future summers. Similarly, no fuel delivery concerns have been identified for coal-fired 

generating stations. In its market manuals, the IESO requires generator market participants in 

Ontario to provide specific information regarding energy or capacity impacts if fuel-supply 

limitations are anticipated. No limitations have been reported for the summer months. 

The province is not experiencing a drought at present. Hydroelectric outputs are based on the 

median historical values of hydroelectric production and contribution to operating reserve during 

the weekday peak hours. The median hydroelectric value assumed available for annual peak is 

about 75% of the total installed capacity. 

Transmission - Hydro One and TransÉnergie are building a 1,250 MW interconnection between 

Hawthorne TS in Ontario and Outaouais station in Quebec consisting of a double circuit 230 kV 

line and back-to-back high-voltage direct-current (HVdc) converters at Outaouais. Work to 

accommodate the tie, scheduled to be in service before summer 2009, will also include 

improvements to load serving capabilities in the Ottawa area. 

The existing special protection system (SPS) at St. Lawrence was modified, allowing increased 

westward transfers. This SPS, which rejects generation at Saunders GS for circuit contingencies 

between eastern Ontario and the Toronto area, is planned to be enhanced further, to increase its 
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151 2008 Long-Term Reliability Assessment 

functionality and reliability under peak load conditions, and to maximize simultaneous import 

capability from Hydro Québec and New York. These future enhancements will be required in 

2009 upon completion of the new 1,250 MW Ontario-Québec interconnection. 

Over the next decade, the need for transmission enhancements is particularly evident in three 

areas of the Ontario: 

• In south-western Ontario to deliver additional nuclear and wind supply from the Bruce 

area, 

• In northern Ontario to enable the planned expansion of hydroelectric and wind capability 

and to reinforce the connection of these areas to the load centre in southern Ontario 

• In the Toronto region in order to meet capacity needs of fast growing areas in the 

Greater Toronto Area and to improve reliability to Canada’s largest city. 

The southwestern Ontario transmission system needs to be enhanced to deliver the planned and 

future increases in generating capability in and around the Bruce peninsula. Currently, there is 

inadequate transmission out of the Bruce area to accommodate both the expected wind 

developments in that area and the expanded capacity of the Bruce nuclear station resulting from 

planned refurbishments. Some near-term reinforcements include the up-rating of the Hanover to 

Orangeville 230 kV circuits, and the installation of additional voltage support facilities at various 

transmission stations in southwestern Ontario. These will increase the transfer capability out of 

Bruce in the short-term. The proposed 500 kV double circuit line from Bruce to Milton received 

the OEB approval for leave to construct on September 15, 2008. This represents a significant 

milestone in the approval process and the line is planned to go into service in December 2011. 

The line will provide the required transmission capability over the long-term to deliver the full 

capability of the Bruce refurbishment and both planned and potential new renewable resources in 

the Bruce area. The new 500 kV line out of the Bruce area is required to accommodate the 

additional generation from both new wind projects and refurbished Bruce nuclear units. 

As the Nanticoke coal-fired station is phased out by 2014, additional voltage support in 

southwestern Ontario will be required. Both static and dynamic reactive power solutions are 

being considered, ranging from shunt capacitors to possible replacement generation. 

Over the next few years, over 1,600 MW of contracted gas-fired generation will be coming inservice in the Sarnia area. This will significantly increase the amount of power flowing between 

the Sarnia area and the London area and stress the existing transmission system west of London. 

The planned retirement of the Lambton coal-fired generating plant (2,000 MW) early next 

decade, however, will reduce this transmission concern. Thus, there is currently no plan to 

reinforce the transmission west of London. This need will be monitored into the future as new 

generating resources such as renewables and combined heat and power projects are proposed in 

the Sarnia and Windsor-Essex areas. 

Transmission enhancements in the northeastern part of the Ontario grid are required to allow the 

delivery of planned generation from that area to southern Ontario. The proposed enhancements, 

including series capacitors at Nobel TS, and a static var compensator (SVC) in northeastern 

Ontario, are expected to relieve existing congestion and accommodate the additional output from 
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152 2008 Long-Term Reliability Assessment 

the proposed expansion of the four existing hydroelectric stations on the Lower Mattagami River 

and other committed renewable energy developments in northeastern Ontario. 

The development of enabling transmission reinforcements is planned to integrate additional 

renewable resources procured in the northern parts of Ontario and to connect these areas to the 

load centre in southern Ontario. 

The continuous economic growth experienced in parts of Ontario in the last decade has resulted 

in the loads in a number of areas reaching or exceeding the capability of the existing transformer 

stations and/or their supply lines. Some large load centers also have concerns with supply 

security. To address these needs and provide additional local area supply capacity for future load 

growth, work has commenced on a number of area supply projects. 

Phase angle regulators (PARs) are installed on the Ontario-Michigan interconnection at 

Lambton TS, representing two of the four interconnections with Michigan, but are not currently 

available to regulate flows on the interconnection except in emergencies. These PARs are 

expected to become operational by the end of 2008. The operation of the these PARs along with 

the PAR on the Ontario-Michigan interconnection near Windsor will control flows to a limited 

extent, and assist in the management of system congestion. 

The capability to control flows on the Ontario-Michigan interconnection between Scott TS and 

Bunce Creek is unavailable. The PAR installed at Bunce Creek in Michigan has failed and is 

scheduled for replacement in 2010. 

The table below lists the transmission projects that are planned for completion within the next 

ten years. They are considered to provide significant improvement to system reliability. 
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153 2008 Long-Term Reliability Assessment 

Voltage 

(kV) Length (Miles) In-service Date(s) Description/Status

Cardiff TS to Hurontario SS 230 3 05-2010 Under Construction

Hurontario TS to Jim Yarrow TS 230 3 05-2011 Under Construction

Hurontario SS 05-2010 Under Construction

Ingersoll Jct. to Woodstock-Karn TS 230 7 04-2011 Construction Imminent

Essa TS to Stayner TS 230 17 04-2009 Under Construction

Nobel SS Series Compensation 500 12-2010 Construction Imminent

Porcupine TS SVC 230 11-2010 Construction Imminent

Bruce GS to Milton TS 500 115 12-2011 EA Approval Phase

Allanburg TS to Middleport TS 230 50 To be determined On-hold

Outaouais SS to Hawthorne TS 230 14 06-2009 Under Construction

Nanticoke TS SVC 500 2011 Planning Phase

Detweiler TS SVC 230 2011 Planning Phase

Lakehead to Birch 230 13 2013 Planning Phase

Sudbury to Greater Toronto Area 500 180-250 2017 Planning Phase

Mississagi TS to Hanmer TS 500 130 2017 Planning Phase

Pinard TS to Hanmer TS 500 230 2017 Planning Phase

Mackay TS to Third Line TS 230 60 2017 Planning Phase

Nipigon TS to Little Jackfish 230 or 115 120 2014 Planning Phase

Seaforth TS to Goderich TS 230 25 2015 Planning Phase

Owen Sound to Bruce Peninsula 230 or 115 30-50 2015 Planning Phase

Manitowadge to Espanola TS 230 or 115 50 2015 Planning Phase

 Transmission Project Name

Alternatives for some other are supply projects are being assessed. These include Supply to 

Essex County and Guelph Area Transmission Reinforcement. Since the terminal points for these 

have not yet been identified, they are not included in the table above.

There are no major transformer additions planned for in service in the next ten years. 

Operational Issues - One of the most important developments in the Ontario system is the 

planned retirement of all coal fired generation by 2014, an initiative taken in response to a 

directive issued by the Ontario government. The Integrated Power System Plan developed by the 

OPA provides a plan to address this resource gap with generation from a number of committed 

and planned resources. Although this presents a major change in the Ontario system, with 

careful planning it is anticipated that all operational challenges can be addressed. 

At this time, there are no unusual operating condition, environmental, or regulatory restrictions 

that are expected to affect capacity availability for the next ten years, beyond those identified in 

the OPA’s IPSP. 

Reliability Assessment Analysis - The IESO reliability assessments include multi-area resource 

adequacy assessments as well as transmission adequacy assessments, to determine the 

deliverability of resources to load. Two major assessments are performed periodically by the 

IESO. 

Every quarter, the IESO prepares an18-Month Outlook which advises market participants of the 

resource and transmission reliability of the Ontario electricity system, assesses potentially 

adverse conditions that might be avoided through adjustment or coordination of maintenance 
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154 2008 Long-Term Reliability Assessment 

plans for generation and transmission equipment, and reports on initiatives that are being put in 

place to improve reliability within the 18-month timeframe. 

At least once a year, the IESO investigates the adequacy of the Ontario system for the next five 

years and the key messages are published in the Ontario Reliability Outlook. The assessment 

processes and the criteria which are followed are described in the documents, “Method to 

Perform Long-Term Assessments”,167 and “Ontario Resource and Transmission Assessment 

Criteria.”168 

The IESO determines required reserve levels based on probabilistic methods deemed by NPCC 

to be acceptable for meeting regional LOLE criteria. In considering what resources contribute to 

adequacy the IESO assumes that the planned and proposed resource additions can meet their 

stated in service dates and the forecast amount of conservation can be achieved. At this time, the 

reserve requirements are met solely with the planned and proposed resources that are internal to 

Ontario. Should capacity commitments be contracted in future from external entities, these will 

be included to the extent they are not considered to be capacity in the balancing area from which 

they may be supplied. 

Each year, in compliance with NPCC requirements, the IESO performs a five-year LOLE 

analysis to determine the resource adequacy of Ontario. Every third year, a comprehensive study 

is conducted, with annual interim reviews between major studies. In addition, IESO participates 

with the other members of NPCC in regional studies which look at regional long range adequacy 

and interconnection benefits between Balancing Authorities in NPCC. 

Projected capacity reserve requirements, determined on the basis of the IESO’s requirements for 

Ontario self-sufficiency, are.14.5% until 2014 and 15.3% thereafter. IESO routinely assesses 

resource requirements for the first five years of the ten-year period. In association with the OPA, 

the periods beyond five years are assessed and resource plans developed as part of the IPSP 

process. Transmission assessments are conducted, as needed, as far into the future as necessary 

recognizing the long lead time for significant transmission facility development. 

IESO considered only the committed and contracted resources in the 2007 assessment. Projects 

that are in the planning stage from the IPSP are included in this year’s assessment. These 

projects amount to about 6,600 MW in the next ten years. 

IESO and the Ontario Power Authority recognize the potential for certain adverse conditions to 

result in higher than expected resource unavailability and establish planning reserves sufficient to 

handle many of these. To the extent resource procurement exceeds the planning reserve 

requirements, resource adequacy can be maintained for higher than normal contingencies. 

 However, there are always conditions which can exceed those planning assumptions. In such 

adverse situations the IESO’s operations would rely on interconnection support and available 

control actions to maintain system reliability. Through development of a diverse resource mix, 

the potential consequence of these events is reduced. 

 

167 http://www.ieso.ca/imoweb/monthsYears/monthsAhead.asp 168 http://www.ieso.ca/imoweb/pubs/marketAdmin/IMO_REQ_0041_TransmissionAssessmentCriteria.pdf
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155 2008 Long-Term Reliability Assessment 

Although energy supplies available within Ontario are expected to be adequate overall, energy 

deficiencies could arise as a result of higher than forecast forced outage situations, prolonged 

extreme weather conditions and other influencing factors. Interconnection capability and 

available market and operational measures have been evaluated as sufficient to ensure summer 

energy demands can be met for a wide variety of conditions. The IESO uses a measure of 

forecast uncertainty in a probabilistic analysis to account for variations in demand due to weather 

volatility. This uncertainty is used in conjunction with the normal weather demand forecast to 

determine resource adequacy. As well, the IESO creates a demand forecast based on extreme 

weather and uses it in further assessing system adequacy. 

IESO assessments of resource adequacy recognize the supply limitations associated with 

uncertain and transmission constrained resources. Transmission limits are modeled on a zonal 

basis and recognize transmission improvements which will result from implementation of the 

OPA’s IPSP. Uncertain resources, such as wind, are considered using a statistical approach 

which conservatively combines simulated and historical data to arrive at expected levels of 

“certain” capability. 

A number of major unit refurbishment or retirement decisions are expected to occur in Ontario 

by the year 2017. Expected unit retirements are approximately 6,400 MW of coal-fired resources 

across four facilities and 15 units (by the end of the year 2014). Measures taken to mitigate 

reliability concerns include the development of an IPSP for Ontario. The IPSP considers 

expected and potential unit refurbishments or retirements and proposes ways to meet resulting 

resource requirements. Specific measures include the procurement of new gas-fired, renewable 

and conservation resources as well as the procurement of refurbished nuclear resources. In 

addition, the IPSP considers the potential role for nuclear refurbishments and new-build nuclear 

resources as well as transmission that would be required to integrate all of the above-mentioned 

resources. Additional options include the potential for firm purchases from outside of Ontario, 

expanding capability at existing gas-fired stations, continuation of capability at existing gas-fired 

stations that would otherwise be retired, developing greater coordination and flexibility related to 

nuclear refurbishment outages and converting existing coal stations to natural gas. Mitigation of 

reliability concerns is to be supported through ongoing monitoring, assessment, measurement 

and verification and regular updates (i.e. every three years) to the IPSP. 

The IESO has a local area deliverability criterion for load security and restoration, and a resource 

adequacy assessment criterion which are described in sections 7 and 8 of the “Ontario Resource 

and Transmission Adequacy Criteria” document. In our quarterly and annual assessments 

mentioned at the beginning of the section, the IESO identifies any deliverability concerns which 

are subsequently addressed by the transmitters as part of their planning activities and the OPA as 

part of the generation procurement programs. 

The IESO reviews its system operating limits on an ongoing basis, as warranted by system 

configuration changes on the grid. In advance of each summer peak season, the IESO analyzes 

the forecast demand for Ontario, and forecast transmission and generation availability, and 

assesses the ability of the planned generation to supply the forecast load (in essence its 

deliverability). Where transfer limits are expected to restrict available generation, these 
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156 2008 Long-Term Reliability Assessment 

restrictions, in addition to zone-to-zone system operating limits, are factored into the reliability 

analysis for the season, to determine IESO’s resource adequacy. IESO, as the Reliability 

Coordinator, and via its authority to direct the operation of the IESO-administered market and 

the IESO-controlled grid, can ensure that generation dispatch does not violate system operating 

limits. Where resources are expected to be insufficient to satisfy established criteria169, the IESO 

can deny final approval for planned outages, and can rely on emergency procedures in the 

operational time frame to address shortfall conditions. 

The IESO regularly conducts transmission studies that include results of stability, voltage, 

thermal and short-circuit analyses in conformance with NPCC criteria. Since the implementation 

of the NERC TPL standards in June 2007, the IESO’s comprehensive 2007 transmission studies 

have been conducted to comply with these standards, in addition to NPCC criteria. 

The IESO has market rules and connection requirements that establish minimum dynamic 

reactive requirements, and the requirement to operate in voltage control mode for all resources 

connected to the IESO-controlled grid. In addition, the IESO’s transmission assessment criteria 

includes requirements for absolute voltage ranges, and permissible voltage changes, transient 

voltage-dip criteria, steady-state voltage stability and requirements for adequate margin 

demonstrated via pre and post-contingency P-V curve analysis. These requirements are applied 

in facility planning studies. Seasonal operating limit studies review and confirm the limiting 

phenomenon identified in planning studies. 

There are currently no Under-Voltage Load Shedding systems installed in Ontario for the 

purpose of controlling the voltage on the bulk power system portion of the IESO-controlled grid 

in response to bulk power system events. There are several systems used for localized voltage 

control in the event of an outage to local supply facilities. 

Following the 1998 ice storm and prior to the 2002 opening of Ontario s competitive markets for 

electricity Ontario’s Emergency Planning Task Force (EPTF) was created. It is chaired by the 

IESO and includes the major electricity sector players including the provincial government’s 

Ministry of Energy. The EPTF oversees an emergency management team, the Crisis 

Management Support Team (CMST), to manage the crisis and mitigate the impact on public 

health and safety due to an extended electricity system emergency. Annually Ontario runs a 

program of Reliability and Emergency Management workshops including table top drills. 

Additionally major integrated exercises are staged in which both the operational response and 

emergency management infrastructure is activated. The CMST also performs regular test 

activations. 

During the nine day capacity and energy emergency that followed the August 2003 blackout, the 

CMST managed the emergency via thirty one conference call meetings and were instrumental in 

producing media messages, facilitating the government's appeal and direction for reduced 

demand and obtaining of environmental variances for additional supply. 

 

169 NPCC Criteria A-02, ”Basic Criteria for Design and Operation of Interconnected Power Systems” and IMO_REQ_0041, “Ontario Resource 

and Transmission Assessment Criteria” 
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157 2008 Long-Term Reliability Assessment 

The province is not experiencing a drought at present. Hydroelectric outputs are based on the 

median historical values of hydroelectric production and contribution to operating reserve during 

the weekday peak hours. The median hydroelectric value assumed available for annual peak is 

about 75% of the total installed capacity. 

In 2007, the IESO conducted a Comprehensive Review of Transmission Adequacy which 

assessed the IESO controlled grid’s conformance with the NERC TPL-001 – 004 standards and 

NPCC’s more stringent planning criteria. The Ontario power system, including the proposed 

generation and transmission changes up to 2012, is in conformance with the applicable NPCC 

and NERC documents, with no exceptions. The proposed changes and additions to the existing 

power system in Ontario will not adversely affect the reliability of the Eastern Interconnection. 

The IESO initiated the Ontario Smart Grid Forum, a broad-based industry working group 

focused on developing a vision for a provincial smart grid that will provide consumers with more 

efficient, responsive and cost effective electricity service. It is hoped that this forum will build 

on the provincial Smart Metering Initiative to install smart meters by 2010 and complements the 

renewal taking place in Ontario’s transmission and generation sectors. 

The IESO is developing an on-line limit derivation tool to maximize transmission capability in 

the operating time frame. This tool is planned to be implemented over the next one to four years. 

The Ontario Market Rules obligate anyone planning to connect or modify a connection to the 

IESO-controlled grid to apply to the IESO for a connection assessment. All connection 

assessment studies performed by the IESO for connection of new or modified generation and 

transmission facilities include a short circuit study which identifies the effect of the new facility 

on the system short circuit levels. In addition, Hydro One periodically performs a short circuit 

level survey and makes the results available to the IESO. Where short circuit levels are 

envisaged to exceed the capability of the existing equipment, new equipment with higher ratings 

is required to be installed if available, or short circuit levels are limited to safe levels by 

operating the system split during the critical periods. 

The reliability impacts due to aging equipment are managed by the equipment owners through 

extensive maintenance programs and equipment replacement programs for equipment that is 

expected to reach end of life. 

Other Region-Specific Issues that were not mentioned above -There are no other issues to 

report. 

Québec 

Demand170

Climatic uncertainty is modeled by recreating each hour of the 36-year period (1971 through 

2006) under the current load forecast conditions. Moreover, each year of historic data is shifted 

up to plus and minus 3 days to gain information on conditions that occurred during a weekend 

 

170 http://www.regie-energie.qc.ca/audiences/3648-07/Requete3648/B-1-HQD-01-01_3648_01nov07.pdf
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158 2008 Long-Term Reliability Assessment 

for example. Such an exercise generates a set of 252 different demand scenarios. The base case 

scenario is the arithmetic average of those 252 scenarios. The Québec Area produces a high case 

demand scenario. Economic parameters are set higher and the same method as the base case is 

reproduced. For the first year of forecasting, the high case scenario is two to three percent higher 

than the base case scenario. In modeling, the uncertainty is represented through load multipliers 

covering errors of two standard deviations. Each load multiplier has a probability of occurrence. 

Given the global uncertainty, the probability that the actual peak for winter 2007/2008 was in the 

range of plus and minus 1,700 MW around the forecast peak was 68 % (assuming a normal 

distribution). 

The 2007-2016 average annual growth rate was 0.66 % and the forecast average annual growth 

rate for 2008-2017 is 0.8 %. 

In Québec, there is only one distributor, and accordingly there is no need to aggregate the load 

forecast. The load forecast incorporates all of Hydro-Québec programs designed to reduce the 

peak demand. For the 2007-2008 winter period, that reduction represents 890 MW; 2,990 MW 

is reduced in the winter period 2016-2017. 

Generation 

Québec has more than 40,000 MW of existing certain capacity. There are more than 2,000 MW 

of planned and proposed capacity. In summer 2008, there are 420 MW of installed wind 

capacity and a total of more than 3,000 MW of wind capacity developed by the winter 

2013/2014. For biomass, there is 44 MW of installed capacity. 

For reliability assessment, Québec considers the installed and planned future capacity 

(construction has started, or regulatory permits approved or approved by corporate management). 

The “La Romaine” project (882 MW) is the only future project included in our long term 

analysis. The in-service date is expected to be late 2014 for the first phase of the project. 

Purchases and Sales on Peak 

Québec has a 200 MW firm purchase contract with New Brunswick until October 2011. New 

Brunswick uses the Millbank unit to deliver this contract. Québec has two firm contracts, one 

with Ontario (145 MW until the end of horizon of this study. The other contract is with New 

England (310 MW until the end of 2011. 

Hydro-Québec Distribution includes, when planning its resources, a potential of 500 MW for 

interconnection assistance for the winter months. When needed, short term calls for tenders are 

launched and transmission capacity is reserved for those purchases. Hydro-Québec Production 

can participate in these calls for tenders. 

Fuel 

Non-hydraulic resources account only for a small portion of total resources. Plants using oil or 

jet fuel are refuelled by boat or by truck, and generally not during the winter season. Natural gas 

is used at a single cogeneration plant, and it is delivered under a firm natural gas purchase 

contract. 
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159 2008 Long-Term Reliability Assessment 

Transmission 

Operational issues 

a) There is one anticipated unit outage (Gentilly-2 nuclear unit of 675 MW, from 

late 2010 to mid-2012) but this outage will not impact reliability. Variable 

resources, transmission additions and temporary operating measures will not 

impact reliability in a negative manner during the next ten years. 

b) No restriction for the Québec Area. 

Reliability Assessment Analysis 

To determine whether existing and planned resources provide an adequate level of reliability, the 

Québec Area uses the NPCC resource adequacy criterion, an LOLE of 0.1 day per year, which 

gives a required reserve of about 11 % of the peak load for the year of analysis. This percentage 

can vary if the future resources have different characteristics and/or the load uncertainty varies. 

i) An LOLE of 0.1 day/year which gives a required reserve of about 11 % of the peak load for 

the current year of analysis. 

ii) Not counting the import of 200 MW from New-Brunswick, the internal resources are 

sufficient to meet the resource adequacy criterion. 

iii) Each year Québec has to produce resource adequacy assessments for the NPCC and the 

Québec Energy Board. These assessments are done during the fall for the next winter peak 

period and the following years. Please refer to the following web sites: 

http://www.npcc.org/adequacy.cfm and for the last assessment to the Québec Energy Board 

(November 2007): http://www.regie-energie.qc.ca/audiences/Suivi.html . 

iv) There is no significant change from last year’s assessment. 

v) In Québec, large multi-year water reservoirs allow hydro generation to be available on 

peak. For all generation, we use the Dependable Maximum Net Capability by month 

taking account the water head. The capacity should be able to withstand a minimum two 

Voltage Length In-service

Transmission Project Name (KV) (Miles)

From / To

Rimouski / Les Boules 230 34,4 08-déc

Les Boules / Matane 230 58,1 08-déc

Rimouski / Matane 230 5,1 08-déc

Matane Goemon 230 43,8 08-déc

Carleton / Line 2398 230 7,5 08-déc

Les Mechins / Line 23 YY 230 6,3 09-déc

Chenier / Outaouais 315 70,6 10-mai

Eastmain-1A / Eastmain-1 315 1,2 10-juil

Sarcelle / Eastmain-1 315 68,8 10-juil

Goemon / Mont-Louis 315 46,3 10-déc

Goemon / Gros Morne 315 55,6 11-déc

Romaine-2 / Arnaud 315 162,9 14-déc

Romaine-1 / Romaine-2 315 19,1 16-déc

Dates 

(In French) 
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160 2008 Long-Term Reliability Assessment 

hours per day run. The run of the river hydro units are derated according to specific 

constraints. Non-hydraulic resources account only for a small portion of total resources. 

Plants using heating oil or jet fuel are refuelled by boat or by truck and generally not during 

the winter season. Natural gas is used at a single cogeneration plant and is delivered under 

a firm purchase contract. 

vi) In this reliability assessment, Québec Area includes a high load forecast scenario. All the 

economic, demographic and energy parameters are upgraded compared to the base case 

scenario. The load uncertainty is then reduced to just weather considerations. If the 

criterion (0.1 day/year of LOLE) isn't met, Québec identifies the different ways to restore 

reliability. 

vii) Hydro-electric capacities monthly withstand at minimum 2 hours per day. Intermittent 

resources are derated according to constraints. Wind resources are not included. 

During the assessment period, the Gentilly-2 nuclear station will be out for major repair, but this 

refurbishment will not impact reliability. 

Québec system operator, TransÉnergie, designs and operates the transmission system within all 

the standards of the electric industry. There are no long term internal transfer limits that impact 

reliability on the Québec system. Projected transmission margin for the peak period are adequate 

to carry the net internal demand plus the firm capacity sales. Moreover, enough transmission 

capability remains on the system to carry additional resources that would be called upon if load 

is greater then forecast. Generation plants do not share common infrastructures other than the 

transmission grid. Therefore, no extreme contingencies are foreseeable other than a loss of 

transmission capacity. During the winter operating period, the day-ahead capacity margin 

requirement is twice the operational reserve to account for uncertainties on load forecast and on 

the availability of generating units. Québec is 95 % hydro generation. Energy (water) 

availability is more a concern then capacity availability. To assess its energy reliability Québec 

has developed an energy criterion that states that sufficient resources should be available to go 

through sequences of two or four years of low water inflows having a two percent probability of 

occurrence. Such assessment is presented three times a year to the Québec Energy Board. For 

reliability assessment, we considered the installed capacity and planned future capacity 

(Construction has started, or regulatory permits approved or approved by corporate 

management). 

Region Description 

NPCC is a New York State not-for-profit membership corporation, the goal of which is to 

promote and enhance the reliable and efficient operation of the international, interconnected 

bulk power system in northeastern North America: 

• through the development of regional reliability standards and compliance 

assessment and enforcement of continent-wide and regional reliability standards, 

coordination of system planning, design and operations, and assessment of 

reliability; and 

• through the establishment of regionally-specific criteria, and monitoring and 

enforcement of compliance with such criteria. 
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161 2008 Long-Term Reliability Assessment 

Geographically, the portion of NPCC within the United States includes the six New England 

states and the state of New York. The Canadian portion of NPCC includes the provinces of New 

Brunswick, Nova Scotia, Ontario and Québec. Approximately 45% of the net energy for load 

generated in NPCC is within the United States, and approximately 55% of the NPCC net energy 

for load is generated within Canada. Approximately 70% of the total Canadian load is within 

the NPCC Region. Geographically, the surface area of NPCC covers about 1.2 million square 

miles, and it is populated by more than 55 million people. 

General Membership in NPCC is voluntary and is open to any person or entity, including any 

entity participating in the Registered Ballot Body of NERC, that has an interest in the reliable 

operation of the Northeastern North American bulk power system. Full Membership shall be 

available to entities which are General Members that also participate in electricity markets in 

the international, interconnected bulk power system in Northeastern North America. The Full 

Members of NPCC include independent system operators (ISO), regional transmission 

organizations (RTOs), Transcos and other organizations or entities that perform the Balancing 

Authority function operating in Northeastern North America. The current membership in NPCC 

totals fifty entities. 

Among the Areas (subregions) of NPCC, Québec and the Maritimes are predominately winter 

peaking Areas; Ontario, New York and New England are summer peaking systems. 
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162 2008 Long-Term Reliability Assessment 

RFC Highlights 

The bulk power systems in the ReliabilityFirst (RFC) 

region are expected to perform well in meeting the forecast 

demand obligations over a wide range of anticipated 

system conditions, as long as operating limits are 

respected, established procedures are followed and 

proposed projects are completed in a timely manner. 

Several major transmission line projects have been 

announced that are expected to enhance reliability of the 

transmission network in the eastern areas of RFC. These projects include the Trans-Allegheny 

Interstate Line (TrAIL), which is in the certification process; the Potomac-Appalachian 

Transmission Highline (PATH); the 500 kV circuit from Susquehanna to Lackawanna to 

Roseland; the Mid-Atlantic Power Pathway (MAPP); and a new 345 kV circuit in southern 

Indiana. Also, the four Phase Angle Regulators (PARs) on the Michigan-Ontario interface are 

expected to be in-service and regulating by the summer of 2009. 

To assess the resource adequacy of the regional area, RFC evaluates the adequacy of the capacity 

in each RTO to supply the demand in each RTO. The reserve margin targets of each RTO are 

weight-averaged together to develop a reserve margin target for use in gauging the general 

adequacy for the RFC region. The amount of proposed resources needed through 2017, in 

addition to the planned resources, represents only 25.0% of the currently proposed projects in the 

PJM and MISO generator queues for the ReliabilityFirst regional area. The expectation is for 

adequate reserves for PJM, MISO and ReliabilityFirst throughout the ten year period of this 

Long Term Resource Assessment. 

RFC - Summer Capacity Margin Comparison

-5%

0%

5%

10%

15%

20%

25%

30%

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Margin (%)

Region/Subregion Target Margin Existing Certain

Net Capacity Resources Adjusted Potential Resources

Total Potential Resources
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163 2008 Long-Term Reliability Assessment 

RFC - Projected On-Peak Capacity by Fuel-Mix

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

Coal

Gas

Nuclear

Oil

Pumped Storage

Hydro

Wind

Other

MW

2008

2017

RFC Capacity vs Demand - Summer

170

180

190

200

210

220

230

240

250

1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016

Thousands of MW

Historic

Demand

High

Demand

Projection

Low

Demand

Projection

Adjusted

Potential

Resources

Net

Capacity

Resources

Note that demand data representing RFC’s predecessors (portions of the MAIN, ECAR, and MAAC 

regions) was not considered as part of the analysis performed to obtain the load forecast bandwidths 

above. 
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164 2008 Long-Term Reliability Assessment 

RFC-MISO - Summer Capacity Margin Comparison

-5%

0%

5%

10%

15%

20%

25%

30%

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Margin (%)

Region/Subregion Target Margin Existing Certain

Net Capacity Resources Adjusted Potential Resources

Total Potential Resources

RFC-PJM - Summer Capacity Margin Comparison

-5%

0%

5%

10%

15%

20%

25%

30%

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Margin (%)

Region/Subregion Target Margin Existing Certain

Net Capacity Resources Adjusted Potential Resources

Total Potential Resources
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165 2008 Long-Term Reliability Assessment 

RFC Self-Assessment 

Introduction 

Almost all ReliabilityFirst Corporation (RFC) members are affiliated with either the Midwest 

ISO (MISO) or PJM RTO (PJM) for operations and reliability coordination. Ohio Valley Electric 

Corporation (OVEC), a generation and transmission cooperative located in Indiana, Kentucky 

and Ohio is not affiliated with either RTO market; however OVEC’s Reliability Coordinator 

services are performed by PJM. Duquesne Light Co. has recently announced its intention to 

withdraw from PJM and join MISO in the third quarter of 2008. For this assessment, Duquesne 

Light continues to be included within the PJM RTO. 

ReliabilityFirst does not have officially-designated subregions; however, about one-third of the 

RFC load is within MISO and nearly all remaining load is within PJM, except for about 100 MW 

of load within the OVEC Balancing Authority area. From the perspective of the RTOs, 

approximately 60% of the MISO load and 85% of the PJM load is within RFC. The PJM RTO 

spans into the SERC region, and the MISO RTO also spans into the MRO and SERC regions. 

The PJM RTO operates in total as one Balancing Authority area. MISO has recently received 

approval to begin operation as a single Balancing Authority area; however operation as a BA is 

not expected to occur until the fall of 2008. 

This assessment provides information on projected resource adequacy across the ReliabilityFirst

region. The RFC Resource Adequacy Standard BAL-502-RFC-01 requires Planned Reserve 

Sharing Groups (PRSGs) to identify the minimum acceptable reserves to maintain resource 

adequacy for their respective areas of RFC. PJM operates as the PRSG for its members. The 

Midwest PRSG consists of a consortium of MISO members that includes about 95% of the 

MISO load in the RFC regional area. Since nearly all ReliabilityFirst area demand is in either 

Midwest ISO or PJM, the reliability of these two RTOs will determine the reliability of the RFC 

region. This report assesses the resource adequacy of each RTO based on the reserve margin 

requirements applicable to each RTO. PJM determines the reserve margin requirement for all 

demand within PJM. The Midwest PRSG and Mid-Continent Area Power Pool (MAPP) 

determine reserve requirements for most of the demand in MISO. MISO uses a 12% default 

reserve requirement for demand not included in the Midwest PRSG and MAPP. The 

combination of reserves from the Midwest PRSG, MAPP and the default reserve calculation was 

used by RFC as the MISO reserve margin target for assessing resource adequacy. 

Demand 

The analysis of the demand data for the long term assessment focuses on three factors, Total 

Internal Demand (TID), Net Internal Demand (NID) and Demand-Side Management (DSM). 

This analysis reviews the demand of the entire PJM RTO, Midwest ISO (MISO), as well as the 

ReliabilityFirst regional area. 

These demand forecasts are based on “50/50” or median weather (a 50% chance of the weather 

being warmer and a 50% chance of the weather being cooler). The PJM RTO prepares the 

demand forecast for the Load Serving Entities (LSEs) in its operational area. The Midwest ISO 

aggregates the reported demand forecasts from its Network Customers. The ReliabilityFirst

demand forecast is aggregated from the OVEC demand forecast and the market demand forecast 

in the ReliabilityFirst area of PJM and MISO. This is the Total Internal Demand (TID) forecast 
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166 2008 Long-Term Reliability Assessment 

of the ReliabilityFirst region. This demand does not include any demand supplied “behind the 

meter” from customer generation or co-generation. Demand diversity is used to develop 

coincident demand forecasts for the respective PJM RTO, Midwest ISO and ReliabilityFirst

areas. PJM, MISO and RFC have each developed the diversity factor (2%) for their respective 

areas. 

 

The ReliabilityFirst RTOs identify the various programs designed to reduce system demand 

during the peak periods as DSM. Individual companies may implement DSM through a demand 

response program, a direct-controlled load program, an interruptible load contract or other 

contractual load reduction arrangement. Since DSM is a contractual management of system 

demand, the reserve margin requirement for the RTO includes the effects of DSM. NID is total 

internal demand (TID) less DSM. Reserve margin requirements are based on NID. 

Demand-Side Management can be addressed in different ways, reflective of its operational 

impact on peak demand and reserve margins. DSM offers the companies that have these 

programs a way to mitigate adverse conditions that the individual companies may experience 

during periods of high demand. The total demand reduction of each RTO is the maximum 

controlled demand mitigation that is expected to be available at the time of the peak system 

demand. 

For this long term assessment, the ReliabilityFirst RTOs have identified the following types of 

DSM programs: 

DIRECT-CONTROLLED LOAD MANAGEMENT 

There are a number of load management programs under the direct control of the system 

operators that allow interruption of demand (typically residential) by controlling specific 

appliances or equipment at the time of the system peak. Radio controlled hot water 

heaters or air conditioners would be included in this category. Direct controlled load 

management is typically used for “peak shaving” by the system operators. 

INTERRUPTIBLE DEMAND 

Industrial and commercial customer demands that can be contractually interrupted at the 

time of the system peak, either by direct control of the system operator (remote tripping) 

or by the customer at the request of the system operator, are included in this category. 

The projected effects of existing and proposed new non-controlled Demand-Side 

Management (DSM) programs (such as conservation and energy efficiency incentives) 

are factored into the TID forecasts provided to ReliabilityFirst. 

PJM RTO DEMAND DATA 

The estimated Net Internal Demand (NID) peak of the entire PJM RTO for the summer of 2008 

is projected to be 133,500 MW. For the summer of 2017, NID is projected to be 153,800 MW. 

The equivalent compound growth rate (ECGR) of the NID forecast is 1.6% from 2008 to 2017. 

This is the same as the ECGR of last year’s NID forecast. These values are based on the Total 

Internal Demand (TID) demand forecast prepared by PJM staff with the full use of the load 

management placed under PJM coordination. The forecast is dated January 2008, and is based on 

economic data from late 2007. 
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167 2008 Long-Term Reliability Assessment 

Load Management placed under PJM coordination is PJM’s program for Demand-Side 

Management (DSM). PJM identifies two types of DSM, Direct Control, and Interruptible. Direct 

control amounts to 400 MW with an additional 4,000 MW of Interruptible Demand. The analysis 

assumes the DSM remains constant in PJM throughout the assessment period. 

The estimated Total Internal Demand (TID) of PJM RTO for the 2008 summer season is 137,900 

MW and is forecast to increase to 158,200 MW by 2017. The ECGR of the 2008 TID forecast is 

1.5%, which is slightly less than the 1.6% ECGR last year for 2007-2016. 

MIDWEST ISO DEMAND DATA 

The estimated Net Internal Demand (NID) peak of the entire Midwest ISO Market for the 

summer of 2008 is projected to be 100,000 MW. For the summer of 2017, NID is projected to be 

114,500 MW. The equivalent compound growth rate (ECGR) of the NID forecast is 1.5% from 

2008 to 2017. This is slightly higher than the 1.4% ECGR of last year’s NID forecast. These 

values are based on the Total Internal Demand (TID) demand forecast developed for the MISO 

market. The forecast was developed early in 2008 from independent member forecasts. Each 

MISO member used applicable economic data from late 2007 during the development of their 

demand forecast. 

MISO identifies two types of DSM, Direct Control and Interruptible, in the demand forecast. 

Direct control amounts to 1,700 MW with an additional 3,100 MW of Interruptible Demand in 

2008. MISO has forecast an initial decline in DSM after 2008 with slow increase back to a total 

DSM forecast of 4,800 MW in 2017. 

The estimated Total Internal Demand (TID) of MISO for the 2008 summer season is 104,800 

MW and is forecast to increase to 119,300 MW by 2017. The ECGR of the 2008 TID forecast is 

about the same as the 2007 ECGR of 1.4%. 

RFC DEMAND DATA 

The region is expected to be summer peaking throughout the study period, therefore this 

assessment will focus its analysis on the summer demand period. In this assessment, the data 

related to the RFC areas of PJM and MISO are combined with the data from the Ohio Valley 

Electric Corporation (OVEC) to develop the RFC regional data. The RFC demand forecast also 

accounts for the expected demand diversity among these entities. RFC uses the minimum 

diversity from the past 5 years which is 2.0%.

The estimated Net Internal Demand (NID) peak of the entire RFC region for the summer of 2008 

is projected to be 177,200 MW. For the summer of 2017, NID is projected to be 201,700 MW. 

The equivalent compound growth rate (ECGR) of the NID forecast is 1.5% from 2008 to 2017. 

This is slightly higher than the 1.4% ECGR of last year’s NID forecast. 

The DSM reported by PJM and MISO amounts to 900 MW of Direct Control Load Management 

with an additional 5,900 MW of Interruptible Demand in 2008. This increases to a total DSM 

forecast of 6,900 MW in 2017. 
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168 2008 Long-Term Reliability Assessment 

The TID for the summer of 2008 is projected to be 184,000 MW. For the summer of 2017, TID 

is projected to be 208,600 MW. The equivalent compound growth rate (ECGR) of the TID 

forecast is 1.4% from 2008 to 2017. This is the same as the 1.4% ECGR of last year’s TID 

forecast. 

Generation 

The generating capacity in this assessment represents the rated capability of the generation in 

OVEC and in the PJM and MISO market areas. For this assessment this capacity is categorized 

as “existing”, “planned”, or “proposed”. Customer generation or co-generation capacity is not 

included in this assessment when it only supplies power to local customer demand not included 

in the regional demand totals. 

Existing capacity is either listed as “certain” or “uncertain”. Certain capacity is a capacity 

resource cleared in PJM’s Reliability Pricing Model (RPM) or a Designated Network Resource 

(DNR) in the MISO market. Uncertain resources are the existing generation that represents 

wind/variable resource de-ratings, generating capacity that has not been studied for delivery 

within the region, and capacity located within the region that is not part of PJM committed 

capacity or MISO DNR. Uncertain generation is not included when determining the reserve 

margins. 

“Planned” capacity is future additions expected to go in-service in the respective years, and are 

used when determining the reserve margins. In this assessment, planned capacity is assumed to 

go in service as scheduled. “Proposed” capacity is less certain future capacity additions and only 

a portion of the total capacity is included when determining the expected reserve margins. 

Generation Interconnection queues are the sources of data for the planned and proposed 

generating unit additions. The amount (percentage) of proposed capacity additions to be included 

in the reserve margins is 20% for PJM and 31% for MISO. 

The recent emphasis on renewable resources is increasing the amount of wind power capacity 

being added to systems in the ReliabilityFirst Region. In this assessment, the amount of available 

wind power capability included in the reserve calculations is less than the nameplate rating of the 

wind resources. PJM uses a three year average of actual wind capability during the summer daily 

peak periods as the expected wind capability. When three years of operating data are not 

available for a specific wind project, that project substitutes a default capability for the 

unavailable data. PJM has recently changed the default wind capability from 20% to 13% for 

new queue projects. In MISO, wind power providers may declare up to 20% of nameplate 

capability as DNR. The difference between the nameplate rating and the expected wind 

capability is not included in the reserve calculations. In this assessment, ReliabilityFirst used 

20% of nameplate rating for both PJM and MISO as the on-peak capability for planned and 

proposed wind power projects. 

Generally, scheduled maintenance is minimized during the peak demand periods. This 

assessment assumes no scheduled maintenance during the summer periods. It is important to note 

that the capacity resources identified as “certain” in this assessment have been pre-certified by 

either PJM or MISO as able to be used within their RTO market area. This means that these 

resources are considered to be fully deliverable within and recallable by their respective markets. 
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169 2008 Long-Term Reliability Assessment 

The planned and proposed generation additions included in the reserve margin calculations for 

both PJM and MISO are assumed in this assessment to satisfy their respective deliverability 

requirements. In both RTOs there may be additional resources identified as uncertain that may be 

available to serve load, yet are not included in calculating the expected reserve margins in this 

assessment. 

PJM GENERATION 

The entire PJM RTO has 165,500 MW of existing “certain” generation for the 2008 summer. 

There is also 1,800 MW of existing capacity that is categorized as “uncertain” for the entire ten 

year assessment period. The increase in planned generation additions through 2017 is 4,400 MW. 

The amount of proposed increase in capability from the PJM generator interconnection queue is 

49,500 MW. The confidence factor used by ReliabilityFirst to calculate the amount of proposed 

capacity to be included in the assessment of future reserve margins is 20% for PJM. 

MISO GENERATION 

The Midwest ISO market has 115,300 MW of existing “certain” generation for the 2008 

summer. There is also 6,600 MW of existing capacity that is categorized as “uncertain” for the 

entire ten year assessment period. The increase in planned generation additions through 2017 is 

4,400 MW. The amount of proposed increase in capability from the MISO generator 

interconnection queue is 25,200 MW. The confidence factor to be used to calculate the amount 

of proposed capacity to be included in the assessment of future reserve margins is 31% for 

MISO. 

RFC GENERATION 

The RFC data only includes generation physically located within the ReliabilityFirst Region, 

although generating capacity outside the regional area owned by member companies may be 

included with the scheduled power imports. 

The amount of OVEC, PJM and MISO “certain” capacity in RFC is 213,700 MW. There is also 

3,100 MW of existing capacity that is categorized as “uncertain” for the entire ten year 

assessment period. The increase in planned generation additions through 2017 is 5,800 MW. The 

amount of proposed increase in capability in the RFC region from the PJM and MISO generator 

interconnection queue is 47,200 MW. The confidence factor used by ReliabilityFirst in this 

assessment is 20% for PJM and 31% for MISO. The amount of proposed capacity that will be 

included in the assessment of future reserve margins will be based on these confidence factor 

percentages. Within ReliabilityFirst there is about 1,700 MW of existing nameplate wind turbine 

capacity with 200 MW being included as on peak capacity for reserve requirements. There is 

also approximately 700 MW of existing biomass type resources within the region. 

Purchases and Sales 

PJM and MISO have assumed for this assessment that the expected purchases and sales across 

their RTO boundaries will be the same for all years. These net transactions identified by PJM 

and MISO are considered firm transactions with firm transmission reservations and they will be 

included when determining the reserve margins in ReliabilityFirst. PJM and MISO only include 

firm transactions and less than 200 MW of the total transactions in MISO use Liquidated 

Damage Contracts. There are no Liquidated Damage Contracts in PJM. 
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170 2008 Long-Term Reliability Assessment 

Some of the total interchange reported by PJM and MISO is due to jointly owned generation. 

These resources are located in one RTO but have owners in both RTOs with entitlements to the 

generation. Also, some of the interchange in PJM and MISO comes from OVEC entitlements. 

Since the jointly owned generation and the OVEC generation is all within RFC, the jointly 

owned and OVEC generation is included in RFC’s generation and not the RFC net interchange. 

Therefore, the total net interchange for the RFC region is not a simple summation of the PJM and 

MISO RTO interchange. 

PJM NET INTERCHANGE 

Transactions for the PJM RTO net to 1,500 MW of interchange out of the PJM RTO. 

MISO NET INTERCHANGE 

MISO has reported net interchange transactions (purchases) of 6,300 MW into the MISO 

market. 

RFC NET INTERCHANGE 

The net interchange transactions for OVEC, MISO and PJM at the time of the peak that cross the 

RFC regional boundary are projected to balance. Forecasts of future interchange transactions are 

very speculative, since they rely on generation resources that are in other regions. While the 

ReliabilityFirst believes significant power could be imported into the region when necessary, no 

import has been included in determining the future reserve margins. 

Fuel 

The fuel mix of generating units in the ReliabilityFirst region in 2008 is 15% nuclear, 3% hydro 

and pumped storage hydro, 47% coal, 8% oil, 26% gas, and 1% wind and other. Many factors 

can adversely impact fuel supply and delivery, and, therefore, adversely impact available 

generating capacity. However, these factors are usually the result of a local accident (train 

derailment), some naturally occurring event (heat wave or drought) or natural disaster 

(hurricane). 

Recent events, such as the 2005 Gulf coast hurricanes and the Powder River Basin railroad 

derailment and subsequent repair and maintenance activities, provide evidence that today the gas 

supply and coal delivery networks are near their current limits. However, since these have 

typically been short term problems, ReliabilityFirst does not expect a fuel problem to affect the 

long term assessment. 

Transmission 

Plans within ReliabilityFirst for the next six years include the addition of over 1,600 miles of 

high voltage transmission lines that will operate at 100 kV and above, as well as numerous new 

substations and transformers that are expected to enhance and strengthen the bulk transmission 

system. Most of the new additions are connections to new generators or substations serving load 

centers. MISO and PJM have identified many new projects as part of the Midwest ISO 

Expansion Plan (MTEP) and the PJM Regional Transmission Expansion Plan (RTEP). MISO 

projects can be referenced at http://www.midwestmarket.org/page/Expansion%20Planning. 
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171 2008 Long-Term Reliability Assessment 

Furthermore, there are several “backbone” transmission projects that are planned within 

ReliabilityFirst. PJM’s RTEP has identified four major “backbone” projects, one from the 2006 

RTEP and three additional ones from the PJM Board-approved 2007 RTEP. Additional PJM 

RTEP project information can be referenced at http://www.pjm.com/planning/reg-trans-expplan.html.

The Trans-Allegheny Interstate Line (TrAIL) project (see http://www.aptrailinfo.com/index.php) 

from the 2006 RTEP is a new 210-mile, 500 kV RFC-SERC interconnection and is scheduled for 

operation in 2011. This project consists of a new 500 kV circuit from 502 Junction to Mt. Storm 

to Meadow Brook to Loudon. This project will relieve anticipated overloads and voltage 

problems in the Washington, DC area, including anticipated overloads expected in 2011 on the 

existing 500 kV network. The four-year period before the existing facilities become overloaded 

presents a very challenging timeframe for the development, licensing, and construction of this 

project. 

The three other PJM “backbone” projects from the 2007 RTEP are planned. One is the 130-mile, 

500 kV circuit from Susquehanna to Lackawanna to Roseland will tie into the existing 500 kV 

network where multiple 230 and 115 kV circuits are tightly networked. This circuit then will 

continue to Roseland. Also, 500/230 kV transformers are proposed at Lackawana and Roseland 

substations. This circuit and transformer additions will create a strong link from generation 

sources in northeastern and north-central Pennsylvania into New Jersey. These facilities are 

expected to be in-service by June 2012. 

The Potomac-Appalachian Transmission Highline (PATH)171 is the second “backbone” project, 

and consists of a 244-mile Amos to Bedington 765 kV line and a 92-mile, twin-circuit 500 kV 

line from Bedington to Kemptown. This project will bring a strong source into the Kemptown, 

MD area by reducing the west-to-east power flow on the existing PJM 500 kV transmission 

paths and provide significant benefits to the constrained area of Washington DC and Baltimore. 

These facilities are expected to be in-service in 2012. 

The third “backbone” project is the Mid-Atlantic Power Pathway (MAPP), which consists of a 

new 190-mile 500 kV line beginning at Possum Point, VA and terminating at Salem, NJ. See 

http://www.powerpathway.com/overview.html for more information. 

In each of these four projects (TrAIL, Susquehanna to Roseland, PATH, and MAPP) PJM and its 

TO’s are working in concert with local and state authorities to ensure project schedules are 

maintained. In the event that any one of these projects is delayed, short-term operating 

procedures will be used to mitigate any problems. However, in the longer term, the most reliable 

solution is the construction of the project. 

Currently, the only approved major project within the RFC area of the Midwest ISO is the 

Vectren 345 kV line from Gibson (Duke) – AB Brown (Vectren) – Reid (BREC). This line is 

expected to be in-service in 2011. 

 

171 http://www.pathtransmission.com/overview/default.asp
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172 2008 Long-Term Reliability Assessment 

Additionally, AEP and Duke have recently announced a joint venture, Pioneer Transmission 

LLC, to build 240 miles of 765 kV transmission line and related facilities in Indiana from the 

Rockport to Greentown stations. The project will be submitted later this year to both MISO and 

PJM for consideration in their MTEP and RTEP expansion plans, respectively. The earliest 

possible in-service date could be 2014 or 2015, depending upon all of the necessary approval 

processes. See http://www.nrel.gov/wind/systemsintegration/news/2008/628.html for more 

information. 

Phase Angle Regulators (PARs) are located on all major ties between northeastern PJM and 

southeastern New York to help control unscheduled power flows. The Ramapo PARs in NPCC 

control flow from RFC to NPCC. The Michigan-Ontario PARs have not yet achieved long-term 

operation of all four units. The B3N PAR in Michigan that previously failed will still be out-ofservice until the summer of 2010, and the remaining three PARs are expected to control flows 

(i.e. will be regulating). An operations agreement for controlling the interface has been 

completed. In this assessment, all four of the PARs on the Michigan-Ontario border are 

regulating and the base flows in Pennsylvania have changed compared to the summer of 2008. 

Transmission Planners will need to address this accordingly. 

 

Historically, ReliabilityFirst (including the heritage regions) has experienced widely varying 

power flows due to transactions and prevailing weather conditions across the region. As a result, 

the transmission system could become constrained during peak periods because of unit 

unavailability and unplanned transmission outages concurrent with large power transactions. 

Generation re-dispatch has the potential to mitigate these potential constraints. Notwithstanding 

the benefits of this re-dispatch, should transmission constraint conditions occur, local operating 

procedures as well as the NERC transmission loading relief (TLR) procedure may be required to 

maintain adequate transmission system reliability. 

Certain critical flow-gates that have experienced TLRs in previous summers continue to be 

identified as heavily loaded in various reliability assessments and may require operator 

intervention to ensure reliability is maintained. 

The transmission system is expected to perform well over a wide range of operating conditions, 

provided that new facilities go into service as scheduled, and that transmission operators take 

appropriate action, as needed, to control power flows, reactive reserves and voltages. Both 

MISO and PJM perform comprehensive generator and load deliverability studies. 

Reliability Assessment Analysis 

The ReliabilityFirst Long Term assessment uses the reserve margin targets determined for the 

PJM and MISO areas to assess the expected adequacy of generation resources over the next ten 

years. Analyses were conducted by PJM and the Midwest PRSG around the end of 2007 and 

early in 2008 to determine the reserve margins that were equivalent to the ReliabilityFirst Loss 

of Load Expectation (LOLE) criterion of not exceeding one occurrence in ten years on an annual 

basis. These analyses include demand forecast uncertainty, outage schedules, and other relevant 

factors when determining the probability of forced outages exceeding the available margin for 

contingencies. ReliabilityFirst’s assessment of long term PJM resource adequacy is based on the 

reserve margin target determined from the PJM Reliability Pricing Model (RPM) analysis for 

planning year 2008-2009. This reserve margin target is 15.0% through 2012 and 15.5% for later 
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173 2008 Long-Term Reliability Assessment 

years. To assess long term MISO resource adequacy, RFC calculated a combined reserve margin 

target for the 2008-2009 planning year of 14.1%. This reserve margin was based on the reserve 

requirement for demand in the Midwest PRSG, the remaining MRO area of MISO that uses the 

MAPP reserve requirement, and the small amount of other MISO demand that uses the MISO 

default reserve requirement. 

This assessment evaluates the adequacy of the capacity in the each RTO and the region to supply 

the demand in each RTO and the region, respectively. The reserve margin targets of each RTO 

were weight-averaged together to develop a reserve margin target to use to gauge the general 

adequacy for the RFC region. This combined reserve margin target for the RFC region is 14.7%. 

Although ReliabilityFirst determines seasonal resource adequacy from the assessments of the 

two RTOs, in the long term assessment there is more variation and uncertainty in future 

resources. Therefore, ReliabilityFirst uses this reserve margin target to review the reserve margin 

forecast of the regional area for the assessment period against a combined reserve margin target 

for each year in the analysis period, in addition to the review of the RTO reserve margins and 

reserve margin targets. 

As previously mentioned in the Generation section, uncertain resources are not included in the 

calculation of expected reserve margins. Energy-only, existing wind deratings and any 

transmission limited resources are considered uncertain in this analysis, and therefore is not 

included. Future planned capacity changes that are factored into the expected reserves include 

rating changes of existing generation, new generation, and known planned retirements of existing 

generation. 

Deliverability of capacity between the RTOs is not addressed in this report. However, each of the 

LOLE studies conducted to determine the target reserve margins used in this assessment has 

assumed limited or no transfer capability between these RTOs. By limiting the transfers between 

PJM and MISO in this assessment, the reserve margin target for the ReliabilityFirst region will 

be somewhat more conservative than a target determine by including the full inter-RTO transfer 

capability. 

ReliabilityFirst has not performed any sensitivity analyses for high resource unavailability or 

high demand due to weather conditions. Any condition that increases regional demand or 

generation resource unavailability beyond the forecast conditions in the assessment analysis will 

decrease overall resource reliability. However, over the ten year assessment period, extreme 

weather, fuel interruptions, and droughts are considered to be short term conditions that are not 

included when determining long term reliability targets. Over time, any adverse trends in forced 

outage rates will be factored into the analyses required by the ReliabilityFirst Planned Resource 

Adequacy Standard, and the reserve margin targets will reflect the need for higher reserves. 

Operational measures that would be expected to be deployed to mitigate adverse conditions 

during this assessment period are the same as those discussed on page 94 of the ReliabilityFirst

section of NERC’s “2008 Summer Reliability Assessment”. 

PJM RESERVE MARGINS 

The reserve margin for existing capacity resources is 30,500 MW in PJM for 2008, which is 

22.8% based on NID. With an additional 4,256 MW of planned new capacity, the reserve 
Regional Reliability Assessment

174 2008 Long-Term Reliability Assessment 

margins are expected to meet the 15.0% reserve margin target through 2013. The target 

increases to 15.5% after that time. Additional resources will be needed beyond 2013. The 

amount of proposed resources needed in this assessment starts at 1,600 MW in 2013 and 

increases to about 9,100 MW by 2017. This is 18.4% of the 49,500 MW of resources in the PJM 

generator interconnection queue that was categorized as proposed resources. 

It should be noted that PJM has assumed a constant 1,500 MW export over the assessment 

period. If there were no net interchange for the RTO, there would only be a need for 7,600 MW 

of additional proposed resources. 

MISO RESERVE MARGINS 

The reserve margin for existing capacity resources is 21,500 MW in MISO for 2008, which is 

21.5% based on NID. With an additional 4,400 MW of planned new capacity, the reserve 

margins are expected to meet the 14.1% target through 2014. Additional resources will be 

needed beyond 2015. The amount of proposed resources needed in this assessment starts at 1,300 

MW in 2015 and increases to about 4,600 MW by 2017. This is about 18.0% percent of the 

proposed resources in the MISO generator interconnection queue. 

It should be noted that MISO has assumed a constant 6,300 MW import over the assessment 

period. If there were no net interchange for the RTO, there would a need for 10,900 MW of 

additional proposed resources by 2017. 

RFC RESERVE MARGINS 

The reserve margin for existing capacity resources is 36,600 MW in ReliabilityFirst for 2008, 

which is 20.6% based on NID. With an additional 5,700 MW of planned new capacity located 

within the region, the reserve margins are expected to meet the 14.7% target through 2012. 

Additional resources will be needed beyond 2012. In 2013, there will be a need for less than 300 

MW of proposed resources. The amount of proposed resources will increase to about 11,800 

MW by 2017. This represents 25.0% of the combined PJM and MISO proposed generator 

resources in the ReliabilityFirst area. 

Both MISO and PJM conduct comprehensive detailed generator load deliverability studies. 

MISO deliverability (http://www.midwestmarket.org/page/Generator+Interconnection) test 

results can be found under Generator Deliverability Tests. For more information on PJM 

deliverability (http://www.pjm.com/contributions/pjm-manuals/pdf/m14b.pdf), see Appendix E 

of the PJM Manual 14b. Results of the PJM analysis are evaluated continuously as part of the 

normal PJM planning process and presented as part of the Transmission Expansion Advisory 

Committee (TEAC) meetings. See http://www.pjm.com/committees/teac/teac.html for more 

details. Neither MISO nor PJM have any deliverability concerns for this assessment period. 

PJM performs voltage stability analysis (including voltage drop) as part of all planning studies 

and also as part of a periodic (every five minutes) analysis performed by the energy management 

system (EMS). Results are translated into thermal interface limits for operators to monitor. 

Transient stability studies are performed as needed and are part of the Regional Transmission 

Expansion Plan (RTEP) analysis (see http://www.pjm.com/planning/rtep-baseline-
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175 2008 Long-Term Reliability Assessment 

reports/baseline-report.html). Small signal analysis is performed as part of long-term studies, but 

not for seasonal assessments. MISO also performs transient stability analysis. 

The Cleveland area was shown to be a reactive power-constrained area from the 2003 blackout. 

However, several actions have been taken to mitigate any future reactive resource problems 

associated with this area. These include the installation of capacitor banks and an automatic 

under voltage load shed (UVLS) scheme (as mentioned below) and enhanced monitoring of 

dynamic reactive resources and system conditions in that area. FirstEnergy has reactive reserve 

criteria for this area. 

There are two automatic under voltage load shed (UVLS) schemes within RFC. One is located in 

the northern Ohio/western Pennsylvania area and the other is in the northern Illinois area. These 

schemes have the capability to automatically shed a combined total of about 2,300 MW and 

provide an effective method to prevent uncontrolled loss-of-load following extreme outages in 

those areas. There are currently no new plans to install UVLS within the RFC region. 

ReliabilityFirst does not specifically study catastrophic events and is not aware of any specific 

studies. However, registered entities such as Transmission Planners may conduct their own 

extreme analyses. ReliabilityFirst does plan to conduct some NERC Category D contingency 

analysis as part of the long-term transmission assessment study later this year. 

Areas within ReliabilityFirst are currently not experiencing drought conditions. 

All Transmission Planners within ReliabilityFirst conduct studies, as required in the NERC TPL 

Standards. ReliabilityFirst also conducts regional studies that include NERC Category A, B, and 

C contingencies. Results of these studies are used in the regional assessment reports. Extensive 

contingency analysis is performed by PJM as part of the RTEP analysis, which includes transient 

stability analysis. Details can be found at http://www.pjm.com/committees/teac/teac.html. 

MISO also performs contingency analysis as part of their MTEP studies. 

ReliabilityFirst is not currently aware of any new technologies that will be deployed within the 

region to improve bulk-power system reliability. 

ReliabilityFirst does not maintain a Regional short-circuit database, which would be required to 

accurately assess the short-circuit levels within RFC. As a result, RFC does not conduct a 

specific assessment of short-circuit levels, does not have a mechanism to assist RFC members in 

maintaining short-circuit equivalents outside their own system, and does not have a strategy to 

address short circuit levels with respect to either installed equipment capabilities or the limits of 

existing technology. Each Transmission Owner and Planner obtains suitable short-circuit 

equivalents from neighboring Transmission Owners to assess their own system and to develop 

and implement any necessary mitigation strategies. In addition, short circuit analysis is 

performed as part of the PJM RTEP analysis. 

No significant trends within ReliabilityFirst have been noted that would suggest that aging 

infrastructure is becoming an issue. 
Regional Reliability Assessment

176 2008 Long-Term Reliability Assessment 

ReliabilityFirst does not have any guidelines nor is aware of any program to share inventory of 

spare equipment. The legacy Regions had previously participated in providing information to 

the NERC spare transformer database. 

Other Region-Specific Issues 

In December 2007, the Maryland Public Service Commission (PSC) issued a first in a series of 

Interim Reports regarding the state of the electricity markets in Maryland. As directed in 

Maryland Senate Bill 400, the report offers the PSC’s recommendations and analysis regarding 

options for “re-regulating” Maryland’s electricity markets and for obtaining new generation and 

transmission resources in the state. The premise for the analysis is the PSC’s view that “unless 

steps are taken now, the State of Maryland may face a critical shortage of in-state electricity 

capacity that could force mandatory use restrictions, such as rolling black-outs, by 2011 or 

2012”. 

The options considered in the PSC’s analysis include full re-regulation, mandatory utilitydirected long-term contracts, establishing a State Power Authority, reinstitution of integrated 

resource planning and aggressive efforts to shape PJM’s wholesale markets. The PSC 

recommended a series of interventions designed to (begin to) address Maryland’s perceived 

reliability problem that could include forcing an increase in the available supply of electricity 

and requiring utilities to implement aggressive and cost-effective demand management and 

energy conservations programs For more information, see the Maryland PSC web site at 

http://www.psc.state.md.us/psc/Reports/2007SupplyAdequacyReport_01172007.pdf 

One method that addresses the aging workforce issue is FirstEnergy's Power Systems Institute 

(PSI), which has teamed with several local community colleges and universities to offer 

Associate Degree programs that lead to careers in skilled technical fields. These unique, twoyear programs combine classroom learning with the hands-on training needed to open the door to 

opportunities as line, substation, plant or nuclear workers in the electric utility industry. For

information, see http://www.firstenergycorp.com/career_center/technical_training/index.html. 

ReliabilityFirst has no additional reliability concerns for this long-term assessment. 

Region Description 

ReliabilityFirst currently consists of 44 Regular Members, 23 Associate Members, and 4 Adjunct 

Members operating within 12 NERC balancing authorities, which includes over 360 owners, 

users, and operators of the bulk-power system. They serve the electrical requirements of more 

than 72 million people in a 240,000 square mile area covering all of the states of Delaware, 

Indiana, Maryland, Ohio, Pennsylvania, New Jersey, and West Virginia, plus the District of 

Columbia; and portions of Illinois, Kentucky, Michigan, Tennessee, Virginia, and Wisconsin. 

The ReliabilityFirst area demand is primarily summer peaking. Additional details are available 

on the ReliabilityFirst website (http://www.rfirst.org). 
Regional Reliability Assessments

177 2008 Long-Term Reliability Assessment 

SERC Highlights 

SERC members project that resources in the region will be 

adequate to meet demand over the forecast period provided there is 

regulatory support on a state and local level for the development of 

needed generation. Although the SERC region does not implement 

a regional reserve requirement, SERC members adhere to their 

respective state commissions’ regulations or internal business 

practices as they plan for or procure resources. 

Significant generation development has occurred in the SERC 

region during the past few years, resulting in thousands of MW of 

non-committed generating capacity being installed without a specific allocation to load. Some of 

this generation can be made available as short-term, non-firm or potential future resources to 

SERC members and others if deliverability is ensured. Some of this generation went unreported 

under the new NERC definitions used for capacity analysis in this LTRA. This reporting issue is 

expected to be remedied in future reports. It is estimated that some 28,000 MW went unreported. 

In this LTRA SERC has reported the details of its Annual Generation Development Survey, 

which is independent of the NERC effort, in order to present a more complete picture of 

potential resources. 

SERC members participate in numerous transmission assessment processes. The individual 

transmission owners within SERC conduct assessment studies to ensure compliance of their 

individual system which are subsequently subject to audits and assessments by SERC. Some 

subregions (like VACAR) conduct assessment studies of the entire subregion to ensure 

simultaneous compliance of the systems within the subregion. Further, SERC has study groups 

that conduct assessment studies of the entire region to ensure simultaneous compliance of all the 

systems within the region. 

In preparation for summer 2008 SERC members conducted a special drought assessment 

considering a hydrological scenario more severe than the forecast 2008 summer conditions. The 

study projects that there will be no major reliability issues under the severe case tested in the 

study. At the present time, (Fall 2008) conditions are improving in many (but not all) of the 

drought-affected areas. The study also provided valuable experience for managing drought 

situations as they arise in the future. 
Regional Reliability Assessments

178 2008 Long-Term Reliability Assessment 

SERC - Summer Capacity Margin Comparison

-5%

0%

5%

10%

15%

20%

25%

30%

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Margin (%)

Region/Subregion Target Margin Existing Certain

Net Capacity Resources Adjusted Potential Resources

Total Potential Resources

SERC - Projected On-Peak Capacity by Fuel-Mix

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

100,000

Coal

Gas

Nuclear

Dual Fuel

Hydro

Pumped Storage

Oil

Undetermined/Unknown

Other

MW

2008

2017
Regional Reliability Assessments

179 2008 Long-Term Reliability Assessment 

SERC Capacity vs Demand - Summer

90

110

130

150

170

190

210

230

250

270

290

310

330

1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016

Thousands of MW

Historic

Demand

High

Demand

Projection

Low

Demand

Projection

Adjusted

Potential

Resources

Net

Capacity

Resources

Central - Summer Capacity Margin Comparison

-5%

0%

5%

10%

15%

20%

25%

30%

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Margin (%)

Region/Subregion Target Margin Existing Certain

Net Capacity Resources Adjusted Potential Resources

Total Potential Resources
Regional Reliability Assessments

180 2008 Long-Term Reliability Assessment 

Delta - Summer Capacity Margin Comparison

-15%

-10%

-5%

0%

5%

10%

15%

20%

25%

30%

35%

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Margin (%)

Region/Subregion Target Margin Existing Certain

Net Capacity Resources Adjusted Potential Resources

Total Potential Resources

Gateway - Summer Capacity Margin Comparison

0%

5%

10%

15%

20%

25%

30%

35%

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Margin (%)

Region/Subregion Target Margin Existing Certain

Net Capacity Resources Adjusted Potential Resources

Total Potential Resources
Regional Reliability Assessments

181 2008 Long-Term Reliability Assessment 

Southeastern - Summer Capacity Margin Comparison

0%

5%

10%

15%

20%

25%

30%

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Margin (%)

Region/Subregion Target Margin Existing Certain

Net Capacity Resources Adjusted Potential Resources

Total Potential Resources

VACAR - Summer Capacity Margin Comparison

-5%

0%

5%

10%

15%

20%

25%

30%

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Margin (%)

Region/Subregion Target Margin Existing Certain

Net Capacity Resources Adjusted Potential Resources

Total Potential Resources
Regional Reliability Assessments

182 2008 Long-Term Reliability Assessment 

SERC Self-Assessment 

Introduction 

The SERC Reliability Corporation (SERC) is the Regional Reliability Organization (RRO) for 

all or portions of 16 central and southeastern states. SERC is divided into five sub-regions: 

Central, Delta, Gateway, Southeastern, and VACAR, that together supply power to 

approximately 23% of the electric customers in the United States. Most electric utilities within 

SERC have traditional vertically integrated corporate structures with planning philosophies 

based on an obligation to serve ensuring that designated generation operates under optimal 

economic dispatch to serve local area customers. A few SERC members, however, have selected 

or been ordered to adopt a non-traditional operating structure whereby management of the 

transmission system operation is provided by a third party under an Independent Coordinator of 

Transmission or a Regional Transmission Organization that manages transmission flows to 

customers over a broader regional area through congestion-based locational marginal pricing. 

Companies within SERC are closely interconnected and the region has operated with high 

reliability for many years. 

It should be noted that the generation capacity figures provided here are based generally on the 

data submitted for the current EIA 411 report. In addition to the collection of data from 

members in accordance with NERC’s prescribed definitions, SERC collects generation data for 

the forecast period from its members. This data focuses on generation which is constructed, but 

not necessarily dedicated or committed to serving load. Such generation performs a merchant 

function, operating when it is economic to do so. Even though a significant amount of merchant 

generation has been developed within SERC in recent years, not all of that generation is reflected 

in the capacity margins is presented here. It is estimated that there is presently nearly 28,000 

MW of such generation in the SERC region that is in addition to what is reported in the EIA 411 

report. 

Capacity resources in the region as a whole are expected to be adequate to reliably supply the 

forecast firm peak demand and energy requirements throughout the long-term assessment period. 

Reported potential capacity additions and existing capacity, including uncommitted resources, 

along with the necessary transmission system upgrades, could satisfy capacity margin needs 

through 2017. The outcomes in terms of resource adequacy is highly dependent on regulatory 

support for generation expansion plans, new state local and federal environmental regulations 

impacting operation of existing generating resources, state and local environmental and siting 

process regulations that influence the development of new generating resources. 

The SERC region has extensive transmission interconnections between its sub-regions and its 

neighboring regions (FRCC, MRO, RFC, and SPP). These interconnections allow the exchange 

of firm and non-firm power and allow systems to assist one another in the event of an 

emergency. 

Transmission capacity is expected to be adequate to supply firm customer demand and firm 

transmission reservations. Like capacity and resource adequacy, the outcomes in terms of 

adequacy of transmission capacity are dependent on regulatory support for transmission 
Regional Reliability Assessments

183 2008 Long-Term Reliability Assessment 

expansion plans. SERC members invested approximately $1.262 billion in transmission system 

upgrades 100 kV and above in 2007, plan to invest approximately $1.631 billion in 2008 and are 

planning transmission capital expenditures of more than $8.66 billion over the next five years. 

Planned transmission additions over the next ten years include 1,644 miles of 230-kV lines, 338 

miles of 345-kV lines, and 447 miles of 500-kV lines. 

Demand 

The 2008 summer net internal demand forecast is 198,522 MW and the forecast for 2017 is 

236,070 MW. The average annual growth rate over the next ten years is 1.94%. This is the 

same as last year’s forecast growth rate of 1.94%. The historical growth rate of actual peaks has 

averaged 2.45% over the last 8 years. 

All reported demands are non-coincident. These forecasts are based on average historical peak 

period weather conditions. There were no significant changes in weather or economic 

assumptions since last year’s forecast. 

The SERC region has significant demand response programs. These programs allow demand to 

be reduced or curtailed when needed to maintain reliability. The amount of interruptible demand 

and load management is expected to increase slightly over the forecast period from 6,269 MW in 

2008 to 6,986 MW in 2017. These amounts are higher than last year’s projections due, in part, to 

the addition of new members. Also, a change in reporting philosophy regarding demand 

response programs within certain companies resulted in the additional increase in interruptible 

demand and demand-side management. However, an offsetting adjustment was made to the 

demand reported, resulting in no net change. In addition to the reported interruptible demand 

and load management, there are significant other demand-side management programs that are 

also available to maintain reliability in the region. 

Temperatures that are higher or lower than normal and the degree to which interruptible demand 

and demand-side management is used can result in actual peak demands that vary considerably 

from the reported forecast peak demand. Although SERC does not perform extreme weather or 

load sensitivity analyses at the region level to account for this, SERC members address these 

issues in a number of ways, considering all NERC, SERC, regulatory, and other requirements. 

These member methods must be documented and are subject to audit by SERC. 

While member methods vary to account for differences in system characteristics, the methods 

share many common considerations including: 

• Use of econometric linear regression models; 

• Relationship of historical annual peak demands to key variables such as weather, 

economic conditions, and demographics; 

• Variance of forecasts due to such considerations as high and low economic scenarios and 

mild and severe weather; and 

• Development of a suite of forecasts to account for the variables mentioned above, and 

associated studies utilizing these forecasts. 
Regional Reliability Assessments

184 2008 Long-Term Reliability Assessment 

In addition, many SERC members use sophisticated, industry accepted methods to evaluate load 

sensitivities in the development of load forecasts. 

Regarding the influence of extreme weather, the 90th percentile peak temperature relates to an 

estimated extreme weather peak of about 6% higher than the regular forecast for the region. An 

extreme peak for 2008 summer equates to 210,433 MW of firm peak demand for the region. The 

capacity margin for this scenario is estimated to be 10.6%, which, although reduced from the 

expected margin under normal forecast conditions, remains at an adequate level for the extreme 

case condition. This analysis assumes the load response to temperatures in this extreme range is 

linear. However, there is insufficient historical evidence to support this, since at some point load 

saturation occurs as temperatures rise into extreme levels. Therefore the capacity margin is 

likely to be higher even under this extreme case. Since capacity margins for SERC are fairly 

constant for the 10-year period, this 2007 summer example can be used to conclude that extreme 

weather is not expected to reduce resource adequacy to critical levels. The SERC region as a 

whole is not expected to have any difficulty serving customers in a 90/10 outcome relative to the 

ten year load forecast. 

Generation 

SERC believes that capacity resources will be sufficient to provide adequate and reliable service 

for forecast demands throughout the long-term assessment period. Reported potential capacity 

additions and existing capacity, including uncommitted resources, along with the necessary 

transmission system upgrades, could satisfy capacity margin through 2017. As can be seen in 

Figure 2, the range of outcomes is quite wide, particularly for the out years. The outcomes in 

terms of resource adequacy are highly dependent on regulatory support for generation expansion 

plans, new state local and federal environmental regulations impacting operation of existing 

generating resources, state and local environmental and siting process regulations that influence 

the development of new generating resources.

The changes in definitions established by the NERC Planning Committee have resulted in a 

significant change in both the reported generation for the 2008 LTRA and the generation 

included in the capacity margin calculation. SERC is presenting both the NERC and SERC 

results in this report. 

SERC has had significant merchant generation development which is not included in the NERC 

margin calculation. SERC member responses to the annual SERC Reliability Review 

Subcommittee’s (RRS) Generation Plant Development Survey indicate nearly 28,000 MW of uncontracted merchant generation is connected to the member systems. This merchant generation 

has not been contracted to serve load within SERC and its deliverability is not assured. For these 

reasons, only merchant generation expected to serve SERC load is included in the capacity 

margins reported for SERC. A significant amount of merchant capacity within the region has 

been participating in the short-term energy markets, indicating that a portion of these resources 

are deliverable during certain system conditions. SERC’s Generation Plant Development Survey 

is a summer capacity survey and does not distinguish winter ratings. If a load serving entity has 

a contractual arrangement with a merchant plant and has reported the arrangement through the 

EIA-411 reporting process, then this capacity is included in this capacity margin assessment. 

Because significant capacity exists in the region, there will continue to be additional generation 
Regional Reliability Assessments

185 2008 Long-Term Reliability Assessment 

above that which is reported in the capacity margin trend. NERC’s capacity margin calculations 

also assume the use of load management and interruptible contracts at the time of the annual 

peak. 

Although the SERC region does not implement a regional planning reserve requirement, 

members adhere to their respective state commissions’ regulations or internal business practices 

as they plan for adequate generation resources. SERC members use various methods172 to ensure 

adequate resources are available and deliverable to the load. 

Resources are expected to be adequate even if resource unavailability is higher than expected 

since SERC entities recognize that planning for variability in resource availability is necessary. 

Many SERC members manage this variability through reserve margins, demand side 

management programs, fuel inventories, diversified fuel mix and sources, and transfer 

capabilities. Some SERC members participate in Reserve Sharing Groups (RSG). In addition, 

emergency energy contracts are used within the region and with neighboring systems to enhance 

recovery from unplanned outages. 

The projected 2008 capacity mix reported for SERC is approximately 37% coal, 15.2% nuclear, 

9.4% hydro/pumped storage, 33% gas and/or oil, and 5.4% for purchases and miscellaneous 

other capacity. The mix has not changed significantly from last year. Generation with coal and 

nuclear fuels continues to lead the region’s fuel mix, accounting for roughly 52.2% of net 

operable capacity in 2008. 

The majority of planned capacity additions, as reported by member systems in the EIA-411 

filings, is comprised of gas/oil fueled combustion turbine or combined cycle units. However, 

there are recent announced additions and plans in the ten-year planning horizon for coal-fired 

and nuclear plant additions. 

Some examples are: 

Potential Additions: 

• Central Sub-region: 750 MW coal addition in 2010; 1,182 nuclear in 2012 

• Delta Sub-region: Up to 3,102 of nuclear additions in 2015 

• Gateway Sub-region: 1,650 MW merchant coal plant in 2011-2012; 1,650 MW nuclear 

addition in 2017 

• Southeastern Sub-region: 1,200 MW merchant coal plant in 2012; 1,100 MW nuclear 

addition in 2016; 1,100 MW nuclear addition in 2017 

• VACAR Sub-region: 620 MW coal addition in 2008-09, 800 MW coal addition in 2012, 

605 MW coal addition in 2012-13, 1,100 MW nuclear addition in 2016 

Of the approximately 7,657 MW of planned resource additions reported for the 2008-2017 time 

period, 7.94% are combined cycle, 26.71% are combustion turbine, 30.66% are steam (including 

nuclear), 26.41% are net purchases, .43% are hydro, 7.84% are pumped storage and .01% are 

 172 Members have a variety of approaches to determining resource adequacy. These range from LOLE/LOLP on a company basis to 

target margin criteria. Some state jurisdictions in SERC have implemented specific requirements for some of SERC’s 

members. SERC is in the process of reviewing the methods used by its members. 
Regional Reliability Assessments

186 2008 Long-Term Reliability Assessment 

categorized as “Other/Unknown”. The “Other/Unknown” category includes potential additions 

that do not have finalized implementation plans. It appears that entities are continuing to 

increase plans for future coal or nuclear base load generation instead of relying on natural gasfired generation or purchases. 

Generation Development in SERC 

Generation facilities need to be planned and constructed to ensure that aggregate generation 

capacity keeps pace with the electric demand. Generation reserve capacity must remain 

sufficient to mitigate postulated grid contingency scenarios. A growing number of independent 

power generating units are interconnecting to the grid and selling their product into the electricity 

market. While mechanisms exist at state and federal agencies to collect data about the 

interconnection of new facilities, it is often difficult to accurately capture all of the generation 

facilities in their various phases of development. The ability to rapidly install peaking capacity 

resources and a general trend toward seasonal and short-term capacity purchases further 

complicate data collection as many utilities are delaying firm purchase commitments as long as 

possible. There are, however, generating plants under development and uncommitted generating 

facilities already in service in SERC that have the potential to provide significant resources for 

certain individual members. The single best source of information regarding generation 

development in the SERC region remains the annual Generation Plant Development Survey. 

To better understand the role that new generation facilities may play in serving the demand 

requirements of the SERC region, the SERC Engineering Committee authorized the SERC RRS 

in 1999 to conduct its first Generation Plant Development Survey. The tenth such survey was 

conducted in February 2008. The survey was directed to the transmission owners or providers 

within SERC. It was expected that these entities would be the best source of information for this 

survey because generation plant developers must coordinate with transmission owners or 

providers in accordance with FERC requirements prior to interconnecting to the transmission 

network. 

Survey respondents were asked to report all generation development connected to the 

transmission systems within SERC, whether uncommitted or dedicated to serve native load. 

Projects were reported according to their stage of development as measured by the level of 

Interconnection Service requested and whether the generation will be designated as a network or 

native load resource (if known). The level of Interconnection Service is measured by two 

categories: 

1) Interconnection Service that has been requested through the OASIS process, or 

2) Interconnection Service Agreements that have been signed or unexecuted agreements that 

have been filed at FERC. 
Regional Reliability Assessments

187 2008 Long-Term Reliability Assessment 

The 2008 survey focused not only on the growth of the generation resources within the region, 

but also provides a more accurate representation of future generation resources that considers 

retirements, total uncommitted resources, and inoperable uncommitted resources. A summary of 

the 2008 Generation Plant Development Survey results is provided in Table 1. 

Table 1: Current Status of Generation Plant Development 

Current Status of 

Generation Plant 

Development

In-Service Year of Added Generation (MW)

CATEGORY 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 10 Yr 

Total 

1) Interconnection 

Service Requested, 

Only 

65 2766 4945 10059 3336 5159 663 3248 2735 3169 36144 

> Designated as 

Network Resource or has 

obtained Firm PTP 

Transmission service 

33 2289 1851 3424 747 2788 663 3132 2735 1403 19065 

> Uncommitted 32 477 3094 6635 2589 2371 0 116 0 1766 17079 

2) Interconnection 

Agreement 

Signed/Filed 

2327 2236 3597 3334 1807 207 110 500 864 250 15231 

> Designated as 

Network Resource or has 

obtained Firm PTP 

Transmission service 

2156 2078 1691 869 1192 116 110 500 864 250 9825 

> Uncommitted 171 158 1906 2465 615 91 0 0 0 0 5406 

3) Unit Retirements 78 0 114 75 198 276 235 486 133 133 1728 

Net Projected 

Additions (1) + (2) – (3) 2314 5002 8428 13318 4945 5090 539 3262 3466 3286 49647 

*Source — SERC Reliability Review Subcommittee 2008 report to the SERC Engineering Committee 

The survey indicates an additional 2,392 MW of generation plant capacity is expected in the 

SERC region for the 2008 summer, with 78 MW of retirements scheduled, resulting in net 

potential additions of 2,314 MW. The vast majority of additions had signed or filed 

interconnection agreements at the time of the survey. In the near-term planning horizon (2008-

2013) there is significant speculation about the amount of generation that will be added 

(approximately 39,800 MW, of which over 26,300 MW falls in category 1), and its impact on 

the capacity margin for the region. Also, a significant number of wind generators (over 3,900 

MW) have requested interconnection service in the Gateway sub-region in this time period. The 

trend from last year’s survey to this year’s indicates that there is more uncertainty regarding 

near-term generation resources, since near-term Category 1 additions outnumber those in 

Category 2, but the amount reported to be constructed will likely change before the next annual 

survey. 

Category 2 additions are significantly smaller in the longer-term (2008-2017). However, the 

more speculative Category 1 additions are higher throughout the 10-year period. This pattern is 

not unexpected since plans for the longer-term continue to undergo review and revisions. The 

39,800 MW of generation development reported in the first six years of this year’s survey is 

significantly higher than the 28,100 MW reported in last year’s survey. The majority of the 

increase is due to Category 1 additions in the VACAR sub-region. The amount of the reported 
Regional Reliability Assessments

188 2008 Long-Term Reliability Assessment 

planned capacity that will actually be built is highly dependent on factors such as regulatory 

approvals, market prices, fuel availability, the ability to arrange suitable interconnection and 

transmission access agreements, the number of other generation plants that are being constructed, 

the ability to permit and complete necessary transmission line additions in a reasonable amount 

of time, the ability of the generation developer to obtain financial backing, and other typical 

business factors. 

The horizontal line in Figure SERC-1 demonstrates that the SERC region has 32,866 MWs more 

generation within the region in 2008 than will be required to meet the region’s demand in 2017. 

Total potential generating plant capability for July 1, 2013 from the 2008 survey is 305,717 MW, 

versus the 288,137 MW that was identified for that time period in the 2007 survey. Over the 

period covered by the 2008 survey, generation capacity additions totaled 49,647 MW versus 

44,463 MW reported in 2007 for the period covered by that survey. This marks the third 

consecutive survey with increased potential capacity additions. The SERC RRS believes that the 

Generation Plant Development Survey provides one important indication of the potential 

generation development within the SERC region and its sub-regions. 

Figure SERC-1: Potential Generation Plant Development in SERC 

190,000

200,000

210,000

220,000

230,000

240,000

250,000

260,000

270,000

280,000

290,000

300,000

310,000

320,000

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

Year

Megawatts

2008 Survey Total Capacity 2008 EIA-411 Demands

32,866 MW

80,199 MW

*Source — SERC Reliability Review Subcommittee 2008 Generation Plant Development Survey 

Purchases and Sales 

Near-term (2008-2013) planned firm purchases across the SERC electrical borders total 1,548 

MW and are comprised of 908 MW from RFC and 640 MW from SPP. These firm purchases 

have been included in the capacity margin calculations for the region. 
Regional Reliability Assessments

189 2008 Long-Term Reliability Assessment 

Near-term planned firm sales across the SERC electrical borders total 3,186 MW and are 

comprised of 1,551 MW to FRCC, 1,247 MW to RFC, 13 MW to MRO, and 375 MW to SPP. 

These firm sales have been accounted for in the capacity margin calculations for the region. 

In the long-term (2008 to 2017), purchases and sales are difficult to forecast with any certainty. 

Purchases declined from 1,553 MW to 780 MW. Sales declined from 3,363 MW to 676 MW. 

Only firm transactions are accounted for in the capacity margin calculations for the region. 

Fuel 

Fuel supplies are expected to be adequate to meet forecast demands over the next 10 years. 

Sufficient inventories (including access to salt-dome natural gas storage), fuel-switching 

capabilities, alternate fuel delivery routes and suppliers, and emergency fuel delivery contracts 

are some of the important measures used by SERC members to reduce reliability risks due to fuel 

supply issues. The predominant fuel type used in the region is coal, and its share of member’s 

capacity is 37.3% of the total generation. Gas generation is used during peaking conditions and 

its reported share of member’s capacity is 16.6% of total generation. 

SERC members recognize that planning for variability in resource availability is necessary. 

Many SERC members typically provide for this variability through capacity margins, demand 

side management programs, fuel inventories, diversified fuel mix and sources, and transfer 

capabilities. Some SERC members participate in Reserve Sharing Groups (RSG). In addition, 

emergency energy contracts are used within the region and with neighboring systems to enhance 

recovery from unplanned outages. Emergency sales and purchases and activation of shared 

reserves have been used in the region during the past year. However, the frequency of their use 

has not increased relative to previous years. 

Fuel supply will always be a critical part of the power supply chain, regardless of fuel choice. 

SERC utilities have been able to maintain fuel diversity in their portfolios, enhancing reliability. 

Looking forward, SERC is following these issues to ensure reliability is maintained into the 

longer-term planning horizon: 

• Protecting the nation’s natural gas production and transportation facilities in the Gulf 

Coast areas 

• Monitoring the development of LNG facilities in both the U.S. and other natural gas 

producing countries 

• Monitoring the next wave of new generation additions over the next 10 - 15 years 

• Ensuring that the coal delivery infrastructure keeps pace with the forecasted increase in 

construction of coal generation facilities 

• Ensuring that fuel inventories continue to be managed appropriately to mitigate the 

effects of natural disasters and other causes of disruptions to fuel supplies 

Transmission 

The existing bulk transmission system within SERC totals 49,994 miles of transmission lines 

comprised of 17,699 miles of 161-kV, 20,447 miles of 230-kV, 3,246 miles of 345-kV, and 

8,602 miles of 500-kV transmission lines. SERC member systems continue to plan for a reliable 

bulk transmission system and plan to add 317 miles of 161-kV, 1,644 miles of 230-kV, 338 

miles of 345-kV, and 447 miles of 500-kV transmission lines in the 2008–2017 time period. As 
Regional Reliability Assessments

190 2008 Long-Term Reliability Assessment 

reported in the 2007-2016 NERC LTRA Report, the bulk transmission expansion plans of SERC 

region members are second only to the WECC. Furthermore, the planned transmission 

expansion in SERC represents approximately 20% of all transmission expansion in the U.S. over 

the next ten years. This marks the sixth consecutive year in which SERC has reported at least 

one-fifth of all planned U.S. transmission expansion. SERC members invested $1.262 billion in 

new transmission lines and system upgrades in 2007 (includes transmission lines 100 kV and 

above and transmission substations with a low-side voltage of 100 kV and above), and are 

planning transmission capital expenditures in excess of $8.66 billion over the next five years. 

SERC member transmission systems are directly interconnected with the transmission systems in 

FRCC, MRO, RFC, and SPP. Transmission studies are coordinated through joint interregional 

reliability study groups. The results of individual system, regional and inter-regional studies 

help to demonstrate that the SERC transmission systems meet NERC Reliability Standards. 

Results from the ERAG (Eastern Interconnection Reliability Assessment Group) sponsored 2008 

Summer MRO-RFC-SERC West-SPP inter-regional study indicate potential transmission 

transfer issues between the Delta sub-region and some neighboring regions involved in the study. 

The areas of interest from this study indicate that the First Contingency Incremental Transfer 

Capability (FCITC) from the Delta sub-region to some neighboring interfaces, including SPP 

and MRO, as “zero”. These transfers are primarily limited by 161 kV transmission facilities on 

the Entergy-SPP interface for the outage of the ANO-Ft. Smith 500 kV line, which is a tie line 

between Entergy and Oklahoma Gas and Electric. Previous reliability studies indicate that 

power flows on these 161 kV transmission lines are extremely sensitive to Entergy and SPP 

generation dispatch in the local area, as well as transactions modeled across Entergy’s northern 

interface. While Entergy and other SPP members have committed to upgrading one of these 

interface constraints (i.e., Danville-Magazine 161 kV line), Entergy is also evaluating other longterm transmission solutions for this limit. However, Entergy does not expect any reliability 

concerns for the summer of 2008 

The transmission systems in SERC are expected to have adequate delivery capacity to support 

forecast demand and energy requirements and firm transmission service commitments during 

normal and applicable contingency system conditions as prescribed in the NERC Reliability 

Standards (see Table 1, Category B of NERC Reliability Standard TPL-002-0) and the member 

companies’ planning criteria relating to transmission system performance. 

Operational Issues 

Coordinated interregional transmission reliability and transfer capability studies for the shorter 

term planning horizon were conducted among all the SERC sub-regions and with the 

neighboring regions. In addition, coordinated intraregional transmission reliability and transfer 

capability studies for the longer term planning horizon were conducted within SERC. These 

studies indicate that the bulk transmission systems within SERC and between adjoining regions 

can be expected to provide adequate and reliable service over a range of system operating 

conditions. 

Drought conditions in SERC are lessoning in some sub-regions; reliability concerns are 

continuing in other sub-regions in the near-term but long-term outlook is unknown. All subregions of SERC experienced drought effects during 2007 which provided a valuable basis for 
Regional Reliability Assessments

191 2008 Long-Term Reliability Assessment 

evaluation of future drought conditions. SERC conducted a special assessment including an 

extreme hydrological scenario more severe in terms of water availability to forecast 2008 

summer conditions. Based on the assessment, if the drought continues through 2008, the 

hydrological conditions leading into 2009 could be more severe. However, at the present time 

hydrological conditions in 2008 are improving in some areas. While it is difficult to predict on a 

long-range basis the impact of long-term drought conditions, the members of SERC have now 

had experience with preparing the special assessment which can be repeated in the future as 

required. The results of this recent special assessment show that no sub-region identified 

significant concerns that might threaten reliability for the near-term. At most, some redispatch, 

modest increases in imports, or operating guidelines will be required. Individual Transmission 

Planners and Planning Coordinators are continuing drought preparedness initiatives already 

underway and operational representatives continue as 

needed to provide opportunities for coordination and 

sharing of system conditions. 

The current status (October 14, 2008) according the US 

Drought Monitor (brown areas are Drought Level 4 – 

exceptional)173 is depicted in the Figure to the right. 

All sub-regions of SERC experienced drought effects 

during 2007 which provided a valuable basis for 

evaluation of future drought conditions. SERC 

conducted a special assessment including an extreme 

hydrological scenario more severe in terms of water 

availability to forecast 2008 summer conditions. Based 

on the assessment, if the drought continues through 2008, 

the hydrological conditions leading into 2009 could be 

more severe. However, at the present time hydrological 

conditions in 2008 are improving in many areas. While it 

is difficult to predict on a long-range basis the impact of 

long-term drought conditions, the members of SERC have now had experience with preparing 

the special assessment which can be repeated in the future as required. The results of this recent 

special assessment show that no sub-region identified significant concerns that might threaten 

reliability for the near-term. At most, some redispatch, modest increases in imports, or operating 

guidelines will be required. Individual Transmission Planners and Planning Coordinators are 

continuing drought preparedness initiatives already underway and operational representatives 

continue as needed to provide opportunities for coordination and sharing of system conditions. 

Reliability Assessment Analysis 

Capacity resources in SERC are expected to be able to supply the projected firm summer 

demand with adequate margin. Although SERC does not specify a regional capacity margin 

requirement, members adhere to their respective state commission regulations, RTO 

requirements and/or internal business practices as applicable. The projected long-term capacity 

margins under various definitions are reflected in Figure 2. 

 

173 http://drought.unl.edu/dm/monitor.html
Regional Reliability Assessments

192 2008 Long-Term Reliability Assessment 

Reported potential capacity additions and existing capacity, including uncommitted resources, 

along with the necessary transmission system upgrades, could satisfy capacity margin needs 

through 2017. The outcomes in terms of resource adequacy is highly dependent on regulatory 

support for generation expansion plans, new state local and federal environmental regulations 

impacting operation of existing generating resources, state and local environmental and siting 

process regulations that influence the development of new generating resources. As can be seen 

in Figure SERC-2, the range of potential outcomes is quite wide, particularly for the out years. 

Note that year-to-year comparisons with prior reports are not possible due to the changes in the 

definition NERC specifies for generation status and margin calculation. 

In order to address unexpected fuel interruptions due to resource unavailability, SERC entities 

with large amounts of gas-fired generation connected to their systems have conducted electricgas interdependency studies. In-depth studies have simulated pipeline outages for near and longterm study periods as well as both summer and winter forecasted peak conditions. Also 

included, for each of the major pipelines serving the service territory, is an analysis of the 

expected sequence of events for the pipeline contingency, replacing the lost generation capacity, 

and assessment of electrical transmission system adequacy under the resulting conditions. Dual 

fuel units are tested to ensure their availability and that back-up fuel supplies are adequately 

maintained and positioned for immediate availability. Some generating units have made 

provisions to switch between two separate natural gas pipeline systems, reducing the dependence 

on any single interstate pipeline system. Moreover, the diversity of generating resources serving 

load in the region further reduces the region’s risk. 

Current projections indicate that the fuel supply infrastructure for the near-term planning horizon 

is adequate even considering possible impacts due to weather extremes. New international gas 

supplies are continuing to emerge in the U.S. market, positively impacting fuel inventories. 

While fuel deliverability problems are possible for limited periods of time due to weather 

extremes such as hurricanes and flooding, assessments indicate that this should not have a 

significant negative impact on reliability. The immediate impact will likely be economic as 

some production is shifted to other fuels. Secondary impacts could involve changes in emission 

levels and increased deliveries from alternate fuel suppliers 
Regional Reliability Assessments

193 2008 Long-Term Reliability Assessment 

SERC Capacity Margin Comparison

-5.0%

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

30.0%

35.0%

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Margin (%)

Existing & Net Firm Transactions Net Capacity Resources Total Potential Resources

Adjusted Potential Resources SERC Potential M argin*

* The SERC Potential Margin line includes under development and uncommitted generation resources, along w ith assumptions regarding generation 

availability and transmission deliverability based on SERC’s Annual Generation Plant Development Survey

Figure SERC-2: 2008 LTRA SERC Region - Capacity Margin Comparison 

Aging Work force Issue 

In general, SERC member companies are actively recruiting replacement employees in field and 

technical functions as the need arises. SERC members recognize the need for continually 

improving skills as both a business requirement and a potential issue for grid reliability. While 

SERC members are addressing this issue on an individual company basis, in general, companies 

work to help enhance the technical education systems through various guidance and support 

mechanisms, continue development of their technical employees through in-house and outside 

training, and support employees through continued upgrading of tools. Technical interchanges 

and industry audits are used to help redefine performance and set challenges that attract capable 

candidates. Meeting industry standards increasingly requires training and performance 

requirements that help improve technical capabilities. 

Sub-regions 

Central 

Demand 

The 2008 summer net internal demand forecast for the Central Sub-region was 42,163 MW and 

the forecast for 2017 is 49,673 MW. This year’s forecast average annual peak growth rate for 

2008-2017 is 1.84% for the sub-region. This is lower than last year’s forecast growth rate of 

2.1% due to the forecast impacts of new Demand Side Management (DSM) programs and lower 

economic projections, and is based on normal weather conditions along with monthly energy 

sales, economic growth, population, employment and gross regional product increases 

throughout the sub-region. There is a mix of various demand response programs including 

interruptible demand, new energy efficiency programs, customer curtailing programs, and direct 

load management including an air conditioner control program. To assess variability, most 

members within the sub-region use forecasts assuming normal weather, and then develop models 

for milder and more extreme weather to create optimistic and pessimistic scenarios. 
Regional Reliability Assessments

194 2008 Long-Term Reliability Assessment 

Generation

Members in the Central sub-region reported a range of various categories of capacity for the 

years 2008-2017. This capacity can be categorized as existing certain and uncertain, planned and 

proposed and is adequate to meet demand during this time period. 

Table SERC-1: Central LTRA Capacity Breakdown 

Capacity Type Year 2008 Year 2017 

Existing Certain 49,668 MW 47,607 MW 

 Solar .56 MW .56 MW 

 Biomass 15 MW 15 MW 

 Hydro 4,965 MW 4,989 MW 

Existing Uncertain 4,608 MW 4,759 MW 

Proposed capacity 1,183 MW 12,944 MW 

Planned capacity 0 MW 2,604 MW 

 Biomass 2 MW 2 MW 

To determine potential resource options for the future, members in this sub-region use long-term 

contracts and are in the process of either evaluating or adding self-build options to add new 

capacity. 

Purchases and Sales

Members in the Central sub-region reported a range of firm and non-firm sales and purchases for 

the years 2008-2017. These sales and purchases are external and internal to the region and subregion and help to ensure resource adequacy within the sub-region. The table below summarizes 

these transactions during this time period. 

Table SERC-2: Central Sub-regional Sales/Purchases 

Transaction Type Year 2008 Year 2017 

Firm Sales (External: RFC) 66 MW 160 MW 

Firm Sales (Internal) 143 MW 244 MW 

Non-firm Sales (Internal) 0 MW 167 MW 

Firm Purchases (External: RFC) 316 MW 176 MW 

Sales of zero for non-firm transactions within the SERC region were reported. 

The majority of these sales/purchases are backed by firm contracts for a mix of generation and 

transmission. Very few are associated with liquidated damages contracts (LDC). Although 

some members in the Central sub-region participate in Contingency Reserve Sharing Groups for 

assistance during emergencies, the sub-region is not dependent on outside purchases or transfers 

to meet its load. 

Fuel

Fuel vulnerability is not considered to be a concern. Central sub-region members have a highly 

diverse mix of suppliers, transportation, supply contracts, on-site storage and fuel alternatives to 

supply generation. Coal is responsible for 47.8% of member generation in the sub-region. The 
Regional Reliability Assessments

195 2008 Long-Term Reliability Assessment 

remaining generation is supported by 13.5% nuclear, 19.1% oil and gas, 3.3% pumped storage, 

10.0% hydro and 6.3% net purchases and sales and other/unknown fuel types. Some oil is stored 

as an alternative fuel. Fuel stocks, transportation systems and supplier communications are 

considered strong and are monitored routinely for adequacy. 

Transmission

For the next ten years, the Central sub-region has planned 9 miles of 230kV, 181 miles of 345kV 

and 67 miles of 500kV as new bulk transmission lines. The following table shows the 

transmission additions to the bulk power system that ensure reliability during the next ten years. 

The details of the transmission expansion plans and transformer additions are shown in the 

Major Transmission Projects > 200 kV section. 

Operational Issues

Sub-regional members plan several generation additions to come into service within the next ten 

years. These additions will increase reliability by diversification of generation type and also 

with locations throughout the service territory. Although the sub-region is not predicting any 

major generation or transmission outages that will affect reliability, generation unit outages will 

include turbine overhauls. Expected outages will be performed during low peak periods and 

capacity replacement planned to ensure resource adequacy. 

No major environmental/regulatory restrictions or temporary operating measures are expected to 

affect the reliability of the Central sub-region for the next ten years. 

Reliability Assessment Analysis

Net capacity resource margins in the sub-region as reported between the years 2008-2017 are 

from 15.2% to 0.6% over the ten-year period using NERC’s 2008 method as shown in Figure 

SERC-3. There is no regional, sub-regional, state or provincial marginal requirement for this 

sub-region. Members within the sub-region project capacity margins based on forecasted 

demand with the assumptions of normal weather, expected economic conditions, and expected 

demographics for each specific area. 

Resource adequacy analyses are performed on a regular basis, and no significant changes have 

been reported from last year. Members use planning studies to ensure generation deliverability. 

Studies are coordinated with neighboring systems to incorporate imports and unit outages. 

Members report no retirements for the upcoming years. Members within the sub-region rely on 

quarterly OASIS studies. For example the SERC Near-term Study Group assesses transfer 

capability issues. 

 Companies within the sub-region maintain individual criteria to address any problems with 

stability. UVLS systems have been installed to prevent voltage collapse at Philadelphia, 

Mississippi, and Knoxville, Tennessee. All other systems are expected to be secure with no 

anticipated stability issues. Companies within the sub-region do not have a general guideline for 

on-site, spare generator step-up unit and auto transformers, although TVA has standardized on a 

small number of 500 kV designs and has studied the interchangeability of existing spares. 
Regional Reliability Assessments

196 2008 Long-Term Reliability Assessment 

Central Capacity Margin Comparison

-10.0%

-5.0%

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

30.0%

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Margin (%)

Existing & Net Firm Transactions Net Capacity Resources Total Potential Resources

Adjusted Potential Resources Central Potential M argin*

* The Central Potential Margin line reflects the Central subregion’s component of the SERC Annual Generation Plant Development Survey 

and includes under development and uncommitted generation resources, along w ith assumptions regarding generation availability and 

transmission deliverability

Figure SERC-3: 2008 NERC LTRA SERC Central Sub-region – With Central Potential Margin 

In order to address plans for catastrophic events companies use techniques such as black start 

analysis and training, emergency load curtailment programs, load shedding plans, and purchases 

of back up power through interconnections. The sub-region experienced a severe drought 

through 2007 which continued into 2008, and some members have seen a reduction in their 

power supply from Southeastern Power Administration due to repair work on the Wolf Creek 

Dam which is likely to continue for several more years. Hydro operations are constantly 

monitored and evaluated for potential changes and mitigation plans are formed to minimize any 

threats to reliability. While the continuing drought and dam repairs will affect hydro energy and 

capacity and cause some thermal de-rating, no problems are foreseen in meeting normal margins 

and maintaining normal reliability. 

To further improve bulk power system reliability, members of the sub-region have reported 

various programs that will be implemented within the next few years. These programs include: 

an Operator Training Simulator (in-service in 2009), a Dynamic Thermal Circuit Rating program 

developed by the Electric Power Research Institute, and improvement to the capabilities of state 

estimator forward analysis tools. 

Member companies have performed assessments to comply with TPL-001 through TPL-004. 

E.ON develops and files annual Transmission Expansion Plans with the ITO, which identifies 

and corrects any system deficiencies due to these standards. Members participate in regional 

studies to assess extreme contingency events. Overall no significant problems have been 

observed on the bulk electric system from these analyses. Some planned and controlled load 

shedding may be required for extreme contingencies. 

The sub-region has various maintenance and project programs in place that assess the reliability 

of existing transmission infrastructure and to repair/replace deficient elements as they are 

encountered. Transmission planning processes routinely identify new facilities and the 
Regional Reliability Assessments

197 2008 Long-Term Reliability Assessment 

replacement of existing facilities that reinforces the transmission infrastructure. Inspections, 

testing, and maintenance are used by members to ensure that reliability is not impacted by 

infrastructure issues. 

To assess short circuit levels on the transmission system within the region, members within the 

region maintain a short circuit model approximately 3 to 4 years into the future and keep limits 

well within the limits of currently available circuit breaker technology. None of the members 

within the sub-region anticipate short circuit levels will impact reliability. 

Delta 

Demand 

The 2008 summer net internal demand forecast for the Delta sub-region was 27,936 MW and the 

forecast for 2017 is 33,144 MW. This year’s compound annual growth rate for 2008-2017 is 

1.92% for the sub-region. This is slightly greater than last year’s forecast growth rate of 1.9%. 

A member reported decreases are due to forecasted use per customer in the Residential and 

Commercial classes during the summer months. Uncertainty and variability is assessed through 

load scenario development, based on historical temperature probabilities. Peak load scenarios 

are also performed to assess conditions due to extreme weather found in historical records. 

Members within the Delta sub-region reported that they have a mix of demand response 

programs which consists of interruptible load programs for larger customers and a range of 

conservation/load management programs for all customer segments. 

Generation

Members in the Delta sub-region reported a range of various categories of capacity for the years 

2008-2017. This capacity can be categorized as existing certain and uncertain, planned and 

proposed and is adequate to meet demand during this time period. There are no planned capacity 

additions and 5,234 MW proposed capacity additions reported within the sub-region. 

Table SERC-3: Delta LTRA Capacity Breakdown 

Capacity Type Year 2008 Year 2017 

Existing Certain 30,091 MW 29,938 MW 

 Hydro 79 MW 79 MW 

Existing Uncertain 11,993MW 11,993 MW 

Planned Capacity 0 MW 0 MW 

Proposed Capacity 0 MW 5,234 MW 

**No Planned or Proposed Capacity was reported within this sub-region. 

Purchases and Sales

Members in the Delta sub-region reported a range of firm and non-firm sales and purchases for 

the years 2008-2017. These sales and purchases are external and internal to the region and subregion and help to ensure resource adequacy within the sub-region. The table below summarizes 

these transactions during this time period. 
Regional Reliability Assessments

198 2008 Long-Term Reliability Assessment 

Table SERC-4: Delta Sub-regional Sales/Purchases 

Transaction Type Year 2008 Year 2017 

Firm Sales (External: RFC, 

SPP) 600 MW 0 MW 

Firm Sales (Internal) 1145 MW 888 MW 

Firm Purchases (Internal) 1125 MW 92 MW 

Firm Purchases (External: 

SPP) 541 MW 505 MW 

Members within the sub-region reported that some of these sales/purchases are backed by firm 

contracts for a mix of generation and transmission. Very few are associated with liquidated 

damages contracts (LDC). Even though some members are a member of reserve sharing groups 

that ensure transmission during emergency conditions, the sub-region is not dependent on 

outside purchases, transfers, or contracts to meet the demands of its load. 

Fuel

Delta sub-regional members reported that they purchase a significant amount of fuel in shortterm markets. The entities ensure that they are in constant communication with pipelines, 

storage facilities and suppliers in the region resulting in continuous up-to-date knowledge of 

supply and transportation issues. Agreements have been set in place to purchase supply, 

transportation, balancing, flexibility and peaking services to serve anticipated generation needs. 

Fuel supplies and infrastructure are expected to be more than adequate for the upcoming years of 

demand. Members rely on a portfolio of firm-fuel resources to ensure adequate fuel supplies to 

generating facilities during projected winter peak demand. Those resources include 17.4% 

nuclear and 26.7% coal-fired generation that are relatively unaffected by winter weather events, 

0.1% fuel oil inventory, 2.5% dual fuel, 0.3% hydro, 2.2% net purchases and sales, and 50.8% 

natural gas at a company-owned natural gas storage facility, and short-term purchases of firm 

natural gas. This mix of resources provides diversity of fuel supply and minimizes the likelihood 

and impact of potentially problematic issues on system reliability. Other measures include 

aggressive maintenance of coal delivery infrastructure. 

Transmission

For the next ten years, the Delta sub-region has new transmission plans for 226 miles of 230kV 

and 100 miles of 345kV. These plans consist of additions, retirements and conversions to the 

bulk transmission lines in this sub-region. The following table shows significant transmission 

additions to the bulk power system influencing reliability during the next ten years. 

The details of the transmission expansion plans and transformer additions are shown in the 

Major Transmission Projects > 200 kV section. 

Operational Issues

Sub-regional members expect several generation additions or changes to come into service 

within the next ten years, but none are expected to be performed during peak season. 

Approximately 1,100 MW of gas-fired steam generation is assumed to be unavailable for 

dispatch for the coming year, during which time a life-cycle assessment will be made to 
Regional Reliability Assessments

199 2008 Long-Term Reliability Assessment 

determine future disposition of this capacity. There is expected to be no effect on reliability or 

temporary operating measures required due to these outages. In addition, approximately 500 

MW of gas-fired steam generation is also expected to be out of service for a period of 18 months 

beginning in 2010, during which time it will be converted to a Petroleum Coke/Coal fired 

facility. The effect of this expected outage on reliability is currently under study. 

No major environmental/regulatory restrictions or temporary operating measures are expected to 

affect the reliability of the Delta sub-region for the next ten years. 

Reliability Assessment Analysis

Net capacity resource margins in the sub-region as reported between the years 2008-2017 are 

from 6.9% to -11.8% as depicted in Figure SERC-4. While these projections indicate a low or 

negative capacity margin during a portion of the forecast period, it is anticipated that loadserving entities within this sub-region will contract for adequate firm capacity to reliably serve 

their loads as the near-term horizon approaches. In addition, because of the large amount of nonfirm generation available within the sub-region, additional resources could be procured to meet 

any expected shortfalls in generation capacity. Such non-firm generation was not reported by the 

sub-region members and thus contributed to the misleading low to negative capacity margins. 

Non-firm or uncommitted generation within this sub-region totals approximately 5,234 MW. 

Taking into account these non-firm or uncommitted resources, the capacity margins for 2008 to 

2017 would thus change to 6.9% to 5.0%. 

While there is no regional or margin requirement for this sub-region, some members within the 

sub-region project capacity margins based on long and short-term planning, along with Loss-ofLoad Studies and reserve allocations from reserve sharing groups. In certain areas of the subregion, capacity margins are expected to decrease as a result of short-term contacts expiring until 

2014. Internal resources are expected to be adequate to meet the needs of the sub-region. 

While the sub-region’s generation capacity is predicted to be adequate for supplying its load, it 

also has access to reserve sharing programs, fuel diversification, fuel policy contracts and other 

firm resource network contracts and power agreements to ensure supply in times of catastrophic 

events. Several analyses (Loss-of-Load Expectation, etc.), coordinated with neighboring regions 

and other SERC sub-regions, assess resource adequacy and transfer capability that will support 

reliable operations. Unreliable resources are not included in these assessments. No generation 

deliverability concerns, major transmission additions or significant changes are expected to be an 

issue for the sub-region for the next ten years. There are no planned retirements of any existing 

units within the sub-region. 
Regional Reliability Assessments

200 2008 Long-Term Reliability Assessment 

Delta Capacity Margin Comparison

-15.00%

-10.00%

-5.00%

0.00%

5.00%

10.00%

15.00%

20.00%

25.00%

30.00%

35.00%

40.00%

45.00%

50.00%

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Margin (%)

Existing & Net Firm Transactions Net Capacity Resources

Total Potential Resources Adjusted Potential Resources

Delta Potential M argin*

* The Delta Potential Margin line reflects the Delta subregion’s component of the SERC Annual Generation Plant Development Survey and 

includes under development and uncommitted generation resources, along w ith assumptions regarding generation availability and 

transmission deliverability

Figure SERC-4: 2008 NERC LTRA SERC Delta Sub-region – With Delta Potential Margin 

Studies have been performed to assess transient dynamics, voltage and small signal stability 

issues for summer conditions in the near-term planning horizons as required by NERC 

Reliability Standards. For certain areas of the sub-region, the 2009 assessment from the study 

was chosen as a proxy for the near-term evaluation. No critical impacts to the bulk electric 

power system were identified. While there is no common sub-region wide criteria to address 

transient dynamics, voltage and small signal stability issues, some members have noted that it 

adheres to voltage schedules and voltage stability margins. In addition, some members employ 

static VAR compensation devices to provide reactive power support and voltage stability. 

Under-voltage load-shedding (UVLS) programs are also used to maintain voltage stability and 

protect against bulk electric system cascading events. It was reported that the maximum load 

that can be shed by the UVLS program is approximately 300 MW. 

Some members in the sub-region reported that they have Capacity and Energy Emergency 

Response Plans in place to address catastrophic events. Other members rely on excessive 

capacity margins or multiple sources for transportation of natural gas in the event of a disruption 

to a major pipeline to its generators. The sub-region anticipates normal hydro conditions for the 

upcoming summer based upon current reservoir levels and anticipated rainfall. Studies that 

assess TPL-001 through TPL-004 standards cover both the near-term and longer-term planning 

horizons. These studies also cover aspects relating to load flow, short circuit, and system 

stability. This analysis is used by some members to monitor any issues caused by these extreme 

events, but does not use these results alone in identifying system improvements. The analysis 

done in the most recent study revealed no unexpected constraints. Certain members reported that 

the TPL-004 contingencies that created loading or voltage problems were corrected to meet 

acceptable planning criteria. The first correction method attempted was a switching solution. If 

switching was not sufficient, selected loads were shed until all element loadings and voltages 

were within acceptable planning criteria. To improve the reliability of the bulk power system the 

sub-region has installed static VAR compensation (SVC) in two locations on the transmission 
Regional Reliability Assessments

201 2008 Long-Term Reliability Assessment 

system in order to provide reactive power support and maintain voltage stability. Series 

compensation on several transmission lines has been installed on the system in order to regulate 

power flows on the transmission system. Members are continuing to pursue plans to employ 

these technologies in order to improve and maintain bulk system reliability. 

To assess short circuit levels on the 230kV and above transmission system within the region, 

various members within the sub-region resort to equipment replacement plans that are deemed 

underrated by short circuit analysis. Other companies will employ techniques such as station 

reconfigurations where appropriate and effective. To address the concerns of aging 

infrastructure, members within the sub-region have plans of replacing equipment around the subregion through maintenance programs. The sub-region does not have guidelines for spare 

generator units. Companies individually have their own criteria and programs to have spare 

transformers for reliability. 

Gateway 

Demand 

The 2008 summer net internal demand forecast for the Gateway Sub-region was 19,105 MW and 

the forecast for 2017 is 20,997 MW. This year’s compound annual growth rate for 2008-2017 is 

1.05% for the sub-region, which is comparable to last year’s forecast growth rate of 1.0%. The 

forecast peak load for the sub-region is calculated as the sum of the forecast peak loads of the 

individual members. Members reported that peak growth rates are due to slower economic 

growth, assumptions on efficiency, and saturation trends used in the Statistically Adjusted EndUse modeling framework. In order to assess the uncertainty and variability in projected demand, 

some members within the sub-region use regression models, multiple forecast scenario models, 

and econometric models. Economic assumptions and historical temperature and weather pattern 

information are considered individually by each sub-region member. The sub-region has a mix 

of voltage reduction curtailment programs, and other interruptible load programs, but these 

programs are minor compared to the total demand in the sub-region. The Illinois Commerce 

Commission is in the process of reviewing a variety of proposed energy efficiency programs, 

including energy audits and direct load control programs, which could further reduce the rate of 

growth in the sub-region. 

Generation

Members in the Gateway sub-region reported a range of various categories of capacity for the 

years 2008-2017. This capacity can be categorized as existing certain and uncertain, planned and 

proposed and is adequate to meet demand during this time period. Some members have reported 

that specific capacity and resource plans for 2013-2017 have not been identified during this 

current assessment period. Members plan to enter into bilateral contracts, purchase capacity as 

needed, or construct new resources as determined by various Integrated Resource Plans. At this 

time, wind and solar plants are not connected within the sub-region, but over 3,900 MW of wind 

generation is proposed to connect over the next five years. Biomass plants (landfill gas) supply 

only a few MWs of capacity to meet the sub-region load requirements and are generally 

connected to distribution facilities. 
Regional Reliability Assessments

202 2008 Long-Term Reliability Assessment 

Table SERC-5: Gateway LTRA Capacity Breakdown 

Capacity Type Year 2008 Year 2017 

Existing Certain 24,786 MW 23,916 MW 

 Hydro 368 MW 368 MW 

Existing Uncertain 4,566 MW 4,671 MW 

 Inoperable 526 MW 86 MW 

Planned 0 MW 565 MW 

**No proposed capacity was reported within this sub-region. 

Purchases and Sales

Gateway sub-regional members reported a variety of firm and non-firm sales and purchases for 

the years 2008-2017. These sales and purchases are both external and internal to the region and 

sub-region. Sales of excess capacity by some members help to ensure resource adequacy within 

the sub-region. The table below summarizes these transactions during this time period. 

Table SERC-6: Gateway Sub-regional Sales/Purchases 

Transaction Type Year 2008 Year 2017 

Firm Sales (External: RFC) 400 MW 0 MW 

Firm Sales (Internal) 420 MW 0 MW 

Non-Firm Sales (Internal) 0 MW 176 MW 

Firm Purchases (Internal) 28 MW 98 MW 

Firm Purchases (External: 

SPP) 79 MW 79 MW 

Non-Firm Purchases 0 MW 234 MW 

Most of the members within the sub-region reported that the sales/purchases for 2008 are backed 

by firm contracts for both generation and transmission. Members reported that liquidated 

damages contracts (LDC) were not used within the sub-region. Although the subregion has a 

robust transmission system with numerous interconnections to other regions and neighboring 

SERC sub-regions, the sub-region is not dependent on outside purchases or transfers to meet the 

demand and planning reserves. 

Fuel

Gateway sub-region members reported various fuel policies and some members have reevaluated 

fuel inventories and delivery practices as a result of fuel delivery issues. These policies take into 

account contracts with surrounding facilities, alternative transportation routes, and use of 

alternative fuels. Some members have developed Integrated Resource Plans to help ensure fuel 

reliability within the sub-region. These practices help to ensure balance and flexibility to serve 

anticipated generation needs. The predominant fuel type used in the sub-region is coal, and its 

share of member’s capacity is 56.6% of the total generation. Other fuel types in the sub-region 

are 15.3% gas, 6.3% nuclear, 26.1% oil/gas, 1.9% hydro, and 9.2% other or net sales and 

purchases. No fuel supply problems are anticipated during the study period. 

Transmission

The transmission system in the Gateway sub-region is robust and highly interconnected with 

EHV tie-lines to MISO, PJM, SPP, and non-MISO members in MRO in addition to the 
Regional Reliability Assessments

203 2008 Long-Term Reliability Assessment 

interconnections with SERC members in the Central and Delta sub-regions. The transmission 

system allows purchases and sales to maintain reliability within the sub-region as well as to 

import and export power and energy as economic conditions warrant. In the event of capacity 

shortfalls within the sub-region, the transmission system provides opportunities to import power 

from sources outside of the sub-region, if generation would be available. 

For the next five years, the Gateway sub-region has plans to build 57 miles of 345 kV 

transmission lines. 

The details of the transmission expansion plans and transformer additions are shown in the

Major Transmission Projects > 200 kV section. Other transmission capacity upgrades are in 

various stages of the planning process and may be required to maintain reliability for specific 

needs. 

Operational Issues 

No reliability problems are anticipated on the transmission systems of the Gateway sub-region 

for 2008 summer. The City of Springfield-CWLP reported that its Dallman generator unit 1, 

which experienced an explosion last year that compromised 86 MW, will not be available until 

the summer of 2009. The new Dallman generator unit 4 is expected to be in service by January 

2010. Several members within this sub-region have noted that there are limitations with 

emissions stipulations, thermal discharge or lake temperature limitations that can have an impact 

on peak energy needs. Many of these issues would be alleviated with the above normal 

precipitation received in late 2007 and early 2008. These limitations or any unusual operating 

conditions are not expected to have a major impact on reliability. The Taum Sauk (440 MW) 

pumped storage facility in the AmerenUE control area remains unavailable but this is not a 

reliability concern as adequate resources are available in the sub-region. The Taum Sauk plant is 

expected to return to service for the summer of 2010. 

Reliability Assessment Analysis

Net capacity resource margins in the sub-region as reported between the years 2008-2017 are 

from 19.4% to 13.6% as shown in Figure SERC-5. There is no single capacity margin 

requirement for the Gateway sub-region. Members follow established business practices or 

guidelines from the governing regulatory bodies. Some members within the sub-region project 

capacity margins for both long and short term planning horizons, and considering new 

constructed generation, along with Loss-of-Load Studies and reserve allocations from reserve 

sharing groups. In certain areas of the sub-region, capacity margins are expected to decrease as a 

result of short-term contacts expiring until 2014. Internal resources, including potential 

additions, are expected to be adequate to meet the needs of the sub-region even assuming 

extreme weather scenarios and 90/10 forecast loads. It is estimated that extreme weather could 

add an additional 5% to the load forecast in the sub-region, resulting in a capacity margin of 

15.4% in 2008 and declining to 9.3% in 2017. As mentioned earlier, the sub-region has a mix of 

voltage reduction curtailment programs, and other interruptible load programs, but these 

programs are minor compared to the total demand in the sub-region, and should not be needed to 

maintain reliability considering the amount of generation capacity available in the Gateway subregion and the reach and strength of the Gateway transmission system to import power from 

adjacent areas that have capacity available. 
Regional Reliability Assessments

204 2008 Long-Term Reliability Assessment 

Generation additions are proposed throughout the sub-region within the next 5 years. The Prairie 

State 1,650 MW coal-fired plant in southwestern Illinois is expected to be in service by 2012, 

and a majority of the new EHV transmission planned in the sub-region is for connection and 

deliverability of this facility. Other minor increases to coal-fired plants in the sub-region are also 

planned. Over 3,900 MW (nameplate) of wind generation is proposed to connect to the 

transmission system in the sub-region through 2013, with approximately 85% of the total located 

in Illinois. Only a small fraction of this wind generation (no more than 20% of nameplate 

capacity based on current MISO business practices) would be considered by sub-region members 

as contributing to the sub-region capacity portfolio during peak conditions. This percentage 

could change based on experience with the wind plants. In the 10-year period, a 1,650 MW (net) 

nuclear unit is proposed for central Missouri and its transmission requirements and impacts are 

under study. 

Gateway Capacity Margin Comparison

0.00%

5.00%

10.00%

15.00%

20.00%

25.00%

30.00%

35.00%

40.00%

45.00%

50.00%

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Margin (%)

Existing & Net Firm Transactions Net Capacity Resources

Total Potential Resources Adjusted Potential Resources

Gateway Projected M argin*

* The Gatew ay Potential Margin line reflects the Gatew ay subregion’s component of the SERC Annual Generation Plant Development Survey 

and includes under development and uncommitted generation resources, along w ith assumptions regarding generation availability and 

transmission deliverability

Figure SERC-5: 2008 NERC LTRA SERC Gateway Sub-region – With Gateway Potential 

Margin 

Fuel supply in the area is not expected to be a problem. Policies considering fuel diversity, 

contracts with various suppliers, inventory requirements, and delivery have been put in place 

throughout the area to ensure that reliability is not impacted. Even though various companies 

within the sub-region rely on sub-regional studies to assess resource adequacy, the market within 

this sub-region allows various entities to purchase the energy necessary to meet any shortfalls 

that would compromise resource adequacy. Members reported that it is not common practice to 

add uncertain resources in their assessments (LOLE, resource studies, etc). There are no 

expected major unit retirements that will impact reliability within the next ten years. 

Retirements of minor generating units total 114 MW over the ten year period 2008-2017. 

Deliverability testing studies are performed on an ongoing basis throughout the sub-region to 

ensure that transmission capacity is sufficient to make the generation deliverable. No concerns 

for deliverability have been reported within the study years. 
Regional Reliability Assessments

205 2008 Long-Term Reliability Assessment 

A number of major transmission system expansions are expected to be placed in-service over the 

next 10 years. The addition of the new Mariosa Delta 345/161 kV Substation in the Jefferson 

City area for 2008 summer has enhanced reliability in central Missouri. The Joachim 345/138 

kV Substation addition is planned to enhance reliability to the southern St. Louis County and 

Jefferson County area of Missouri, and should be placed in-service by the fall of 2008. The 

addition of a Rush Island-Baldwin 345 kV line in response to the addition of coal-fired 

generating capacity at the Prairie State facility in southwestern Illinois is expected to be inservice mid-2010. A number of other transmission system expansions are being contemplated, 

but the timing for such additions awaits a definitive need. All additions are expected to improve 

reliability within the sub-region. Deliverability problems from generation centers or into local 

load centers are not anticipated to be an issue. 

Sub-regional studies involving power flow, short-circuit, and stability analyses are not performed 

on a regular basis involving the entire sub-region, but joint studies are performed by the 

members as needed to address member and sub-regional needs. To address plans for 

catastrophic events, some members of the sub-region consider diversity of gas supply and rely on 

generation supplied from various pipelines to safeguard against disruptions from a single 

pipeline, although the reliance on gas generation in the sub-region is minimal. Other members 

rely on large interconnections to neighboring systems, energy contracts, diverse generation 

options and contingency study plans to help safeguard against unforeseen events. The Gateway 

sub-region has adequate and diverse capacity resources and is heavily interconnected, internally 

as well as to other SERC sub-regions and NERC regions, to provide system reliability for its 

members. 

Some sub-region members have studied the performance of local area load pockets for multiple 

contingency events. The addition of capacitor banks, modifications to transmission 

arrangements, and additional transmission supplies are planned to reinforce these local area 

supplies. Under Voltage Load Shedding (UVLS) has not been implemented and should not be 

needed if these planned facility additions are completed in a timely manner. 

The sub-region is not experiencing a drought and cooling water reservoirs are expected to be 

adequate due to heavy precipitation received this spring and early summer. Assessment studies 

to meet NERC Standards TPL 001 through 004, including both powerflow and stability studies 

have been performed by the larger members. No major reliability issues have been reported in 

these studies, which include transient dynamics, voltage, and small signal stability analyses. 

Members continue to evaluate the performance of their systems studies and upgrade those 

limiting areas to enhance reliability Members within the sub-region do not anticipate short 

circuit problems on their transmission systems. 

New equipment and techniques such as updating tie line metering, installing new Real Time 

Data Monitoring System (RTDMS) software, and installing phasor sensing devices are expected 

to continue within the next ten years as companies attempt to make improvements to improve 

reliability. Continued use of the phasor measurement equipment installed in various places on 

the transmission and interconnection system are expected to provide options to operations 

personnel in assessing immediate near-term conditions as well as provide data for disturbances 

experienced on the system. 
Regional Reliability Assessments

206 2008 Long-Term Reliability Assessment 

Sub-region members are also individually implementing programs to address aging infrastructure 

and spare equipment through coordinated transmission planning activities, and other programs. 

Some Gateway members have a limited number of spare transmission transformers and GSU 

transformers to minimize the outage time to portions of the transmission system and major power 

plant units. There are no anticipated reliability problems associated with these facility issues. 

Southeastern 

Demand

The 2008 summer net internal demand forecast for the Southeastern Sub-region is 48,215 MW 

and the forecast for 2017 is 60,156 MW. This year’s compound annual growth rate for 2008-

2017 is 2.49% for the sub-region. This is comparable to last year’s forecast growth rate of 2.4%. 

Demand forecast is based on normal weather conditions and uses normal/median weather, 

normal load growth and conservative economic scenarios. The sub-region has a mix of various 

demand response programs including interruptible demand, customer curtailing programs, direct 

load control (irrigation, A/C and water heater controls) and distributed generation to reduce the 

effects of summer peaks. To assess variability, some sub-region members develop forecasts 

using econometric analysis based on approximately 30 year (normal, extreme and mild) weather, 

economics and demographics. Others within the sub-region use the analysis of historical peaks, 

reserve margins and demand models to predict variance. 

Generation

Members in the Southeastern sub-region reported a range of various categories of capacity for 

the years 2008-2017. This capacity can be categorized as existing certain and uncertain, planned 

and proposed and is adequate to meet demand during this time period. The resources for 

reliability are evaluated by future power supply plans, purchased power through contracts, and 

self building options of generation. 

Table SERC-7: Southeastern LTRA Capacity Breakdown 

Capacity Type Year 2008 Year 2017 

Existing Certain 59,540 MW 62,611 MW 

 > Existing Certain Hydro 4,058 MW 4,058 MW 

Existing Uncertain 5,800 MW 5,800 MW 

Planned 0 MW 1,682 MW 

Proposed 0 MW 9,253 MW 

**No proposed capacity was reported within this sub-region. 

Purchases and Sales

Southeastern sub-regional members reported a range of firm sales and purchases for the years 

2008-2017. These sales and purchases are external and internal to the region and sub-region and 

help to ensure resource adequacy within the sub-region. The table below summarizes these 

transactions during this time period. 
Regional Reliability Assessments

207 2008 Long-Term Reliability Assessment 

Table SERC-8: Southeastern Sub-regional Sales/Purchases 

Transaction Type Year 2008 Year 2017 

Firm Sales (External: FRCC) 1,551 MW 0 MW 

Firm Sales (Internal) 931 MW 1,038 MW 

Firm Purchases (Internal) 408 MW 332 MW 

Members within the sub-region reported that some of these sales/purchases are backed by firm 

contracts for a mix of generation and transmission. None of these transactions are considered 

liquidated damages contracts (LDC). To ensure transmission during emergency conditions, the 

sub-region is not dependent on outside purchases or transfers to meet the demand and planning 

reserves. 

Fuel

Southeastern sub-regional members reported that fuel vulnerability is not an expected reliability 

concern for the study period. The members have a highly diverse fuel mix to supply its demand, 

including nuclear, PRB coal, Eastern coal, natural gas and hydro, along with dual fuel units. 

Some members have implemented fuel storage and coal conservation programs, and various fuel 

policies to address this concern. These tactics help to ensure balance and flexibility to serve 

anticipated generation needs. Coal fired generation comprises 41.7% of the total generation 

reported by sub-regional members. Other fuel types within the sub-region are 9.8% nuclear, 

29.9% oil/gas, 2.6% pumped storage, 6.8% hydro and 9.2% net sales and purchases. No fuel 

supply problems are anticipated during the study period. 

Transmission

For the next ten years, the Southeastern sub-region members have transmission plans or 

projections for 712 miles of 230 kV and 195 miles of 500kV. These plans consist of additions, 

retirements and conversions to the bulk transmission lines in this sub-region. The following 

table shows significant transmission additions to the bulk power system influencing reliability 

during the next ten years. 

The details of the transmission expansion plans and transformer additions are shown in the 

Major Transmission Projects > 200 kV section. 

Operational Issues 

No reliability, environmental or regulatory restrictions are anticipated on the transmission 

systems of the Southeastern sub-region. Members have reported that some hydro and other 

generation units will undergo major rehabilitation, but outages will be coordinated in such a way 

that system reliability and contractual commitments will not be affected. 

Reliability Assessment Analysis

Net capacity resource margins in the sub-region as reported between the years 2008-2017 are 

from 16.1% to 5.4% as shown in Figure SERC-6. There are no regional, or sub-regional, 

marginal requirements for this sub-region. Some members within the sub-region project 

capacity margins based on existing resources, unit retirements, expected firm purchases 

agreements and anticipated generation additions. Internal resources are expected to be adequate 
Regional Reliability Assessments

208 2008 Long-Term Reliability Assessment 

to meet the needs of the sub-region. Unit retirements within the sub-region total 1,006 and the 

majority (925 MWs) are scheduled to retire in the 2011-2013 period. 

Capacity in the sub-region should be adequate to supply forecast demand. There are no 

significant changes to LOLP, EUE, generation resource models and other resources adequacy 

studies that will affect margins. Various tactics are being used to ensure these resource adequacy 

measurements are within an acceptable range. Annual Transmission Transfer Capability, System 

Impact, and Facility studies are performed jointly with various members within the sub-region to 

determine external generation deliverability. Operating guides are developed as necessary to 

ensure acceptable transfer levels are reached. Some entities perform annual contingency analysis 

(studies typically covering up to ten future years) and biannual stability studies to ensure internal 

generation deliverability. Current studies have identified no deliverability concerns or major unit 

retirements expected to impact reliability. No significant changes are expected to come about in 

the next ten years. 

Southeastern Capacity Margin Comparison

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

30.0%

35.0%

40.0%

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Margin (%)

Existing & Net Firm Transactions Net Capacity Resources

Total Potential Resources Adjusted Potential Resources

Southeastern Potential M argin*

* The Southeastern Potential Margin line reflects the Southeastern subregion’s component of the SERC Annual Generation Plant 

Development Survey and includes under development and uncommitted generation resources, along w ith assumptions regarding 

generation availability and transmission deliverability

Figure SERC-6: 2008 NERC LTRA SERC Southeastern Sub-region – With Southeastern 

Potential Margin 

Various companies within the sub-region have firm transportation, gas storage, firm pipeline 

capacity, and on-site fuel oil and coal supplies to meet the peak demand. The sub-region has a 

very diverse fuel portfolio and implements fuel storage, sourcing, dual fuel capability units, and 

conservation programs. Using 90/10 forecast, some members show that planning reserves are 

adequate to meet weather and forecast uncertainty. Other members anticipate utilizing existing 

resources, energy purchases, and/or interruptible load shedding to maintain reliable operation of 

their transmission system in these more severe conditions. Variable resources are not included in 

these studies.
Regional Reliability Assessments

209 2008 Long-Term Reliability Assessment 

Studies to determine transmission needs for new resources in the next ten years are currently 

being performed by various members in the sub-region. Bulk transmission projects will be put 

into place with long lead times in order to accommodate any needed resources. Rapid forecasted 

load growth in the Metro Atlanta area will drive several 230 kV and 500 kV projects over the 

next ten year planning period. The Southeastern sub-region does not have sub-regional criteria 

for dynamics, voltage or small signal stability; however, various companies within the subregion maintain individual criteria and perform appropriate studies to address any stability 

issues. All systems are expected to be secure for the study period. 

Members are expected to address catastrophic events by contractual arrangements that amount to 

reserve sharing agreements, fuel supply diversity, interruptible load contracts, and excess 

reserves. Other members perform transmission studies considering loss-of-pipeline, extreme 

event (TPL-003 & 004), and infrastructure security studies. Studies are also conducted 

considering outages of up to three 500 kV lines within neighboring utilities. The purpose of all 

these is to assess vulnerability to catastrophic events and the development of appropriate 

mitigation plans. The general conclusion is that the system is capable of weathering many 

potential catastrophic events with minimal impacts on neighboring systems. 

Various areas are currently experiencing drought conditions; however recent weather 

assessments show significant improvement and this trend is expected to continue throughout 

2008. The sub-region members participated in the SERC regional drought assessment which did 

not identify significant reliability impacts from the drought. Although hydro generation is 

predicted to be lower than normal for the upcoming season, reliability will not be affected due to 

ready access to other generation sources. Members’ planning studies within this sub-region 

cover TPL-001 through TPL-004 to ensure adequate and compliant systems. No problems were 

cited for the next ten years and members stated that mitigation plans for previous problems are 

currently being addressed. 

Tools such as the installation of microprocessor based relays in transmission facilities, Dissolved 

Gas Analysis monitoring capabilities on Generator Step-Up transformers (GSUs), power flow 

analysis programs, and Static VAR Compensators have helped members take steps to improve 

the reliability and robustness of the system. Short circuit limits are assessed through fault current 

studies and exceeded limits are mitigated through breaker replacements, transient recovery 

voltage capacitors, and the installation of reactors. Aging infrastructure is addressed by 

equipment testing, maintenance programs and equipment replacements when it nears the end of 

its useful life. Members do not anticipate that planning or operational activities will be 

influenced by an aging infrastructure. Guidelines for on-site spare GSUs are implemented on an 

individual member basis within the sub-region. A variety of techniques such as maintaining a 

spare unit for all GSUs, programs for sharing spare transformers, and equipment loss programs 

are practiced by the sub-region to maintain equipment reliability. 

VACAR 

Demand 

The 2008 summer net internal demand forecast for the VACAR Sub-region is 61,103 MW and 

the forecast for 2017 is 72,100 MW. This year’s compound annual growth rate for 2008-2017 is 

1.86% for the sub-region. This is comparable to last year’s forecast growth rate of 1.8%. 
Regional Reliability Assessments

210 2008 Long-Term Reliability Assessment 

Members reported that peak growth rates are lower due to a slight economic decline and DSM 

reductions, but overall rates are comparable to last year’s rates. Demand forecast is based on 

averages of the latest 20 to 35 years of historical weather, forecast economic growth, and 

regressing demographics against system load. These tools are used to develop weather variables 

for forecasting peak demands. Some members reported that the demand forecast is based on a 

50-50 weather projection. The sub-region has a mix of various demand response programs 

including interruptible demand, customer curtailing programs, Standby Generator Control, 

Residential Time-of-Use, General Service and Industrial Time-of-Use, and Hourly Pricing for 

Incremental Load Interruptible programs to reduce the affects of summer peaks. To assess 

variability, some members within the sub-region use forecasts that are developed using 

assumptions through economic models, historical weather conditions, energy consumption and 

demographics. Others assess variability of forecast demand by accounting for reserve margins 

instead. 

Generation

Members in the VACAR sub-region reported a range of various categories of capacity for the 

years 2008-2017. This capacity can be categorized as existing certain and uncertain, planned and 

proposed and is adequate to meet demand during this time period. The resources for reliability 

are evaluated by future power supply plans, forward purchased power agreements with 

conventional and renewable resources, conservation programs, and self building options of 

generation. 

 

Table SERC-9: VACAR LTRA Capacity Breakdown 

Capacity Type Year 2008 Year 2017 

Existing Certain 72,934 MW 71,007 MW 

 Hydro 3,721 MW 3,730 MW 

 Biomass 225 MW 225 MW 

Existing Uncertain 2,005 MW 2,005 MW 

 Inoperable 65 MW 65 MW 

Planned 349 MW 3,009 MW 

Proposed 0 MW 3,298 MW 

Purchases and Sales

VACAR sub-regional members reported a range of firm sales and purchases for the years 2008-

2017. These sales and purchases are external and internal to the region and sub-region and help 

to ensure resource adequacy within the sub-region. The table below summarizes these 

transactions during this time period. 

Table SERC-10: VACAR Sub-regional Sales/Purchases 

Transaction Type Year 2008 Year 2017 

Firm Sales (External: RFC) 50 MW 0 MW 

Firm Sales (Internal) 200 MW 100 MW 

Firm Purchases (Internal) 1,538 MW 1,052 MW 

Provisional Purchases 

(Internal) 0 MW 753 MW 
Regional Reliability Assessments

211 2008 Long-Term Reliability Assessment 

Members within the sub-region reported that some of these sales/purchases are backed by firm 

contracts for a mix of generation and transmission. Very few transactions are considered 

liquidated damages contracts (LDC). To ensure transmission during emergency conditions, the 

sub-region is not dependent on outside purchases or transfers to meet the demand and planning 

reserves. 

Fuel

Fuel vulnerability is not a concern within this sub-region. The members have a highly diverse 

mix of options which consist of on-site storage, transportation alternatives and fuel contracts to 

ensure supply to its resources. Other mitigation plans generally involve tiered strategies that are 

invoked depending on the severity of the situation. This guidance on managing fuel in short 

supply has been formalized in procedures as required by NERC Reliability Standards. These 

tactics help to ensure balance and flexibility to serve anticipated generation needs for the 

upcoming season. The sub-region has 26.1% of coal fired generation, 31.5% dual fuel (gas/oil), 

2.7% oil, 2.0% gas, 8.1% pumped storage, 5.1% hydro, and 2.7% other and net sales and 

purchases. No fuel supply problems are anticipated during the study period. 

Transmission

For the next ten years, the VACAR sub-region has new transmission plans for 697 miles of 230 

kV and 185 miles of 500kV. These plans consist of additions, retirements and conversions to the 

bulk transmission lines in this sub-region. The following table shows significant transmission 

additions to the bulk power system influencing reliability during the next ten years. 

The details of the transmission expansion plans and transformer additions are shown in the 

Major Transmission Projects > 200 kV section. 

Operational Issues 

For the next ten years members within the VACAR sub-region intends to perform capital 

improvements, routine and major maintenance activities, but are anticipated to be scheduled 

during lower demand periods (spring and fall). These outages are not expected to affect its 

system reliability during this time period. The sub-region also plans to add approximately 834 

MW from 2012 through 2018 in the form of contracts and/or generation. Some of these 

additions are to replace expiring contracts. They too are not expected to cause a major deviation 

from the current reliability levels as a result of these additions. Some members also expected to 

slightly reduce generation due to the installation of scrubbers to fossil units due to North 

Carolina Clean Smokestacks legislation. Operating licenses are expected to have some 

restrictions if the drought in the area continues to limit peaking capacity for long durations. 

Although all of these environmental factors are issues within the sub-region, members are not 

predicting that these issues will have major impacts on reliability.

Reliability Assessment Analysis

Net capacity resource margins in the sub-region as reported between the years 2008-2017 are 

from 18.1% to 3.8% as shown in Figure SERC-7. There is no regional, sub-regional, state or 

provincial marginal requirement for this sub-region. Some members within the sub-region 

project capacity margins based on long-term planning tools which considers a combination of 

weather-induced load, the probability of units on outage, maintenance scheduling, and operating 

reserve obligations, resource adequacy studies and system reserve margins. Others rely on loss 
Regional Reliability Assessments

212 2008 Long-Term Reliability Assessment 

of load expectation studies to continue to guide the level of reserves maintained to ensure 

reliable service. To assess resource adequacy, some members have conducted studies and have 

determined that LOLP, LOLE and EUE figures are comparable to those for the previous year’s 

study. These studies may include estimates of the impacts of forced and planned outages on the 

system operation. Other members use reserve margins to account for worse-case scenarios with 

unavailability. However, members have reported that there are no significant changes from last 

year’s assessment that will impact reliability. 

VACAR Capacity Margin Comparison

-5.0%

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

30.0%

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Margin (%)

Existing & Net Firm Transactions Net Capacity Resources

Total Potential Resources Adjusted Potential Resources

VACAR Potential M argin*

* The VACAR Potential Margin line reflects the VACAR subregion’s component of the SERC Annual Generation Plant Development Survey 

and includes under development and uncommitted generation resources, along w ith assumptions regarding generation availability and 

transmission deliverability

Figure SERC-7: 2008 NERC LTRA SERC VACAR Sub-region – With VACAR Potential Margin 

The retirement of approximately 1,000 MW of older coal-fired capacity by the end of 2018, 

along with the retirement of 500 MW of older combustion turbines by 2015 are expected to 

affect the sub-regions resources over the next ten years. Companies are prepared to mitigate this 

issue by implementing Integrated Resource Plans to determine new resource requirements over 

the next ten years. To ensure generation deliverability, some members use deliverability load 

test as a requirement for new generation that will serve load in their system. These tests ensure 

that all new generation is accessible for the supply of load. Other members within the sub-region 

rely on contracts for fuel and transportation, operating limits and security constraints to ensure 

their deliverability. Fuel supplies are expected to be adequate. Members have a very diverse 

mix of suppliers, transportation contracts, fuel switching plants and on-site storage to ensure 

adequacy of fuel supply. No fuel supply or delivery issues are expected for this study period. 

Adequate reserve capacity is maintained in various ways to address resource availability issues 

(contracts, existing resources, etc.). In addition, members participate in a VACAR reserve 

sharing agreement whereby VACAR members supply emergency power to other members upon 

request. Other companies are evaluating the economics and impacts of potentially adding large 

baseload generation facilities by 2018 or later. To ensure resource adequacy against operational 

issues due to unexpected conditions, members implement emergency procedures such as Primary 

Reserve Warnings, Maximum Emergency Generation, Emergency Load Response programs, 

excess reserve programs, DSM, interruption of firm load, load forecasting tools, and reserve 
Regional Reliability Assessments

213 2008 Long-Term Reliability Assessment 

sharing groups. The members within this sub-region are divided in how they count renewable 

resources within their studies. Some members include them in their models as a design capacity 

value and others prefer to not include them in capacity counted on for resource adequacy. 

VACAR members report no major transmission additions or specific deliverability problems 

from generation centers that could impact reliability. 

Members within the VACAR sub-region are involved in studies performed by SERC Study 

Groups and interregional reliability assessments conducted under the direction of the ERAG 

Management Committee. These studies analyze transfer capability problems and constraints 

throughout the sub-region. No constraints to the bulk electric system for the study period was 

identified that could impact reliability. The VACAR sub-region does not have a sub-regional 

criterion for dynamics, voltage and small signal stability. Various companies within the subregion perform individual studies in accordance with NERC Reliability Standards and maintain 

individual criterion to address any problems with these stability issues. The sub-region does not 

predict any stability issues that will impact reliability. 

To mitigate catastrophic events, VACAR members use various options such as firm purchased 

power sources, excess reserve margins, membership in reserve sharing agreements, as well as 

fuel source diversity. Companies have also formed Emergency Action Plans for Power System 

Disasters to provide a systematic and effective means of restoring power systems within the subregion. Members report that they have experienced a drought and are expecting conditions to 

continue for the upcoming summer 2008 season. These conditions have caused substantial 

constraints on hydro operations. However, coupled with other resources, projected hydro 

generation and reservoir levels are expected to be adequate to meet both normal and emergency 

energy demands for the 2008 summer. Members within the sub-region are also monitoring 

drought conditions through studies to assess the expected severity and its impact on the system. 

TPL-001 through TPL-004 are commonly studied throughout the sub-region. Companies 

implement these studies internally and coordinate externally with neighboring companies. 

Members report very little problems from the results of the studies. Problems that were reported 

showed that companies needed to address line loadings (mitigated through operating guides) and 

line outages that will restrict units. Operating procedures are being put in place to address these 

issues so that reliability will not be impacted during the upcoming years. Improved SCADA 

systems with real-time analysis tools, small signal stability analysis tools, transient stability 

programs, static VAR compensators are all tools that are being evaluated and purchased within 

the sub-region to improve reliability. Members are individually evaluating plans to assess and 

limit short circuit levels. Various companies evaluate equipment design limits and use a variety 

of solution options such as equipment replacements, system reconfigurations, and the 

installations of reactors to manage problematic locations. Programs are also implemented 

around the sub-region to address aging infrastructure. Programs such as maintenance programs, 

transmission projects, asset management programs, and redundancy programs all help companies 

to assess their systems for improvement. The sub-region also has individual guidelines for spare 

GSUs and autotransformers. Members use various practices such as membership in spare 

equipment programs and replacement programs to address the issue. 
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214 2008 Long-Term Reliability Assessment 

Region Description 

The SERC Region is a summer peaking region covering all or portions of 16 central and 

southeastern states. Owners, operators, and users of the bulk power system in these states cover 

an area of approximately 560,000 square miles. The SERC Reliability Corporation (SERC) is 

the regional entity for the region and is a nonprofit corporation responsible for promoting and 

improving the reliability, adequacy, and critical infrastructure of the bulk power supply system. 

SERC membership includes 63 member entities consisting of publicly owned (federal, municipal

and cooperative), investor owned operations. In the SERC Region there are 31 balancing 

authorities and over 200 registered entities under the NERC functional model. 

SERC serves as a regional entity with delegated authority from NERC for the purpose of 

proposing and enforcing reliability standards within the SERC Region. SERC is divided 

geographically into five sub-regions that are identified as Central, Delta, Gateway, 

Southeastern, and VACAR. Additional information can be found on the SERC Web site

(www.serc1.org)
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215 2008 Long-Term Reliability Assessment 

SPP Highlights 

The annual net capacity margin for SPP is greater than the 

required 12 percent until the year 2014, where the margin 

drops to 11.5 percent. The resources internal and external to 

the SPP region that are needed to meet the required 12% 

capacity margin based on the 2013 forecast total 53,860 MW 

and 2,789 MW respectively. For the remaining years (2014 

through 2017), SPP anticipates more resources will be 

qualified as certain and can be counted against capacity 

margin in the next few years. 

These capacity margin projections include the effects of demand–side response programs, such 

as direct–control load management and interruptible demand. Currently SPP does not have 

specific demand response program. However, according to SPP’s Strategic Plan, SPP has 

established a Center of Excellence (COE) to leverage collective knowledge and provide member 

areas including conservation and efficiency (IRP, DSM). In the meantime, over the next ten 

years, interruptible demand relief is expected to increase from 487 MW to 529 MW. Also, SPP 

anticipates that programs initiated by its state regulators, members and other parties coupled with 

an expansion of energy markets will bring Demand Resources to an increasing point of greater 

significance. 

The SPP Transmission Expansion Plan 2008-2017 reported approximately $2.2 billion of 

transmission network upgrades for the years 2008 through 2017. Network upgrades identified in 

the near term four year horizon, approximately $762 Million, were approved by the SPP Board 

of Directors (BOD) with issued Notifications to Construct. They are specifically needed for 

reliability and these network upgrades have a financial commitment lead time falling inside the 

2008 through 2011 four year commitment window. 

In addition to the STEP plan, SPP has also conducted a EHV Overlay study. The objective of 

this study is to develop a long range strategic assessment of the reliability, capacity and seams 

integration needs of the grid through the use of 345kV, 500kV and 765kV or higher transmission 

improvements. The study considered four design options to meet these objectives ranging from 

$6.9 Billion to $7.1 Billion. All these options evaluated the combination of 765 and/or 500-345 

kV option. 

SPP as a Planning Authority conducts various reliability assessments to comply with NERC TPL 

standards and coordinate the mitigation effort with its members. Based on the studies performed, 

SPP is not anticipating any near-term or long-term reliability issues that have not addressed by 

any mitigation plan or local operating guides 

The penetration of wind generation in the western half of SPP footprint could have a significant 

impact on operations due to the variable nature of this type of resource. SPP is in process of 

scoping wind integration and penetration study that will help address market/operations and 

planning needs associated with additional wind development in the region. 
Regional Reliability Assessments

216 2008 Long-Term Reliability Assessment 

SPP - Summer Capacity Margin Comparison

-5%

0%

5%

10%

15%

20%

25%

30%

35%

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Margin (%)

Region/Subregion Target Margin Existing Certain

Net Capacity Resources Adjusted Potential Resources

Total Potential Resources

SPP - Projected On-Peak Capacity by Fuel-Mix

0

5,000

10,000

15,000

20,000

25,000

Gas

Coal

Dual Fuel

Hydro

Undetermined/Unknown

Nuclear

Oil

Pumped Storage

Wind

Other

MW

2008

2017
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217 2008 Long-Term Reliability Assessment 

SPP Capacity vs Demand - Summer

30

35

40

45

50

55

60

65

70

1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016

Thousands of MW

Historic

Demand

High

Demand

Projection

Low

Demand

Projection

Adjusted

Potential

Resources

Net

Capacity

Resources
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218 2008 Long-Term Reliability Assessment 

SPP Self Assessment 

Southwest Power Pool (SPP) continues to anticipate consistent growth in demand and energy 

consumption over the next ten years. Significant generation capacity using uncommitted 

resources is forecasted in SPP to be available throughout the planning horizon to meet native 

network load needs with committed generation resources meeting minimum capacity margins 

until 2014. 

Demand 

According to the most recent data, the projected annual rate of growth for peak demand in the 

SPP region over the next ten years is 1.7 percent, from 43,167 MW in 2008 to 50,640 MW in 

2017. This is consistent to the 2007 LTRA ten–year (2007–2016) forecasted growth rate of 1.7 

percent. 

For the 2008–2017 timeframe, the projected annual rate of growth for energy consumption in the 

SPP region is 1.5 percent, from 208,532 GWh in 2008 to 246,409 GWh in 2017. This is slightly 

less as compared to the previously forecasted growth rate of 1.8 percent. 

Each SPP member annually provides a ten–year forecast of peak demand and net energy 

requirements. The forecasts are developed in accordance with generally recognized methods and 

in accordance with the following principles: 

 Each member selects its own demand forecasting method and establishes its own forecast. 

 Each member forecasts demand based on expected weather conditions. In the case of 

extreme weather, peak demand would be increased by approximately 2.9 percent. 

 Methods used, factors considered, and assumptions made are submitted along with the 

annual forecast to SPP. 

 Economic, technological, sociological, demographic, and any other significant factors are 

considered when producing the forecast. 

The resultant SPP forecast is the total of the member forecasts. High and low growth rates and 

unusual weather scenario bands are then produced for the SPP regional demand and energy 

forecasts. As such, SPP criteria require that members maintain a 12 percent capacity margin, unless 

their system is primarily hydro–based where the required margin is lowered to 9 percent. This 

requirement ensures to cover any variation in the load forecast along with maintaining resource 

adequacy within the SPP footprint. 

Although actual demand is very dependent upon weather conditions and typically includes 

interruptible loads, forecasted net internal demands used for assessing net capacity margins are 

based on normal weather conditions and do not include interruptible loads. 

These capacity margin projections include the effects of demand–side response programs, such 

as direct–control load management and interruptible demand. Currently SPP does not have 
Regional Reliability Assessments

219 2008 Long-Term Reliability Assessment 

specific demand response program. However, according to SPP’s Strategic Plan174, SPP has 

established a Center of Excellence (COE) to leverage collective knowledge and provide member 

areas including conservation and efficiency (IRP, DSM). In the meantime, over the next ten 

years, interruptible demand relief is expected to increase from 487 MW to 529 MW. Also, SPP 

anticipates that programs initiated by its state regulators, members and other parties coupled with 

an expansion of energy markets will bring Demand Resources to an increasing point of greater 

significance. 

To quantify peak demand uncertainty and variability due to extreme weather, economic 

conditions, and other variables an analysis of our region has been completed by the Bandwidth 

Working Group. The outcome of this report175 supports the current predicted growth rates and 

allows for up to a 1.2 percent variation in current and future predictions through the year 2012. 

SPP anticipates this trend will continue for the remaining study period. 

Generation 

For the 2008-2017 assessment period, SPP projects it will have 47,151 MW towards Existing 

Certain Capacity; 9,892 MW Existing Uncertain Capacity; 5,849 MW Planned Capacity and 

2,758 MW of Proposed Capacity resources that are either in-service or are expected to be inservice. The Existing Certain Capacity amount portions that are from variable plants are 194 

MW (Wind), 3,045 MW (Hydro), and 365 MW (Biomass). Existing Uncertain Capacity amount 

portions that are from variable plants (mostly wind) is 976 MW. Planned Capacity for 2017 that 

are from variable plants (mostly wind) is 150 MW. At present, SPP relies on their members to 

submit the generation output (including variable) towards certain capacity based on the historical 

and the actual test data. This data gets routinely scrutinized by SPP staff for accuracy and an 

internal supply adequacy audit is conducted every five years to verify and document all the 

historical as well as test data for all the resources. 

Purchases and Sales 

A small portion of SPP’s capacity margin comes from the purchases from other regions. The 

transactions for the 2008-2017 assessment period are 2,149 MW (this is a ten year average) that 

is purchased from other regions. Based on a ten year average (2008-2017), 1960 MW of these 

purchases are firm, and 189 MW is firm delivery service from WECC administered under Xcel 

Energy’s OATT. None of the purchase contracts are Liquidated Damage Contracts. 

SPP has a total of 1,550 MW of firm sales to regions external to SPP. None of the sales contracts 

are Liquidated Damage Contracts. 

SPP members along with neighboring entities like Entergy from the SERC region have formed a 

Reserve Sharing Group. The members of this group receive contingency reserve assistance from 

other SPP Reserve Sharing Group members. The SPP’s Operating Reliability Working Group 

will set the Minimum Daily Contingency Reserve Requirement for the SPP Reserve Sharing 

Group. The SPP Reserve Sharing Group will maintain a minimum first Contingency Reserve 

equal to the generating capacity of the largest unit scheduled to be on-line. 

 

174 http://www.spp.org/section.asp?pageID=83 175 The Demand and Energy Bandwidth Report is located here (http://www.spp.org/publications/BWG_Report_2003.pdf ). 
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220 2008 Long-Term Reliability Assessment 

Fuel 

SPP monitors potential fuel supply limitations by consulting with its generation owning and 

controlling members at the beginning of each year. Presently, there are no known infrastructure 

issues which could affect fuel deliverability as SPP is blanketed by major pipelines and railroads 

to provide an adequate fuel supply. In addition, coal and natural gas power plants, which make 

up approximately 48% and 44% of total generation respectively, are required by SPP criteria to 

keep sufficient quantities of standby fuel in the case of deliverability issues. As previously stated, 

because hydro capacity is a small fraction of capacity for the region, run–of–river hydro issues 

brought about by extreme weather are also not expected to be critical. 

Transmission 

The SPP Transmission Expansion Plan 2008-2017176 reported approximately $2.2 billion of 

transmission network upgrades for the years 2008 through 2017. Network upgrades identified in 

the near term four year horizon, approximately $762 Million, were approved by the SPP Board 

of Directors (BOD) with issued Notifications to Construct. They are specifically needed for 

reliability and these network upgrades have a financial commitment lead time falling inside the 

2008 through 2011 four year commitment window. 

SPP is committed to perform all necessary analysis in an effort to determine need, cost, and 

benefits supporting the state regulatory requirements of its members which are necessary to 

substantiate funding of each member share of identified network upgrade cost responsibility. 

The following pie chart summarizes the near-term network upgrades in SPP Footprint: 

 

176 http://www.spp.org/publications/2007%20SPP%20Transmission%20Expansion%20Plan%2020080131_BOD_Public.pdf 

Near-Term Network Upgrade Breakdown

Total $762 Million

Transformers

22%

Caps/Reactive Device

5%

New Lines

40%

Line Rebuild/ Upgrades

24%

Substation Upgrade

2%

Voltage Conversion

7%

Line Rebuild/ Upgrades New Lines Voltage Conversion

Substation Upgrade Transformers Caps/Reactive Device
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221 2008 Long-Term Reliability Assessment 

The specific list of these network upgrades (transmission lines and transformers) is included in 

the NERC master list of upgrades. 

In addition to the STEP, SPP has recently completed an updated EHV Overlay Study in the 

beginning of 2008. 

The objective of the SPP EHV Overlay Study is to develop a long range strategic assessment of 

the reliability, capacity and seams integration needs of the grid through the use of 345kV, 500kV 

and 765kV or higher transmission improvements. The study was updated to evaluate the effect 

of intensifying wind development activity in portions of the SPP system on the EHV 

recommendation that was developed in the previous EHV Overlay Study conducted in the spring 

of 2007. This updated EHV Overlay Study also incorporated recent decisions regarding the 

development of certain lines in the western portion of the SPP X-plan 

The study considered four design options to meet these objectives ranging from $6.9 Billion to 

$7.1 Billion. All these options evaluated the combination of 765 and/or 500-345 kV option. It 

was determined that all of the designs provide SPP, its members and its stakeholders improved 

reliability for the SPP electric system while providing the ability to be a key provider of 

renewable energy for the Eastern Interconnection. All designs are flexible and allow for 

alternative interconnections to the east and for the wind collector system based upon cost, 

summer peak performance, export capability and losses, “Mid Point Design 2” and “Mid Point 

Design 4” were the top two performing options. Both terminate at the same substations for the 

EHV Overlay loop. The details of this study results can be found in the final study report which 

is available on SPP website.177

 

Operational Issues 

The penetration of wind generation in the western half of SPP footprint could have a significant 

impact on operations due to the variable nature of this type of resource. There are currently 

several avenues being explored to provide transmission outlets for this energy during the next ten 

years such as the EHV overlay or facilities resulting from the Joint Coordinated System Plan 

(JCSP). However, the operational impacts to regulation and control performance that the 

variable generation will cause are still unknown. As the penetration rate of variable generation 

grows, further study will be required to mitigate any issues that arise. SPP is in process of 

scoping wind integration and penetration studies that will help address market/operations and 

planning needs associated with additional wind development in the region. 

At this time, there are no known existing or upcoming environmental or regulatory restrictions 

that are thought to cause any impact to reliability. SPP has a substantially diverse mix of 

generation capacity and a sufficient expected capacity margin such that no reliability impacts are 

foreseen. 

Reliability Assessment Analysis 

For the 2008–2017 assessment period, the current EIA–411 data indicates that SPP members 

maintain a 14.1 percent net capacity margin in 2008 down, and this margin will decrease to 8.1% 

 

177 http://www.spp.org/publications/Quanta_Technology_March_2_2008_Update_to_the_EHV_Study_Final_Report.pdf
Regional Reliability Assessments

222 2008 Long-Term Reliability Assessment 

percent in 2017. Based on the Bandwidth Working group report, SPP’s load may vary by 

approximately 1.2% due to a 90/10 type of weather scenario. As mentioned before, SPP requires 

each member to maintain 12% capacity margin and this will address the 90/10 weather scenario. 

On the whole, the annual net capacity margin for SPP is greater than the required 12 percent until 

the year 2014, where the margin drops to 11.5 percent. The resources internal and external to the 

SPP region that are needed to meet the required 12% capacity margin based on the 2013 forecast 

total 53,860 MW and 2,789 MW respectively. For the remaining years (2014 through 2017) SPP 

anticipates more resources will be qualified as certain and can be counted against capacity 

margin in the next few years. 

SPP defines firm deliverability as electric power intended to be continuously available to the 

buyer even 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 contracts 

towards this category 

There are no significant deliverability problems expected due to transmission limitation at this 

time on the SPP system, However, on June 17, 2008, the western portion of the SPP footprint 

has experienced a system disturbance that resulted in loss of 600 MW load. In addition, SPP’s 

EIS market continues to experience price differentials between eastern and western portion of the 

SPP system. SPP will continue to closely monitor the western portion of the system through the 

Flowgate assessment analysis. The flowgate analysis validates the list of flowgates that SPP 

monitors on a short term basis using various scenario models developed by the SPP Staff. These 

scenario models reflect all the potential transactions in various directions being requested on SPP 

system. The results of this study are reviewed and approved by SPP’s Transmission Working 

Group prior to summer and winter of each study year. 

Also, SPP periodically conducts Loss-of-Load Expectation and Expected Unserved Energy 

study. The preliminary results of the ongoing study triggers additional assessment for the western 

portion of SPP system that includes a sensitivity of wind penetration. The final study is expected 

to be completed by end of 2008. Historically, SPP has adhered to a 12% regional capacity 

margin to ensure the minimum LOLE of 1 day in 10 years is met. Presently the 12% capacity 

margin requirement (both short-term and long-term) is checked annually in the EIA-411 

reporting as well as through supply adequacy audits of regional members. The last supply 

adequacy audit was conducted in 2007 and the subsequent audit is scheduled in 2012. 

SPP develops an annual SPP Transmission Expansion Plan (STEP) with regional group of 

projects to address regional reliability needs for the next 10 years (2008 through 2017). The 

latest STEP that was approved by SPP Board of Directors is available on SPP website. During 

the STEP process, SPP also performs a dynamic stability analysis. The latest dynamic study that 

was completed for the 2008 operating conditions did not indicate any dynamic stability issues for 

the SPP region. In addition, SPP also performs an annual review of reactive reserve 

requirements for load pockets within the region. Currently, SPP does not have specific criteria 

for maintaining minimum dynamic reactive requirement or transient voltage dip criteria. 
Regional Reliability Assessments

223 2008 Long-Term Reliability Assessment 

However, according to reactive requirement study scope, which is completed as a STEP process, 

each load pocket or constrained area was studied to determine the available reactive reserve 

margin in the SPP transmission system during possible severe contingencies. This study assumes 

typical P-V curve characteristic where possible voltage collapse is studied when the voltage on 

the key buses start declining below 90%. The annual STEP process conducted by SPP did not 

indicate dynamic and static reactive power limited areas on the bulk power system. 

SPP has an under-voltage load shedding (UVLS) program in the western Arkansas area within 

the AEP-West footprint. This program targets about 180 MW of load shed during the peak 

summer conditions to protect bulk power system against under-voltage events. 

The significant changes from last years LTRA includes the SPP capacity margin 12% forecasted 

to fall below the target level in 2013. This was forecasted not to happen until 2016 in the 2007 

LTRA due to the fact that more capacity was considered to calculate capacity margin. SPP 

members have adjusted their forecast based on the new definition of Certain capacity this year 

that results into a decrease in capacity margin during 2013 and beyond. However, in the next 

few years, SPP anticipates a significant portion of wind capacity to be added in the SPP footprint 

in the western part of the footprint. Although these are predominantly energy only resources and 

only a small portion (0 -20%) of this capacity will be counted as Certain based on the historical 

trend, it would be sufficient to meet SPP’s capacity margin requirement. There are no major unit 

retirements that are planned within the next ten years. 

Due to the diverse generation portfolio in SPP, there is no concern of the fuel supply being 

affected by the extremes of summer weather during peak conditions. If there is to be a fuel 

shortage, it is communicated to SPP operations staff, in advance, so that they can take the 

appropriate measures SPP would assess if capacity or reserves would become insufficient due to 

the unavailable generation. If so, SPP would declare either EEA (Energy Emergency Alert) or 

OEC (Other Extreme Contingency) and post as needed on the RCIS (Reliability Coordinator 

Information System). SPP does not conduct operation planning study to evaluate the extreme hot 

weather condition. The current capacity margin criteria are intended to address the load forecast 

uncertainty. 

Energy only, uncommitted resources and transmission–limited resources are not used in 

calculating net capacity margin. As previously stated, the EIA–411 data does not include the 

9,892 MW of uncommitted resources that are located within the SPP footprint. These are 

reflected in the total potential resources capacity margin which is considerably greater than the 

net capacity margin. SPP staff coordinates the specific short circuit level with its members as 

they maintain all the latest data for the assessment period. SPP is in a process of developing a 

coordinated short circuit model in the later half of 2008 so that these studies can be conducted on 

a regional basis. There are no reliability impacts that have been addressed due to aging 

infrastructure and at this time SPP does not have any guideline for on-site, spare-generator stepup (GSU) and auto transformers. 
Regional Reliability Assessments

224 2008 Long-Term Reliability Assessment 

SPP as a Planning Authority conducts various reliability assessments to comply with NERC TPL 

standards: 

• TPL-001 - SPP Model Development Working Group (MDWG) ensures that all thermal 

and voltage violation addresses during Base Case development. 

• TPL-002 - Using the SPP MDWG Models, Near and Long Term Analysis are performed 

by SPP staff. 

• TPL-003 - SPP members submit selected N-2 contingencies that are evaluated by SPP 

staff. 

• TPL-004 - SPP periodically conducts reactive reserve and stability study that addresses 

the key requirement in this standard. 

Based on the studies performed, SPP is not anticipating any near-term or long-term reliability 

issues that have not addressed by any mitigation plan or local operating guides. 

SPP has been proactive in addressing aging workforce issue in the utility industry. Since last 

year, SPP has sponsored a new graduate level course in Electric Power System at the University 

of Arkansas, Little Rock. This course focuses on the power system fundamentals with a final 

project targeting current industry issue. The students at the university along with SPP employees 

new to the power system concepts are encouraged to take this course. Also, SPP has initiated an 

“Engineer In Training” program in 2007. This 18 month program targets top performing students 

in local universities and have them rotated in various functional areas before permanent 

placement and assigned with specific role. 

Region Description 

Southwest Power Pool (SPP) region covers a geographic area of 255,000 square miles and has 

members in eight states: Arkansas, Kansas, Louisiana, Mississippi, Missouri, New Mexico, 

Oklahoma, and Texas. SPP manages transmission in seven of those states. SPP’s footprint 

includes 17 balancing authorities and 40,364 miles of transmission lines. SPP has 50 members 

that serve over 4.5 million customers. SPP’s membership consists of 13 investor–owned utilities, 

11 generation and transmission cooperatives, 11 power marketers, 7 municipal systems, 3 

independent power producers, 2 state authorities, and 2 independent transmission companies. 

Additional information can be found on the SPP Web site (www.spp.org). 
Regional Reliability Assessments

225 2008 Long-Term Reliability Assessment 

WECC Highlights

• WECC loads are growing — the projected 2008 summer total 

internal demand of 162,052 MW is expected to increase by 

about 2.0 percent per year to 193,530 MW in 2017. 

• Planning reserve margin targets (target margins) used for this 

report were developed using a Building Block method. These 

target margins ranged between 10 and 16%, with a WECC 

overall average of 13.7% (summer) and 12.6% (winter). The 

equivalent capacity margins are 12.1% and 11.2%, respectively. By 2017, reserve margins 

for the majority of the WECC subregions are below target margins, when using the existing 

plus planned resource or adjusted potential resource mix. 

• The WECC target margins are in addition to serving the total load (both firm and non-firm 

loads). 

• Neither the summer nor the winter analysis for the Northwest subregion fully captures the 

limitations on the ability of the Northwest hydro system to sustain output levels beyond a 

single hour. 

• Resource surpluses or deficits, aggregated into several WECC subregions (four U.S., one 

Canadian and one Mexican), are reported in graphs comparing loads with existing plus future 

resources. Descriptions of the classes of resources are provided in the generation section, 

Class 4 is highlighted here because it contains resources that had been identified as having 

been approved by corporate management or in a company’s capital budget but did not meet 

WECC’s criteria for “Planned”, but Class 4 resources may meet a section of the NERC 

criteria for being “Planned” resources. 

• The summer peak MW amounts of each of the five classes and the existing certain 

resources178 (existing resources), are summarized in the following table: 

Existing 

Resources 

“Planned” Resources “Proposed” Resources Adjusted Proposed 

Resources 

As of 12/31/2007 Class 1 Class 2 Class 3 Class 4 Class 5 Class 4 Class 5 

194,836 8,146 713 2,582 7,286 7,425 0 0 

(Summer Rating) Total Planned = 11,441 MW Proposed = 14,711 MW Adj. Proposed = 0 MW 

The Proposed resources or the Adjusted Proposed resources would be in addition to the 

Existing and Planned resources. 

• There are several Class 4 and 5 (Proposed) projects that are short lead projects (primarily 

wind generation projects), that require only a short time for construction. These projects 

could contribute to serving loads sooner than their classification would indicate, which would 

increase the margins of the respective subregion(s). 

• Diversity exchange transfers among subregions, as constrained by derated transmission, are 

assumed to meet deficits against the target margins. These transfers were submitted to 

NERC as Expected179 transactions and were derived from WECC’s draft 2008 Power Supply 

 

178 NERC definition – See Appendix III Capacity and Demand Definitions 179 NERC definition – See Appendix III Capacity and Demand Definitions 
Regional Reliability Assessments

226 2008 Long-Term Reliability Assessment 

Assessment (PSA). The net capacity resources line in the margin graphics includes these 

transfers and transmission modeled losses. 

• This analysis does not include the “Proposed” resources other than to reflect the quantity in 

the “Total Potential Resources” line in the margin graphics and some tables. This approach 

was taken as the regulatory and financial status of these projects is not known at this time. 

WECC intends this representation to highlight the importance of investment in the future. 

Resources, either currently identified or unknown, need to move deliberately into 

development as deficits approach and as project development timelines dictate. 

• When only considering “planned” resources and transfers, the Northwestern Power Pool - 

Canada subregion goes below the WECC developed target margin for that subregion, as early 

as the winter of 2009-2010. One of the NWPP-CN provinces has indicated that there are 

several short lead projects that have been classified by WECC as class 4 or 5 that are 

scheduled to be in-service by the winter of 2009-2010. It is anticipated that with those 

projects the NWPP-CN margin will be close to the target margin for that subregion. 

• By the summer of 2017, the difference between WECC’s Net Capacity Resources (202,379 

MW) and WECC’s Total Internal Load (193,530 MW) would be 8,849 MW (4.6% reserve 

margin), if there were no transmission constraints. This would be 17,054 MW below the 

desired target margin. This included serving 4,898 MW of Demand-Side-Management 

(DSM) load. If the DSM load were not to be served it would result in a 7.3% reserve margin. 

When looking at subregions, or a region overall, it may be a concern to only consider the Net 

Internal Demand (Total Internal Demand minus DSM programs) when determining margins, 

because the DSM programs are generally not sharable between balancing authorities, 

subregions or regions, some have a limited number of times they can be called upon and 

some can only be called upon during a declared emergency. 

• Margin results from the PSA were used to derive expected inter-subregion transfers. In the 

PSA, conservative transmission limits were placed on paths between the 26 PSA load 

groupings (bubbles) and were observed when calculating the transfers between these bubbles. 

The aggregation of PSA load bubbles into LTRA reporting subregions may obscure 

differences in adequacy or deliverability between bubbles in the subregion. Deficits below 

planning reserve targets (while serving total load) begin to emerge toward the end of this 

decade. Including Classes 1 through 3, summer electricity supply shortages relative to 

planning summer reserve targets could occur as early as 2010 in the desert southwest, and 

Mexico area and winter electricity supply shortages relative to planning winter reserve 

targets could occur as early as 2009-2010 in Canada as mentioned above. 

• The analysis is based on loads and resources data submitted in December 2007 and February 

2008. The reported data was “locked” on March 31, 2008, and project changes reported to 

WECC after the data was locked were not included in the studies. For instance, it does not 

appear that the two Holcomb coal plants that were reported by WACM will be constructed 

by the time reported. However, this was learned after the data was locked and the effects of 

the Holcomb units can be seen in the RMPA area. Salt River Project in the AZ-NM-SNV 

subregion has announced plans for several natural gas generating units, but these additions 

were announced after the data was locked and were therefore not included in this study, in 

order to be consistent with other studies that are being performed. 
Regional Reliability Assessments

227 2008 Long-Term Reliability Assessment 

WECC - Summer Capacity Margin Comparison

0%

5%

10%

15%

20%

25%

30%

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Margin (%)

Region/Subregion Target Margin Existing Certain

Net Capacity Resources Adjusted Potential Resources

Total Potential Resources

WECC - Projected On-Peak Capacity by Fuel-Mix

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

Gas

Hydro

Coal

Dual Fuel

Nuclear

Pumped Storage

Geothermal

Wind

Oil

Other

MW

2008

2017
Regional Reliability Assessments

228 2008 Long-Term Reliability Assessment 

WECC-US - Summer Capacity Margin Comparison

0%

5%

10%

15%

20%

25%

30%

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Margin (%)

Region/Subregion Target Margin Existing Certain

Net Capacity Resources Adjusted Potential Resources

Total Potential Resources

WECC US Capacity vs Demand - Summer

90

100

110

120

130

140

150

160

170

180

190

1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016

Thousands of MW

Historic

Demand

High

Demand

Projection

Low

Demand

Projection

Adjusted

Potential

Resources

Net

Capacity

Resources
Regional Reliability Assessments

229 2008 Long-Term Reliability Assessment 

WECC-Canada - Winter Capacity Margin Comparison

-20%

-15%

-10%

-5%

0%

5%

10%

15%

20%

25%

30%

2008/09

2009/10

2010/11

2011/12

2012/13

2013/14

2014/15

2015/16

2016/17

2017/18

Margin (%)

Region/Subregion Target Margin Existing Certain

Net Capacity Resources Adjusted Potential Resources

Total Potential Resources

WECC CANADA Capacity vs Demand - Winter

10

15

20

25

30

1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016

Thousands of MW

Historic

Demand

High

Demand

Projection

Low

Demand

Projection

Adjusted

Potential

Resources

Net

Capacity

Resources
Regional Reliability Assessments

230 2008 Long-Term Reliability Assessment 

WECC-AZ-NM-SNV - Summer Capacity Margin Comparison

-10%

-5%

0%

5%

10%

15%

20%

25%

30%

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Margin (%)

Region/Subregion Target Margin Existing Certain

Net Capacity Resources Adjusted Potential Resources

Total Potential Resources

WECC-CA-MX US - Summer Capacity Margin Comparison

-5%

0%

5%

10%

15%

20%

25%

30%

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Margin (%)

Region/Subregion Target Margin Existing Certain

Net Capacity Resources Adjusted Potential Resources

Total Potential Resources
Regional Reliability Assessments

231 2008 Long-Term Reliability Assessment 

WECC-NWPP US - Winter Capacity Margin Comparison

0%

5%

10%

15%

20%

25%

30%

2008/09

2009/10

2010/11

2011/12

2012/13

2013/14

2014/15

2015/16

2016/17

2017/18

Margin (%)

Region/Subregion Target Margin Existing Certain

Net Capacity Resources Adjusted Potential Resources

Total Potential Resources

WECC-RMPA - Summer Capacity Margin Comparison

-15%

-10%

-5%

0%

5%

10%

15%

20%

25%

30%

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Margin (%)

Region/Subregion Target Margin Existing Certain

Net Capacity Resources Adjusted Potential Resources

Total Potential Resources
Regional Reliability Assessments

232 2008 Long-Term Reliability Assessment 

WECC CA-MX Mex - Summer Capacity Margin Comparison

-60%

-50%

-40%

-30%

-20%

-10%

0%

10%

20%

30%

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Margin (%)

Region/Subregion Target Margin Existing Certain

Net Capacity Resources Adjusted Potential Resources

Total Potential Resources
Regional Reliability Assessments

233 2008 Long-Term Reliability Assessment 

WECC Self-Assessment 

Peak Demand 

Total actual internal demand decreased by 1.8 percent from 2006 to 2007. Summer temperatures 

in 2006 were much warmer than normal and summer temperatures in 2007, were generally 

normal to somewhat above normal. The projected aggregate WECC 2008 summer total internal 

demand is forecast to be 162,052 MW (U.S. systems 142,032 MW, Canadian systems 17,907 

MW, and Mexican system 2,223 MW) which is an expected 2.45 percent increase from the 2007 

actual demand of 158,178 MW. The anticipated rate of growth for the long term is essentially 

unchanged changed from last year. The summer total internal demand is expected to increase by 

about 2.0 percent per year for the 2008-2017 timeframe which is the same as the 2.0 percent 

projected last year for the 2007-2016 period. 

SUMMER PEAK GROWTHS 

 WECC WECC US WECC CN WECC MX 

2007 Actual 158,178 139,389 17,265 2,153 

2008 Projected 162,052 142,032 17,907 2,223 

Growth % 2.45% 1.90% 3.72% 3.25% 

2017 Projected 193,530 167,661 22,489 3,598 

2008 – 2017 

Growth % 

1.99% 1.86% 2.56% 5.50% 

WECC specifically directs its balancing authorities (BAs) to submit forecasts with a 1 year in 2 

probability of occurrence; most of the entities based their forecasts on population growth, 

economic conditions and normalized weather such that there is a 50% probability of exceeding 

the forecast (i.e., 1 in 2). WECC has not established a quantitative analyses process for assessing 

the variability in projected demands due to the economy. 

The internal peak demand forecasts presented here are a non-coincident sum of the forecasted 

demands from WECC’s 35 BAs. Comparisons with hourly demand data indicate that WECC 

non-coincident peak demands generally exceed coincident peak demands by two to four percent. 

The entities within the Balancing Authorities use various peak forecasting methods that range 

from not making any weather or economic assumptions (due to having a statutory load obligation 

with zero load growth) to using a combination of the EPRI developed Residential End-Use 

Energy Planning System (REEPS) and the Commercial End-Use Model (COMMEND) model to 

forecast the commercial sector energy demands by end-use and then using an econometric 

method by major Standard Industrial Classification codes. Some of the BAs used linear 

regression techniques with a historical multi-year database to develop the winter and summer 

season peak forecasts. 
Regional Reliability Assessments

234 2008 Long-Term Reliability Assessment 

Several of the entities use various weather scenarios (i.e., 1 year in 5, 1 year in 10 conditions) for 

other internal planning purposes. Econometric models used by various entities within the 

Western Interconnection, consider rate effects, average area population income, etc. 

Within the WECC region and its subregions there is a mixture of demand response programs. 

Demand response programs have several different types but they usually fall into two categories: 

1) Passive DSM programs such as encouraging end-users, through economic incentives, high 

efficiency lighting, heat pumps, and water heaters as well as home insulation improvements and 

in some cases the planting of shade trees which help manage demand and energy growth in 

commercial and residential areas; 2) Active DSM programs. A key difference in some of these 

programs is whether the program is dispatchable by the BA. Dispatchable programs, such as 

direct control, interruptible tariffs, or demand bidding programs, have triggering conditions and 

are not under the control of the customer and cannot be anticipated by the customer. WECC has 

historically only gathered data on these traditional Demand Side Management (DSM) programs 

(Dispatchable Load Management air conditioners etc. and interruptible loads). For the 2008 

LTRA, WECC requested further information on DSM programs from the BAs, if applicable. 

The various dispatch operator direct controlled programs reported are largely: interruptible 

demand and direct control load management (air conditioning management), some of which have 

specific criteria that must be met prior to be called upon. There are also other DSM programs 

i.e., critical peak pricing, demand bidding and others that are customer activated after receiving 

some form of notification from a control center. 

The total WECC internal demand forecast includes demand response and interruptible loads that 

range from 4,107 MW in 2008 to 4,898 MW by 2017. The direct control demand-side 

management capability is located mostly in California (3,281 MW), but the other subregions’ 

DSM programs are increasing. Much of the demand response in WECC is based on air 

conditioner cycling programs. Interruptible load programs are more focused on large water 

pumping operations and large commercial operations such as mining. 

Generation 

WECC’s resource data excludes non-metered self-generation and expected wind and hydro 

limitations. The data for the LTRA is provided by all of the balancing authorities within the 

Western Interconnection and is processed by WECC’s Staff under the direction of WECC’s 

Loads and Resources Subcommittee (LRS). 

This year NERC redefined its resource classifications as shown in the Capacity & Demand 

Definitions section in the back of this document. As mentioned in earlier, WECC’s LRS chose 

to classify the future capacity resources into five classes that help provide greater definition and 

granularity, instead of NERC’s two classifications (Planned and Proposed). The five class 

definitions are to be used in both WECC’s Self-Assessment for this LTRA and the Power Supply 

Assessment (PSA) analyses. The class descriptions and using January 1, 2008 as the starting 

point, the 2017 megawatt totals for each class are: 

Class 1: Under active construction and projected in service by Jan. 2012 (8,146 MW). 
Regional Reliability Assessments

235 2008 Long-Term Reliability Assessment 

Class 2: All regulatory permits approved and Interconnection agreement signed and 

projected to be on-line by Jan. 2014 (713 MW). 

Class 3: At least under regulatory review and at least facility study done and 

interconnection agreement in active negotiation and projected to be on-line by 

Jan. 2014 (2,582 MW). 

Class 4: All other resources that meet NERC criteria for “Planned” resources. This is 

intended to capture those “Planned” resources that qualify only through meeting 

the management approval criterion, which LRS does not believe carries a similar 

degree of commitment or likely construction outcome as the other criteria in the 

“Planned” category (7,286 MW). 

Class 5: All other resources that meet NERC criteria for “Proposed” resources (7,425 MW). 

“Planned” Resources “Proposed” Resources

Class 1 Class 2 Class 3 Class 4 Class 5

8,146 713 2,582 7,286 7,425

Total Planned = 11,441 MW Proposed = 14,711 MW

The following four tables reflect the WECC existing and “Planned” resources by generation 

classification and subregion, for the study period for the both non-derated capacity and summer 

on-peak capacity. 

EXISTING RESOURCES

AS OF 12/31/2007

SUMMER RATINGS

- NON DERATED -

NORTHWEST 

POWER 

POOL AREA

ROCKY 

MOUNTAIN 

POWER AREA

ARIZONA

NEW MEXICO

SO. NEVADA

 POWER AREA

CALIFORNIA 

MEXICO 

POWER AREA WECC TOTAL

PERCENT

 OF

 TOTAL

HYDRO - CONV. & PUMPED 49,126 1,426 4,700 14,008 69,260 30.2%

THERMAL 33,757 11,307 30,990 44,343 120,397 2.5%

NUCLEAR 1,150 0 3,872 4,530 9,552 17.1%

GEOTHERMAL 180 0 450 2,255 2,885 1.4%

INTERNAL COMBUSTION 211 253 0 49 513 0.2%

BIOMASS 639 2 58 1,120 1,819 0.9%

SOLAR 0 8 49 458 515 0.2%

WIND 3,243 662 295 2,374 6,574 3.1%

OTHER 174 0 53 535 762 0.4%

TOTAL 88,480 13,658 40,467 69,672 212,277 100.0%

PERCENT OF WECC TOTAL 41.7% 6.4% 19.1% 32.8% 100.0%

EXISTING RESOURCES

AS OF 12/31/2007

SUMMER PEAK RATING

NORTHWEST 

POWER 

POOL AREA

ROCKY 

MOUNTAIN 

POWER AREA

ARIZONA

NEW MEXICO

SO. NEVADA

 POWER AREA

CALIFORNIA 

MEXICO 

POWER AREA WECC TOTAL

PERCENT

 OF

 TOTAL

HYDRO - CONV. & PUMPED 43,160 1,310 4,070 12,787 61,327 31.5%

THERMAL 33,757 11,307 30,990 41,484 117,538 60.3%

NUCLEAR 1,150 0 3,872 4,466 9,488 4.9%

GEOTHERMAL 180 0 450 1,876 2,506 1.3%

INTERNAL COMBUSTION 211 253 0 27 491 0.3%

BIOMASS 639 2 58 570 1,269 0.7%

SOLAR 0 4 49 347 400 0.2%

WIND 596 80 1 490 1,167 0.6%

OTHER 174 0 53 423 650 0.3%

TOTAL 79,867 12,956 39,543 62,470 194,836 100.0%

PERCENT OF WECC TOTAL 41.0% 6.6% 20.3% 32.1% 100.0%

WECC has 194,836 MW of Existing Certain resources as of 12/31/2007, including the 

anticipated summer on-peak values (de-rated) of approximately 1,167 MW from wind, 400 MW 

from solar, 1,269 MW from biomass and 61,327 MW of hydro (56,646 MW of conventional 

hydro, 4,681 MW of pumped storage hydro). The Existing Uncertain180 resources for 2008 are 

 

180 See Capacity, Demand & Event Definitions Section of this report 
Regional Reliability Assessments

236 2008 Long-Term Reliability Assessment 

5,407 MW of wind, 115 MW of solar, 550 MW of biomass, 7,933 MW of hydro (7,369 MW of 

conventional hydro, 564 MW of pumped storage hydro) and 2,472 MW of inoperable for a total 

of 16,477 MW. The non-derated values for the existing variable resources can be seen above. 

FUTURE "PLANNED"

RESOURCES 

NON-DERATED RATING

NORTHWEST 

POWER 

POOL AREA

ROCKY 

MOUNTAIN 

POWER AREA

ARIZONA

NEW MEXICO

SO. NEVADA

 POWER AREA

CALIFORNIA 

MEXICO 

POWER AREA WECC TOTAL

PERCENT

 OF

 TOTAL

HYDRO - CONV. & PUMPED 1,416 0 0 97 1,513 11.0%

THERMAL 1,902 2,111 1,952 2,684 8,649 62.9%

NUCLEAR 0 071 071 0.5%

GEOTHERMAL 156 0 0 107 263 1.9%

INTERNAL COMBUSTION -44 112 0 118 186 1.4%

BIOMASS 96 4 56 50 206 1.5%

SOLAR 0 0280 0280 2.0%

WIND 1,566 449 0 566 2,581 18.8%

OTHER 0 0 0 1 10.0%

TOTAL 5,092 2,676 2,359 3,623 13,750 100.0%

PERCENT OF WECC TOTAL 37.0% 19.5% 17.2% 26.3% 100.0%

FUTURE "PLANNED"

RESOURCES 

SUMMER PEAK RATING

NORTHWEST 

POWER 

POOL AREA

ROCKY 

MOUNTAIN 

POWER AREA

ARIZONA

NEW MEXICO

SO. NEVADA

 POWER AREA

CALIFORNIA 

MEXICO 

POWER AREA WECC TOTAL

PERCENT

 OF

 TOTAL

HYDRO - CONV. & PUMPED 1,416 0 0 200 1,616 14.1%

THERMAL 1,902 2,111 1,952 2,438 8,403 73.4%

NUCLEAR 0 071 071 0.6%

GEOTHERMAL 156 0 0 107 263 2.3%

INTERNAL COMBUSTION -44 112 0 113 181 1.6%

BIOMASS 96 4 56 39 195 1.7%

SOLAR 0 0280 0280 2.4%

WIND 250 56 0 125 431 3.8%

OTHER 0 0 0 1 10.0%

TOTAL 3,776 2,283 2,359 3,023 11,441 100.0%

PERCENT OF WECC TOTAL 33.0% 20.0% 20.6% 26.4% 100.0%

In the above two Planned tables it should be noted that in some resources the non-derated value 

did not increase as much as the summer peak rating. This can be due to a Planned action taking 

place on an existing resource, such as a reduction to the summer de-rates. A negative value in 

the summer peak rating table may be due to deratings of existing units or the mothballing or 

retirement of a unit. 

The Planned capacity resources (Classes 1 through 3) projected to be in-service by the end of this 

assessment period is 11,441 MW. Included in that value are 431 MW of wind, 280 MW of solar, 

195 MW of biomass and 1,616 MW of hydro. The non-derated values for these can also be seen 

in the above tables. 

WECC is using its defined “Planned” resources (11,441 MW) in its PSA as the basis for 

determining the expected transfers used in this LTRA to reflect diversity exchanges. Classes 4 

and 5 (14,711 MW) resources are considered “Proposed” resources but are reduced to zero when 

a zero percent confidence factor assigned to them. They appear in the graphics in the Total 

“Potential” line but are reduced to the “Adjusted Potential” line when the confidence factor is 

applied. 

When analyzing the entire WECC, there are various items that may misrepresent the actual 

condition or resource adequacy. Two of the primary items are: 

1) Neither the summer nor the winter analysis for the Northwest sub-region fully captures 

the limitations on the ability of the Northwest hydro system to sustain output levels 

beyond a single hour. Because of this limitation, the reported surpluses, both to meet 
Regional Reliability Assessments

237 2008 Long-Term Reliability Assessment 

Northwest load and for potential export to other subregions of the West, may be 

unrealistically high. 

2) Looking at the Net Internal Demand (Total Demand minus Demand Side Management 

(DSM) programs) of WECC, when DSM programs are not sharable between the various 

subregions and in some cases not even within the subregion. The graphics below only 

considers the Net Internal Demand when initially calculating the quantity of capacity that 

should be above the total demand. 

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

WECC TOTAL AREA 

SUMMER RESERVE MARGINS

Reserve Target Margin = 13.7% Planned (Class 1-3) Reserve Resources

Total Potential (Class 1-5) Resources Adjusted Potential Resources

The Planned Reserve line overlays the Adjusted Potential line.

Graphic is highly sensitive to the assumptions listed in the notes below.

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

30.0%

35.0%

40.0%

NORTHWEST POWER POOL - U.S. 

WINTER RESERVE MARGINS

Reserve Target Margin = 14.7% Planned (Class 1-3) Reserve Resources

Total Potential (Class 1-5) Resources Adjusted Potential Resources

The Planned Reserve line overlays the Adjusted Potential line

-5.0%

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

30.0%

35.0%

NORTHWEST POWER POOL - CANADA 

WINTER RESERVE MARGINS

Reserve Target Margin = 13.2% Planned (Class 1-3) Reserve Resources

Total Potential (Class 1-5) Resources Adjusted Potential Resources

The Planned Reserve line overlays the Adjusted Potential line.
Regional Reliability Assessments

238 2008 Long-Term Reliability Assessment 

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

ROCKY MOUNTAIN POWER AREA SUMMER RESERVE MARGINS

Reserve Target Margin = 11.8% Planned (Class 1-3) Reserve Resources

Total Potential (Class 1-5) Resources Adjusted Potential Resources

The Planned Reserve line overlays the Adjusted Potential line.

Graphic is highly sensitive to the assumptions listed in the notes below.

-10.0%

-5.0%

0.0%

5.0%

10.0%

15.0%

20.0%

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

ARIZONA - NEW MEXICO - SO. NEVADA SUMMER RESERVE MARGINS

Reserve Target Margin = 13.3% Planned (Class 1-3) Reserve Resources

Total Potential (Class 1-5) Resources Adjusted Potential Resources

The Planned Reserve line overlays the Adjusted Potential line.

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

CALIFORNIA - MEXICO - (U.S.)

SUMMER RESERVE MARGINS

Reserve Target Margin = 15.3% Planned (Class 1-3) Reserve Resources

Total Potential (Class 1-5) Resources Adjusted Potential Resources

The Planned Reserve line overlays the Adjusted Potential line.

Graphic is highly sensitive to the assumptions listed in the notes below.

-30.0%

-20.0%

-10.0%

0.0%

10.0%

20.0%

30.0%

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

CALIFORNIA - MEXICO - (MEXICO)

SUMMER RESERVE MARGINS

Reserve Target Margin = 14.3% Planned (Class 1-3) Reserve Resources

Total Potential (Class 1-5) Resources Adjusted Potential Resources

The Planned Reserve line overlays the Adjusted Potential line.

Graphic is highly sensitive to the assumptions listed in the notes below.

Note: These graphics reflect assumptions that are highly sensitive related to: Assignment of resources to class; 

Renewable energy resource derates or limitations; Inter-subregion diversity exchanges or power transfers; and the 

ability to share Demand Side Management programs between Balancing Authorities. Changes in these inputs may 

affect the results significantly. 

Chart 1—Summer Reserve Margins: WECC Region. 

Chart 2—Winter Reserve Margins; Northwest Power Pool (NWPP) (both the U.S. and Canada) 

Chart 3—Winter Reserve Margins; Northwest Power Pool (NWPP-CN) (Canada only) 

Chart 4—Reserve Margin: Rocky Mountain Power Area (RMPA) 

Chart 5—Reserve Margin: Desert Southwest Area (DSWA) or Arizona-New Mexico-So. 

Nevada (AZ-NM-SNV) 

Chart 6—Reserve Margin: California-Mexico Total Area (CAMX) (both the U.S. and Mexico) 

Chart 7—Reserve Margin: California-México (México) Area (CAMX-MX) 

The graphics above and throughout the rest of the WECC self assessment are shown using 

reserve margins versus the NERC graphics (after the WECC highlights) which uses capacity 

margins. The difference of reserve margins versus capacity margins is the denominator. Both 

the reserve and capacity margins usually have the same numerator (the sum of the net capacity 

resources (including transfers) minus the net demand), but for the reserve margin you divide the 

numerator by the net demand versus dividing by the net capacity resources for the capacity 

margin. WECC used the total demand instead of the net demand due to concerns of sharability 

of DSM programs as mentioned earlier. Because the targeted capacity will be bigger than the 
Regional Reliability Assessments

239 2008 Long-Term Reliability Assessment 

load, the capacity margin calculation will give a smaller percentage value than the reserve 

margin for the same MW value as seen in the Table of Target/Planning Margins. 

Table of Target Margins 

WECC WECC-US NWPP NWPP-CN NWPP-US RMPA AS-NM-SNV CAMX CAMX-US CAMX-MX

Summer Reserve Margin 13.73% 14.03% 13.52% 13.52% 11.31% 11.76% 13.27% 15.28% 15.28% 14.25%

Summer Capacity Margin 12.07% 12.30% 11.91% 11.91% 10.16% 10.53% 11.72% 13.25% 13.25% 12.47%

Winter Reserve Margin 12.92% 12.89% 14.20% 14.69% 13.24% 13.36% 12.77% 11.04% 11.06% 10.35%

Winter Capacity Margin 11.44% 11.42% 12.44% 12.81% 11.69% 11.79% 11.32% 9.94% 9.96% 9.38%

Example: In July of 2008, the DSWA projected Net Load is 30,996 MW and a Total Load of 31,551MW therefore the required Reserve margin then would be:

Typical Reserve Margin target method: Apply Reserve Margin %: 13.27% 30,996 x = 4,113 MW

Calculate Target Capacity desired: 30,996 4,113 + = 35,109 MW

Typical Capacity Margin method: Capacity Margin: (35109 - 30996) / (35109) = 11.71%

WECC Reserve Margin Target Method: Apply Reserve Margin %: 13.27% 30,996 x = 4,113 MW (based on net demand) except California

Calculate Target Capacity desired for WECC (serving total load): 31,551 4,113 + = 35,664 MW

Recalculated reserve margin percent (reserve plus total load): (35664 - 30996) / (35664) = 13.09%

Note: On some of the graphics it may be seen that the calculated reserve margin may be parallel but slightly less than the Target Margin, this is due to

 the above difference. For the California-Mexico subregion, the reserve margin % was applied to the total load.

Summary of Target Margins 

The “Target” reserve margins in the above table, are derived from the Planning Reserve Margins 

that are used in WECC’s Power Supply Assessment (PSA). The PSA uses a “building block” 

method for developing Planning Reserve Margins. The building block approach has four 

elements: contingency reserves, regulating reserves, reserves for additional forced outages, and 

reserves for 1-in-10 weather events. The building block values were developed for each 

balancing authority and then aggregated by subregions and the entire WECC for the PSA and 

this LTRA analysis. The aggregated summer season Planning Reserve Margin (not Capacity 

Margin) for WECC was 13.73% as calculated for the 2008 PSA. This reserve margin maybe 

lower or higher than some of the state, provincial or Load Serving Entity (LSE) requirements 

within WECC, but was developed specifically for use in the PSA and LTRA. 

In the above graphs, the “Net Capacity Resources” margin line equals the sum of Planned 

resources (Classes 1, 2 and 3) plus the Existing Certain resources plus the net transfers of both 

firm and Expected transfers. The “Total Potential Resource” line equals the sum of the Net 

Capacity Resources plus the Existing Uncertain Capacity (cold standby/mothballed units, etc.) 

plus “Proposed Capacity” (Classes 4 and5). The “Adjusted Potential Resources” line equals the 

formula used above for the Total Potential Resource line, but the “Proposed Capacity” is 

multiplied by an estimated certainty factor (which WECC has assigned a zero value) and results 

in nearly the same values as the “Net Capacity Resources.” 
Regional Reliability Assessments

240 2008 Long-Term Reliability Assessment 

The pool of supply/demand side resource options come from a variety of sources including 

forward markets, self-build projects, merchant plants and RFP responses. 

The processes used by the LSEs and BAs to select resources for internal reliability 

analysis/capacity margin calculations vary 

throughout WECC. Some of the processes 

used to evaluate the needs for more 

resources are: forward capacity markets and 

resource adequacy needs; obligation to 

serve activities; low certainty classes of 

resources under consideration, etc. Many of 

the entities within WECC use formal RFPs, 

review resource mix, evaluate fuel diversity 

environmental impacts, and/or look at the 

need to add new generation for meeting 

actual and prospective state and federal 

mandated “renewable portfolio standards”. 

The preliminary 2008 PSA shows 

congestion within some of WECC’s 

subregions, i.e., Mexico (CAMX-MX) and 

the Desert Southwest Area (AZ-NM-SNV) 

beginning in July 2010. A condition called 

the “North-South split” occurs when the 

transmission system between the COB 

intertie, the Pacific Northwest, British Columbia and Montana (the North) and the areas to the 

south (the South) is insufficient to allow all reported surpluses north of the constraint to meet 

loads south of the constraint in the economic dispatch performed in SAM. The North-South split 

occurs within the Northwest subregion but affects all the southern subregions of WECC. 

The PSA does not indicate transmission limitations going from the DSWA into California 

perhaps due to the projected lack of excess resources in the DSWA. Because the transfers 

between subregions are calculated using the derated capacity of wind generators, additional 

transfers, from this or other generation, may be blocked by inadequate transmission capacity. 

The extent of these additional potential transfers is unknown and was not considered in the PSA 

analysis. WECC has not established an interconnection-wide process to address the issue of 

planning for variability in resource availability due to fuel or hydro limitations and other 

conditions. 

Purchases and Sales on Peak 

For the summer of 2008, WECC entities report net firm imports from Eastern Interconnection 

entities of 467 MW, composed of 614 MW of gross imports and 147 MW of gross exports. By 

the summer of 2017, imports decline to 301 MW and exports have risen to 182 MW. The gross 

imports are scheduled across three back-to-back DC ties with SPP and four of the five back-to-
Regional Reliability Assessments

241 2008 Long-Term Reliability Assessment 

back DC ties with MRO. The gross exports are scheduled across the back-to-back DC ties with 

MRO. Expected transfers with the Eastern Interconnection are not modeled. 

The resource data for the individual subregions include transfers between subregions that are 

either firm or projected potential economic transfers with a high probability of occurrence. The 

firm transfers represent both firm purchases or sales and Joint Plant transfers (distribution of 

generation from facilities that have multiple owners) from one subregion to another. 

The projected potential economic transfers reflect the potential use of seasonal demand diversity 

between the winter-peaking northwest and the summer-peaking southwest, as well as other 

economy and short-term firm purchases that are expected to be available in the western market. 

These potential transactions, internal transfers within the region, were simulated in WECC’s 

preparation for the 2008 PSA and are reported as Expected purchases or sales and are included in 

the Net Capacity Resources line on the subregional capacity graphs. The modeling for the PSA 

is performed using a modified least cost dispatch program called the Supply Adequacy Model 

(SAM). SAM, which was developed by the California Energy Commission calculates transfers 

that are physically possible and economically justifiable (basic transmission costs and losses and 

generation costs), but they do not reflect any underlying contractual or other commitments. 

Despite the fact that these transactions are not contracted, they have a high probability of 

occurrence, given the history and extensive activity of the Western market and the otherwise 

underused transmission from the Northwest to the other subregions. The preliminary 2008 PSA 

studies show that the North-South Split first occurs in July of 2010. at which time it shows both 

Mexico and the Desert Southwest Area going below the sum of the total internal load plus the 

specific planning reserve for those areas. For the LTRA results from the PSA were observed. In 

the PSA, conservative transmission limits were placed on paths between the 26 PSA load 

groupings (bubbles) and were observed when calculating the transfers between these bubbles. 

The aggregation of PSA load bubbles into LTRA reporting subregions may obscure differences 

in adequacy or deliverability between bubbles internal to a subregion. 

In order to translate the preliminary analyses completed to date for the 2008 PSA, the various 

area bubbles used in the PSA were combined into the appropriate WECC subregions (see 

diagram on the previous page) and the excess or deficit capacity as reported by SAM was 

summed for each of the WECC subregions. The excess/deficit capacity was then used to 

calculate the amount of Expected Purchases or Expected Sales transactions between the various 

subregions. 

In WECC’s preliminary analysis for the 2008 PSA report, summer transfer capability limitations 

between the northern and southern portions of the Western Interconnection could occur as early 

as 2010 when using Planned generation. These transfer capability limitations could leave 

generation that is available in the northern portion unavailable to meet short-term loads in the 

southern region. (Note: due to energy constraints on the operation of the hydro system in the 

Northwest, much of this surplus generation would be unavailable to meet multi-hour load 

requirements in areas external to the northern portions of the Western Interconnection). 

Although the transmission limitations represented in the PSA analysis are conservative, they are 
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242 2008 Long-Term Reliability Assessment 

not unreasonable and the report establishes that WECC presently has insufficient transmission to 

fully use seasonal capacity/demand diversity within the Western Interconnection. 

The following table presents an example of the July imports and exports for the Arizona – New 

Mexico – So. Nevada subregion through 2014. 

EXISTING AND EXPECTED SUMMER TRANSFERS 

Arizona - New Mexico - So. Nevada Subregion 2008 2009 2010 2011 2012 2013 2014

Joint Plant Transfer to AZ-NM-SNV from RMPA 389 389 389 389 390 389 389

Firm Purchase by AZ-NM-SNV from NWUS 480 480 480 480 480 480 480

Joint Plant Transfer to AZ-NM-SNV from NWUS 0 0 0 0 203 229 229

Firm Purchase by AZ-NM-SNV from SPP (external Region) 283 283 150 0 0 0 0

Firm Purchase Contracts 763 763 630 480 480 480 480

Firm Plant Contingent Imports 389 389 389 389 593 618 618

Existing Imports (Firm & JP) to this subregion 1152 1152 1019 869 1073 1098 1098

Future Expected Imports (including diversity exchanges) 1173 1286 968 354 0 75 5

Total Existing and Expected Imports 2325 2438 1987 1223 1073 1173 1103

Joint Plant Transfer from AZ-NM-SNV to CMUS 4169 4188 4188 4207 4207 4207 4207

Firm Sale From AZ-NM-SNV to RMPA 300 235 235 235 235 235 235

Joint Plant Transfer from AZ-NM-SNV to RMPA 254 254 254 254 254 254 254

Firm Sale From AZ-NM-SNV to NWUS 221 171 171 171 171 171 171

Joint Plant Transfer from AZ-NM-SNV to NWUS 438 438 438 438 438 449 449

Firm Sale Contracts 521 406 406 406 406 406 406

Firm Plant Contingent Exports 4861 4880 4880 4899 4899 4910 4910

Existing Exports (Firm & JP) from this region to all others 5382 5286 5286 5305 5305 5316 5316

Future Expected Exports (including diversity exchanges) 236 254 258 251 298 249 249

Total Existing and Expected Exports 5618 5540 5544 5556 5603 5565 5565

IMPORTS EXPORTS

In summary, inter-subregion transmission interconnection power transfer capabilities are not 

sufficient to accommodate all economy energy transactions at all times of the year. For example, 

the transmission interconnections between the northern and southern portions of the Western 

Interconnection are periodically fully loaded in the north-to-south direction during the summer 

period and may experience limitations in the opposite direction during the winter period. In 

addition to the inter-subregion limitations, transmission with subregions is not always sufficient 

to accommodate all economy energy transactions at all times of the year. WECC establishes 

seasonal operating transfer capability limits and invokes schedule curtailments to address the 

near-term inter and intra-subregion transmission limitations. 

Generally, Western entities rely heavily on shorter-term power markets, for which no forecasts 

are available, which is a primary reason the WECC analysis uses the simulation process 

described above to determine the expected transfer values. The WSPP contract, which contains 

liquidated damage (LD) provisions, is heavily relied upon as the template for such transactions. 

For example, currently SMUD considers that LDs include WSPP Schedule C – type block 

energy contracts, which are not referenced back to specific generating units or a system of units, 

and for which LDs are the only remedy for non-delivery. BPA considers that all WSPP 

Schedule C firm power purchases and long term power purchases contain liquidated damage 

(make whole) provisions. Most of the entities have some contracts that are WSPP Schedule C 

and are not tied back to a unit(s). One entity has a contract with a wind project with a maximum 

capacity of 104 MW and only 66 MW of firm network transmission. The remainder of the 

project is imported using secondary network or non-firm point-to-point transmission. 
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243 2008 Long-Term Reliability Assessment 

Fuel 

WECC has not implemented a formal fuel supply interruption analysis method. Historically, 

coal-fired plants have been built at or near their fuel source and generally have long-term fuel 

contracts with the mine operators, or actually own the mines. This pattern is less true for newer 

plants or those proposed for possible development post-2010. Gas-fired plants were historically 

located near major load centers and relied on relatively abundant western gas supplies. As 

demand for natural gas has increased dramatically for electric generation and other end-uses, 

(and western supplies are made available to the eastern markets) states such as California are 

faced with possible declining western supply availability or greater price volatility. Some of the 

older gas-fired generators in the region have backup fuel capability and normally carry an 

inventory of backup fuel, but WECC does not require verification of the operability of the 

backup fuel systems and does not track onsite backup fuel inventories. Most of the newer 

generators are strictly gas-fired plants, increasing the region’s exposure to interruptions to that 

fuel source. 

A survey of major power plant operators indicates that their natural gas supplies largely come 

from the San Juan and Permian Basins in western Texas, from gas fields in the Rocky 

Mountains, and from the Sedimentary Basin of western Canada. 

Dual-fuel capability is not a significant source of supplement to natural gas within the Western 

Interconnection. Only a nominal amount of generation outside of the Southwest has dual fuel 

capability and the dual-fueled plants are generally subject to severe air emission limitations that 

make alternate fuel use prohibitive for anything other than very short term emergency conditions. 

Some of the WECC entities have taken steps to mitigate possible fuel supply vulnerabilities 

through obtaining long term, firm transport capacity on gas lines, having multiple pipeline 

services, natural gas storage, back-up oil supplies, maintaining adequate coal supplies or 

acquiring purchase power agreements for periods of possible adverse hydro conditions. 

Individual entities may have fuel supply interruption mitigation procedures in place, including 

on-site coal storage facilities. However, on-site natural gas storage is generally impractical so 

gas-fired plants rely on the general robustness of the pipeline delivery system and firm supply 

contracts. Introduction of LNG supplies to the Western Interchange (WI) supply mix later this 

decade will add a new set of fuel supply complexities. 

As of 12/31/2007, the WECC’s existing resource mix percentage of coal or gas/dual fuel 

resources were 18.7% (36,280 MW) and 41.4% (80,564 MW) respectively of 194,836 MW. In 

2017, the resource mix is projected to be 19.1% (39,315 MW) of coal and 41.7% (85,950 MW) 

of gas/dual fuel resources out of 206,277 MW. The following table includes existing and 

“planned” resources. 
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244 2008 Long-Term Reliability Assessment 

FUEL TYPE BREAKDOWN – WECC SUMMER PEAK RATING 

(Existing as of 12/31/2007 and Planned Resources) 

SUMMER Actual

Category Code 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Nuclear CSNU 9488 9559 9559 9559 9559 9559 9559 9559 9559 9559 9559

Hydro CSHY 56646 56628 56739 57109 58072 58079 58079 58079 58079 58079 58079

Pumped Storage CSPS 4681 4681 4741 4761 4864 4864 4864 4864 4864 4864 4864

Geothermal CSGE 2506 2518 2518 2710 2744 2769 2769 2769 2769 2769 2769

Wind CSWD 1167 1278 1532 1559 1598 1598 1598 1598 1598 1598 1598

Coal CSSTC 36280 36522 36551 37792 38508 38589 39315 39315 39315 39315 39315

Oil CSSTO 00000000000

Gas CSSTG 2302 2220 2220 2009 2009 2009 2009 2009 2009 2009 2009

Dual Fuel CSSTDF 17715 17715 17715 17715 17715 17715 17715 17715 17715 17715 17715

Steam 56297 56457 56486 57516 58232 58313 59039 59039 59039 59039 59039

87777777777

Oil CSCTO 694 694 694 694 694 676 676 676 676 676 676

Gas CSCTG 10353 11463 12388 12554 13038 12932 12936 12936 12936 12932 12932

Dual Fuel CSCTDF 5138 5138 5138 5138 5138 5138 5138 5138 5138 5138 5138

Combustion Turbine 16185 17295 18220 18386 18870 18746 18750 18750 18750 18746 18746

Aug Jul Jul Jul Jul Jul Jul Jul Jul Jul Jul

Oil CSCCO 00000000000

Gas CSCCG 41123 43002 44179 44223 44223 44223 44223 44223 44223 44223 44223

Dual Fuel CSCCDF 3933 3933 3933 3933 3933 3933 3933 3933 3933 3933 3933

Combined Cycle 45056 46935 48112 48156 48156 48156 48156 48156 48156 48156 48156

Other CSOT 2810 2981 3120 3205 3187 3467 3467 3467 3467 3467 3467

Undetermined/Unknown CSUN 0 0 000000000

Total CSTF 194836 198332 201027 202961 205282 205551 206281 206281 206281 206277 206277

Projected

Transmission 

For the 2008 - 2017 period, approximately 8,100 miles of 230 – 500 kV transmission line 

projects have been reported to WECC. These projects are what the transmission planners and 

entities have reported to WECC for inclusion in WECC’s Significant Additions report and they 

did not include the details as to what projects have obtained financing or site approvals. 

EXISTING AND FUTURE TRANSMISSION 

(CIRCUIT MILES)

AC & DC

Category 230 345 500 Total AC 250-300 500 Total DC Total

Existing as of 12/31/2007 42,839 9,987 16,170 68,996 106 1,333 1,439 70,435

Planned First Five Years 2,428 434 2,896 5,758 - 488 488 6,246

Planned Second Five Years 171 701 974 1,846 - - - 1,846

Total 12/31/2017 45,438 11,122 20,040 76,600 106 1,821 1,927 78,527

AC Voltage (kV) +/- DC Voltage (kV)

WECC currently does not have a formal definition of generation deliverability, but transmission 

facilities are planned in accordance with NERC and WECC planning standards. These standards 

establish performance levels intended to limit the adverse effects of each transmission system’s 

operation on others and they recommend that each system provide sufficient transmission 

capability to serve its customers, to accommodate planned inter-area power transfers, and to 
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245 2008 Long-Term Reliability Assessment 

meet its transmission obligation to others. The standards do not require construction of 

transmission to address intra-regional transfer capability constraints. 

Planning Authorities and the Transmission Planners are responsible for ensuring that their areas 

are compliant with the TPL Standards 001 through 004. When the Planning Authorities and the 

Transmission Planners have created their datasets and successfully run their simulations, they 

forward their data to the WECC (the Regional Entity). WECC’s System Review Working Group 

(SRWG) compiles and develops a WECC-wide base case under TPL-005-0 which is used for the 

WECC Annual Study Program. 

The Annual Study Program181 provides base cases for WECC members and WECC staff, and 

provides an ongoing reliability and risk assessment of the existing and planned western 

interconnected electric system for the next ten years. To achieve this goal in 2007, eleven new 

power flow base cases were compiled and forty-one disturbances were simulated. Five of the 

power flow cases were prepared for conducting operating studies and the remaining six modeled 

various planning cases out to year 2017. Disturbance simulations emphasize multiple 

contingency (N-2) outages (units and branches). Severe disturbances are simulated including loss 

of entire substations and entire generating plants to identify potential deficiencies leading to 

unacceptable system performance. 

The Annual Study Program rotates its focus on specific areas of subregions. For the 2007 Study 

Report, the Idaho-Montana-Utah-Wyoming area was the focus. Disturbances identified as 

critical outages within this area of study included transfer paths as well as initiating events for 

RAS (remedial action scheme) operation in the study focus area. The intent was to model system 

performance under stressed conditions with identified critical contingencies that might not 

normally be considered in operations and long-term planning studies and to identify potential 

concerns requiring further investigation. For the 2008 Study Report, the Colorado-UtahNorthern Nevada-Northern California area will be the focus. 

In addition to providing WECC Members with an assessment of the WECC transmission system, 

the Annual Study Program report helps support compliance with the following requirements in 

the NERC Reliability Standards relating to Reliability Assessment, Special Protection Schemes, 

and System Data. 

• MOD 010,012 Steady State/Dynamics Data for Transmission System Modeling & Simulation 

• FAC 005 Electrical Facility Ratings for System Modeling 

• PRC 006 UFLS Dynamics Data Base 

• PRC 014 Special Protection System Assessment 

• PRC 020 UVLS Dynamics Data Base 

• TPL 001-004 Transmission Planning (System Performance) 

If the study results do not meet expected performance levels established in the criteria, the 

responsible organizations are obligated to provide a written response that specifies how and 

when they expect to achieve compliance with the criteria. Other measures that have been 

implemented to reduce the likelihood of widespread system disturbances include: an islanding 

 

181 http://www.wecc.biz/TechStudies/2007StudyProgram/body07_final.pdf 
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246 2008 Long-Term Reliability Assessment 

scheme for loss of the AC Pacific Intertie that separates the Western Interconnection into two 

islands and drops load in the generation-deficit southern island; a coordinated off-nominal 

frequency load shedding and restoration plan; measures to maintain voltage stability; a 

comprehensive generator testing program; enhancements to the processes for conducting system 

studies; and a reliability management system. 

Operating studies are reviewed to ensure that simultaneous transfer limitations of critical 

transmission paths are identified and managed through nomograms and operating procedures. 

Four subregional study groups prepare seasonal transfer capability studies for all major paths in a 

coordinated subregional approach for submission to WECC’s Operating Transfer Capability 

Policy Committee. 

On the basis of these ongoing activities, transmission system reliability within the Western 

Interconnection is expected to meet NERC and WECC standards throughout the ten-year period. 

While WECC has eight back-to-back direct current ties to the Eastern Interconnection with a 

combined transfer capability of almost 1,500 MW, only about 614 MW of imports are planned 

for the 2008 summer period and there are 147 MW of exports for a net of 467 net imports. It has 

been reported that the capacity imports have firm resource and associated firm transmission 

commitments. By 2017, the imports are decreased to 301 MW and there are 182 MW of exports. 

Individual entities within the Western Interconnection have established generator interconnection 

requirements that include power flow and stability studies to identify adverse impacts from 

proposed projects. In addition, WECC has established a review procedure that is applied to larger 

transmission projects that may impact the interconnected system. The details of this review 

procedure are located in Section III of the WECC Planning Coordinating Committee’s 

Handbook182. These processes identify potential deliverability issues that may result in actions 

such as the implementation of system protection schemes designed to enhance deliverability and 

to mitigate possible adverse power system conditions. 

For this LTRA and the PSA, the LRS and WECC staff used future generation information 

provided by the balancing authorities. The LRS and WECC staff assumes that the balancing 

authorities are, or will be studying the effects of these resources in the process of granting 

interconnection agreements. 

The U.S. Department of Energy (DOE) announced the issuance of two draft National Interest 

Electric Transmission Corridor (National Corridor) designations in early 2007. One of two 

proposed National Corridors is in the Southwest area of WECC and is called the Southwest Area 

National Corridor which includes counties in California and Arizona. WECC’s Transmission 

Expansion Planning Policy Committee (TEPPC) has commented to the DOE that “TEPPC is not 

advocating for or against the draft corridors”. The Energy Policy Act of 2005 authorizes the 

DOE, based on the findings of DOE’s National Electric Transmission Congestion Study 

(Congestion Study), to designate National Corridors. The DOE issues draft National Corridors 

in order to encourage a full consideration of all options available to meet local, regional and 

 

182 http://www.wecc.biz/documents/library/publications/PCC/PCC_Handbook_Section_III.pdf.
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247 2008 Long-Term Reliability Assessment 

national electric demand, which includes more local generation, transmission capacity, demand 

response, and energy efficiency measures. 

In addition to the currently planned transmission projects, there have been several megatransmission projects proposed. Some of these are the Northern Lights – Celilo Project (Alberta 

to Oregon), the Northern Lights – Inland Project (from as far north as Montana to as far south as 

Los Angeles and Phoenix), the Frontier Line (from Montana and Wyoming to California), the 

TransWest Express Project (from Wyoming to Arizona), the Canada/Pacific Northwest to 

Northern California Study, and several others. These projects range from 1,500 to 3,000 MW of 

transfer capability. These projects and others are in the early stages of being considered and are 

not included in this assessment. They are only mentioned for informational purposes. Most of 

these projects would be associated with potential renewable energy projects and reinforcing the 

transmission system but would help reduce future North-South transmission constraints such as 

the North-South split. 

Operational Issues 

Under WECC’s current regional reliability plan, two reliability centers are being established for 

the region, one in Colorado and one in Washington. The reliability coordinators are charged 

with actively monitoring, on a real-time basis, the interconnected system conditions on a widearea basis to anticipate and mitigate potential reliability problems and to coordinate system 

restoration should an outage occur. 

WECC operations personnel have the West-wide System Model, which is an energy 

management system (EMS) system that allows the monitoring of the electrical grid but does not 

allow any control. In January 2009 the reliability centers are planning to have a better 

monitoring system and modeling system (providing contingency analysis). 

Each of the balancing authorities and transmission providers have their own plans for complying 

with NERC EOP-002 standards pertaining to response to catastrophic events. 

Most of WECC’s entities are members of various reserve sharing groups that may be called upon 

to provide emergency imports or reserve sharing and may be outside of their respective areas. 

Some entities also have direct reserve sharing agreements with other entities and may be tied to a 

qualifying unit trip condition and may have other conditions in regards to the number of times it 

may be called upon and the length of time to cover (some are up to 168 hours). 

The WECC region is spread over a wide geographic area with significant distances between load 

and generation areas. In addition, the northern portion of the region is winter peaking while the 

southern portion of the region is summer peaking. Consequently, systems within the Western 

Interconnection may seasonally exchange very significant amounts of electric power but 

transmission constraints between the subregions are a significant factor affecting economic use 

of surplus power. Due to the inter-subregion transmission constraints, reliability in the Western 

Interconnection is best examined at a subregional level. 

The integration of variable capacity resources (wind, solar etc.) that may be required to meet 

state or local Renewable Portfolio Standards (RPS) raises operating issues. Integrating the 
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248 2008 Long-Term Reliability Assessment 

generation from these variable resources into the various systems may require balancing 

authorities to change how they operate their system due to the intermittency and diversity, or 

lack thereof, of the generation from these resources. These variable resources place an increased 

demand on the ability of entities to regulate generation, balance their systems and support the 

various types of generation to meet their RPS obligations. This may require an increase in 

spinning reserves, or other methods to mitigate undesirable impacts on the system and to 

maintain reliability. 

With the major additions (generation and transmission) that are planned, or the possible upgrades 

to existing facilities (new emission controls or other extended major maintenance items) that will 

need to occur over the next ten years, it may require a different pattern of maintenance outages 

on the existing system. Maintenance outages that affect the system will be timed and staged by 

the entities as much as possible to minimize any limitations on the system. 

In some areas with hydro generation, the Endangered Species Act (ESA) requirements for fish 

have placed more limitations on the hydro-system and operating requirements are stricter than in 

the past. The ability to react quickly to difficult operational circumstances has been degraded. 

Other Items 

The Environmental Protection Agency is readdressing the Clean Water Act (CWA) Section 

316(b) Phase II, which pertains of once-through-cooling (OTC) on existing power plants. The 

OTC process uses water from a river or ocean for condensing low-pressure steam to water as part 

of the thermal cycle of these units. In January 2007, the Second Circuit Court issued its decision 

(Decision) on the Phase II Rule litigation. The result of that Decision was to remand significant 

portions of the previous EPA 316 b rule back to the EPA. As a result, the EPA withdrew the 

Phase II Rule in its entirety and directed EPA regions and states to implement §316(b) on a Best 

Professional Judgment (BPJ) basis until the litigation issues are resolved. Within the State of 

California, there are a significant number of thermal generating units that use once-throughcooling technology, utilizing large amounts of ocean or estuarial water. The California State 

Water Resources Control Board (SWRCB) is also considering a proposal183 that would require 

these units to stop or greatly reduce the amount of ocean or estuarial water they use in the 

cooling process in order to minimize the intake and mortality of marine life. 

Considering the SWRCB proposal from the perspective of the interconnected electrical grid in 

California, there are reliability and market implications in the California ISO control area of 

removing these units from service, even assuming different levels of offsetting generation 

additions. It is not expected that the SWRCB will take any action until the later part of 2008. 

Depending on the policy adopted, impacts could be seen as soon as 2009. 

Reliability Assessment Analysis 

WECC does not currently have any region wide formal planning reserve margin standard. But in 

the past, WECC has required balancing authorities to maintain a reserve margin to cover the 

 

183 http://www.waterboards.ca.gov/npdes/cwa316.html 
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249 2008 Long-Term Reliability Assessment 

worst single planning contingency during the forecast peak hour. But as mentioned earlier, for 

WECC’s annual Power Supply Assessment (PSA)184 the summer and winter reserve margin 

targets were developed using a building block method that takes into account factors for weather, 

forced outages, operating reserves and operating contingencies. These planning reserve margins 

were held constant for the entire study period. The intent of the assessment is to identify 

subregions within the Western Interconnection that have the potential for electricity supply 

deficits below reserve targets based on reported total demand, resource, and transmission data. 

While classifying the reported future resources into WECC’s classes 1 through 5, any reported 

retirements that were associated with future resources were also studied. They were placed into 

the appropriate class based upon the information received and included in the assessment data 

and in the results. For the PSA and LTRA, conservative transmission limits were placed on 

paths between load bubbles and were observed when calculating the transfers between bubbles. 

But beyond that i.e., within the load bubbles, deliverability was not studied. Moreover, the 

aggregation of load bubbles into reporting sub-areas may obscure differences in adequacy or 

deliverability between bubbles internal to the sub-area. 

Currently WECC does not use a probabilistic model that calculates the Loss of Load Probability 

(LOLP) or unserved energy, but WECC has a goal to investigate using a probabilistic model. 

Each of WECC’s transmission authorities or transmission planners performs reliability studies 

on its own system and compares the study results to NERC and/or WECC standards. As 

mentioned earlier in the transmission section, WECC staff and the System Review Working 

Group help develop various base cases and studies as reported in the Annual Study Report. As 

part of the studies, WECC staff does perform selective transient dynamics and post-transient 

analyses on the base cases and has these published in WECC’s Annual Study Report. 

WECC currently has Power System Stabilizer (PSS) standards that require generators with high 

initial response exciters to be equipped with a PSS and to have those PSS properly tuned and inservice. The Power System stabilizer (PSS) is an optional control that is part of the excitation 

system for generator control. The PSS acts to modulate the generator field voltage to damp 

electrical power-speed oscillations. Due to these standards, the Western Interchange does not 

regularly perform WECC-wide small signal stability studies but has conducted them in the past 

and used them for technical justification of the PSS standard. 

As part of WECC’s Planning Coordination Committee Handbook, WECC has developed a 

WECC a Disturbance – Performance Criteria and a Voltage Support and Reactive Power 

Standard, these can be found on pages XI 16-17185 and pages XI 36-39. The WECC Disturbance 

– Performance criteria provides standards for Transient Voltage Dip, Minimum Transient 

Frequency and Post Transient Voltage Deviation. 

The Voltage Support and Reactive Power Standard help provide the criteria for minimum 

dynamic reactive requirements. Dynamic reactive power support and voltage control are 

 

184 Link to WECC's Power Supply Assessment Reports 185http://www.wecc.biz/documents/library/publications/PCC/PCC_Handbook_Section_11.pdf
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250 2008 Long-Term Reliability Assessment 

essential during power system disturbances. Synchronous generators, synchronous condensers, 

and static var compensators (SVCs and STATCOMs) can provide dynamic support. 

Transmission line charging and series and shunt capacitors are also sources of reactive support, 

but are static sources. Reactive power sources must be distributed throughout the electric systems 

among the generation, transmission, and distribution facilities, as well as at some customer 

locations. Because customer reactive demands and facility loadings are constantly changing, 

coordination of distribution and transmission reactive power is required. Unlike active or real 

power (MW), reactive power (Mvars) cannot be transmitted over long distances and must be 

supplied locally. Each year WECC sends out a data request letter to the Technical Studies 

Subcommittee (TSS) and the System Review Working Group asking for areas of “potential 

voltage stability problems and the measurers that are being taken to address the problems 

throughout the WECC region.” The results of this survey are compiled and posted on the WECC 

website as the Voltage Stability Summary. The Voltage Stability Summaries, by year are 

available on the WECC website186. 

Subregions 

Northwest Power Pool Area 

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

30.0%

35.0%

40.0%

NORTHWEST POWER POOL - U.S. 

WINTER RESERVE MARGINS

Reserve Target Margin = 14.7% Planned (Class 1-3) Reserve Resources

Total Potential (Class 1-5) Resources Adjusted Potential Resources

The Planned Reserve line overlays the Adjusted Potential line

 

186 Link to WECC Voltage Stability Summaries
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251 2008 Long-Term Reliability Assessment 

Peak Demand and Energy — The Northwest Power Pool (NWPP) area is a winter peaking 

subregion and is comprised of all or major portions of the states of Idaho, Montana, Nevada, 

Oregon, Utah, Washington, and Wyoming; a small portion of northern California; and the 

Canadian provinces of British Columbia and Alberta. For the period from 2008 through 2017, 

winter total internal demands are projected to grow at annual compound rates of 1.4 percent and 

2.4 percent in the United States and Canadian areas, respectively. For the total NWPP, the 

difference in the summer of 2017 between the net capacity resources (77,071 MW) and the total 

internal demand plus target margin (76,169 MW) and is 902 MW or 4,937 MW without future 

expected sales. The difference in the winter season of 2017-2018 (82,931 MW – 83,892 MW) is 

-961 MW or -4,224 MW without future expected purchases. For the assessment period 2008 

through 2017, the annual energy requirements are projected to grow at annual compound rates of 

1.65 percent and 2.68 percent in the U.S. and Canadian areas, respectively. 

The annual energy use for the NWPP, increased by 2.5 percent from 368,894 GWh in 2006 to 

378,304 GWh in 2007. The 2007 energy use was 1.8 percent greater than the forecast in last 

year’s assessment. Annual energy use for the ten-year period from 2007 through 2017 is forecast 

to increase by 1.9 percent compared to the historic annual energy use increase of 1.3 percent 

from 1997 through 2007. For the period from 2007 through 2017 the annual energy 

requirements are projected to grow at annual compound rates of 1.5 percent and 2.8 percent in 

the U.S. and Canada areas, respectively. 

Resource Adequacy Assessment — The winter Planning Reserve Margin for the United States 

portion of the NWPP (NWPP-US) is 14.7 percent. The data indicates a winter 2008/2009 

reserve margins of 31.8 percent without any “Planned” generation or expected sales and 34.7 

percent with those resources (Reported Margin). Much of WECC’s forecast surplus reserve 

margin exists due to the Columbia River Basin hydroelectric dams located in the NWPP-US, but 

deliverability to other areas is problematic due to both the possibility of a constrained North-toSouth transfer capability and the limited energy associated with the hydro storage. By winter 

2012/2013, those margins change to 23.7 percent and 26.7 percent, respectively. (Note, due to 

energy constraints on the operation of the hydro system in the Northwest, much of this surplus 

would be unavailable to meet multi-hour load requirements, including transfers to other regions 

of WECC). 

0.0%

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25.0%

30.0%

35.0%

40.0%

NORTHWEST POWER POOL - U.S. 

WINTER RESERVE MARGINS

Reserve Target Margin = 14.7% Planned (Class 1-3) Reserve Resources

Total Potential (Class 1-5) Resources Adjusted Potential Resources

The Planned Reserve line overlays the Adjusted Potential line

 

-5.0%

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35.0%

NORTHWEST POWER POOL - CANADA 

WINTER RESERVE MARGINS

Reserve Target Margin = 13.2% Planned (Class 1-3) Reserve Resources

Total Potential (Class 1-5) Resources Adjusted Potential Resources

The Planned Reserve line overlays the Adjusted Potential line.
Regional Reliability Assessments

252 2008 Long-Term Reliability Assessment 

For the Canadian portion of the NWPP, the winter planning reserve margin is 13.2%. In the 

winter of 2008/2009, the reserve margins are 7.3 percent without any “planned” generation or 

expected purchases and 13.2 percent with those resources. In WECC’s 2008 PSA, the Alberta 

150 MW interconnection with the Saskatchewan was not modeled. There are several short lead 

time generation technologies that responded to market conditions in the provinces, that may not 

have been in the regulatory permitting phase (for example wind and simple cycle gas turbines) 

and were classified as being class 4 or 5. Consequently, the assignment of a zero percent 

confidence factor to the “proposed” (Class 4 and 5) resources has a significant impact on the 

reserve margin of the Canada sub-region. The first year that the subregion goes below the 

reserve target margin with ”planned” resources and expected transactions is projected to be the 

winter of 2009-10. That winter the reserve margin would be 11.9% or the difference between net 

capacity resources (24,992 MW) and the total internal load plus reserve margin (25,293 MW) is 

a negative 301 MW. As mentioned previously, there are some resources in the proposed 

category that fall under the short-lead time technologies and have an in-service date prior to the 

winter of 2009, which would delay the time when the Canada sub-region would drop below the 

target margin. The next year, the subregion is projected to be deficient by -1,054 MW. By the 

winter of 2012/2013, those margins decline to a negative 3.3 percent without any ”planned” 

generation or expected purchases and 6.3 percent with those resources (25,622 MW – 27,295 

MW = -1,673 MW below target). The Canadian entities are aware of the need for resource 

adequacy and transmission reinforcement and believe that through the open market and proper 

planning the resource adequacies will be met. 

The AESO has instituted “The Two Year Probability of Supply Adequacy Shortfall Metric” 

187which is a probabilistic assessment of encountering a supply shortfall over the next two years. 

The calculation estimates, on a probabilistic basis, how much load may go without supply over 

the next two year period. Based on extensive consultation with their stakeholders, when this 

unserved energy exceeds 1,600 MWh in any two year period (equivalent to one hour 800 MW 

shortfall in each of the two years), the party may take certain actions to bridge the temporary 

supply adequacy gap without impacting investor confidence in the market. The method of 

bridging the gap may be in the form of:1) Load Shed Service (“LSS”), 2) Self Supply and Backup Generation Support from existing backup generation owned by commercial businesses etc., 

and 3) Emergency Portable Generation. 

Generation in the province of Alberta, Canada, operates in a fully deregulated market and thus 

resource additions are market driven. Generation additions and load growth are expected to 

result in some transmission constraints in a number of areas over the course of the review period 

if identified system reinforcements are not completed on time. The impact of most of these 

constraints is anticipated to be local in nature and will not impact the transmission systems 

outside of Alberta. 

NWPP planning is conducted by sub-area. Idaho, northern Nevada, Wyoming, Utah, British 

Columbia, and Alberta individually optimize their resources to their demand. The coordinated 

system (Oregon, Washington, and western Montana) coordinates the operation of its hydro 

resources to serve its demand. In 2001, the northwest experienced its second lowest Coordinated 

Columbia River System volume runoff since record keeping began, with reservoirs refilling to 

 

187 http://www.aeso.ca/downloads/LTA_Recommendations_Paper_Final.pdf pages 18-24 Items 4 through 5.5 
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253 2008 Long-Term Reliability Assessment 

just 71 percent of capacity, the lowest levels in almost a decade. Since 2001, the reservoir refill 

has ranged between 87 percent and 94 percent of capacity. 

The reservoirs are managed to address all of the competing requirements including but not 

limited to: current electric power generation, future (winter) electric power generation; flood 

control; fish and wildlife requirements; special river operations for recreation; irrigation; 

navigation; and refilling of the reservoirs. With the recent addition of significant wind resources, 

these hydro electric resources are also used to integrate wind into grid operations. In addition to 

managing the competing requirements, other available generating resources, market conditions, 

and load requirements are considered and incorporated into the decision for refilling the 

reservoirs. Any time precipitation levels are below normal, balancing these interests becomes 

even more difficult. A ten-year agreement was reached in 2000 among parties involved in 

operation of the Columbia River Basin concerning river operations. However, this agreement is 

subject to three-, five-, and eight-year performance checks and reopening by the parties. The net 

impact of the agreement is a reduction in generating capability as a result of hydro generation 

spill policies designed to favor fish migration. The capability reduction, which varies depending 

on water flows and other factors, is reflected in the margin calculations presented in this report. 

The agreement includes a provision for negotiating changes in the plan under emergency 

conditions as occurred in 2001. 

The Northwest Power and Conservation Council has adopted resource adequacy assessment 

standards for the Pacific Northwest (PNW) portion of the subregion (representing approximately 

25 percent of the load), which consists of the states of Oregon, Washington, Idaho, and a portion 

of Montana. The adopted energy and capacity-adequacy standards are both tied to probabilistic 

analyses targeting a loss of load probability of 5 percent or less. The remaining portions of the 

subregion have not established a formal process for assessing resource adequacy. Individual 

entities within the subregion, however, have addressed resource adequacy as a part of either their 

integrated resource plan procedures or some other similar process. 

Fuel Supply & Delivery — A significant portion of the electric power generated in the Pacific 

Northwest is derived from hydroelectric generation. Hence, wide variations in annual 

precipitation, water storage and flow limitations, and other factors significantly affect energy 

generation from other resources and complicate the fuel planning processes. Coal-fired 

generation in the area is also very significant. Much of the coal fired generation is near the fuel 

sources and is often operated in a base-load mode. Consequently, the area is not highly reliant 

on gas-fired plants relative to annual energy generation and many of those plants are more often 

operated as seasonal peaking units. Wind-powered generation is increasing rapidly in the area. 

As of 12/31/07, the existing wind resources within WECC, the NWPP has 47.9 % of WECC’s 

non-derated wind resources (3,243 MW), and 51% of the expected summer on-peak wind 

capacity (539 MW.) Of the future WECC planned and projected wind resources, the NWPP 

accounts for 1,566 MW (61%) and 7,504 MW (95%) respectively. The expected derated 

summer on-peak values are 247 MW for the planned resources and 314 MW for the projected 

resources but the “adjusted” projected value is 0 MW. Since the wind resources exhibit wide 

fluctuations in output, areas with relatively large amounts of wind-powered generation are 

investigating the costs and options for integrating wind. Careful and site-specific assessments 

are needed to minimize adverse consequences that may occur. 
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254 2008 Long-Term Reliability Assessment 

Transmission Assessment — In view of the longer time required for transmission permitting and 

construction, it is recognized that network planning should focus on establishing a flexible grid 

infrastructure. This is being done with the goals of allowing anticipated transfers among NWPP 

systems, addressing several areas of constraint within Washington, Oregon, Montana, and other 

areas within the region, and integrating new generation. Projects at various stages of planning 

and implementation include approximately 2,285 miles of 500-kV transmission lines (1,882 

miles NWPP-US and 403 miles NWPP-CN). 

Maintaining the capability to import power into the Pacific Northwest during infrequent extreme 

cold weather periods continues to be an important component of transmission grid operation. In 

order to support maximum import transfer capabilities under double-circuit simultaneous outage 

conditions, the northwest depends on an automatic under-frequency load shedding scheme. 

Power flow studies have been conducted by the Transmission Planning Authorities and in some 

cases where there have been N-1 and N-2 critical contingencies identified, mitigation measures 

(adding reactive sources) or new facilities (a new transformer) have been proposed as items to be 

budgeted and installed. Because some of these are driven by future load growth and 

transmission requests not yet firmed up by the customers, some of these measures have not yet 

escalated to the project level and no specific date for their completion has been assigned at this 

time. 

Some balancing authorities are taking steps to help make the transmission queue process and 

transmission queue assessments are more efficient. BPA has instituted a process called the 

Network Open Season188 (NOS) for allowing resources placement in its transmission queue. 

Under the NOS, those seeking transmission capacity are asked to sign Precedent Transmission 

Service Agreements (PTSA), which commit them to take service at a specified time and under 

specified terms. At one time, BPA’s transmission queue was over 18,000 MW, after the first 

phase of the 2008 NOS there were 6,410 MW worth of transmission requests made and PTSAs 

signed by customers. The PSTA contract is still contingent on BPA’s ability to offer new service 

at its embedded cost rate and is subject to BPA’s completion of the required environmental work 

prior to construction of new facilities. For more information refer to the link below. 

In Alberta, several system reinforcement projects have been completed recently. The most 

significant of these is the re-energization of the Keephills – Genesee and Genesee – Ellerslie 240 

kV lines to their design voltage of 500 kV. This also included the addition of 500/240 kV 

transformers at the Keephills and Ellerslie substations. A project to reinforce the downtown area 

of Edmonton with the addition of 6 miles of underground 240 kV cable is nearing completion 

and has a late fall 2008 in-service date. 

Approvals of need, for a number of system reinforcements, have been received from the Alberta 

provincial regulator. One of these is for the development of approximately 105 kilometers (65 

miles) of 240-kV transmission line to accommodate several new wind generation developments 

in southwest Alberta. This development has an in-service date of 2009. Need approval has also 

 

188 http://www.bpa.gov/corporate/pubs/fact_sheets/08fs/fs_Network_Open_Season.pdf
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255 2008 Long-Term Reliability Assessment 

been received for a number of projects in the Edmonton area. These projects will also include 

the installation of two 600 MVA 240 kV phase shifting transformers (the first in Alberta) to be 

used to balance the flows between the northwest and the northeast regions of the province. 

Planning efforts continue on a number of other major system reinforcements including supply 

into the Fort Saskatchewan and For McMurray areas of northeast Alberta. This reinforcement 

will likely be a combination of 500 kV and 240 kV developments. Planning efforts are also 

continuing on reinforcing the main north – south transmission greed in Alberta. For various 

regions the need approval for this project was rescinded by the regulator. It is anticipated this 

project will be in-service in the 2012 time frame. 

A Calgary area transmission must run (TMR) procedure addresses 240-kV transmission gridloading issues and ensures that voltage stability margins are maintained. The TMR service is an 

ancillary service contract with generators that is required to address contingencies in areas of 

inadequate transmission to help provide voltage support to the transmission system in southern 

Alberta, near Calgary, and assist in maintaining overall system security. 

The Canadian province of British Columbia relies on hydroelectric generation for 90 percent of 

its resources. British Columbia Transmission Corporation (BCTC) is responsible for the 

planning, operation, and maintenance of British Columbia’s publicly-owned transmission 

system. BCTC is addressing constraints between remote hydro plants and lower mainland and 

Vancouver Island load centers. The Interior to Lower Mainland189 (ILM) transmission project is 

BCTC’s largest expansion project in 30 years for the province. In August of 2008 the BC Utility 

Commission approved the ILM project which is a new 500-kV line between the Nicola and 

Meridian substations and has a projected in-service date in 2014. The Vancouver Island 

Transmission Reinforcement190 project involves the removal of two 138 kV lines (one 

submarine) and replacing them with a 230 kV double circuit infrastructure including a 230-kV 

underwater cable between Arnott substation and Vancouver Island terminal. The expected inservice date of the project is October 2008. The ILM reinforcement project will increase the 

total transfer capability of the interior to lower mainland area grid and the new 230-kV cable will 

increase the transfer capability from the lower mainland area to Vancouver Island. 

Operational Issues — Under normal weather conditions, the NWPP does not anticipate 

dependence on imports from external areas during summer peak demand periods. In the event of 

either extreme weather or much lower than normal precipitation, the NWPP could increase 

imports, which would reduce reservoir drafts and aid reservoir filling. Off-peak energy transfers 

allow southwest generators to increase thermal plant loading during normally light load hours to 

offset to some extent the effects of any adverse hydro conditions. 

Preliminary analysis for WECC’s 2008 PSA report indicates that transmission constraints exist 

between the United States and Canadian portions of the NWPP and that by 2017 over 4,000 MW 

of additional capacity (generation or transmission for imports) will be needed in Canada. The 

majority of this additional capacity will need to come from IPPs or the market. 

 

189 http://www.bctc.com/projects/ilm/ 190 http://www.bctc.com/projects/vitr/ 
Regional Reliability Assessments

256 2008 Long-Term Reliability Assessment 

Rocky Mountain Power Area 

0.0%

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15.0%

20.0%

25.0%

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

ROCKY MOUNTAIN POWER AREA

SUMMER RESERVE MARGINS

Reserve Target Margin = 11.8% Planned (Class 1-3) Reserve Resources

Total Potential (Class 1-5) Resources Adjusted Potential Resources

The Planned Reserve line overlays the Adjusted Potential line.

Graphic is highly sensitive to the assumptions listed in the notes below.

Peak Demand and Energy — The Rocky Mountain Power Area (RMPA) consists of Colorado, 

eastern Wyoming, and portions of western Nebraska and South Dakota. The RMPA may 

experience its annual peak demand in either the summer or winter season due to variations in 

weather. For the period from 2008 through 2017, summer total internal demands and annual 

energy requirements are projected to grow at annual compound rates of 2.35 percent and 2.24 

percent, respectively. The difference in 2017 between the “Planned” reserve resources (15,418 

MW) and the total internal demand plus target margin (16,880 MW) and is -1,462 MW (this 

includes serving 398 MW of interruptible load). 

Annual energy use increased by 3.1 percent from 61,174 GWh in 2006 to 63,050 GWh in 2007. 

The 2007 energy use was 1.3 percent greater than the forecast in last year’s assessment. The 

annual energy use for the ten-year period from 2007 through 2017 is forecast to increase by 2.4 

percent compared to the historic annual energy use increase of 3.0 percent from 1997 through 

2007. Annual energy use for the nine-year period from 2008 through 2017 is forecast to increase 

by 2.2 percent.

Resources — The RMPA target margin is 11.8 percent for the summer and 13.4 percent for the 

winter. The data for the Rocky Mountain Power Area present the summer 2008 reserve margins 

of 9.4 percent without any “Planned” generation or expected purchases and 11.5 percent with 

those resources (including serving interruptible load) (“Planned” reserve margin). The first time 

the reserve margin goes below the target margin with the “Planned” resources and expected 
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257 2008 Long-Term Reliability Assessment 

purchases is in July of 2012, where there is a shortfall of 245 MW which produces a margin 

9.6%. 

As of 12/31/2007, of the existing summer rated wind resources within WECC, the RMPA has 

662 MW (10% of the WECC nameplate) which is derated to 80 MW during the summer peak 

period (7% of the WECC on peak wind capacity). Of the future WECC planned and projected 

non-derated wind resources, the RMPA accounts for 449 MW (17%) and 0 MW (0%) 

respectively. The expected derated summer on-peak value is 56 MW for the planned resources. 

Public Service Company of Colorado (PSC) has a 750 MW coal-fired plant under construction at 

the existing Comanche station with an expected in-service date of 2010. There is also the 

Holcomb 1 coal fired generator (700 MW) planned for 2013. Holcomb 2 is projected for 2014, 

but had the confidence factor applied to it, so it is only reflected in the potential line on the 

reserve graph. (As mentioned in the highlights section, it is questionable as to whether either of 

these Holcomb units will meet their current in-service dates.) 

The subregion has not established a process for assessing resource adequacy. Individual entities 

within the subregion, however, have addressed resource adequacy as a part of either their 

integrated resource plan procedures or some other similar process. 

Fuel Supply and Delivery — Coal, hydro, and gas-fired plants are the dominant electricity 

sources in the area. Much of the coal is provided by relatively nearby mines and is often 

procured through long-term contracts. Hydroelectric plants, however, may experience 

operational limitations due to variations in precipitation. As in the northwest, gas-fired plants are 

most often operated in a peaking mode. Abundant natural gas supplies exist within the area but 

delivery constraints may occur at some plants during unexpected severe cold weather conditions. 

Transmission Assessment — Tri-State Generation and Transmission is proposing a new project 

in southern Colorado called the San Luis Valley Electric System Improvement project. The 

project would involve the construction of a 80 mile 230-kilovolt transmission line between the 

Walsenburg Substation and the San Luis Valley Substation. The San Luis Valley’s existing 

electrical system has reached its limit due to continued residential and irrigation growth. One 

major concern is that the radial nature of the existing 230 kV transmission system does not 

provide the reliability benefits of redundant service. The other major problem currently 

experienced on the transmission system is a drop in voltage that occurs when the load on the 

electric system in the valley is above 65 megawatts. This line will provide the power delivery 

infrastructure to increase the reliability and capacity of the existing transmission system and 

support proposed renewable energy development in the area. 

The Western Area Power Administration (WAPA) plans to upgrade several 115-kV transmission 

lines to 230 kV over the next ten years to increase transfer capabilities and help maintain the 

operating transfer capability between southeastern Wyoming and northeastern Colorado. In 

addition to those conversions, the table at the end of WECC’s self assessment describes 

additional transmission projects. 
Regional Reliability Assessments

258 2008 Long-Term Reliability Assessment 

Operational Issues — Transmission upgrades in the area have alleviated some transfer capability 

limitations, but some system constraints remain. Operator flexibility will be limited by the 

transmission constraints and operating conditions must be closely monitored, especially during 

periods of high demand. In some cases, special protection schemes are used to preserve system 

adequacy should multiple outage contingencies occur. 

Arizona-New Mexico-Southern Nevada Power Area 

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2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

ARIZONA - NEW MEXICO - SO. NEVADA

SUMMER RESERVE MARGINS

Reserve Target Margin = 13.3% Planned (Class 1-3) Reserve Resources

Total Potential (Class 1-5) Resources Adjusted Potential Resources

The Planned Reserve line overlays the Adjusted Potential line.

Peak Demand and Energy — The Arizona-New Mexico-Southern Nevada (AZ-NM-SNV) 

power area consists of Arizona, most of New Mexico, southern Nevada, the westernmost part of 

Texas, and a portion of southeastern California. For the period 2008 through 2017, summer total 

internal demands and annual energy requirements are projected to grow at annual compound 

rates of 2.7 percent and 2.5 percent, respectively. The difference in 2017 between the “Planned” 

reserve resources (37,332 MW) and the total internal demand plus target margin (45,438 MW) 

and is -8,106 MW (this includes serving 575 MW of interruptible load and 187 MW of direct 

control load management.) 

The AZ-NM-SNV reserve margin graph depicts that the subregion drops below its reserve target 

margin as early as 2010 due to lack of resources both within the subregion and from surrounding 

subregions. The SAM model used for the LTRA and PSA allows the transfer of excess energy to 

areas of need or higher cost, based upon transfer costs and whether the target margin was met. 

Since California is closer to the Northwest, the cost of transmission is less and much of the 
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259 2008 Long-Term Reliability Assessment 

excess generation in the northwest is absorbed into California and then if any is left after it 

continues to the RMPA or AZ-NM-SNV subregion. The north-south split occurs in 2010 where 

there is not adequate transmission to allow the transfer of energy through California and into the 

AZ-NM-SNV subregion in 2010. . 

The annual energy use increased by 5.9 percent from 134,950 GWh in 2006 to 142,951 GWh in 

2007. The 2007 energy use was 4.7 percent greater than the forecast in last year’s assessment. 

For the ten-year period from 2007 through 2017, the energy use is forecasted to increase by 2.2 

percent compared to the historic annual energy use increase of 3.8 percent from 1997 through 

2007. The annual energy use from 2008 through 2017 is forecast to increase by 2.5 percent. 

Resource Adequacy Assessment— The AZ-NM-SNV planning reserve margin target is 13.27 

percent for the summer and 12.77 percent for the winter. The data for this sub-area present the 

summer 2008 reserve margins of 11.4 percent without any “Planned” generation no expected 

purchases and 17.0 percent with those resources (Reported Margin). With or without the 

“Planned” generation and expected purchases, the AZ-NM-SNV falls below the planning 

reserve target in July 2010 where it drops to 4.2 percent without the resources, and only drops to 

11.1 percent with the resources (this includes serving DSM loads). By the summer of 2012, 

those margins further decline to a negative 1.3 percent and a positive 4.5 percent, respectively, as 

depicted in the margin information graphic. 

Long-term contracts have been signed since the data for the PSA and LTRA were submitted and 

thus are not included in the current analysis. SRP signed a twenty year contract for 500 MW of 

peaking capacity with TransCanada beginning in 2011. The plant will be built 45 miles southeast 

of Phoenix. 

Of the existing wind resources within WECC, the AZ-NM-SNV has 295 MW (4% of the WECC 

nameplate) which is derated to 1 MW during the summer peak period (0% of the WECC on peak 

wind capacity). Of the future WECC planned and projected wind resources, the AZ-NM-SNV 

has projected 0 MW. 

As with other areas within WECC, the future adequacy of the generation supply over the next ten 

years in this area will depend on how much new capacity is actually constructed. The margin 

information graphic for the area demonstrates the subregion faces a somewhat limited window of 

opportunity to address area resource adequacy issues. Frequently, resource acquisitions, 

including load reduction options, are subject to a request for proposal process that may increase 

the uncertainty regarding plant type, location, etc. These factors combine to make resource 

adequacy forecasting problematic over an extended period of time. 

The subregion has not established a process for assessing resource adequacy. Individual entities 

within the subregion, however, have addressed resource adequacy as a part of either their 

integrated resource plan procedures or some other similar process. 

Fuel Supply and Delivery — Coal, hydro, and nuclear plants are the dominant electricity sources 

in the area. As in the northwest, gas-fired plants are most often operated in a peaking mode. 

Much of the coal is provided by relatively nearby mines and is often procured through long-term 
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260 2008 Long-Term Reliability Assessment 

contracts. Major hydroelectric plants are located at dams with significant storage capability so 

short-term variations in precipitation are not a significant factor in fuel planning. 

Transmission Assessment —Transmission providers from the AZ-NM-SNV along with other 

stakeholders from southern California are actively engaged in the Southwest Transmission 

Expansion Planning (STEP) group. The goal of this group is to participate in the planning, 

coordination, and implementation of a robust transmission system between Arizona, southern 

Nevada, Mexico, and southern California that is capable of supporting a competitive, efficient, 

and seamless west-wide wholesale electricity market while meeting established reliability 

standards. The STEP group has developed three projects resulting from the study efforts to 

upgrade the transmission path from Arizona to southern California and southern Nevada. The 

three projects will increase the transmission path capability by about 3,000 MW. The first set of 

upgrades was completed in 2006 and increased the transfer capacity by 505 MW. The second set 

of upgrades will increase the transfer capacity by 1,245 MW and is scheduled to be completed in 

2008. The third and last set of upgrades is the Palo Verde to Devers #2 500-kV transmission line 

(PVD2). The third set of upgrades as proposed by the STEP group developed complications in 

2007 with the Arizona Corporation Commission’s refusal to grant a permit for the construction 

of the Palo Verde to Devers #2 line which may cancel or delay the construction of the PVD2 

line. Currently Southern California Edison (SCE) is projecting the in-service date of the PVD2 

line to be in 2011. SCE states that after all regulatory approvals for the project the construction 

of the project will take approximately 2 years. This line was not included in this year’s LTRA or 

PSA analysis, since in last year’s SAM analysis, this line did not have an impact on transfers due 

to the AZ-NM-SNV being short on resources and there was still unutilized capacity on the 

existing transmission lines going from the California-Mexico subregion into the AZ-NM-SNV. 

As mentioned earlier, the Department of Energy (DOE) has also studied various areas of 

congestion and identified the desert southwest as an area of concern and has proposed the 

Southwest Area National Corridor which includes counties in California and Arizona. The table 

at the end of the WECC self assessment outlines some of the ongoing transmission projects that 

are past the conceptual stage and considered in this assessment. 

Operational Issues — Special protection schemes play an important role in maintaining system 

adequacy should multiple system outages occur. These schemes include generator tripping in 

response to specific transmission line outages. In addition, operators rely on procedures such as 

operating nomograms so that the system can respond adequately to planned and unplanned 

transmission and/or generation outages. 

With the numerous coal fired generators residing in this subregion, there could be significant 

impact from possible carbon emission limits. WECC’s TEPPC group is currently studying the 

possible impact or alternatives to reduce the carbon emissions. 
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261 2008 Long-Term Reliability Assessment 

California-Mexico Power Area 

0.0%

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10.0%

15.0%

20.0%

25.0%

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

CALIFORNIA - MEXICO - (U.S.)

SUMMER RESERVE MARGINS

Reserve Target Margin = 15.3% Planned (Class 1-3) Reserve Resources

Total Potential (Class 1-5) Resources Adjusted Potential Resources

The Planned Reserve line overlays the Adjusted Potential line.

Graphic is highly sensitive to the assumptions listed in the notes below.

-30.0%

-20.0%

-10.0%

0.0%

10.0%

20.0%

30.0%

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

CALIFORNIA - MEXICO - (MEXICO)

SUMMER RESERVE MARGINS

Reserve Target Margin = 14.3% Planned (Class 1-3) Reserve Resources

Total Potential (Class 1-5) Resources Adjusted Potential Resources

The Planned Reserve line overlays the Adjusted Potential line.

Graphic is highly sensitive to the assumptions listed in the notes below.
Regional Reliability Assessments

262 2008 Long-Term Reliability Assessment 

Peak Demand and Energy — The California-Mexico power area encompasses most of 

California and the northern portion of Baja California, Mexico. Summer total internal demands 

are currently projected to grow at annual compound rates of 1.3 percent and 5.5 percent in the 

United States and Mexico areas, respectively, from 2008 through 2017. Annual energy 

requirements are projected to grow at annual compound rates of 1.3 percent and 5.2 percent in 

the U.S. and Mexican areas, respectively. The difference in 2017 between the “Planned” reserve 

resources (75,935 MW) and the total internal demand plus target margin (82,473 MW) and is a 

negative 6,538 MW (this includes serving 75 MW of interruptible load and 3,281 MW of direct 

control load management.) Of the 14,711 MW of total “proposed” resources (summer peak 

rating) throughout WECC,, about 6,900 MW are projected for the California-Mexico Area (but 

have a zero percent confidence factor assigned to them, zeroing them out.) California, which 

generally peaks in August, shows dropping below its planned reserve margin in August of 2011 

(while serving total load and not calling upon their DSM programs). A large portion of the load 

management programs or interruptible load available to the California Independent System 

Operator (CAISO) use a Stage 1 or Stage 2 emergency as trigger mechanisms for the CAISO to 

access these programs. California accounts for 2,892 MW or 94.7 percent of the 3,053 MW of 

Direct Control Load Management (DCLM) for 2008. 

The California-Mexico subregion’s annual energy use increased by 1.5 percent from 297,339 

GWh in 2006 to 301,736 GWh in 2007. The actual 2007 energy use was 2.1 percent less than 

the forecast in last year’s assessment. Annual energy use for the ten-year period from 2007 

through 2017 is forecasted to increase by 1.5 percent compared to the historic annual energy use 

increase of 1.6 percent from 1997 through 2007. Annual energy use for the nine-year period 

from 2008 through 2017 is forecast to increase by 1.5 percent. 

Resource Adequacy Assessment — The California-Mexico total area (CA-MX) planning reserve 

margin is 15.3% for the summer and 11.0% for the winter. The planning reserve margin for 

California U.S. is 15.3% and 11.0% for the summer and winter respectively. The planning 

reserve margin for Baja Mexico is 14.3% and 10.3% for the summer and winter respectively. 

The data for the United States portion of the California-Mexico sub-area present summer 2008 

reserve margins of 7.2 percent without any “planned” generation or expected purchases and 15.3 

percent with those resources. Using “planned” resources and expected purchases, California first 

shows going below its planned reserve margin in August of 2011, where there is a shortfall of 

615 MW which produces a margin 14.3%. In the summer of 2012, California’s reserve margin 

is 12.7 percent as depicted in the margin information graphic. For the Mexican portion of the 

subregion, the summer of 2008 reserve margins are 25.5 percent without any “planned” 

generation or expected sales and 14.3 percent with those resources. By the summer 2012, those 

margins become a negative 14.9 percent and a negative 1.7 percent, respectively. 

Of the existing wind resources within WECC,(6,574 MW of nameplate and derated to 1,167 

MW on-peak) the CMUS has 2,374 MW (36% of the WECC nameplate) which is derated to 490 

MW during the summer peak period (42% of the WECC on-peak wind capacity). Of the future 

WECC planned and projected wind resources, the CMUS accounts for 566 MW (22%) and 406 

MW (5%) respectively. The expected derated summer on-peak value is 125 MW for the planned 

resources, 121 MW the projected resources but the “adjusted” projected value is 0 MW. 
Regional Reliability Assessments

263 2008 Long-Term Reliability Assessment 

The shortfall in Mexico in 2017, between the total load plus planned margin (4,111 MW) versus 

the planned resource reserve (2,722) is -1,389 MW 

California employs a mandatory resource adequacy program requiring load serving entities to 

procure 115% of their forecast demand. State entities are working together and with other 

entities in the Western Interconnection to address transmission planning issues. 

In June of 2006 California passed Assembly Bill 32, the California Global Warming Solutions 

Act of 2006, which had a significant influence on how California plans to meet its future needs 

and cap California’s greenhouse gas emissions at the 1990 level by 2020. On December 5th, 

2007 California adopted the 2007 Integrated Energy Policy Report (IEPR)191 which states that 

“Scenario analysis indicates that these aggressive cost-effective efficiency programs, when 

coupled with renewables development, could allow the electricity industry to achieve at least a 

proportional reduction, and perhaps more, of the state's CO2 emissions to meet AB 32's 2020 

goals” 

Fuel Supply and Delivery — California is highly reliant on gas-fired generation and has very 

little alternate fuel capability for these plants. In February, 2008 the California Energy 

Commission produced the 2008 Update to the Energy Action Plan (UEAP)192 and on page 16 

begins to address the Natural Gas Supply, Demand and Infrastructure and states they will: A) 

Continue to monitor and assess the gas market and its impact on California consumers; B) 

Examine whether and how California utilities should enter into contracts for LNG supplies; C) 

Ensure that California has adequate access to those supplies. The UEAP also mentions that there 

have been proposals for the expansion of gas storage capacities and for a significant expansion of 

pipeline capacity from the Rocky Mountains to California and that they will be assessing those 

projects. 

Transmission Assessment — With California’s new energy policies that require substantial 

increases in the generation of electricity from renewable energy resources, implementation of 

these policies will require extensive improvements to California's electric transmission 

infrastructure. California has developed the Renewable Energy Transmission Initiative 

(RETI)193 which is a statewide initiative to help identify the transmission projects needed to 

accommodate California’s renewable energy goals; facilitate transmission corridor designation 

and facilitate transmission and generation siting permitting. 

As mentioned earlier, With the Arizona Corporation Commission’s May 2007 denial of SCE’s 

Palo Verde – Devers #2 (PVD2) permit, Southern California Edison delayed the projected inservice date to be in 2011. On May 16, 2008, SCE filed its pre-filing application at FERC. The 

FERC pre-filing process triggers a project wide National Environmental Policy Act review, 

preparation of a preliminary draft environmental impact statement, and noticing along the entire 

right-of-way. SCE is requesting the pre-filing process to conclude by end of 2008. SCE also filed 

a motion to modify the PVD2 with the CPUC on May 16, 2008 to support interconnection needs in 

the region near Blythe, California. SCE requested to construct PVD2 facilities in California to 

 

191 http://www.energy.ca.gov/2007_energypolicy/index.html 192 http://www.energy.ca.gov/2008publications/CEC-100-2008-001/CEC-100-2008-001.PDF 193 http://www.energy.ca.gov/reti/index.html 
Regional Reliability Assessments

264 2008 Long-Term Reliability Assessment 

allow SCE to access potential new renewable and conventional gas fired generation in the 

Blythe, California area. 

Special protection schemes have been implemented for generation connected to the Imperial 

Valley substation in order to relieve some of the congestion and an operating nomogram is used 

to limit the simultaneous operation of generating plants connected to the Imperial Valley 

substation and imports from CFE and Arizona. 

Operational Issues— The CAISO is moving forward on a Market Redesign and Technology 

Upgrade (MRTU) program of changes to ISO market and grid operations. The CAISO launch 

date for the MRTU program is now projected to be in 2009, which includes upgrades to the 

CAISO’s computer technology to a scalable system that can grow and adapt to future system 

requirements. Transmission upgrades in the area have alleviated some transfer capability 

limitations, but numerous system constraints remain. 

Regional Description 

WECC’s 216 members, including 35 balancing authorities, represent the entire spectrum of 

organizations with an interest in the bulk power system. Serving an area of nearly 1.8 million 

square miles and 71 million people, it is the largest and most diverse of the eight NERC regional 

reliability organizations. Additional information regarding WECC can be found on its Web site 

(www.wecc.biz). 

AZ/NM/SNV — 230,100 Sq. Mi. 

RMPA — 167,000 Sq. Mi. 

CAMX — 156,000 Sq. Mi. 

NWPP — 1,214,000 Sq. Mi.

WECC TOTAL — 1,760,000 Sq. Mi. 
Abbreviations Used in this Report

265 2008 Long-Term Reliability Assessment 

Abbreviations Used in This Report 

AZ-NM-SNV Arizona-New Mexico-Southern Nevada (Subregion of WECC) 

CA-MX-US California-México (Subregion of WECC) 

dc Direct Current 

DOE U.S. Department of Energy 

EECP Emergency Electric Curtailment Plan 

ERO Electric Reliability Organization 

ERCOT Electric Reliability Council of Texas 

FERC U.S. Federal Energy Regulatory Commission 

FRCC Florida Reliability Coordinating Council 

GHG Greenhouse Gas 

GRSP Generation Reserve Sharing Pool 

GTA Greater Toronto Area 

GWh Gigawatthours 

ICAP Installed Capacity 

IESO Independent Electric System Operator (in Ontario) 

IROL Interconnection Reliability Operating Limit 

ICTE 

ISO 

Independent Coordinator of Transmission for Entergy 

Independent System Operator 

ISO-NE New England Independent System Operator 

kV Kilovolts (one thousand volts) 

LFU Load Forecast Uncertainty 

LNG Liquefied Natural Gas 

LOLE Loss of Load Expectation 

LSE Load-serving Entities 

LTRA Long-Term Reliability Assessment 

MAPP Mid-Continent Area Power Pool 

MISO Midwest Independent Transmission System Operator 

MRO Midwest Reliability Organization 

MVA Megavoltamperes 

Mvar Megavars 

MW Megawatts (millions of watts) 

NERC North American Electric Reliability Corporation 

NIETC National Interest Electric Transmission Corridor 

NPCC Northeast Power Coordinating Council 

NWPP Northwest Power Pool Area (subregion of WECC) 

NYISO New York Independent System Operator 

ONT 

OVEC 

Ontario – IESO 

Ohio Valley Electric Corporation 

PAR Phase Angle Regulators 

PC NERC Planning Committee 

PJM PJM Interconnection 

PRB Powder River Basin 

PRSG Planned Reserve Sharing Group 
Abbreviations Used in this Report

266 2008 Long-Term Reliability Assessment 

RAS Reliability Assessment Subcommittee of NERC Planning Committee 

RCC Reliability Coordinating Committee 

RFC ReliabilityFirst Corporation 

RFP Request For Proposal 

RMPA Rocky Mountain Power Area (subregion of WECC) 

RMR Reliability Must Run 

RRS Reliability Review Subcommittee 

RTO Regional Transmission Organization 

SCR Special Case Resources 

SERC SERC Reliability Corporation 

SOL System Operating Limit 

SWPP 

SPP 

Southwest Power Pool 

Southwest Power Pool 

SPS Special Protection System 

TRE Texas Regional Entity 

THI Temperature Humidity Index 

TLR Transmission Loading Relief 

TVA Tennessee Valley Authority 

VACAR Virginia and Carolinas (subregion of SERC) 

VACS 

WECC 

VACAR – South 

Western Electricity Coordinating Council 
Capacity, Demand & Event Definitions

267 2008 Long-Term Reliability Assessment 

Capacity, Demand & Event Definitions 

a) Demand Definitions 

Total Internal Demand: Is the sum of the metered (net) outputs of all generators within the 

system and the metered line flows into the system, less the metered line flows out of the system. 

The demands for station service or auxiliary needs (such as fan motors, pump motors, and other 

equipment essential to the operation of the generating units) are not included. Internal Demand 

includes adjustments for all non-dispatchable demand response programs (such as Time-of-Use, 

Critical Peak Pricing, Real Time Pricing and System Peak Response Transmission Tariffs) and 

some dispatchable demand response (such as Demand Bidding and Buy-Back). 

Net Internal Demand: Equals the Total Internal Demand reduced by the total Dispatchable, 

Controllable, Capacity Demand Response equaling the sum of Direct Control Load Management, 

Contractually Interruptible (Curtailable), Critical Peak Pricing (CPP) with Control, and Load as a 

Capacity Resource. 

b) Demand Forecast Bandwidths 

The Load Forecast Working Group (LFWG) is responsible for assessing uncertainty inherent in the 

forecasts provided by member Regions in accordance to the NERC standards for the long-term 

reliability assessments. For this purpose, LFWG develops uncertainty bandwidths around 

aggregated Regional, United States and Canadian annual forecasts of peak demand and energy.194 

. 

For a more comprehensive discussion on method, a research paper “Method Proposal for the 

NERC 2008-2017 Regional and National Peak Demand and Energy Projection Bandwidths,”195 

Background - Forecasts cannot precisely predict the future. Instead, many forecasts report a 

baseline or most likely outcome, and a range of possible outcomes based on probabilities around 

the baseline or midpoint. Each NERC's Region Member is responsible to provide demand 

forecasts for the long term Reliability Assessment 2008-2017. Each regional demand forecast, for 

example, is assumed to represent the expected midpoint of possible future outcomes. This means 

that a future year’s actual demand may deviate from the midpoint projections due to variability in 

key factors that drive electrical use. In the case of the NERC regional forecasts, there is generally a 

long-run 50% probability that actual demand will be higher than the forecast midpoint and a longrun 50% probability that it will be lower. 

For securing energy supply or ensuring reliability of the bulk power system, adequate risk 

management implies defining possible future outcomes and their probability of occurrence. 

For planning and analytical purposes, it is useful to have an estimate not only of the expected 

midpoint of possible future outcomes, but also of the distribution of probabilities around the 

projection. Accordingly, LFWG develops upper and lower 10% confidence bands around the 

NERC regional peak demand and energy forecasts. This means that there is a long-run 80% 

probability that future demand and energy will occur within these bands. Conversely, there is a 

 

194 For the full report, see http://www.nerc.com/docs/pc/lfwg/NERC_2008-2017_Regional_Bandwidths.pdf 195 http://www.nerc.com/docs/pc/lfwg/Method_for_2008-2017_Bandwidths.pdf 
Capacity, Demand & Event Definitions

268 2008 Long-Term Reliability Assessment 

10% chance that future outcomes could be less than the lower band, and a 10% chance that future 

outcomes could be higher than the upper band. 

 

Overview of Method - LFWG continued to introduce enhancements to the regional bandwidth 

method this year. The previous method used first order autoregressive models for every region’s 

energy, summer peak, and winter peak. Although using a single statistical time-series model has 

merits and results were satisfactory, LFWG desired to investigate other approaches and model 

specifications for possible improvements or better model fits. Optimal modeling for each Region 

and each series (energy, summer peak, and winter peak) was identified by the LFWG members.

It leads to an automated model selection procedure based on minimizing the BIC statistic, or 

Schwarz Bayesian Information Criterion. [BIC = n * ln(MSE) + k * ln(n) ], where MSE = (SSE/n) 

is the mean squared errors, n is the number of observations, and k is the number of parameters. The 

study looked at a variety of univariate time-series models including simple ARIMA models, the 

original first order autoregressive model, a first order moving average model, and random walk, 

with and without drift. The study also looked at a linear trend, simple exponential smoothing, and 

other smoothing techniques such as Holt, Holt/Winters, and damped exponential. Results indicate 

candidate models can be limited to the four simple ARIMA type models, since in both cases the 

method selected only those models (See Table A-1). 

No. Candidate Model Form ARIMA (p,d,q)Notation Frequency 

1 Random Walk with drift yt = μ + yt-1 +εt (0,1,0) with Intercept 17 

2 Random Walk without drift yt = yt-1 +εt (0,1,0) without Intercept 4 

3 Moving Average yt = μ +εt +θεt-1 (0,1,1) with Intercept 7 

4 Autoregressive yt = μ + ρyt-1 +εt (1,1,0) with Intercept 5 

Table A-1: Models for Bandwidth Calculations 

The principal features of the regional bandwidth method include: 

1. The regional projections of demand and net energy for load are modeled as a function of 

past peak demand or energy. An optimal model is selected for each region’s energy, 

summer peak, and winter peak (33 models in all). 

2. The most frequent (17 out of 33) optimal model was the random walk model with drift 

specification. This approach expresses the current value of the time series as a linear 

function of the previous values of the series and a random shock. The functional form 

again is: 

yt = μ + yt-1 +εt

where μ is a constant term. The shocks are random errors or white noise and are 

assumed to be normally and independently distributed with mean zero, constant variance, 

and independent of 

3. In cases where membership changes resulted in significant changes to a region’s energy 

and load, an intervention variable is added to the equation to allow the bandwidths to 

suitably depict post-change energy and load uncertainty. The historic variability 

observed in demand and energy is used to develop uncertainty bandwidths for demand 

and energy projections. Variability, represented by the variance of the historic data 

series, is combined with other model information to derive the uncertainty bandwidths 

unique to each regional projection. 

t ε

2 σ ε t−1 y

2 σ ε
Capacity, Demand & Event Definitions

269 2008 Long-Term Reliability Assessment 

Each of the eight US and three Canadian regions is modeled separately with three regions 

segmented into their United States and Canadian counterparts. Irregular patterns of deregulation, 

different economic trends, and variable weather patterns contribute to the variability of actual peak 

demand and electricity use. The response to these factors differs across regions due to different 

weather variation, economic conditions, energy prices, and regulation/deregulation policies. The 

bandwidths around NERC regional projections of long-term peak demand forecasts implicitly 

reflect the combined uncertainty from these factors. Accordingly, the bandwidth results on a 

region-by-region basis are unique. 

Results196- The bandwidths produced are theoretical bandwidths based on mathematical 

representations of the series. They are derived from in sample residuals (fitting errors) and 80% 

standard normal confidence intervals. Bandwidths obtained with the theoretical formulas are then 

proportionally projected onto the regional forecasts provided by the Regions. 

Table A-2 shows the optimal model for each region based on the BIC statistic. The graphical and 

numerical results of the bandwidth analyses follow in the figures and tables below: 

Table & 

Figure 

Region Net Energy for 

Load 

Summer 

Demand 

Winter 

Demand 

1 ERCOT RW with drift RW with drift RW with drift 

2 FRCC RW with drift Autoregressive Autoregressive 

3 MRO-US RW with drift RW without drift Autoregressive 

4 NPCC-US RW with drift RW without drift RW without drift 

5 RFC RW with drift Autoregressive RW without drift 

6 SERC RW with drift RW with drift RW with drift 

7 SPP RW with drift Autoregressive RW with drift 

8 WECC-US Moving Average Moving Average Moving Average 

9 MRO-Can RW with drift Moving Average Moving Average 

10 NPCC-Can RW with drift RW with drift RW with drift 

11 WECC-Can RW with drift Moving Average Moving Average 

12 US Sum of regions Sum of regions Sum of regions 

13 Canada Sum of regions Sum of regions Sum of regions 

Table A-2: Optimal Model for Bandwidth Calculation by Region 

The traditional method for choosing or “identifying” the correct form of an ARIMA model is to 

visually examine the autocorrelation and partial autocorrelation functions of the data series. Doing 

this for the energy series results in the same outcome as the optimization method for all cases 

where the Random Walk with drift model is optimal. Where the optimization method chose an 

MA model for WECC-US energy, visual identification indicates a toss-up between the MA and 

AR models. 

 

196 During the 1990s and 2000s several regions including MAIN, MAPP, MRO, RFC, SERC and SPP experienced changes in 

membership and geography. The historical net energy and peak load data and figures depict these changes. 
Capacity, Demand & Event Definitions

270 2008 Long-Term Reliability Assessment 

c) Demand Response Categorization 

Information about demand response categories in Phase 1 were collected for the 2008 Long Term 

Reliability Assessment. Figure A-1 provides an overview of NERC’s Demand-side management 

categories. 

Figure A-1: Demand-Side Management and NERC’s Data Collection

Each of these elements of demand response is defined below: 

Demand Response: changes in electric use by demand-side resources from their normal 

consumption patterns in response to changes in the price of electricity, or to incentive payments 

designed to induce lower electricity use at times of high wholesale market prices or when system 

reliability is jeopardized 

Dispatchable: demand-side resource curtails according to instruction from a control center 

Controllable: dispatchable demand response, demand-side resources used to supplement 

generation resources resolving system and/or local capacity constraints 

Capacity: demand-side resource displaces or augments generation for planning 

and/or operating resource adequacy; penalties are assessed for nonperformance 

Direct Control Load Management: demand-side management that is under 

direct remote control of a control center. It is the magnitude of customer 

demand that can be interrupted at the time of the Regional Council seasonal 

peak by direct control of the System Operator by interrupting power supply to 

individual appliances or equipment on customer premises. 

Contractually Interruptible (Curtailable): curtailment options integrated into 

retail tariffs that provide a rate discount or bill credit for agreeing to reduce load 

during system contingencies. It is the magnitude of customer demand that, in 

Demand Side Management (DSM)

Demand Response (DR) New Energy Efficiency

Dispatchable Non-Dispatchable

Controllable Economic

Capacity Ancillary Energy-Price

EnergyVoluntary 

Direct 

Load 

Control 

Interruptible 

Demand 

Critical 

Peak 

Pricing 

w/Control 

Load as a 

Capacity 

Resource 

Spinning 

Reserves 

Non-Spin 

Reserves 

Regulation 

Emergency 

Demand 

Bidding & 

Buyback 

Time-Sensitive Pricing

Time-of-Use 

Critical Peak Pricing 

Real Time Pricing 

System Peak Response 

Transmission Tariff 

Phase2AreasofInterest

NERC Inaugurated Projected

DR Data Collectionin2008
Capacity, Demand & Event Definitions

271 2008 Long-Term Reliability Assessment 

accordance with contractual arrangements, can be interrupted at the time of the 

Regional Council’s seasonal peak. In some instances, the demand reduction 

may be effected by action of the System Operator (remote tripping) after notice 

to the customer in accordance with contractual provisions. 

Critical Peak Pricing (CPP) with Control: demand-side management that 

combines direct remote control with a pre-specified high price for use during 

designated critical peak periods, triggered by system contingencies or high 

wholesale market prices. 

Load as a Capacity Resource: demand-side resources that commit to prespecified load reductions when system contingencies arise 

Ancillary: demand-side resource displaces generation deployed as operating reserves 

and/or regulation; penalties are assessed for nonperformance 

Non-Spin Reserves: demand-side resource not connected to the system but 

capable of serving demand within a specified time 

Spinning/Responsive Reserves: demand-side resources that is synchronized 

and ready to provide solutions for energy supply and demand imbalance within 

the first few minutes of an electric grid event. 

Regulation: demand-side resources responsive to Automatic Generation 

Control (AGC) to provide normal regulating margin 

Energy-Voluntary: demand-side resource curtails voluntarily when offered the 

opportunity to do so for compensation, but nonperformance is not penalized 

Emergency: demand-side resource curtails during system and/or local capacity 

constraints 

Non-dispatchable197: demand-side resource curtails according to tariff structure, not 

instruction from a control center

Time-Sensitive Pricing: retail rates and/or price structures designed to reflect timevarying differences in wholesale electricity costs, and thus provide consumers with an 

incentive to modify consumption behavior during high-cost and/or peak periods 

Time-of-Use (TOU): rate and/or price structures with different unit prices for 

use during different blocks of time 

Critical Peak Pricing (CPP): rate and/or price structure designed to encourage 

reduced consumption during periods of high wholesale market prices or system 

contingencies by imposing a pre-specified high rate for a limited number of 

days or hours 

Real Time Pricing (RTP): rate and price structure in which the price for 

electricity typically fluctuates to reflect changes in the wholesale price of 

electricity on either a day-ahead or hour-ahead basis 

System Peak Response Transmission Tariff: rate and/or price structure in 

which interval metered customers reduce load during coincident peaks as a way 

of reducing transmission charges 

 

197 Projected Non-dispatchable demand response is not currently collected for reliability assessment. 
Capacity, Demand & Event Definitions

272 2008 Long-Term Reliability Assessment 

d) Capacity, Transaction and Margin Categories 

Capacity Categories 

Existing 

a. Certain — This category includes all existing resources reasonably anticipated 

to be available to operate and deliver power to or into the region. 

b. Uncertain — This category includes mothballed generation and portions of 

intermittent generation not included in the “Existing - Certain” category. 

Planned — This category includes generation that has achieved one or more of these 

milestones: 

• Construction has started 

• Regulatory permits approved 

 Site permit 

 Construction permit 

 Environmental permit 

• Approved by corporate or appropriate senior management 

 Included in a capital budget 

 BOD approved 

Announced/Proposed — This category includes generation that is not in a prior listed 

category, but has been identified through one or more of the following sources: 

• Corporate or appropriate senior management announcement 

• Included in integrated resource plan 

• Generator Interconnection Queues 

Bulk Power System Transactions 

Capacity Purchases and Sales – the following categories may be applied to existing and 

future capacity calculations. Purchases are negative values, sales are positive values. Each 

interregional purchase/sale has been reported.

a) Firm – contract signed 

b) Non-Firm – contract signed 

c) Expected – no contract executed, but in negotiation, projected, or other. 

d) Provisional – transactions under study, but negotiations have not begun. 

Resource Margins 

Total Internal Capacity — The Sum of Existing (both Certain and Uncertain) and 

Planned Capacity.

Existing-Certain Capacity and Net Firm Transactions (MW) — Existing capacity 

resources reasonably anticipated to be available and operate as well as deliverable to or into 

the region plus net Firm Purchases/Sales. 

Net Capacity Resources (MW) — Total Internal Capacity, less Transmission-Limited 

Resources, all Derates, Energy Only, and Inoperable resources; plus net Firm, Expected 
Capacity, Demand & Event Definitions

273 2008 Long-Term Reliability Assessment 

and Provisional Purchases/Sales. Net Capacity Resources do not include Non-Firm 

Purchases/Sales.

Total Potential Resources (MW) — Total Internal Capacity, less Transmission-Limited 

Resources plus the net of all Purchases/Sales.

Adjusted Potential Resources (MW) — Net Capacity Resources, Existing Uncertain 

Resources less all Derates, Total Proposed Resources reduced (multiplied) by a confidence 

factor (percentage); plus Net Non-Firm Transactions. 

Existing Certain Capacity and Net Firm Transactions Margin (%) — Existing-Certain 

Capacity and Net Firm Transactions less Net Internal Demand shown as a percent of 

Existing Certain Capacity and Net Firm Transactions.

Net Capacity Resources Margin (%) — Net Capacity Resources reduced by the Net 

Internal Demand; shown as a percent of Net Capacity Resources.

Total Potential Resources Margin (%) — Total Potential Resources reduced by the Net 

Internal Demand; shown as a percent of Total Potential Resources 

. 

Adjusted Potential Resources Margin (%) — Capacity margin using the Total Potential 

Resources reduced (multiplied) by the confidence factor (percentage). 

Target Capacity Margin (%) — Established target for capacity margin by the region or 

sub-region. 

e) How NERC Defines Bulk Power System Reliability 

NERC defines the reliability of the interconnected bulk power system in terms of two basic and 

functional aspects: 

• Adequacy — The ability of the bulk power system to supply the aggregate electrical 

demand and energy requirements of the customers at all times, taking into account 

scheduled and reasonably expected unscheduled outages of system elements. 

• Operating Reliability — The ability of the bulk power system to withstand sudden 

disturbances such as electric short circuits or unanticipated loss of system elements from 

creditable contingencies. 
Capacity, Demand & Event Definitions

274 2008 Long-Term Reliability Assessment 

Regarding Adequacy, system operators can and should take “controlled” actions or procedures to 

maintain a continual balance between supply and demand within a balancing area (formerly 

control area). These actions include: 

• Public appeals. 

• Interruptible demand — customer demand that, in accordance with contractual arrangements, 

can be interrupted by direct control of the system operator or by action of the customer at the 

direct request of the system operator. 

• Voltage reductions (sometimes referred to as “brownouts” because incandescent lights will dim 

as voltage is lowered, sometimes as much as 5 percent). 

• Rotating blackouts — the term “rotating” is used because each set of distribution feeders is 

interrupted for a limited time, typically 20–30 minutes, and then those feeders are put back in 

service and another set is interrupted, and so on, rotating the outages among individual feeders. 

Under the heading of Operating Reliability, are all other system disturbances that result in the 

unplanned and/or uncontrolled interruption of customer demand, regardless of cause. When these 

interruptions are contained within a localized area, they are considered unplanned interruptions or 

disturbances. When they spread over a wide area of the grid, they are referred to as “cascading 

blackouts” — the uncontrolled successive loss of system elements triggered by an incident at any 

location. Cascading results in widespread electric service interruption that cannot be restrained 

from sequentially spreading beyond an area predetermined by studies. 

What occurred in 1965 and again in 2003 in the northeast were uncontrolled cascading blackouts. 

What happened in the summer of 2000 in California, when supply was insufficient to meet all the 

demand, was a “rotating blackout” or controlled interruption of customer demand to maintain a 

balance with available supplies while maintaining the overall reliability of the interconnected 

system. 

f) Event Classifications 

In order to gauge operating reliability performance and resource adequacy, a set of bulk power 

system event scale is used to classify bulk power system disturbances by severity, size, and impact 

to the general public. Events are classified using the technical requirements below as a guide. 

Category 1 An event results in any or combination of the following actions: 

a. The loss of a bulk power transmission component beyond recognized criteria, i.e. 

single-phase line-to-ground fault with delayed clearing, line tripping due to growing 

trees, etc. 

b. Frequency below the Low Frequency Trigger Limit (FTL) more than 5 minutes. 

c. Frequency above the High FTL more than 5 minutes. 

d. Partial loss of dc converter station (mono-polar operation). 

e. Inter-area oscillations. 

Category 2: An event results in any or combination of the following actions: 

a. The loss of multiple bulk power transmission components. 

b. System separation with no loss of load or generation. 
Capacity, Demand & Event Definitions

275 2008 Long-Term Reliability Assessment 

c. Special Protection System or Remedial Action Scheme misoperation. 

d. The loss of generation (between 1,000 and 2,000 MW in the Eastern Interconnection or 

Western Interconnection and between 500 MW and 1,000 MW in the ERCOT 

Interconnection). 

e. The loss of an entire generation station or 5 or more generators. 

f. The loss of an entire switching station (all lines, 100 kV or above). 

g. Complete loss of dc converter station. 

Category 3: An event results in any or combination of the following actions: 

a. The loss of generation (2,000 MW or more in the Eastern Interconnection or Western 

Interconnection and 1,000 MW or more in the ERCOT Interconnection). 

b. the loss of load (less than 1,000 MW) 

c. System separation or islanding with loss of load or generation (less than 1,000 MW). 

d. UFLS or UVLS operation. 

Category 4: An event results in any or combination of the following actions: 

a. System separation or islanding of more than 1,000 MW of load. 

b. The loss of load (1,000 to 9,999 MW). 

Category 5: An event results in any or combination of the following actions: 

a. The occurrence of an uncontrolled or cascading blackout 

b. The loss of load (10,000 MW or more) 
Major Transmission Projects > 200 kV

276 2008 Long-Term Reliability Assessment 

Major Transmission Projects > 200 kV 

 

Transmission 

Terminal From 

Location 

 Terminal To 

Location 

Line Length 

(Miles) 

Voltage 

Operating 

(kV) 

Capacity 

Rating 

(MVA) 

Expected 

Service 

Date 

ERCOT 

Jacksboro switch W. Denton 72 345 1631 12-2006 

STP Dow 0 345 1450 03-2007 

Collin Switch NW Carrolton 19 345 1072 05-2016 

Anna Switch Collin Switch 13 345 1969 12-2008 

W. Levee Norwood 7 345 1631 12-2009 

Jewett Big Brown 0 345 1072 12-2008 

P H Robinson Oasis 0 345 1173 05-2009 

Spruce Skyline 21 345 1446 06-2009 

Hutto Switch Salado Switch 32 345 1631 06-2010 

W. Denton NW Carrolton 9 345 1631 05-2010 

Lobo San Miguel 110 345 1623 07-2009 

Zorn Hutto Switch 71 345 1630 08-2011 

TNP One Bell County SE 88 345 1631 05-2011 

Temple Switch Salado Switch 15 345 1912 05-2010 

Tricorner Seagoville Switch 9 345 1072 05-2015 

Trinidad Watermill 52 345 1072 05-2015 

Krum W and Anna Krum W 50 345 N/A 05-2015 

Lobo Rio Bravo 30 345 1939 06-2013 

Venus Cedar Hill 21 345 1912 05-2011 

Oklaunion Bowman 38 345 2724 12-2012 

Ajo Cabillo 25 345 2740 10-2008 

Cagnon Hillcountry 20 345 1171 06-2016 

Sol Rio Bravo 122 345 N/A 03-2015 

N. Edinburg Sol 15 345 N/A 03-2015 

Frontera Sol 12 345 N/A 03-2015 

La Palma Ranchito 10 345 N/A 06-2015 

Frontera South McAllen 12 345 N/A 06-2015 

Ranchito South McAllen 38 345 N/A 05-2016 

Liggett Trinity Switch 13 345 N/A 05-2015 

FRCC 

Northeast 40th Street 8 230 810 09-2008 

Pasadena 51st Street 1 230 810 09-2008 

51st Street 40th Street 1 230 810 09-2008 

St. Johns Pringle 25 230 759 12-2008 

Bayside Gannon 0.1 230 460 04-2009 

Avalon Gifford 7 230 1141 05-2009 

Bartow Northeast Circuit 1 4 230 612 06-2009 

Bartow Northeast Circuit 2 4 230 612 06-2009 

Bartow Northeast Circuit 3 4 230 612 06-2009 
Major Transmission Projects > 200 kV

277 2008 Long-Term Reliability Assessment 

Terminal From 

Location 

 Terminal To 

Location 

Line Length 

(Miles) 

Voltage 

Operating 

(kV) 

Capacity 

Rating 

(MVA) 

Expected 

Service 

Date 

Big Bend (Plant) Big Bend (Switching 

Station) 0.1 230 460 10-2009 

Hines Energy Complex West Lake Wales #2 21 230 1141 05-2010 

Bithlo Stanton (OUC) 6 230 1141 05-2010 

Intercession City West Lake Wales #2 30 230 1141 06-2010 

Stanton Bithlo 4.4 230 800 05-2011 

Jax Heights Substation Duval Substation 12.5 230 668 05-2011 

Intercession City West Lake Wales #1 30 230 1141 06-2011 

Lake Agnes (TECO) Gifford 32 230 1141 06-2011 

Manatee BobWhite 30 230 1190 12-2011 

Polk Power Station Polk Switching 

Station 0.7 230 650 04-2012 

Bartram Substation Switzerland 

Substation 6.88 230 668 05-2012 

Southeast Generating 

Station Bartram Substation 8.84 230 668 05-2012 

Bartram Substation Sampson Substation 4.04 230 668 05-2012 

Bartram Substation Switzerland 

Substation 6.88 230 668 05-2012 

Polk Pebbledale (1) 13.5 230 749 06-2012 

Polk Pebbledale (2) 9.9 230 1013 06-2012 

Hopkins-Crawford 230 

TAP SUB 5 230 10 230 464 06-2012 

Gilchrist Generating 

Station 

Gilchrist Switching 

Station 10 230 1195 12-2012 

Gilchrist Generating 

Station 

Gilchrist Switching 

Station 10 230 1195 12-2012 

Polk FishHawk 28 230 1013 12-2012 

Ft White Suwannee 40 230 1141 06-2013 

St. Cloud South KUA 10 230 800 11-2015 

Levy Central FL South 50 500 2870 06-2016 

Levy Crystal River 10 500 2870 06-2016 

SUB 5 230 SUB 7 230 13 230 464 06-2016 

Kathleen Lake Tarpon 45 230 1141 06-2016 

Citrus Crystal River East #1 6 230 1141 06-2016 

Citrus Crystal River East #2 6 230 1141 06-2016 

Levy Citrus #1 10 500 2870 06-2016 

Levy Citrus #2 10 500 2870 06-2016 

Crystal River Brookridge 35 230 1141 06-2016 

Brookridge Brooksville West 4 230 1141 06-2016 

MRO 

Stone Lake Arrowhead (WUMS) 79 345 1219 01-2008 

Paddock Rockdale (WUMS) 30 345 1348 2010 

Gardner Park Highway 22 

(WUMS) 55 345 1425 2010 

Morgan Highway 22 

(WUMS) 27 345 1425 2010 

Werner West Highway 22 

(WUMS) 24 345 1425 2010 

Rockdale West Middleton 

(WUMS) 21 345 1195 2013 

Brookings County White 10 345 TBD 2009 
Major Transmission Projects > 200 kV

278 2008 Long-Term Reliability Assessment 

Terminal From 

Location 

 Terminal To 

Location 

Line Length 

(Miles) 

Voltage 

Operating 

(kV) 

Capacity 

Rating 

(MVA) 

Expected 

Service 

Date 

Big Stone II outlet Granite Falls 

(SD/MN) 100 230 TBD 2011 

Boswell Wilton (MN) 68 230 TBD 2012 

Fargo St. Cloud (MN) 250 345 TBD 2015 

Twin Cities N. Rochester-La 

Crosse (MN/WI) 150 345 TBD 2015 

Brookings Twin Cities (SD/MN) 225 345 TBD 2015 

Columbus East LES NW68th & 

Holdrege (NE) 67 345 1195 2010 

Columbus East Shell Creek (NE) 12 345 1195 2010 

Shell Creek Hoskins (NE) 45 345 1195 2008 

Wagener NW68th & Holdrege 

(NE) 26 345 TBD 2009 

S3458 103rd & Rokeby 

Road (NE) 49 345 TBD 2009 

103rd & Rokeby Rd 

Substation - 345 TBD 2009 

Salem Lore – Hazleton (IA) 75 345 1195 2011 

South-Central 

Saskatchewan 99 230 TBD 2010 

Conawapa Riel DC (MH) 833 500 2 2017 

Wuskwatim Herblet Lake (MH) 86 230 420 2010 

Wuskwatim Herblet Lake (MH) 

circuit 2 86 230 420 2010 

Herblet Lake Ralls Island (MH) 103 230 420 2011 

Dorsey Portage South (MH) 43.5 230 284 2013 

NPCC 

Coleson Cove Salisbury 103 345 TBD 

Bridgewater Carver 345 04-2009 

Pilgrim Carver 345 04-2009 

Stoughton Mattapan 345 06-2009 

Mattapan K Street 345 06-2009 

Beseck 

Junction East Devon 345 08-2008 

East Devon Singer 345 12-2009 

Singer Norwalk 345 12-2009 

Tewksbury Wakefield Jct. 345 07-2009 

Wakefield Jct. Mystic 345 07-2009 

New England 

Singer Norwalk 345 12-2009 

Sprain Brook Sherman Creek 10 345 

872-S/1010-

W 2011-Sum 

Willis 1 Patnode 9.1 230 426-S/545-W 

2008/09-

Win 

Patnode Duley 15.3 230 426-S/545-W 

2008/09-

Win 

Duley Plattsburgh 9.3 230 426-S/545-W 

2008/09-

Win 

Willis 2 Ryan 6.5 230 426-S/545-W 

2008/09-

Win 

Ryan Plattsburgh 27.2 230 426-S/545-W 

2008/09-

Win 

New York 

Princetown S. Saratoga #3 17 345 2018 
Major Transmission Projects > 200 kV

279 2008 Long-Term Reliability Assessment 

Terminal From 

Location 

 Terminal To 

Location 

Line Length 

(Miles) 

Voltage 

Operating 

(kV) 

Capacity 

Rating 

(MVA) 

Expected 

Service 

Date 

Princetown S. Saratoga #4 17 345 2018 

Outaouais Hawthorne 25 230 06-2009 

Essa Stayner 17 230 06-2009 

Cardiff Hurontario 3 230 05-2010 

Hurontario Jim Yarrow 2 230 05-2010 

Ingersoll Woodstock 10 230 06-2010 

Bruce Milton 115 500 03-2012 

Allanburg Middleport 50 230 TBD 

Lakehead Birch 13 230 2013 

Hanmer or 

Sudbury Greater Toronto 180-250 500 2017 

Missisagi Hanmer 130 230 2017 

Pinard Hanmer 230 500 2017 

Mackay Third Line 60 230 2017 

Nipigon Little Jackfish 120 230 2017 

Seaforth Goderich 25 230 2015 

Owen Sound Bruce Peninsula 30-50 230 2015 

Manitowaning Espanola 50 230 2015 

Nobel Series Compensation N/A 500 12-2010 

Ontario 

Porcupine Static VAR Compensator N/A 230 11-2010 

Rimouski Les Boules 34 230 12-2008 

Les Boules Matane 58 230 12-2008 

Rimouski Matane 5 230 12-2008 

Matane Goemon 44 230 12-2008 

Carleton Line2398 7.5 230 12-2008 

Les Mechins Line 23 YY 6 230 12-2009 

Chenier Outaouais 71 315 05-2010 

Eastmain-1A Eastmain-1 1 315 07-2010 

Sarcelle Eastmain-1 69 315 07-2010 

Goemon Mont-Louis 46 315 12-2010 

Goemon Gros Morne 56 315 12-2011 

Romaine-2 Arnaud 163 315 12-2014 

Québec 

Romaine-1 Romaine-2 19 315 12-2016 

RFC 

Cranberry Wylie Ridge 40 500 2800/3600 12-2011 

Bismarck Troy 14 345 700 05-2010 

Goodison Belle River 35 345 1757 12-2009 

Goodison Pontiac 6 345 1757 12-2009 

Edenville Warren 15 138 345 06-2010 

Argenta Palisades 1 40 345 1238 06-2010 

Argenta Palisades 2 40 345 1238 06-2010 

Keystone Clearwater 23 138 345 05-2009 

Simpson Batavia 22 138 345 12-2009 

Almeda Saginaw River 25 138 345 05-2010 

Tippy Chase 30 138 345 12-2010 

Algoma Cedar Spring Jct 2 138 345 05-2011 

Croton Cedar Spring Jct 16 138 345 05-2011 

Croton Felch 9 138 345 12-2009 
Major Transmission Projects > 200 kV

280 2008 Long-Term Reliability Assessment 

Terminal From 

Location 

 Terminal To 

Location 

Line Length 

(Miles) 

Voltage 

Operating 

(kV) 

Capacity 

Rating 

(MVA) 

Expected 

Service 

Date 

Richland Titabawassee 12 345 1236 04-2009 

Richland Nelson Rd 47 345 1236 04-2009 

Possum Point Burches Hill 3 230 TBD 06-2013 

Burches Hill Chalk Point 19 500 TBD 06-2013 

Chalk Point Calvert Cliffs 19 500 TBD 06-2013 

Sourth Akron Berks 12 230 264 06-2008 

Bergen Leonia 3 230 366 06-2008 

Branchburg Flagtown 4 230 878 06-2008 

Roseland Montville 7 500 3005 06-2012 

Montville Jefferson 15 500 3005 06-2012 

Jefferson Bushkill 22 500 3005 06-2012 

Hope Creek Cedar Creek 12 500 3005 06-2013 

Linden South Waterfront 6 230 873 06-2011 

Gibson Brown 34 345 1400 12-2010 

Reid Brown 25 345 1400 12-2010 

SERC 

Cumberland Montgomery 40 500 2598 06-2008 

Maury Rutherford 27 500 1732 04-2010 

J.K. Smith West Garrard County 33 345 1947 12-2009 

Mill Creek Hardin County 42 345 1195 12-2009 

Trimble County Ghent-Speed Line 3 345 1195 03-2009 

Resaca Moss Lake 9 230 265 10-2010 

Hardin Co. Smith OMU -66 345 535 02-2008 

Hardin Co. Daviess Co. 59 345 535 02-2008 

Smith OMU Daviess Co. 7 345 535 02-2008 

Brown North West Garrard 14 345 1195 05-2009 

Central 

Pineville West Garrard 89 345 1195 05-2009 

Cypress Jacinto 53 230 884 06-2012 

Porter Lewis Creek 28 230 884 06-2014 

Winnfield Danville 21 230 521 06-2014 

Jacinto Lewis Creek 29 230 884 06-2010 

Franklin Natches SES 51 230 400 06-2012 

Coly Hammond 20 230 640 09-2012 

Franklin McComb 24 230 400 06-2013 

Delta 

Chouteau GRDA 100 345 954 06-2011 

Loose Creek Mariosa Delta 11 345 1793 06-2008 

Joachim Substation Tyson Substation 0 345 1195 10-2008 

Rush Island Plant Joachim Substation 0 345 1200 10-2008 

Baldwin Power 

Plant Substation 

Prairie State Power 

Plant 2 345 1297 06-2010 

Baldwin Power 

Plant Substation 

Prairie State Power 

Plant 8 345 1297 06-2010 

Baldwin Power 

Plant Substation 

Rush Island Plant 

Substation 26 345 1793 06-2010 

Prairie State Power 

Plant Stallings Substation 8 345 1195 06-2010 

Gateway 

Prairie State Power 

Plant 

W. Mount Vernon 

Substation 2 345 1195 06-2010 
Major Transmission Projects > 200 kV

281 2008 Long-Term Reliability Assessment 

AnnistonHammond line North Anniston 1 230 502 03-2017 

Arkwright West Milledgeville 33 230 866 06-2016 

Athena Rainey 45 230 866 06-2012 

Battlefield Frey Road 3 230 866 11-2009 

Bethabara Clarksboro 15 230 602 12-2009 

Bethabara East Walton 8 230 602 06-2011 

Bethbara East Walton (black) 6 230 602 06-2014 

Bostwick East Walton 4 230 602 06-2011 

Bowen Villa Rica 28 230 1578 06-2009 

Braselton Sharon Church 3 230 602 06-2008 

Bucks SS Tensaw SS 9 230 865 08-2009 

Calvert SS Tensaw SS 5 230 865 05-2009 

Camp Creek Cliftondale 5 230 602 10-2008 

Clermont Jct South Cleveland 17 230 602 06-2014 

Clermont Jct. South Cleveland 23 230 602 06-2014 

Clermont Junction Dawson Crossing 20 230 602 08-2012 

Cliftondale Ono 6 230 602 06-2013 

Cumming Sharon Springs 7 230 602 06-2011 

Dawson Crossing Palmer Creek 4 230 602 06-2008 

Deptford Kraft 13 230 433 06-2011 

Dorsett Jct-57a Substation 11 230 602 06-2013 

Dum Jon Thomson Primary 23 230 596 06-2010 

East Lake Road Jackson Creek 9 230 602 06-2010 

East Lake Road Ola 4 230 602 06-2010 

East Walton Jack's Creek 9 230 602 06-2011 

East Walton Rockville 40 500 3464 06-2011 

Ellicott TS West McIntosh 1 230 602 12-2008 

Ellijay Primary Cherry Log 12 230 602 06-2012 

Farley Raccoon Creek 60 230 602 06-2013 

Farley-Scholz line Cottonwood TS 1 230 502 04-2011 

Forrest Road West Milledgeville 35 230 602 06-2015 

Frey Road Huntsville 5 230 866 11-2009 

Gaston Bessemer 1 230 502 04-2009 

Gordon North Dublin 32 230 602 06-2014 

Homeland Kettle Creek 36 230 602 06-2008 

Hopewell McGrau Ford (black) 11 230 602 06-2013 

Jack's Creek Cornish Mountain 15 230 602 06-2011 

JC Penny tap JC Penny 2 230 602 06-2014 

Jim Moore Road Sharon Church 11 230 602 06-2010 

Kiln Carriere SW 26 230 602 06-2011 

Klondike Jackson Creek 4 230 602 06-2008 

Laguna Beach Santa Rosa 22 230 602 06-2012 

Lansing Smith Laguna Beach 14 230 602 06-2010 

Line Creek Ono 6 230 602 06-2014 

LPM-Monroe-str 

31 

Str. 31 (Cornish 

Mountain) 4 230 580 06-2011 

McConnell Road Woodlore 5 230 866 06-2009 

McDonough Ola 10 230 602 06-2015 

McGrau Ford Hopewell 12 230 602 06-2015 

Southeastern 

Mitchell Slappy Drive 13 230 602 05-2016 
Major Transmission Projects > 200 kV

282 2008 Long-Term Reliability Assessment 

O'Hara McDonough 20 230 602 06-2014 

Ono Line Creek 3 230 602 06-2013 

Pegamore Huntsville 2 230 866 06-2010 

Plant McDonough Smyrna 6 230 1205 06-2010 

Plant McDonough 

CC 

Plant McDonough 

(black) 1 230 1205 06-2011 

Plant McDonough 

CC 

Plant McDonough 

(white) 1 230 1205 06-2011 

Prattville CT TS County Line Road 

TS 1 230 1003 10-2013 

Shoal Creek Suwanee 8 230 602 06-2013 

South Dahlonega Palmer Creek 8 230 602 06-2014 

South Hall Suwanee 10 230 664 06-2016 

Thomson Warthen 35 500 3464 06-2010 

Thomson Primary Vogtle 50 500 2701 06-2016 

Vogtle Thomson 70 500 3464 06-2015 

Woodlore Battlefield 3 230 866 06-2009 

Brambleton Greenway 11 230 796 05-2008 

Bennettsville Bennettsville (PEC) 2 230 956 05-2008 

Clarendon Rosslyn 1 230 600 05-2008 

Durham Falls 8 230 1195 06-2008 

Cross Aiken 88 230 956 06-2008 

Kingstree Lake City 13 230 956 01-2009 

Denny Terrace Pineland 8 230 950 05-2009 

Rockingham Wadesboro Bowman 

School 12 230 1256 06-2009 

Bristers Gainesville 15 230 1047 06-2009 

Chickahominy Old Church 16 230 797 11-2009 

A M Williams Mt Pleasant 17 230 352 05-2010 

Hamilton Pleasant View 12 230 800 05-2010 

Harrisonburg Valley 11 230 797 05-2010 

Clinton Lee 26 230 628 06-2010 

Chickahominy Lanexa 14 230 722 06-2010 

Asheville Enka 5 230 566 12-2010 

Rockingham West End 38 230 1195 06-2011 

Kinston DuPont Greenville 30 230 628 06-2011 

Asheboro Pleasant Garden 22 230 1195 06-2011 

Harris RTP 22 230 1195 06-2011 

Pleasant Garden Asheboro 20 230 1100 06-2011 

Rockingham Lilesville 14 230 1195 06-2011 

Loudoun Mt Storm 100 500 3450 06-2011 

Carson Suffolk 50 500 3450 06-2011 

Suffolk Thrasher 26 230 1047 06-2011 

Bristers Garrisonville 13 230 1047 06-2011 

Gainesville Remington 25 230 1047 04-2012 

Pepperhill Summerville 7 230 950 05-2012 

Elizabeth City Shawboro 10 230 1047 06-2012 

Winyah Campfield 14 230 956 12-2012 

Canadys Church Creek 38 230 950 12-2013 

Canadys Pepperhill 35 230 950 12-2013 

Pepperhill Church Creek 16 230 950 12-2013 

VACAR 

VC Summer VC Summer #2 1 230 950 12-2013 
Major Transmission Projects > 200 kV

283 2008 Long-Term Reliability Assessment 

VC Summer VC Summer #2 1 230 950 12-2013 

Canadys Church Creek -38 230 352 12-2013 

Reeves Avenue Sewells Point 11 230 1047 05-2015 

Landstown Virginia Beach 11 230 800 05-2015 

Clark Idylwood 4 230 515 05-2015 

VC Summer Killian 38 230 950 12-2015 

VC Summer #2 Lake Murray 19 230 950 12-2015 

Denny Terrace Lyles 3 230 950 12-2015 

Urquhart Graniteville 18 230 950 05-2016 

Urquhart Graniteville -38 230 352 05-2016 

Bristers Possum Point 35 500 3464 05-2016 

Chesterfield Midlothian 22 230 1047 05-2016 

Cape Fear Siler City 30 230 628 06-2017 

Florence Marion (PEC) 26 230 628 06-2017 

SPP 

Blackberry Chouteau 108 345 1099 06-2010 

Chouteau GRDA1 5 345 1099 06-2010 

Chamber Springs Tonitown 14 345 1176 06-2008 

Turk NW Texarkana 34 345 1778 06-2011 

Centerton Oasge Creek 41 345 440 06-2016 

Sooner OK/KS Border 53 345 1052 12-2010 

Valiant Hugo 19 345 956 12-2008 

Wichita Reno County 40 345 1468 12-2008 

Reno County Summit 51 345 956 12-2009 

Rose Hill OK/KS Border 53 345 1052 12-2010 

Potash Junction 

Interchange Pecos Interchange 16 230 541 06-2009 

Seven Rivers Interchange Pecos Interchange 18 230 541 06-2009 

Pringle Interchange Hitchland 34 230 541 12-2010 

Moore Co Hitchland 50 230 541 12-2010 

Hitchland Perryton 35 230 541 12-2010 

ELK CITY Stateline 6 48 230 351 06-2010 

Grapevine Interchange Stateline 6 48 230 351 06-2010 

Mustang Station Seminole 21 230 541 06-2009 

Hobbs Seminole 45 230 541 06-2010 

WECC 

Montana Alberta 80 230 TBD 05-2009 

Montana Alberta 135 230 TBD 05-2009 

Northwest Alberta 

Reinforcement 83 144 330/422 04-2010 

Northwest Alberta 

Reinforcement 145 240 TBD 04-2010 

Midpoint Boise Bench: Loop 

King 80 230 TBD 06-2010 

Populus Terminal 135 345 TBD 06-2010 

Gonder Harry Allen 250 525 3000 06-2012 

Northwest Alberta 

Reinforcement 135 144 TBD 04-2011 

East Kootenay 

Reinforcement 80 230 TBD 10-2011 

NWPP 

Edmonton 

Calgary 

Transmission 

Reinforcement 

206 500 3000 11-2011 
Major Transmission Projects > 200 kV

284 2008 Long-Term Reliability Assessment 

Rock Springs, WY American Falls, ID 1041 500 TBD 06-2012 

Hemingway Boardman 202 500 3000 06-2012 

Mountain States 

Transmission 

Intertie 

 460 500 1500 01-2013 

Pearl Transmission 

Station 78 230 394 05-2014 

Shoshone, ID Walters Ferry, ID 126 500 3000 06-2014 

Nicola, BC Meridian, BC 153 500 TBD 10-2014 

Donkey Creek Pumpkin Buttes 75 230 TBD 10-2008 

Hughes Sheridan 105 230 460 12-2009 

Miracle Mile Ault 146 239 402 12-2009 

Comanche Midway 50 230 506 05-2010 

Comanche Daniels Park 125 345 1200 05-2010 

Comanche Daniels Park 125 345 1200 05-2010 

Midway Waterton 82 345 1200 11-2010 

San Luis Valley Walsenburg 80 230 613 12-2011 

RMPA 

Pawnee Smoky Hill 96 345 735 05-2013 

Southeast Valley 

Project 51 500 1405 06-2008 

Navajo 

Transmission 

Project 

 189 500 1300 04-2009 

Navajo 

Transmission 

Project 

 62 500 1300 12-2010 

Southeast Valley 

Project 87 500 1405 05-2011 

Centennial II 

Project 61 525 3000 06-2011 

Navajo 

Transmission 

Project 

 218 500 1300 12-2011 

Palo Verde North Gila 115 500 1200 06-2012 

AZ / NM / SNV 

Tortolita Vail 60 345 925 06-2014 

Metcalf Moss Landing 

Reconductoring 70 230 TBD 12-2008 

Big Creek 3 Rector 75 230 460 04-2009 

Palo Verde Devers 225 500 TBD 06-2011 

IPPDC Upgrade 488 ± 500 TBD 07-2009 

Sunrise Powerlink 

(IV-Central) 100 500 TBD 06-2011 

Barren Ridge Castaic 72 230 TBD 07-2005 

Barren Ridge Castaic 234 230 TBD 07-2005 

Green Path North 85 500 TBD 11-2013 

La Jovita, MX La Herradura MX 50 230 430 10-2013 

CA / MX 

El Cañon, MX El Ciprés, MX 52 230 430 06-2015 
Major Transmission Projects > 200 kV

285 2008 Long-Term Reliability Assessment 

Transformers 

Transformer Project 

Name 

HighSide 

Voltage 

(kV) 

LowSide 

Voltage 

(kV) 

InService 

Date(s)

Description/Status 

ERCOT 

Seagoville Switch 345/138 kV 

autotransformer 345 138 12-2008 Replace the existing 345/138 kV autotransformer 

Roanoke Switching Station #1 

345/138 kV autotransformer 

replacement 

345 138 05-2009 Replace existing 345/138 kV autotransformer 

Tyler Grande 345/138 kV 

Switching Station 345 138 05-2009 

Construct switching station and install a 345/138 

kV autotransformer, 138 kV capacitor and 138 kV 

series reactor 

Second Whitney 345/138 

Autotransformer 345 138 09-2009 Install second 450MVA 345/138KV auto at Whitney 

Second Concord 345/138 

Autotransformer 345 138 09-2009 Install second 300MVA 345/138KV auto at Concord 

CenterPoint Energy/TNMP Alvin 

interconnection 345 138 10-2009 

Build a new 345 kV, 3 breaker ring bus South 

Alvin substation looped into ckt.99 P.H. Robinson 

- Oasis. Add 345/138 kV autotransformer at new 

South Alvin substation interconnect with TNMP 

138 kV North Alvin bus. 

Skyline - Install a Third 345kV 

Autotransformer 345 138 11-2009 Install one 600 MVA autotransformer. 

Lobo, build 345 kV for 675MVA 

autotransformer 345 138 12-2009 

Construct new Laredo Lobo to San Miguel 345 kV 

line with Laredo Lobo 345/138 kV substation 

where the existing Falfurrias to Laredo 138 kV and 

the Freer to Laredo 69 kV transmission lines cross 

Highway 59, rebuild Laredo Lobo to Laredo 138 

kV line and convert Lobo to Laredo 69 kV line 

section to 138 kV 

Eagle Mountain 345/138 kV 

autotransformer 345 138 05-2010 Install second 345/138 kV autotransformer 

Rothwood 345/138 kV substation 345 138 05-2010 

Build a new 345/138 kV Rothwood substation. 

Loop ckt.74 Kuykendahl to King and 138 kV 

ckt.66 Rayford tap section into the new substation. 

Add one 800 MVA 345/138 kV autotransformer at 

Rothwood substation. 

Hutto Switch and 345/138 kV 

autotransformer 345 138 06-2010 Create 345 kV switching station and install a 345/138 kV autotransformer 
Major Transmission Projects > 200 kV

286 2008 Long-Term Reliability Assessment 

Transformer Project 

Name 

HighSide 

Voltage 

(kV) 

LowSide 

Voltage 

(kV) 

InService 

Date(s)

Description/Status 

Lytton Springs Autotransformer 

Addition 345 138 06-2010 

Add a new 345-138 kV 478 MVA autotransformer 

at the Lytton Springs substation (9074). Terminate 

the Mendoza (7325) - Turnersville (7500) 138 kV 

transmission line (T-382) into the Lytton Springs 

substation 138 kV bus (9075), creating the new 

Turnersville (7500) - Lytton Springs (9075) and 

Mendoza (7325) - Lytton Springs (9075) 138 kV 

transmission lines. Upgrade the new Turnersville 

(7500) - Lytton Springs (9075) 138 kV 

transmission line from 795 ACSR (220MVA) to 

1433 ACSS/TW (507 MVA). Upgrade the new 

Mendoza (7325) - Lytton Springs (9075) 138 kV 

transmission line from 795 ACSR (220 MVA) to 

bundled 795 ACSR (440 MVA). 

Sargent Road 345/138 kV 

autotransformer 345 138 05-2011 Install second 345/138 kV autotransformer 

N Edinburg to Frontera, build 345 

kV dbl crct Line 345 138 05-2011 

Addition North Edinburg to Frontera 345 kV line 

with bundled 1590 ACSR and double circuit 

capable structures and 345/138 kV substation at 

Frontera 

2nd Lewisville Auto 345 06-2011 Install (2nd) 345/138 kV autotransformer at 

Lewisville station 

Gilleland 345/138kV 

autotransformer 345 138 06-2011 Install a 600 MVA 345/138kV autotransformer at the new Gilleland switching substation 

Gilleland 345/138 kV Project 345 138 06-2012 

Establish a 345kV switching station adjacent to 

LCRA's Gilleland station. Establish a new 138kV 

circuit from Gilleland to Techridge and maintain a 

normally close tie between AEN and LCRA's 

switchyard at Gilleland. 

Dunlap Autotransformer 345 138 08-2012 

The original proposal is to add the 3rd 

autotransformer at Austrop. The extended outage 

necessary for the project has resulted in the 

alternative to install a 600MVA auto at the Dunlap 

substation. The Clear Springs to Gilleland 345kV 

circuit will terminate on the 345kV bus at Dunlap. 

In addition, the existing ckt 921 will be converted 

to 345kV and terminate at the 345kV bus at 

Dunlap. 

Cagnon - Install a Third 345kV 

Autotransformer 345 138 06-2013 Install one 600 MVA autotransformer. 

North McCamey Three 345/138 

kV autotransformers 345 138 06-2013 12/02 plan recommends the addition of Three 345/138kV autotransformers North McCamey 

Lobo to Rio Bravo, build 345 kV 

line 345 138 06-2013 

Construct 345 kV line from Lobo to Rio Bravo and 

add 345/138 kV substation at Rio Bravo with 

345/138 kV autotransformer 
Major Transmission Projects > 200 kV

287 2008 Long-Term Reliability Assessment 

Transformer Project 

Name 

HighSide 

Voltage 

(kV) 

LowSide 

Voltage 

(kV) 

InService 

Date(s)

Description/Status 

Zorn Autotransformer Addition 345 138 06-2013 Add a new 345-138 kV 478 MVA autotransformer 

at the Zorn substation (7042). 

Rio Bravo, 345 kV SS with 

345/138 kV autotransformer 345 138 03-2015 

Construct 345 kV line from Lobo to Rio Bravo and 

add 345/138 kV substation at Rio Bravo with 

345/138 kV autotransformer 

Frontera, add SS with 345/138 kV 

autotransformer 345 138 03-2015 

Addition North Edinburg to Frontera to South 

McAllen 345 kV line with bundled 1590 ACSR 

conductor and double circuit capable structures 

and 345/138 kV substation at Frontera 

Sol, Build 345 KV SS 345 138 03-2015 

Construct 345 kV line from Rio Bravo to Sol to N 

Edinburg and add 345/138 kV substation at Rio 

Bravo with 345/138 kV autotransformer 

Trinity Switch 345/138 kV 

autotransformer 345 138 05-2015 Create Trinity Switch and install a 600 MVA 345/138 kV autotransformer 

Lavon 345/138 kV Switching 

Station 345 138 05-2015 Construct 345/138 kV switching station 

Liggett 345/138 kV 

autotransformer 345 138 05-2015 Replace the existing 450 MVA 345/138 kV autransformer 

Collin 345/138 kV 

autotransformer 345 138 05-2015 Install second 345/138 kV autotransformer 

North Lake 345/138 kV 

autotransformer 345 138 05-2015 Install a 345/138 kV autotransformer 

Loma Alta 345kV station and 

autotransformer 345 138 06-2015 Construct a 345 substation and connect to the existing Loma Alta 138 substation. 

Ranchito, New SS with 345/138 

kV autotransformer 345 138 06-2015 

Construct 345 kV line from LaPalma to Ranchito 

to South McAllen and add 345/138/69 kV 

substation adjacent to existing Cavazos 69 kV 

substation with 600 MVA 345/138 kV 

autotransformer 

South McAllen, new SS with 

345/138 kV autotransformer 345 138 06-2015 

Add Frontera to South McAllen 345 kV line with 

bundled 1590 ACSR and double circuit capable 

structures and 345/138 kV substations at Frontera 

and South McAllen 

FRCC 

Central Florida south transformer 500 230 Summer 

2016 Planned 

Alico transformer 230 138 Winter 

2008/09 Planned 

Buckingham transformer 230 138 Winter 

2009/10 Planned 

Normandy transformer 230 138 Summer 

2008 Active 

Center Park transformer 230 138 Summer 

2010 Planned 
Major Transmission Projects > 200 kV

288 2008 Long-Term Reliability Assessment 

Transformer Project 

Name 

HighSide 

Voltage 

(kV) 

LowSide 

Voltage 

(kV) 

InService 

Date(s)

Description/Status 

MRO 

Oak Creek Transformer No. 2 

(WUMS) 345 138 2009 Add 2nd Transformer / Planned 

Kewaunee Transformer No. 2 

(WUMS) 345 138 2011 Add 2nd Transformer / Provisional 

West Middleton Transformer No. 

1 (WUMS) 345 138 2013 New Transformer / Planned 

North Randolph Transformer No. 

1 (WUMS) 345 138 2018 New Transformer / Provisional 

Shell Creek Transformer (NE) 345 230 2008 New Transformer / Planned 

Hoskins Transformer (NE) 345 230 2008 New Transformer / Planned 

Columbus East Transformer (NE) 345 115 2010 New Transformer / Planned 

Grand Island Transformer (NE) 345 230 2009 New Transformer / Planned 

North Platte Transformer (NE) 230 115 2009 New Transformer / Planned 

NW68th&Holdrege Transformer 

(NE) 345 115 2010 New Transformer / Proposed 

Salem 345/161 kV transformer 

(IA) 345 161 2009 New Transformer / Planned 

Hazleton 345/161 kV transformer 

#1 (IA) 345 161 2010 New Transformer / Planned 

Lore 345/161 kV transformer (IA) 345 161 2012 New Transformer / Planned 

South-Central Saskatchewan 

(SPC) 230 138 2010 New Transformer / Planned 

Transcona Transformer (MH) 230 66 2010 New Transformer / Planned 

Transcona Transformer2 (MH) 230 66 2010 New Transformer / Planned 

Stanley Transformer (MH) 230 66 2010 New Transformer / Planned 

Neepawa Transformer (MH) 230 66 2011 New Transformer / Proposed 

Riel Transformer (MH) 500 230 2012 New Transformer / Planned 

NPCC 

Fitzwilliam 345 115 12-2008 Under Construction 

Wachusett 345 115 06-2011 Planned 

Berry Street 345 115 03-2011 Concept 

Norwalk 345 115 12-2008 Under Construction 

Singer 345 115 12-2009 Under Construction 

Singer 345 115 12-2009 Under Construction 

Wakefield Junction 345 115 06-2009 Under Construction 

Wakefield Junction 345 115 06-2009 Under Construction 

Wakefield Junction 345 115 06-2009 Under Construction 

Wakefield Junction 345 115 06-2009 Under Construction 
Major Transmission Projects > 200 kV

289 2008 Long-Term Reliability Assessment 

Transformer Project 

Name 

HighSide 

Voltage 

(kV) 

LowSide 

Voltage 

(kV) 

InService 

Date(s)

Description/Status 

Auburn Street 345 115 06-2010 Concept 

Lapeer 345 115 2010-

Winter Planned 

Lapeer 345 115 2010-

Winter Planned 

Lovett 345 138 Before 

2013 Planned 

RFC 

Cumberland 230 138 05-2009 New 

Marquis 345 138 06-2009 Add 450 MVA 

Conesville 345 138 12-2008 New 675 MVA 

Jug Street 345 138 12-2009 New 450 MVA 

Twin Branch 345 138 06-2009 New 675 MVA 

Matt Funk 345 138 06-2011 New 675 MVA 

Sporn 345 138 12-2009 New 450 MVA 

Prexy 500 138 06-2011 New 

Kammer 765 500 11-2009 Replacement 

Doubs Bank #2 500 230 05-2011 Replacement 

Doubs Bank #3 500 230 05-2011 Replacement 

Doubs Bank #4 500 230 05-2011 Replacement 

Waugh Chapel 500 230 06-2012 Replacement 

Lisle 345 138 05-2010 New 

Qualitech 345 138 06-2010 New 

Logans Ferry 345 138 06-2010 New 

Brady 345 138 06-2012 New 

Red Lion 230 138 05-2009 New 300 MVA 

Indian River 230 138 06-2011 New 

Avon 345 138 06-2009 New 400 MVA 

Tangy 345 138 06-2009 New 

Cranberry 500 138 06-2013 New 600 MVA 

Worthington 161 138 09-2009 Add capacity 

Decatur Switch Station 161 138 12-2009 New 

Bunce Creek 220 220 05-2009 Replace failed PAR 

Tallmadge #3 345 138 12-2008 New 

Richland 345 138 04-2009 New 
Major Transmission Projects > 200 kV

290 2008 Long-Term Reliability Assessment 

Transformer Project 

Name 

HighSide 

Voltage 

(kV) 

LowSide 

Voltage 

(kV) 

InService 

Date(s)

Description/Status 

Hiple #2 345 138 08-2008 New 

St. John #2 345 138 12-2011 New 

Brighton #2 500 230 06-2009 New 

Burches Hill #2 500 230 06-2011 New 

Burches Hill #3 500 230 12-2011 New 

Brighton 500 230 06-2012 Replacement 

Metuchen 230 138 01-2009 New 

Roseland 230 138 06-2009 Upgrade 

Roseland 230 138 02-2010 Upgrade 

Roseland #1 500 230 06-2012 New 

Roseland #2 500 230 06-2012 New 

Brown 345 138 12-2012 New 

SERC 

Rutherford 500kV Substation 500 161 06-2010 Planned 

Jackson 500kV Substation 500 161 06-2011 Planned 2nd Transformer 

Clay County, MS 500kV 

Substation 500 161 06-2011 Planned 

Hardin County 345kV Substation 345 138 05-2011 Planned-2nd Transformer 

Middletown 345kV Substation 345 138 05-2017 Planned-4th Transformer 

West Garrard 345kV Substation 345 12-2009 Planned 

JK Smith Power Plant 345 138 2008 Planned 

Marion County 161kV Substation 161 138 2008 Planned 

Brookline 345 kV Substation 345 161 Summer 

2008 Planned 

Joachim Substation 345 138 Fall 

2008 Planned 

Gray Summit Substation 345 138 Winter 

2010 Planned-2nd Transformer 

South Bloomington, (IL) 

Substation 345 138 Winter 2012 PlannedFargo (Northwest Peoria, IL) 

Substation 345 138 Winter 

2013 Proposed 

Bonaire 230/115 kV Transformer 230 115 Fall 

2008 Planned-Replacement 

Sinai Cemetery 230/115 kV 

Transformer 230 115 Summer 2008 Planned 

Gordon 230/115 kV Transformer 230 115 Summer 

2008 Planned 

Miller Bayou 230/115 kV 

Transformer 230 115 Summer 

2008 Planned 

Boulevard 230/115 kV 

Transformer 230 115 Winter 2008 Planned 
Major Transmission Projects > 200 kV

291 2008 Long-Term Reliability Assessment 

Transformer Project 

Name 

HighSide 

Voltage 

(kV) 

LowSide 

Voltage 

(kV) 

InService 

Date(s)

Description/Status 

Elsanor 230/115 kV Transformer 230 115 Summer 

2009 Planned 

Thompson 500/230 kV 

Transformer 500 230 Summer 

2010 Planned 

Brentwood 230/115 kV 

Transformer 230 115 Summer 2010 Planned 

Deptford 230/115 kV Transformer 230 115 Summer 

2011 Planned 

Lansing Smith 230/115 kV 230 115 Summer 

2011 Planned 

Smyrna 230/115 kV Transformer 230 115 Summer 

2011 Planned 

Santa Rosa 230/115 kV 

Transformer 230 115 Summer 2012 Planned 

Peachtree 230/115 kV 

Transformer 230 115 Summer 

2012 Planned 

Meldrim 230/115 kV Transformer 230 115 Summer 

2012 Planned 

Jct-57a 230/115 kV Transformer 230 115 Summer 

2013 Planned 

Gainesville #2 230/115 kV 

Transformer 230 115 Summer 

2013 Planned 

Nelson 230/115 kV Transformer 230 115 Summer 

2013 Planned 

Sweatt 230/115 kV Transformer 230 115 Summer 

2013 Planned 

Buzzard Roost 230/115 kV 

Transformer 230 115 Summer 

2013 Planned 

Greene County 230/115 kV 

Transformer 230 115 Summer 

2013 Planned 

East Point 230/115 kV 

Transformer 230 115 Summer 2014 Planned 

JC Penney 230/115 kV 

Transformer 230 115 Summer 2014 Planned 

McDonough 230/115 kV 

Transformer 230 115 Summer 

2014 Planned 

McConnel Road 230/115 kV 

Transformer 230 115 Summer 2014 Planned 

Roswell 230/115 kV Transformer 230 115 Summer 

2014 Planned 

South Cleveland 230/115 kV 

Transformer 230 115 Summer 

2014 Planned 

South Macon 230/115 kV 

Transformer 230 115 Summer 

2014 Planned 

McIntosh 230/115 kV 

Transformer 230 115 Summer 2015 Planned 

Offerman 230/115 kV 

Transformer 230 115 Summer 

2015 Planned 

O’Hara 500/230 kV Transformer 500 230 Summer 

2016 Planned 

Middlefork 500/230 kV 

Transformer 500 230 Summer 2016 Planned 

Arkwright 230/115 kV 

Transformer 230 115 Summer 2016 Planned 

Woodstock 230/115 kV 

Transformer 230 115 Summer 

2016 Planned 

Slappy Drive 230/115 kV 

Transformer 230 115 Summer 2016 Planned 
Major Transmission Projects > 200 kV

292 2008 Long-Term Reliability Assessment 

Transformer Project 

Name 

HighSide 

Voltage 

(kV) 

LowSide 

Voltage 

(kV) 

InService 

Date(s)

Description/Status 

County Line Road 230/115 kV 

Transformer 230 115 Summer 

2017 Planned 

Silverhill 230/115 kV 

Transformer 230 115 Spring 

2018 Planned 

Holt 230/115 kV Transformer 230 115 Summer 

2018 Planned 

Bay Creek 230/115 kV 

Transformer 230 115 Summer 2018 Planned 

Bluffton 230/115 kV Substation 230 115 Summer 

2008 Planned-Replacement 

Durham 500 kV Substation 500 Summer 

2008 Planned 

Hopkins 230/115 kV Substation 230 115 Summer 

2008 Planned 

SPP 

Southwest Shrevport 345 kV 

Transformer 345 138 Spring 2009 Planned 

Turk 345 kV Transformer 345 138 Summer 

2011 Planned 

Centerton 345/161kV 

Transformer 345 161 Summer 2014 Planned 

Flint Creek 345/161 kV 

Transformer 345 161 Summer 

2010 Planned 

Osage Creek 345/161kV 

Transformer 345 161 Summer 

2014 Planned 

Johnson Coutny 345/138 kV 

Transformer 345 138 Summer 2011 Planned 

Valiant 345/138 kV Transformer 345 138 Summer 

2010 Planned 

Hitchland 345/230 kV 

Transformer 345 230 Summer 

2010 Planned 

Reno County 345/115 kV Ckt 1 

Transformer 345 115 Winter 2008 Planned 

Reno County 345/115 kV Ckt 2 

Transformer 345 115 Winter 2009 Planned 

Stranger Creek 345/115 kV #2 

Transformer 345 115 Summer 

2009 Planned 

Rose Hill 345/138 kV #3 

Transformer 345 138 Summer 

2011 Planned 

Spearville 345/230 kV #2 

Transformer 345 230 Winter 2013 Planned 

West Gardner 345/161 kV 

Transformer 345 161 Summer 

2008 Planned 

WECC 

Mora Substation 230 138 05-2008 230/138 kV auto-transformer. 

Mill Creek Phase Shifter 230 - 06-2008 Phase Shifter 

Lower Valley Reinforcement 

Project (Hooper Springs) 138 - 10-2008 A 138/115 kV transformer. Part of the Lower Valley Project. Joint project with PAC. 
Major Transmission Projects > 200 kV

293 2008 Long-Term Reliability Assessment 

Transformer Project 

Name 

HighSide 

Voltage 

(kV) 

LowSide 

Voltage 

(kV) 

InService 

Date(s)

Description/Status 

Three Peaks 345/138kV 

transformer 345 138 06-2009 

Oquirrh 345kV/138kV 

transformer 345 138 06 2009 Capacity addition for potential Vineyard area generation addition. 

Caribou 345kV/138kV 

transformer 345 138 06-2009 Transformer to be located at new Caribou 345 kV Substation 

Sunset Auto-transformer 230 - 06-2009 

Install a 230/115 kV, 320 MVA auto transformer at 

Sunset Substation and construct a new 230 kV line 

from Keeler Sub to Sunset Sub. 

King Substation 230 138 06-2010 

Terminal 345/138kV transformer 

#1 345 138 05-2012 

Terminal 345/138kV transformer 

#2 345 138 05-2012 

Gateway West Transm. 500 345 06-2012 

Midvalley 345/138kV transformer 

#1 345 138 05-2013 

Midvalley 345/138kV transformer 

#2 345 138 05-2013 

Selkirk Transformer Addition 500 230 10-2008 Add transformer T4 

Montana - Alberta Tie 230 - 05-2009 

Selkirk Transormer Addition 500 230 10-2010 Add transformer T4 

West Loop Switching Station 345 230 06-2008 345 / 230 kV transformer. 

Palo Verde – Pinal West Project 500 - 05-2008 

Southeast Valley Project 230 - 05-2008 

McDonald 230/138kV 

Transformer 230 138 03-2009 Load service to McDonald 

Springerville #4 500 - 05-2009 

Northwest 230/138 kV 

Transformer 230 138 06-2009 

Sinatra 230/138 kV Transformer 230 138 06-2009 

Northwest 500/230 kV 

Transformer 500 230 06-2010 

Sunrise 500/230 kV Transformer 500 230 06-2011 

Southeast Valley Project 500 - 06-2011 

Lone Tree Substation 

Interconnection 230 - 05-2008 Meet customer demand and improve service reliability. 

Rancho Vista Substation 500 230 06-2009 500/230 kV transformer bank. 

Rancho Vista Substation 500 230 06-2009 500/230 kV transformer bank. 

Sunrise Powerlink 230 230 06-2011 New substation, 500/230kV 500/230/12 kV xfmr 

banks 

Sunrise Powerlink 500 230 06-2011 New substation, 500/230kV 500/230/12 kV xfmr 

banks 
Report Content Responsibility

294 2008 Long-Term Reliability Assessment 

Report Content Responsibility 

 

The following NERC industry groups have provided input into NERC’s 2008 Long-Term 

Reliability Assessment: 

 

NERC Group Relationship Contribution Action 

 

Planning Committee (PC) Reports to NERC’s 

Board of Trustees 

• Review 2008 LTRA 

• Risk Assessment of 

Emerging Issues 

• Improvement Plan 

• Endorse 

• Completed

• Approve 

Reliability Assessment 

Improvement Task Force 

Reports to the PC • Develop Reliability 

Enhancement Plan 

• Report 

Reliability Assessment 

Subcommittee (RAS) 

Reports to the PC • Peer Reviews 

• Develop Emerging Issues 

• Report 

• Completed

Data Coordination 

Working Group 

Report to RAS • Develop data and 

regional reliability 

narrative requests 

• Completed

Load Forecasting Working 

Group 

Reports to RAS • Develop load forecasting 

bandwidths 

• Completed

Resource Issues 

Subcommittee (RIS) 

Reports to PC • Develop Emerging Issues 

• Demand Resources 

• Completed

• Report 

Demand Side 

Management Task 

Force 

Reports to RIS • Demand Reponses 

collection taxonomy 

• Completed

Operating Committee 

(OC) 

Reports to NERC’s 

Board of Trustees 

• Reviewed Reliability 

Trends section 

• Completed

Reliability Metrics Working 

Group 

Reports to the PC 

and OC 

• Reviewed the reliability 

trends Metrics 

• Completed

Integration of Variable 

Generation Task Force 

Reports to the PC 

and OC 

• Integration of variable 

generation 

• Ongoing 

Board of Trustees NERC’s Independent 

Board 

● Review the 2008 LTRA 

● Approve for publication 

• Completed
Reliability Assessment Subcommittee

295 2008 Long-Term Reliability Assessment 

Reliability Assessment Subcommittee 

Chair William O. Bojorquez 

Consultant 

Hunt Transmission Services, L.L.C. 

701 Brazos Street, Suite 970 

Austin, TX 78701-2559 

(512) 721-2653 

(512) 721-2656 Fx 

bbojorquez@hunttr

ansmission.com 

 

Vice Chair Mark J. Kuras 

Senior Engineer, NERC and 

Regional Coordination 

PJM Interconnection, L.L.C. 

955 Jefferson Avenue 

Valley Forge Corporate Center 

Norristown, Pennsylvania 19403-2497 

(610) 666-8924 

(610) 666-4779 Fx 

kuras@pjm.com 

 

ERCOT Dan Woodfin 

Director, System Planning 

Electric Reliability Council of Texas, Inc. 

2705 West Lake Drive 

Taylor, Texas 76574 

(512) 248-3115 

(512) 248-4235 Fx 

dwoodfin@ 

ercot.com 

 

FRCC Vince Ordax 

Transmission Planning 

Engineer 

Florida Reliability Coordinating Council 

1408 N. Westshore Boulevard 

Suite 1002 

Tampa, Florida 33607-4512 

(813) 207-7988 

(813) 289-5646 Fx 

vordax@frcc.com 

 

MRO Hoa Nguyen 

Resource Planning 

Coordinator 

Montana-Dakota Utilities Co. 

400 North Fourth Street 

Bismarck, North Dakota 58501 

(701) 222-7656 

(701) 222-7970 Fx 

hoa.nguyen@ 

mdu.com 

 

NPCC John G. Mosier, Jr. 

AVP-System Operations 

Northeast Power Coordinating Council, Inc. 

1515 Broadway 

43rd Floor 

New York, New York 10036-8901 

(212) 840-1070 

(212) 302-2782 Fx 

jmosier@npcc.org 

 

RFC Bernard M. Pasternack, P.E. 

Managing Director - 

Transmission Asset 

Management 

American Electric Power 

700 Morrison Road 

Gahanna, Ohio 43230-8250 

(614) 552-1600 

(614) 552-2602 Fx 

bmpasternack@ 

aep.com 

 

SERC Hubert C. Young 

Manager of Transmission 

Planning 

South Carolina Electric & Gas Co. 

1426 Main Street 

MC 034 

Columbia, South Carolina 29201 

(803) 217-9129 

(803) 933-7264 Fx 

 

SPP Mak Nagle 

Manager of Technical 

Studies & Modeling 

Southwest Power Pool 

415 North McKinley 

Suite 140 

Little Rock, Arkansas 72205-3020 

(501) 614-3564 

(501) 666-0376 Fx 

mnagle@spp.org 

 

WECC James Leigh-Kendall 

Regulatory Compliance 

Officer 

Sacramento Municipal Utility District 

Mail Stop D113 

P.O. Box 15830 

Sacramento, California 95852-1830 

(916) 732-5357 

(916) 732-7527 Fx 

jleighk@smud.org 

 

WECC Christopher S Smart 

Staff Engineer 

Western Electricity Coordinating Council 

615 Arapeen Drive 

Suite 210 

Salt Lake City, Utah 84108-1262 

(801) 883-6865 

(801) 824-0129 Fx 

csmart@wecc.biz 
Reliability Assessment Subcommittee

296 2008 Long-Term Reliability Assessment 

 

IOU & 

DCWG Chair 

K. R. Chakravarthi 

Manager, Interconnection 

and Special Studies 

Southern Company Services, Inc. 

13N-8183 

P.O. Box 2641 

Birmingham, Alabama 35291 

(205) 257-6125 

(205) 257-1040 Fx 

krchakra@ 

southernco.com 

 

ISO/RTO John Lawhorn, P.E. 

Director, Regulatory and 

Economic Standards 

Transmission Asset 

Management 

Midwest ISO, Inc. 

1125 Energy Park Drive 

St. Paul, Minnesota 55108 

(651) 632-8479 

(651) 632-8417 Fx 

jlawhorn@ 

midwestiso.org 

 

ISO/RTO Peter Wong 

Manager, Resource 

Adequacy 

ISO New England, Inc. 

One Sullivan Road 

Holyoke, Massachusetts 01040-2841 

(413) 535-4172 

(413) 540-4203 Fx 

pwong@isone.com 

Canadian-AtLarge 

Daniel Rochester, P. Eng. 

Manager, Reliability 

Standards and Assessments 

Independent Electricity System Operator 

2635 Lakeshore Road, West 

Mississauga, Ontario L5J 4R9 

(905) 855-6363 

(905) 403-6932 Fx 

dan.rochester@ 

ieso.ca 

 

FERC Sedina Eric 

Electrical Engineer 

Federal Energy Regulatory Commission 

888 First Street, NE, 91-11 

Washington, D.C. 20426 

(202) 502-6441 

(202) 219-1274 Fx 

sedina.eric@ 

ferc.gov 

DOE Patricia Hoffman 

Acting Director Research 

and Development 

Department of Energy 

1000 Independence Avenue 

SW 6e-069 

Washington, D.C. 20045 

(202) 586-1411 

patricia.hoffman@ 

hq.doe.gov 

 

LFWG Chair Yves Nadeau 

Manager, Load and 

Revenue Forecasting 

Hydro-Quebec 

Complexe Desjardins, Tour Est 

25 etage -- Case postale 10000 

Montreal, Quebec H5B 1H7 

(514) 879-6228 

nadeau.yves@ 

hydro.qc.ca 

 

Alternate 

SERC 

Herbert Schrayshuen 

Director Reliability 

Assessment 

SERC Reliability Corporation 

2815 Coliseum Centre Drive 

Charlotte, North Carolina 28217 

(704) 940-8223 

(315) 428 5114 Fx 

hschrayshuen@ 

serc1.org 

 

Alternate 

FRCC 

John E. Odom, Jr. 

Manager of System 

Planning 

Florida Reliability Coordinating Council 

1408 N. Westshore Blvd. 

Suite 1002 

Tampa, Florida 33607 

(813) 207-7985 

(813) 289-5646 Fx 

jodom@frcc.com 

 

Alternate 

MRO 

John Seidel 

Manager of Reliability 

Assessment 

Midwest Reliability Organization 

2774 Cleveland Avenue 

Roseville, MN 55113 

(651)855-1716 

(651) 855-1712 Fx 

ja.seidel@midwest

reliability.org 

 

RFC Jeffrey L. Mitchell 

Director - Engineering 

ReliabilityFirst Corporation 

320 Springside Drive 

Suite 300 

Akron, Ohio 44333 

(330) 247-3043 

(330) 456-3648 Fx 

jeff.mitchell@ 

rfirst.org 

 
Reliability Assessment Subcommittee

297 2008 Long-Term Reliability Assessment 

Alternate 

RFC 

Paul D. Kure 

Senior Consultant, 

Resources 

ReliabilityFirst Corporation 

320 Springside Drive 

Suite 300 

Akron, Ohio 44333 

(330) 247-3057 

(330) 456-3648 Fx 

paul.kure@ 

rfirst.org 

 

Alternate 

SPP 

Jay Caspary 

Director, Engineering 

Southwest Power Pool 

415 North McKinley 

Suite 140 

Little Rock, Arkansas 72205 

(501) 614-3220 

(501) 666-0376 Fx 

jcaspary@spp.org 

 

NERC Dave Nevius 

Senior Vice President and 

Director of Reliability 

Assessment and 

Performance Analysis 

North American Electric Reliability 

Corporation 

116-390 Village Boulevard 

Princeton, New Jersey 08540-5721 

(609) 452-8060 

(609) 452-9550 Fx 

dave.nevius@ 

nerc.net 

 

NERC Kelly Ziegler 

Manager of Communications

North American Electric Reliability 

Corporation 

116-390 Village Boulevard 

Princeton, New Jersey 08540-5721 

(609) 452-8060 

(609) 452-9550 Fx 

kelly.ziegler@ 

nerc.net 

NERC 

Analyst 

John Moura 

Technical Analyst, 

Reliability Assessments 

North American Electric Reliability 

Corporation 

116-390 Village Boulevard 

Princeton, New Jersey 08540-5721 

(609) 452-8060 

(609) 452-9550 Fx 

john.moura@ 

nerc.net 

 

NERC 

Coordinator 

Mark G. Lauby 

Manager of Reliability 

Assessments 

North American Electric Reliability 

Corporation 

116-390 Village Boulevard 

Princeton, New Jersey 08540-5721

(609) 452-8060 

(609) 452-9550 Fx 

mark.lauby@ 

nerc.net