to ensure reliability bulk power system

2010 SummerReliability Assessment

116-390 Village Blvd., Princeton, NJ 08540609.452.8060 | 609.452.9550 fax

www.nerc.com

the reliability of theto ensure

bulk power system

May 2010

Page i 2010 Summer Reliability Assessment

NNEERRCC’’ss MMiissssiioonn The North American Electric Reliability Corporation (NERC) is an international regulatory authority for reliability of the bulk power system (BPS) in North America. NERC develops and enforces Reliability Standards; assesses adequacy annually via a 10-year forecast and winter and summer forecasts; monitors the BPS; and educates, trains, and certifies industry personnel. NERC is a self-regulatory organization, subject to oversight by the U.S. Federal Energy Regulatory Commission (FERC) and governmental authorities in Canada.1 NERC assesses and reports2 on the reliability and adequacy of the North American BPS divided into the eight Regional Areas as shown on the map below (See Table A).3 The users, owners, and operators of the BPS within these areas account for virtually all the electricity supplied in the U.S., Canada, and a portion of Baja California Norte, México.

Note: The highlighted area between SPP and SERC denotes overlapping Regional boundaries. For example, some load serving entities participate in one Region and their associated transmission owner/operators in another.

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 BPS, and made compliance with those standards mandatory and enforceable. In Canada, NERC presently has memorandums of understanding in place with provincial authorities in Ontario, New Brunswick, Nova Scotia, Québec and Saskatchewan, and with the Canadian National Energy Board. NERC standards are mandatory and enforceable in Ontario and New Brunswick as a matter of provincial law. NERC has an agreement with Manitoba Hydro, making reliability standards mandatory for that entity, and Manitoba has recently adopted legislation setting out a framework for standards to become mandatory for users, owners, and operators in the province. In addition, NERC has been designated as the “electric reliability organization” under Alberta’s Transportation Regulation, and certain reliability standards have been approved in that jurisdiction; others are pending. NERC and NPCC have been recognized as standards setting bodies by the Régie de l’énergie of Québec, and Québec has the framework in place for reliability standards to become mandatory. Nova Scotia and British Columbia also have a framework in place for reliability standards to become mandatory and enforceable. NERC is working with the other governmental authorities in Canada to achieve equivalent recognition.

2 Readers may refer to the Reliability Concepts Used in this Report Section for more information on NERC’s reporting definitions and methods.

3 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.

Table A: NERC Regional Entities

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

NPCC Northeast Power Coordinating Council

WECC Western Electricity Coordinating Council

Table of Contents

2010 Summer Reliability Assessment Page ii

Table of Contents

NERC’s Mission ........................................................................................................................... i

Summary Reliability Assessment of North America ............................................................... 1

Summer Key Highlights ..................................................................................................... 1 Reliability Assessment ...................................................................................................... 2 Demand ............................................................................................................................. 3 Generation ........................................................................................................................ 8 Transmission ................................................................................................................... 10 Operational Issues .......................................................................................................... 11

Projected Demand, Resources, and Reserve Margins .......................................................... 13

Regional Reliability Assessment Highlights .......................................................................... 19

ERCOT ............................................................................................................................ 19 FRCC .............................................................................................................................. 19 MRO ................................................................................................................................ 20 NPCC .............................................................................................................................. 20 RFC ................................................................................................................................. 21 SERC .............................................................................................................................. 21 SPP ................................................................................................................................. 22 WECC ............................................................................................................................. 22

Regional Reliability Self-Assessments ................................................................................... 23

Texas Interconnection .............................................................................................................. 24

ERCOT ............................................................................................................................ 24

Western Interconnection .......................................................................................................... 31

WECC ............................................................................................................................. 31

California/México Area ........................................................................................ 41 Desert Southwest Area ....................................................................................... 44 Rocky Mountain Power Area ............................................................................... 46 Northwest Power Pool ......................................................................................... 48

Eastern Interconnection ........................................................................................................... 56

FRCC .............................................................................................................................. 56

MRO ................................................................................................................................ 62

RFC ................................................................................................................................. 74

SERC .............................................................................................................................. 83

Central ................................................................................................................. 92 Delta .................................................................................................................... 99 Gateway ............................................................................................................ 106 Southeastern ..................................................................................................... 113 VACAR .............................................................................................................. 120

SPP ............................................................................................................................... 128

MISO-RTO .................................................................................................................... 135

PJM-RTO ...................................................................................................................... 140

Table of Contents

Page iii 2010 Summer Reliability Assessment

NPCC ............................................................................................................................ 144

Maritimes ........................................................................................................... 151 New England ..................................................................................................... 156 New York ........................................................................................................... 167 Ontario ............................................................................................................... 174

Québec Interconnection ......................................................................................................... 180

Québec .............................................................................................................. 180

About This Report ................................................................................................................... 189

Reliability Concepts Used in This Report ............................................................................. 192

How NERC Defines Bulk Power System Reliability ...................................................... 192 Demand Response Concepts and Categorization ........................................................ 193

Data Checking Methods Applied ........................................................................................... 194

Terms Used in This Report .................................................................................................... 197

Abbreviations Used in This Report ....................................................................................... 207

Reliability Assessment Subcommittee Roster ..................................................................... 212

North American Electric Reliability Corporation Staff Roster ............................................ 216

Summary Reliability Assessment of North America

2010 Summer Reliability Assessment Page 1

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SSuummmmaarryy RReelliiaabbiilliittyy AAsssseessssmmeenntt ooff NNoorrtthh AAmmeerriiccaa Summer Key Highlights

An overall increase in Reserve Margins can be primarily attributed to the forecast demand reductions. Decreased economic activity across North America continues to be primarily responsible for a significant reduction in forecasted summer peak demand. Peak summer demand has decreased over 10 GW per year, for two consecutive years. While the reductions are most prevalent in the U.S., a 3.1 percent decrease is also projected in Canada.

Wind generation continues to increase, with 7,000 MW of installed nameplate capacity added since last summer, resulting in just over 37,000 MW of installed capacity currently interconnected to the bulk power system and providing approximately 4,300 MW of on-peak capacity. Industry continues to improve methods for determining expected on-peak capacity for large-scale, wind generation integration. For NERC overall, the percentage of expected on-peak wind generation capacity is less than that projected last year by nearly 4 percentage points.

For the first time in four years, participation in Demand Response decreases, reducing to just under 30,000 MW for 2010, when compared to last year. A combination of the economic recession reducing large-end use of electricity and lower overall forecast demand has decreased the need and economic incentives for Demand Response providers. In all Regions, flat or reduced Demand Response participation is expected for this summer when compared to last summer. Nonetheless, Demand Response is expected to be available and support emergency operating procedures to reduce peak demand.

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Derated Capacity On‐Peak

Expected On‐Peak Capacity

% of Nameplate Capacity Expected On‐Peak

Recession Continues to Drive Broad Decline in Forecast Demand

Peak-Reducing Demand Response Plateaus in 2010

Growth in Wind Resources Continue; Enhanced Planning Approaches Applied


Page 2 2010 Summer Reliability Assessment

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Reliability Assessment All Regional Entities indicated they project to have sufficient Reserve Margins4 to ensure reliability throughout the 2010 summer months. The summer peak Reserve Margin across North America is expected to be 28.6 percent, 3.2 percentage points higher than in 2009 and 7.9 percentage points higher than in 2008.5 The significant increase in Reserve Margin is large in part due to the reduction in peak summer demand and approximately a 0.8 percent (8,000 MW) net increase in new capacity resources since 2009. In the U.S., all Regional Entities have projected summer on-peak Reserve Margins well above the NERC Reference Margin Level6 (Figure 1a), with increases observed in almost every Region, except the U.S. portion of NPCC. Reserve Margins in Canada are also projected to remain above the NERC Reference Margin Level, though not to the extent as in 2009 (Figure 1b).7 Ontario, the only Canadian subregion that peaks during the summer months, is projecting a slight Reserve Margin increase.

For the U.S. subregions, all forecast Reserve Margins remain above NERC Reference Margin Levels (Figure 2). The VACAR subregion of SERC, while tight, appears to have sufficient reserves through the summer months. The projected SERC-Gateway and SERC-Southeastern Reserve Margin has improved since last year, both increasing about 7 percentage points and resulting in reliable reserve levels for the upcoming summer. The NWPP subregion of WECC (U.S. portion) is projecting a significant Reserve Margin reduction (21 percentage points), despite reductions in the summer peak demand forecast, when compared to last summer. This reduction is attributed to a 13,500 MW decrease in capacity resources (23 percent, when compared to Existing-Certain resources from July 2009) due to a change in hydo generation operating assumptions. NWPP is projecting an Anticipated Reserve Margin that is almost 5 percentage points higher than the NERC Reference Margin Level.

4 In this report, “Reserve Margin” represents “Planning Reserve Margin.” 5 The North American transmission system does not have the capability to transmit power across its entire expanse; therefore, a

North American Reserve Margin is only a general indicator or reference of adequate resources. 6 See the Reliability Concepts Used in this Report Section for the NERC Reference Reserve Margin Level definition. 7 Deliverable Reserve Margin, from the 2009 reliability assessment reports have been substituted with Anticipated Reserve

Margin. The definitions to this resource category and margin calculation have not changed.

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2009 Deliverable Reserve Margin2010 Anticipated Reserve MarginNERC Reference Margin Level

Figure 1a: U.S. Summer Peak Planning Reserve Margin Projections

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Figure 1b: Canada Summer Peak Planning Reserve Margin Projections



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The New York subregion of NPCC is projecting a reserve margin reduction from last summer (26.4 percent in 2009, to 22.4 percent in 2010) despite reductions in the summer peak demand forecast. This reduction is attributed to a decrease in both capacity resources (approximately 1,000 MW of retirements and reratings) and reduced power imports. Nonetheless, New York projects an Anticipated Reserve Margin for this summer, which is more than 4 percentage points higher than their NERC Reference Margin Level of 18 percent.

Demand Summer forecast8 peak demands across NERC Regional Entities and subregions appear manageable for the upcoming summer season, with a majority of the subregions showing decreases when compared to last year. (Figure 3) For the system as a whole, summer peak demand is projected to reach 814,900 MW; assuming approximately 30,000 MW of Demand Response will be available and deployed on peak.9 A key driver for the overall improvement in Reserve Margins is the substantial reduction in projected peak Net Internal Demand, representing more than a 2.2 percent decrease (18,600 MW) from last year’s projected summer peak demand and 3.9 percent (32,300 MW) since 2008.

8 A 50/50 forecast is defined as a forecast adjusted to reflect normal weather, and is expected on a 50 percent probability basis,

i.e. a peak demand forecast level which has a 50 percent probably of being under or over achieved by the actual peak. 9 This is a non-coincident value for all eight NERC Regional Entities, occurring in different months. This value will not equal

values shown on Tables 2a-2d.

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Figure 2: U.S. Subregion Summer Peak Planning Reserve Margin Projections

020,00040,00060,00080,000

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Figure 3: 2009 and 2010 Summer Peak Net Internal Demand Comparisons for Summer Peaking Subregions

2009 Forecast 2009 Actual 2010 Forecast



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One subregion, WECC-CAN (Canada), is projecting an all-time summer peak demand in 2010 (Figure 4). However, WECC-CAN is winter-peaking subregion and is projecting sufficient reserves to meet summer peak demand. For the upcoming summer, CA-MX-MEX (Mexico), and ERCOT are within one percent of their all-time summer peak demand. Further, the Gateway subregion of SERC and SPP are within three percent of their all-time summer peak demand. All subregions are projecting 2010 summer peak demand within 15 percent of their all-time summer peak demand, which occurred majorly in August of 2007 and 2008.

Less predictable economic conditions result in a degree of uncertainty in 2010 demand forecasts that is not typically seen in periods of more stable economic activity. When the 2010 projected peak summer Total Internal Demand is compared to the pre-recession 2008 forecast a total reduction of 28 GW results (Figure 5).10 Further, in year to year comparisons of Canada, summer peak demand is reduced by approximately 3,000 MW, or 3.1 percent, since last year (Figure 6). Though the recession

10 This value does not include adjustments from Demand Response.

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Sorted by least 2010 Summer Demand Forecast (left) to greatest 2010 Summer Demand Forecast (right)

Figure 4: Peak Summer Net Internal Demand Summary Shown as a Percentage of the All-Time Subregional Peak Summer Demand

All-Time Actual Peak Demand 2010 Summer Forecast Net Internal Demand

2009 Summer Forecast Net Internal Demand 2009 Actual Peak Demand

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Figure 5: Annual Change in Forecast Summer Peak Total Internal Demand for all of NERC

Reduced 28 GW since 2008



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effects did not impact Canada with the same intensity as in the U.S. during 2009, it appears now to be having a considerable affect.

RFC has realized the largest demand reduction in total magnitude, about 7,000 MW or 3.8 percent of its 2008 forecast (Figure 7). On a Regional basis, WECC-US subregions show a reductions ranging from 1,300 MW to 3,700 MW, ranging from 2.8 percent in NWPP to 11.8 percent in AZ-NM-SNV—the largest percentage reduction observed across all the subregions. RMPA also shows a significant percentage reduction of 10.6 percent since 2008. The VACAR subregion of SERC, MRO Canada, and the Maritimes subregion of NPCC show slight increases in peak demand, with 0.5 percent, 1.3 percent, and 1.9 percent, respectively.

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Figure 6: Forecast Summer Peak Total Internal Demand

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Figure 7: Change in Peak Forecast Summer Total Internal Demand Since 2008 by Subregion



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Weather and temperature are key drivers for peak electricity demand in North America. In most of the U.S., summer temperatures are projected to be mild during the peaking months of July and August (Figure 8).11 During these months, much of the Western Interconnection is projected to experience average to cooler than average weather patterns. ERCOT and the Delta subregion of SERC may experience warmer than normal temperatures through the summer; however, given the projected Reserve Margins, temperature excursions are not expected to affect reliability during the 2010 summer season. A majority of North America may experience warmer than normal temperatures in September, which may indicate prolonged summer temperatures. This may delay scheduled maintenance following the normal peaking season.

11 Source data is provided by Dynamic Predictables, LLC ATLAS climate prediction technology as of April 7th, 2010.

July 2010

August 2010 September 2010

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Figure 8: 2010 Summer Climate Forecast by NERC Subregion

Cooler than average temperatures

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Another variable affecting demand forecasts is the amount of Demand Response contributing to peak demand reduction. Economic factors and regional, state, or provincial Demand Response initiatives can greatly increase or decrease the amount (i.e., capacity) of responsive demand-side resources available for system operators to manage peak demand. With declining peak demand forecasts and higher projected Reserve Margins, the actual activation of Demand Response is expected to contribute less in meeting peak demands this summer, with a reduction of about 3,000 MW when compared to last year (Figure 9). Decreases in RFC and NPCC are the driving force for this reduced Demand Response with a composite reduction of about 2,800 MW. Demand Response programs for this summer total approximately 30,000 MW for all of NERC.12 In all Regions, flat or reduced Demand Response participation is expected for this summer when compared to last summer (Figure 10).

The reductions in Demand Response resources are primarily due to current economic conditions resulting in a slow-down of commercial and manufacturing sectors, thereby eliminating a portion of potential demand resources. Additionally, with Reserve Margins at high levels, it may not be economical for Demand Response resources to provide capacity in a market that competes with traditional generation. However, current economic conditions should not affect the actual performance of Demand Response already expected to be available this summer, as these resources (Dispatchable and Controllable) are not economically driven. 12 Demand Response is not a shareable resource, largely used for local-area reliability within a single operating entity. The total

NERC value is only a general indicator or reference for growth in Demand Response resources.

01,0002,0003,0004,0005,0006,0007,0008,0009,000

2009 2010 2009 2010 2009 2010 2009 2010 2009 2010 2009 2010 2009 2010 2009 2010

ERCOT FRCC MRO NPCC RFC SERC SPP WECC

MW

Figure 10: NERC Summer Peak Capacity Demand Response 2009 and 2010 Comparison

Load as a Capacity Resource Critical Peak-Pricing with Control

Contractually Interruptible (Curtailable) Direct Control Load Management

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Figure 9: NERC Summer Peak Demand Response Projections (2006-2010)

Load as a Capacity Resource Critical Peak-Pricing with ControlContractually Interruptible Direct Control Load Management



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Generation The total Existing-Certain capacity for NERC this summer peak is approximately 1,022,000 MW (July), an increase of about 7,500 MW (or 0.7 percent) when compared to last summer. While the 2010 summer on-peak fuel-mix remains relatively unchanged from last year, natural gas-fired generation continues to be the primary fuel for new on-peak capacity, with the addition of approximately 11,000 MW since last year. Figure 11 shows the relative on-peak capacity for the summer by fuel type for all of the interconnected North American bulk power system.

Installed nameplate13 wind capacity increased by almost 7,000 MW since last summer to 37,142 MW throughout North America. Steady growth has been experienced in all Regions with prominent wind resource potential, including ERCOT, MRO, SPP, and WECC.14 A significant amount of wind generation was added in RFC since the summer of 2009 (over 2,200 MW), effectively doubling the amount of installed capacity in that Region (Figure 12). In the Gateway subregion of SERC, wind resource development is growing slowly, with a total installed capacity of 100 MW. However, the total expected on-peak capacity from these resources is 700 MW less than last year at 4,300 MW for all of NERC (Figure 13). On-peak capacity from wind plants, as a percentage of total installed capacity, is less this year and ranges from zero in one NERC Region (FRCC, which has no wind resources connected to the bulk power system) to over 22 percent in the WECC Region during

13From EIA: Installed nameplate capacity “The maximum rated output of a generator under specific conditions designated by the

manufacturer. Generator nameplate capacity is usually indicated in units of kilovolt-amperes (kVA) and in kilowatts (kW) on a nameplate physically attached to the generator.” http://www.eia.doe.gov/glossary/glossary_i.htm

14 FRCC does not have prominent wind resource potential.

Geothermal0.2%

Undetermined/Unknown

0.3%Wind0.4%Biomass

0.5%

Other0.7%

Pumped Storage2.0%

Oil3.8%

Nuclear10.9%Dual Fuel

11.2%

Hydro12.8%

Gas27.8%

Coal29.4%

Renewables 4.1%

Figure 11: Summer On-Peak Capacity Fuel-Mix

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Figure 12: Installed Nameplate Wind Capacity Growth Since Summer of 2009

2009 Nameplate Capacity Installed Nameplate Increase Since 2009

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the 2010 summer. The most significant change is represented in MRO, where enhanced probabilistic assessment methods used by the Midwest ISO have reduced the amount of expected wind capacity assumed available on-peak. Prior to 2010, MRO used a 20 percent policy for wind generation in their resource adequacy studies. As noted by NERC in prior assessments, consistent methods to determine on-peak wind capacity are needed ensuring uniform measurement and resource adequacy assumptions.15 The enhancement by MRO is appropriate and in support of reaching these industry recommendations.

On-peak wind capacity values shown in Table 1 are a non-coincident, consolidated sum of subregional values, which may vary widely. For example, WECC and NPCC subregions use diverse policies and methods to calculate expected on-peak capacity of wind generation (i.e., Effective Load Carrying Capability), with results ranging from 2.3 to 33.6 percent in WECC and 0 to 21.6 percent in NPCC (Table 1). In SPP, while significant wind resources both exist and are planned, little of the installed capacity (1.5 percent) is being counted on to meet on-peak capacity requirements, representing a considerable change from last summer (8.8 percent for 2009). On average, NERC expects 11.7 percent of total installed wind capacity to be available on peak, representing a reduction of almost 4 percentage points since last year. These values are expected to fluctuate until planners and operators become more comfortable and experienced with patterns of wind generation output.

15 Currently, Regions and subregions (in particular, different operating entities) use different methods to determine expected on-

peak values of wind capacity. The Integration of Variable Generation Task Force is addressing this issue. The summary report is available at: http://www.nerc.com/files/IVGTF_Report_041609.pdf

Table 1: Summer 2010 Wind Resource Penetration Levels and Expected On-Peak

Capacity

Region

% of

NameplateNameplate Capacity

(MW)

On-Peak (MW)

Capacity Expected On-Peak

ERCOT 9,117 793 8.7%

MRO-US 7,041 563 8.0%

MRO-CAN 440 0 0.0%

NPCC-Maritimes 537 116 21.6%

NPCC-New England 73 5 6.8%

NPCC-New York 1,275 127 10.0%

NPCC-Ontario 1,084 109 10.1%

NPCC-Quebec 642 0 0.0%

RFC 4,200 500 11.9%

SERC 102 20 19.6%

SPP 3,485 52 1.5%

WECC-CA-MX 1,950 45 2.3%

WECC-AZ-NM-SNV 346 90 26.0%

WECC-NWPP 5,112 1,718 33.6%

WECC-RMPA 1,198 188 15.7%

WECC-CAN 540 30 5.6%

NERC Total 37,142 4,356 11.7%

8.7%

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Figure 13: Projected 2010 Summer On-Peak Wind Capacity

Existing Planned In-Service by 2010 Summer % of Nameplate Capacity Expected On-Peak



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Transmission Overall, approximately 3,000 circuit line miles were either added or upgraded since last summer (Figure 14). Based on previous assessments this represents an average year of growth.

One reliability concern was identified in SERC for meeting the Bethabara – Clarksboro 230 kV line targeted in-service date of June 1, 2010 re-scheduled for completion one month late (July 1, 2010). Georgia Transmission Corporation (GTC) will address this concern by working with Georgia Power operations and Walton EMC to create an operational solution to ensure that reliability will be maintained.

Some Regions made other significant transmission enhancements for bulk power system reliability since the previous summer.

In ERCOT, several reactive devices including Static Var Compensators (SVCs), were added to the 138kV system. Further, ERCOT added approximately 1,545 MVA of autotransformer since the 2009 summer and schedules 4,861 MVA for completion by the end of the 2010 summer.

In MRO, completion of a the Electric Transmission Reliability (ETR) Project (79 miles of 345kV) will improve both local area voltage support and peak load voltage issues, enhancing the Nebraska regional transmission system.

In RFC, a 300 MW Variable Frequency Transformer (VFT) was placed in-service, connecting the PJM and NYISO systems, enabling system operators to control power flows across this new tie-line between the two systems, providing more flexibility, and improved controllability.16 The VFT is the first merchant transmission project with multiple parties holding the entitlements to the new transmission capacity.

For Midwest ISO, the Morgan-Highway 22 transmission project, spanning 28 miles of 345 kV, was placed in-service in October 2009 and has alleviated common constraints in the northern Wisconsin area.

Based on the self-assessments provided by the Regional Entities, transmission facilities across the NERC Regions appear adequate for the upcoming summer season. Any potential delays in meeting target in-service dates for transmission additions appear to be manageable using operating procedures. While some Regional Entities have identified transmission constraints, operating procedures are in place to manage their impacts. 16 For more detailed explanation of this new technology, refer to the RFC Self-Assessment: Transmission section.

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Figure 14: Transmission Circuit Line Mile Additions and Upgrades Since Summer 2009

100kV - 199kV 230kV 345kV 500kV



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Operational Issues No operational conditions were reported to significantly impact bulk system reliability this summer. All operating entities have operational procedures and strategies to mitigate reliability issues that may arise during the summer season. However, some issues are continually monitored and addressed, such as generator and transmission outage coordination and constrained flowgates. Overall, the Regional Entities do not project any major scheduled generating unit outages, transmission facility outages, or unusual operating conditions that would adversely affect reliable operations. The balancing authorities and planning authorities have coordinated the planning of long-range scheduled maintenance outages, assuring there is sufficient generation available during scheduled transmission outages and sufficient transmission capacity available during scheduled generation outages to access needed resources.

Drought Conditions

Parts of WECC are currently experiencing moderate to severe drought conditions, leading to concerns over generation plant operability. The Lower Colorado River Basin is in the unprecedented tenth year of a drought. Due to low reservoir levels, current Hoover power plant capacity projections for this summer indicate an expected average capacity of 1,585 MW compared to a maximum plant output of 2,074 MW. Increased imports and operating procedures may be required if drought conditions worsen. The U.S. Seasonal Drought Outlook forecasts, drought conditions to persist or even intensify through the summer months (Figure 15). Drought conditions, therefore, should be closely monitored. While no significant reliability concerns have been identified, drought conditions will be closely monitored should conditions intensify and become more widespread. In SERC, reservoir levels are mostly at or near normal levels as the drought conditions previously experienced have improved in most of the Region. In Canada, drought conditions are not expected to have any significant impact on reliability, though some drought conditions have been observed in Alberta, which may persist through the upcoming summer.17

17 Agriculture and Agri-Food Canada: Drought Watch: http://www.agr.gc.ca/pfra/drought/nlplmr_e.htm

Figure 15: U.S. Drought Seasonal Outlook, NOAA



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Historical Reliability Trend Assessment The Energy Emergency Alert 3 (EEA 3) metric identifies the number of times EEA 3 declarations are issued (ALR 6-2).18 EEA 3 declarations are firm-load interruptions due to capacity and energy deficiency. EEA 3 is defined in NERC’s Reliability Standard EOP-002-2.19 Analysis of the historical reports identified transmission constraints, extreme weather, significant short-term load forecast errors and unplanned generation outages are the main causes of these emergency events. EEA 3 rose significantly in SPP during the summer of 2009 with 28 EEA 3 declarations (Figure 16).20 The increase is driven, in large part, by the demand in the Acadiana Load Pocket,21 where SPP anticipates that the ability to adequately meet firm demand will be a concern.

As outlined in SPP’s Regional self-assessment, since June 2009, SPP has been working with each entity to resolve the issues and put in place long-term solutions. The SPP Independent Coordinator of Transmission facilitated an agreement with members in the Acadiana pocket to expand and upgrade electric transmission in the area.22 The joint project includes upgrades to certain existing electric facilities as well as the construction of new substations, transmission lines, and capacitor banks. Each utility is responsible for various components of the project work. All upgrades are expected to be in-service between 2010 and 2012. A description of the detailed expansion plan and upgrades are available on the SPP website.23 When completed, these upgrades will address the resource and transmission adequacy issues currently experienced in the Acadiana area. SPP is continuing to monitor the western part of the grid, due to the reliability concerns and challenges experienced in 2008 and 2009. 18 The Adequate Level of Reliability (ALR) 6-3 approved metric can be found at: http://www.nerc.com/page.php?cid=4|331|335 19 EEA 3 definition is available at http://www.nerc.com/files/EOP-002-2_1.pdf 20The frequency of EEA 3 declarations over a timeframe provides an indication of performance measured at a balancing authority

(BA) or interconnection level. 21 Refer to SPP’s Regional Assessment for more details of adequacy issues in the Acadiana Load Pocket. 22 In this case, additional transmission was determined to be the solution to alleviate transmission constraints; however, additional

local generation or demand-side management may alleviate constraints in some cases. 23 http://www.spp.org/publications/SPP_Acadiana_news_release_1-19-09.pdf

ALR 6-2 Energy Emergency Alert 3 (EEA3)

Firm load interruption imminent or in progress.

A Balancing Authority or Load Serving Entity foresees or has implemented firm load obligation interruption. The available energy to the Energy Deficient Entity, as determined from EEA Level 2, is only accessible with actions taken to increase transmission transfer capabilities.

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Figure 16: EEA 3 Events for June to September2006 to 2009



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Total Internal Demand (MW) — 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. Total Internal Demand includes adjustments for indirect Demand-Side Management programs such as conservation programs, improvements in efficiency of electric energy use, and all non-dispatchable Demand Response programs

Net Internal Demand (MW) — Total Internal Demand less Dispatchable, Controllable Capacity Demand Response used to reduce load.

Existing-Certain and Net Firm Transactions (MW) — Existing-Certain capacity resources plus Firm Imports, minus Firm Exports.

Anticipated Capacity Resources (MW) — Existing-Certain and Net Firm Transactions plus Future, Planned capacity resources plus Expected Imports, minus Expected Exports

Prospective Capacity Resources (MW) — Anticipated Capacity Resources plus Existing-Other capacity resources, minus all Existing, Other deratings (includes derates from variable resources, energy only resources, scheduled outages for maintenance, and transmission-limited resources), plus Future-Other capacity resources, minus all Future-Other deratings.

Existing-Certain and Net Firm Transactions (%) — Existing-Certain, and Net Firm Transactions minus Net Internal Demand shown as a percent of Net Internal Demand.

Anticipated Reserve Margin (%) — Anticipated Capacity Resources minus Net Internal Demand shown as a percent of Net Internal Demand.

Prospective Reserve Margin (%) — Prospective Capacity Resources minus Net Internal Demand shown as a percent of Net Internal Demand.

NERC Reference Reserve Margin Level (%) – Either the Target Capacity Margin provided by the Region/subregion or NERC assigned based on capacity mix (i.e. thermal/hydro).

PPrroojjeecctteedd DDeemmaanndd,, RReessoouurrcceess,, aanndd RReesseerrvvee MMaarrggiinnss To improve consistency and increase granularity and transparency, the NERC Planning Committee approved these categories24 for capacity resources and transactions (see Table 2 and below): 1. Existing:

a. Existing-Certain — Existing generation resources available to operate and deliver power within or into the Region during the period of analysis in the assessment.

b. Existing-Other — Existing generation resources that may be available to operate and deliver power within or into the Region during the period of analysis in the assessment, but may be curtailed or interrupted at any time for various reasons.

c. Existing, but Inoperable — Existing portion of generation resources that are out-of-service and cannot be brought back into service to serve load during the period of analysis in the assessment.

2. Future:

a. Future-Planned — Generation resources anticipated to be available to operate and deliver power within or into the Region during the period of analysis in the assessment.

b. Future-Other — Future generating resources that do not qualify in Future-Planned and are not included in the Conceptual category.

The monthly estimates of peak-demand, resources and Reserve Margins for each Region during the 2010 summer season are in Table 2a-2d.25

24 See the section entitled “Reliability Concepts Used in this Report” for definitions that are more detailed. 25 For the ERCOT and WECC (US and Canada) Regions, and the subregions of NPCC and RFC, coincident peaks are provided.

Table 2: Demand, Capacity, and Margins

Projected Demand, Resources, and Reserve Margins


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Table 2a: Estimated June 2010 Demand, Resources, and Reserve Margins

Total Internal Demand

Net Internal Demand

Existing Certain & Net

Firm Transactions

Anticipated Capacity

Resources

Prospective

Capacity Resources

Existing Certain & Net Firm

Transactions

Anticipated

Reserve Margin

Prospective

Reserve Margin

NERC Reference Reserve Margin Level

(MW) (MW) (MW) (MW) (MW) (%) (%) (%) (%)

United States

ERCOT 56,644 55,582 74,848 74,848 74,848 34.7% 34.7% 34.7% 12.5%

FRCC 43,856 40,657 55,014 55,270 55,270 35.3% 35.9% 35.9% 15.0%

MRO 39,596 36,604 48,917 48,928 48,927 33.6% 33.7% 33.7% 15.0%

NPCC 57,275 55,024 68,602 70,182 71,373 24.7% 27.5% 29.7% 15.0%

New England 24,250 24,250 32,517 32,517 33,708 34.1% 34.1% 39.0% 15.0%

New York 33,025 30,774 36,085 37,665 37,665 17.3% 22.4% 22.4% 15.0%

RFC 165,300 159,100 219,600 219,600 224,200 38.0% 38.0% 40.9% 15.0%

SERC 187,320 181,735 244,642 246,128 253,689 34.6% 35.4% 39.6% 15.0%

Central 40,109 39,063 50,769 51,392 51,392 30.0% 31.6% 31.6% 15.0%

Delta 25,571 24,888 38,795 38,795 40,529 55.9% 55.9% 62.8% 15.0%

Gateway 17,419 17,328 21,970 21,970 22,736 26.8% 26.8% 31.2% 11.9%

Southeastern 45,326 43,660 61,872 62,694 65,975 41.7% 43.6% 51.1% 15.0%

VACAR 58,895 56,796 71,236 71,277 73,057 25.4% 25.5% 28.6% 15.0%

SPP 41,007 40,384 50,952 51,417 56,163 26.2% 27.3% 39.1% 13.6%

WECC 119,560 115,109 158,181 158,968 158,967 37.4% 38.1% 38.1% 14.7%

AZ-NM-SNV 25,627 24,955 33,089 33,359 33,359 32.6% 33.7% 33.7% 13.6%

CA-MX US 51,188 48,731 71,636 72,114 72,115 47.0% 48.0% 48.0% 14.8%

NWPP 34,746 33,794 41,299 41,378 41,378 22.2% 22.4% 22.4% 18.8%

RMPA 10,085 9,716 13,129 13,096 13,096 35.1% 34.8% 34.8% 12.3%

Total-U.S. 710,558 684,194 920,756 925,341 943,437 34.6% 35.2% 37.9% 15.0%

Canada

MRO 6,092 5,850 7,376 7,276 7,268 26.1% 24.4% 24.3% 15.0%

NPCC 46,501 46,128 64,971 64,268 65,478 40.8% 39.3% 41.9% 15.0%

Maritimes 3,599 3,226 5,290 5,290 5,289 64.0% 64.0% 63.9% 15.0%

Ontario 22,475 22,475 28,234 28,293 29,288 25.6% 25.9% 30.3% 18.2%

Quebec 20,427 20,427 31,447 30,685 30,901 54.0% 50.2% 51.3% 10.0%

WECC 17,347 17,337 20,469 20,659 20,659 18.1% 19.2% 19.2% 11.5%

Total-Canada 69,940 69,315 92,816 92,203 93,405 33.9% 33.0% 34.8% 10.0%

Mexico

WECC CA-MX Mex 1,995 1,995 2,589 2,589 2,589 29.8% 29.8% 29.8% 14.8%

Total-NERC 782,493 755,504 1,016,161 1,020,133 1,039,431 34.5% 35.0% 37.6% 15.0%

MISO-RTO 104,075 100,734 129,428 129,428 137,142 28.5% 28.5% 36.1% 15.0%

PJM-RTO 126,634 122,711 167,000 167,000 167,000 36.1% 36.1% 36.1% 15.5%



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Table 2b: Estimated July 2010 Demand, Resources, and Reserve Margins


Net Internal Demand


Firm Transactions


Resources

Prospective

Capacity Resources


Transactions

Anticipated

Reserve Margin

Prospective

Reserve Margin


(MW) (MW) (MW) (MW) (MW) (%) (%) (%) (%)

United States

ERCOT 60,371 59,309 74,993 75,043 75,043 26.4% 26.5% 26.5% 12.5%

FRCC 45,104 41,905 55,014 55,270 55,270 31.3% 31.9% 31.9% 15.0%

MRO 42,579 39,505 48,581 48,633 48,629 23.0% 23.1% 23.1% 15.0%

NPCC 60,215 57,964 68,570 70,150 71,341 18.3% 21.0% 23.1% 15.0%

New England 27,190 27,190 32,517 32,517 33,708 19.6% 19.6% 24.0% 15.0%

New York 33,025 30,774 36,053 37,633 37,633 17.2% 22.3% 22.3% 15.0%

RFC 177,000 170,800 219,600 219,600 224,200 28.6% 28.6% 31.3% 15.0%

SERC 199,617 193,930 246,139 247,632 255,221 26.9% 27.7% 31.6% 15.0%

Central 42,364 41,298 51,391 52,021 52,021 24.4% 26.0% 26.0% 15.0%

Delta 26,708 26,021 38,797 38,797 40,559 49.1% 49.1% 55.9% 15.0%

Gateway 19,113 19,003 22,219 22,219 22,985 16.9% 16.9% 21.0% 11.9%

Southeastern 47,976 46,310 62,641 63,463 66,744 35.3% 37.0% 44.1% 15.0%

VACAR 63,456 61,298 71,091 71,132 72,912 16.0% 16.0% 18.9% 15.0%

SPP 42,790 42,164 50,952 51,419 56,165 20.8% 21.9% 33.2% 13.6%

WECC 126,711 122,121 159,775 160,587 160,587 30.8% 31.5% 31.5% 14.7%

AZ-NM-SNV 27,350 26,791 34,290 34,304 34,304 28.0% 28.0% 28.0% 13.6%

CA-MX US 56,003 53,367 72,877 73,782 73,781 36.6% 38.3% 38.3% 14.8%

NWPP 37,062 36,039 44,289 44,552 44,553 22.9% 23.6% 23.6% 18.8%

RMPA 10,979 10,607 13,899 13,865 13,865 31.0% 30.7% 30.7% 12.3%

Total-U.S. 754,387 727,698 923,624 928,334 946,456 26.9% 27.6% 30.1% 15.0%

Canada

MRO 6,218 5,976 7,675 7,575 7,574 28.4% 26.8% 26.7% 15.0%

NPCC 47,557 47,193 68,151 67,684 68,777 44.4% 43.4% 45.7% 15.0%

Maritimes 3,526 3,162 5,414 5,414 5,414 71.2% 71.2% 71.2% 15.0%

Ontario 23,556 23,556 29,770 30,066 30,930 26.4% 27.6% 31.3% 18.2%

Quebec 20,475 20,475 32,967 32,205 32,434 61.0% 57.3% 58.4% 10.0%

WECC 17,703 17,696 21,059 21,620 21,620 19.0% 22.2% 22.2% 11.5%

Total-Canada 71,479 70,866 96,885 96,880 97,971 36.7% 36.7% 38.2% 10.0%

Mexico

WECC CA-MX Mex 2,109 2,109 2,568 2,568 2,568 21.8% 21.8% 21.8% 14.8%

Total-NERC 827,974 800,673 1,023,077 1,027,781 1,046,995 27.8% 28.4% 30.8% 15.0%

MISO-RTO 107,629 104,288 131,284 131,284 137,249 25.9% 25.9% 31.6% 15.0%

PJM-RTO 135,750 131,827 167,000 167,000 167,000 26.7% 26.7% 26.7% 15.5%



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Table 2c: Estimated August 2010 Demand, Resources, and Reserve Margins


Net Internal Demand


Firm Transactions


Resources

Prospective

Capacity Resources


Transactions

Anticipated

Reserve Margin

Prospective

Reserve Margin


(MW) (MW) (MW) (MW) (MW) (%) (%) (%) (%)

United States

ERCOT 64,056 62,994 75,168 75,218 75,218 19.3% 19.4% 19.4% 12.5%

FRCC 46,034 42,820 55,014 55,270 55,270 28.5% 29.1% 29.1% 15.0%

MRO 41,249 38,167 48,617 48,668 48,663 27.4% 27.5% 27.5% 15.0%

NPCC 60,215 57,964 69,185 70,765 71,956 19.4% 22.1% 24.1% 15.0%

New England 27,190 27,190 32,517 32,517 33,708 19.6% 19.6% 24.0% 15.0%

New York 33,025 30,774 36,668 38,248 38,248 19.2% 24.3% 24.3% 15.0%

RFC 172,000 165,800 219,600 219,600 224,200 32.4% 32.4% 35.2% 15.0%

SERC 199,143 193,414 247,745 249,245 256,833 28.1% 28.9% 32.8% 15.0%

Central 42,091 41,024 51,386 52,023 52,023 25.3% 26.8% 26.8% 15.0%

Delta 27,944 27,231 39,452 39,452 41,214 44.9% 44.9% 51.3% 15.0%

Gateway 19,078 18,968 23,090 23,090 23,856 21.7% 21.7% 25.8% 11.9%

Southeastern 48,472 46,807 62,786 63,608 66,889 34.1% 35.9% 42.9% 15.0%

VACAR 61,558 59,384 71,031 71,072 72,851 19.6% 19.7% 22.7% 15.0%

SPP 43,426 42,800 51,002 51,519 56,265 19.2% 20.4% 31.5% 13.6%

WECC 129,072 124,924 159,293 160,244 160,244 27.5% 28.3% 28.3% 14.7%

AZ-NM-SNV 27,816 27,289 33,619 33,633 33,633 23.2% 23.2% 23.2% 13.6%

CA-MX US 57,609 55,018 71,234 71,912 71,912 29.5% 30.7% 30.7% 14.8%

NWPP 36,162 35,507 44,490 44,644 44,644 25.3% 25.7% 25.7% 18.8%

RMPA 10,322 9,947 12,042 12,184 12,184 21.1% 22.5% 22.5% 12.3%

Total-U.S. 755,195 728,883 925,624 930,529 948,649 27.0% 27.7% 30.2% 15.0%

Canada

MRO 6,162 5,920 7,601 7,501 7,500 28.4% 26.7% 26.7% 15.0%

NPCC 47,090 46,703 65,221 64,799 65,911 39.7% 38.7% 41.1% 15.0%

Maritimes 3,504 3,117 5,410 5,410 5,410 73.6% 73.6% 73.6% 15.0%

Ontario 22,931 22,931 29,952 30,293 31,179 30.6% 32.1% 36.0% 18.2%

Quebec 20,655 20,655 29,859 29,097 29,322 44.6% 40.9% 42.0% 10.0%

WECC 17,340 17,340 20,765 21,323 21,323 19.8% 23.0% 23.0% 11.5%

Total-Canada 70,592 69,963 93,587 93,623 94,734 33.8% 33.8% 35.4% 10.0%

Mexico

WECC CA-MX Mex 2,140 2,140 2,608 2,554 2,554 21.9% 19.3% 19.3% 14.8%

Total-NERC 827,927 800,986 1,021,819 1,026,707 1,045,937 27.6% 28.2% 30.6% 15.0%

MISO-RTO 111,414 108,073 129,781 129,781 137,142 20.1% 20.1% 26.9% 15.0%

PJM-RTO 129,697 125,774 167,000 167,000 167,000 32.8% 32.8% 32.8% 15.5%



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Table 2d: Estimated September 2010 Demand, Resources, and Reserve Margins


Net Internal Demand


Firm Transactions


Resources

Prospective

Capacity Resources


Transactions

Anticipated

Reserve Margin

Prospective

Reserve Margin


(MW) (MW) (MW) (MW) (MW) (%) (%) (%) (%)

United States

ERCOT 49,684 48,622 74,539 74,602 74,602 53.3% 53.4% 53.4% 12.5%

FRCC 43,751 40,575 55,014 55,270 55,270 35.6% 36.2% 36.2% 15.0%

MRO 37,408 34,644 48,867 49,027 49,020 41.1% 41.5% 41.5% 15.0%

NPCC 55,160 46,927 61,585 63,165 64,356 31.2% 34.6% 37.1% 15.0%

New England 22,135 22,135 31,617 31,617 32,808 42.8% 42.8% 48.2% 15.0%

New York 27,043 24,792 29,968 31,548 31,548 20.9% 27.3% 27.3% 15.0%

RFC 151,100 144,900 219,600 219,600 224,200 51.6% 51.6% 54.7% 15.0%

SERC 180,975 175,447 242,462 243,939 251,527 38.2% 39.0% 43.4% 15.0%

Central 39,556 38,600 50,087 50,701 50,701 29.8% 31.3% 31.3% 15.0%

Delta 25,555 24,860 39,983 39,983 41,745 60.8% 60.8% 67.9% 15.0%

Gateway 16,375 16,284 22,892 22,892 23,658 40.6% 40.6% 45.3% 11.9%

Southeastern 43,223 41,559 60,863 61,685 64,966 46.4% 48.4% 56.3% 15.0%

VACAR 56,266 54,144 68,637 68,678 70,457 26.8% 26.8% 30.1% 15.0%

SPP 39,537 38,914 51,002 51,519 56,265 31.1% 32.4% 44.6% 13.6%

WECC 118,471 114,737 158,242 159,243 159,243 37.9% 38.8% 38.8% 14.7%

AZ-NM-SNV 25,321 24,768 30,621 30,647 30,647 23.6% 23.7% 23.7% 13.6%

CA-MX US 53,516 50,825 72,677 73,354 73,354 43.0% 44.3% 44.3% 14.8%

NWPP 31,515 31,263 44,152 44,466 44,466 41.2% 42.2% 42.2% 18.8%

RMPA 9,276 9,038 12,471 12,571 12,571 38.0% 39.1% 39.1% 12.3%

Total-U.S. 676,086 651,400 911,311 916,365 934,483 39.9% 40.7% 43.5% 15.0%

Canada

MRO 5,783 5,541 7,382 7,282 7,281 33.2% 31.4% 31.4% 15.0%

NPCC 45,921 45,542 64,868 64,477 65,288 42.4% 41.6% 43.4% 15.0%

Maritimes 3,610 3,231 5,009 5,039 5,039 55.0% 56.0% 56.0% 15.0%

Ontario 21,634 21,634 28,561 28,902 29,532 32.0% 33.6% 36.5% 18.2%

Quebec 20,677 20,677 31,298 30,536 30,717 51.4% 47.7% 48.6% 10.0%

WECC 17,104 17,104 20,424 21,139 21,139 19.4% 23.6% 23.6% 11.5%

Total-Canada 68,808 68,187 92,674 92,898 93,708 35.9% 36.2% 37.4% 10.0%

Mexico

WECC CA-MX Mex 2,115 2,115 2,605 2,605 2,605 23.2% 23.2% 23.2% 14.8%

Total-NERC 747,009 721,702 1,006,590 1,011,867 1,030,796 39.5% 40.2% 42.8% 15.0%

MISO-RTO 98,498 95,157 129,781 129,781 137,142 36.4% 36.4% 44.1% 15.0%

PJM-RTO 115,305 111,382 167,000 167,000 167,000 49.9% 49.9% 49.9% 15.5%



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Notes for Table 2a through 2d Note 1: Existing-Certain resources and Net Firm Transactions 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-US peak demands or resources do not necessarily equal the sums of the non-coincident WECC-US 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 non-coincident WECC-U.S., Canada, and Mexico peak demands or resources. In addition, the subregional resource numbers include use of seasonal demand diversity between the winter-peaking northwest and the summer-peaking portions of the Western Interconnection. 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 United States. Note 6: These demand and supply forecasts were reported on March 26, 2010. Note 7: Each Region/subregion may have their own specific Reserve Margin level based on load, generation, and transmission characteristics as well as regulatory requirements. If provided in the data submittals, the Regional/subregional Target Reserve Margin level is adopted as the NERC Reference Reserve Margin Level. If not, NERC assigned a 15 percent Reserve Margin for predominately thermal systems and a 10 percent Reserve Margin for predominately hydro systems. Note 8: Based on Midwest ISO tariff requirements, individual LSE reserve levels in the SERC Gateway subregion are 12.7 percent. Accordingly, the NERC Reference Margin Reserve Level for SERC Gateway subregion is 11.9 percent.26 Note 9: Deliverable Capacity Resources and Deliverable Reserve Margin, from the 2009 Reliability Assessment Reports have been changed to Anticipated Capacity Resources and Anticipated Reserve Margin, respectively to avoid confusion with the term “deliverability” related to the ability to transport resources. The definitions to this resource category and margin calculation have not changed. Note 10: MISO-RTO and PJM-RTO are provided for reference only. These areas overlap Regional Entity boundaries, and therefore, are not included in the summed values for NERC totals.

26 For more information, see the Midwest ISO 2009–2010 LOLE Study Report at: http://www.midwestmarket.org/publish/Document/62c6cd_120e7409639_-7f2a0a48324a

Regional Reliability Assessment Highlights


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RReeggiioonnaall RReelliiaabbiilliittyy AAsssseessssmmeenntt HHiigghhlliigghhttss

ERCOT The present uncertainty in economic conditions for the ERCOT Region is reflected in the relatively unchanged net internal peak demand forecast from the 2009 projection for 2010 of 62,781 MW to the current projection for 2010 of 62,994 MW. Currently, ERCOT has 74,817 MW of Existing-Certain generation at time of system peak, which includes the addition of 4,617 MW of generating capacity since last summer. In addition, net firm

imports of 351 MW and future planned capacity additions of 50 MW are assumed, which results in anticipated capacity resources of 75,218 MW at time of system peak. This results in a reserve margin of 19.4 percent for the summer of 2010—well above the 12.5 percent minimum reserve margin—indicating that the ERCOT Region is projected to have sufficient resources to serve the peak demand in the Region this summer. Approximately 440 miles of new or rebuilt 345 kV transmission lines have been completed or are projected to be completed before the end of the 2010 summer period. There are no known transmission constraints that could significantly impact reliability across the ERCOT Region. Integration of additional wind generation continues to affect system operations; changes to requirements and processes continue to be implemented to mitigate these impacts. Several entities in the Region have recently announced their intention to mothball or retire several generating units this summer. As a result, ERCOT is evaluating the need to maintain operation of some of these units to maintain system reliability through Reliability Must Run agreements.

FRCC The FRCC is forecasted to reach its 2010 summer non-coincident peak Total Internal Demand of 46,034 MW in August, which represents a projected demand increase of 0.7 percent when compared to last year’s summer forecast of 45,734 MW. The small increase in the 2010 projected summer peak demand is attributed to a sluggish economy primarily driven by a declining housing market and higher energy prices. Based on

the projected load and generation capacity, the calculated Reserve Margin for the summer of 2010 is 29.1 percent. This year’s calculated Reserve Margin is seven percent higher than last year’s calculation for the summer of 2009, primarily related to the availability of new generation. FRCC expects to have adequate generating reserves with transmission system deliverability throughout the 2010 summer peak demand. The transmission capability within the FRCC Region is projected to be adequate to supply firm customer demand and 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 these potential impacts to the bulk transmission system.



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MRO The Midwest Reliability Organization’s (MRO) forecasted 2010 Non-Coincident Summer Peak Total Internal Demand is 48,797 MW. The Net Internal Demand is projected to be 45,481 MW. These projected demands are slightly lower than the 2009 demand projections due to the economic downturn. The Existing-Certain resources for 2010 summer are 57,204 MW. This is 810 MW lower than the Existing-Certain resources

reported for the 2009 summer (58,014 MW). This drop in internal capacity is in part caused by a reduction in capacity assumed available at peak for wind generation (eight percent nameplate now used vs. 20 percent previously). The projected MRO reserve margin is 26.2 percent, which is above the various target reserve margins established by the entities within MRO. Numerous transmission reinforcements will be completed by or during the upcoming summer season. These reinforcements include: several rebuilt/reconductored transmission lines; several new 115 kV, 138 kV, and 161 kV lines; one new 230 kV line; four new 345 kV lines, four new bulk power transformers; three new substations, and various substation expansions and upgrades. The MRO footprint will have about 7,700 MW of nameplate wind generation before or during the summer. Most of this wind generation is managed by the Midwest ISO Reliability Coordinator. At the present time, ramp rates, output volatility, and the inverse nature of wind generation with respect to load levels have been manageable. However, the Midwest ISO closely watches the ramp-down rate of wind generation during the morning load pickup period.

NPCC The NPCC is forecasted to reach its 2010 summer non-coincident peak Net Internal Demand of 105,157 MW in July, which represents a projected demand decrease of 1.1 percent when compared to last year’s summer forecast of 106,334 MW. Actual peak demands last summer were lower than forecast in four of the NPCC subregions due to milder weather than forecast and economic activity slowdowns. Demand

forecasts for 2010 summer are all lower than last summer’s forecasts, mainly due to economic activity slowdowns. NPCC expects to have adequate generating reserves for the 2010 summer peak demand. Currently, NPCC has 136,721 MW of Existing-Certain generation, with an additional 1,100 MW planned to be in service by summer peak. Based on the projected load and generation capacity, the calculated Reserve Margin for summer 2010 is 31.1 percent. This year’s calculated Reserve Margin is lower than last year’s calculation for the summer of 2009, primarily related to a reduction in demand response resources and availability of generation resources. Transmission additions are noted in New England, New York, Ontario, and Québec subregions. The transmission capability within the NPCC Region is projected to be adequate to supply planned firm transmission service with no delays to new transmission in-service dates. In March of 2010, NPCC adopted a revision to the NPCC underfrequency load shedding program, modifying the frequency steps and amounts of load to be shed at each step. Implementation will take place over several years.



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RFC The ReliabilityFirst Regional area is projected to have a peak Net Internal Demand of 170,800 MW in July, supplied from 219,600 MW of capacity resources. This 48,800 MW of reserves represents a 28.6 percent reserve margin. Since both PJM and Midwest ISO have adequate reserves this summer, the RFC reserve margin is also adequate.

Approximately 54 miles of new high voltage transmission lines have been completed or are projected to be completed before the 2010 summer period. There were no reliability concerns meeting target in-service dates for these new transmission additions. However, there is currently a two-week outage request for a 500 kV line in August 2010. PJM will study this outage to determine if there is a better opportunity to take this outage depending on weather and other factors. There are no other significant transmission outages planned through the summer season. The 2010 summer ERAG studies have identified significantly lower first contingency incremental transfer capability (FCITC) values when simulating west-to-east transfers. These lower FCITC values can be attributed to high north-to-south flows through the Wisconsin-Illinois eastern interface and new generation in that area. PJM and Midwest ISO are evaluating the potential constraint as part of the joint Midwest ISO-PJM Cross Border Top Congested Flowgate Study to determine procedures to manage the potential flows.

SERC SERC Total Internal Demand for 2010 summer is projected to be 199,617 MW. This projection is 0.9 percent lower than the 2009 summer forecast of 201,364 MW and 14,042 MW (7.6 percent) higher than the actual 2009 summer peak demand of 185,575 MW. Decreases in the forecast are attributed to the current economic recession. SERC expects 255,591 MW of existing capacity for the summer period. Of the projected resources,

244,704 MW will be considered Existing-Certain capacity. Since 2009, the amount of Existing-Certain capacity has increased by 2,698 MW. Additionally, 485 MW of future resources are projected to be in service through the end of the assessment period. Aggregate 2010 summer reserve margins are 26.6 percent, indicating capacity resources in SERC are projected to be adequate to supply the projected firm summer demand. Utilities within SERC have 316 miles of new transmission lines projected to be in service for the summer season. In addition, entities within the SERC Region have plans to install or upgrade 13 transformers. Entities are not expecting any transmission reliability concerns that will significantly impact bulk power system reliability for the summer season. The following are the most common challenging operational issues: routine loop flows, congestion, and real-time transmission loading issues. Entities have found that the availability of large amounts of excess generation and low-cost base-load generation during light load and peak conditions within the Southeastern and Gateway subregions have resulted in fairly volatile day-to-day scheduling patterns and exacerbate transmission loading concerns. These operational issues are not reliability concerns but are market issues. Transmission constraints identified are studied and can be mitigated as needed to minimize reliability concerns on the bulk power system.



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SPP The SPP Net Internal Demand for the 2010 summer is projected to be higher than the 2009 actual summer demand, but lower than the 2009 forecast, at 42,800 MW. Existing capacity resources in the SPP footprint are projected to be 55,387 MW; of those, 49,777 MW are Existing-Certain resources. New Existing-Certain resources have not been added since the 2009 Summer Assessment. Future-Planned resources projected

to be in service during the assessment timeframe total 266 MW. The SPP minimum required capacity margin requirement is 12 percent, which translates to a reserve margin of 13.6 percent. For 2010 summer, the reserve margin for the SPP Region, based on Existing-Certain, and Net-Firm Transactions, is 19.2 percent. The 2010 summer reserve margin based on Anticipated Capacity Resources is 20.4 percent. This is well above the SPP minimum required reserve margin. There have been no significant transmission line additions since the previous reporting year. However, five bulk power transformers with 345 kV high voltage side are projected to be added to the SPP Regional Transmission Organization (RTO) grid. There are no known transmission reliability concerns identified during the assessment timeframe.

WECC The aggregate WECC 2010 summer coincident Total Internal Demand is forecast to be 148,365 MW and is projected to occur in August 2010. The 2010 summer Total Internal Demand forecast is 7.7 percent less than the forecast non-coincident peak demand of 160,688 MW for 2009 summer. For the peak, WECC expects a reserve margin of 28.1 percent (40,487 MW), which significantly exceeds a supply adequacy model Planning Reserve Margin of about 14.3 percent. The Anticipated Capacity Resources for this summer’s peak period are

projected to be 184,704 MW compared to 199,310 MW for 2009 summer. Most of the transmission facility additions scheduled to enter service prior to next fall relate to local area improvements or renewable energy delivery projects and are not particularly significant to overall interconnected system operation. However, the Gateway West 500 kV transmission project across portions of southern Wyoming and southern Idaho and the Miracle Mile to Ault 115 kV line upgrade to 230 kV are in the transmission-constrained Wyoming/Idaho/Utah/ Colorado portion of the system and delays in their in-service dates could adversely impact economy energy transfers. WECC does not expect any major scheduled generating unit outages, transmission facility outages, or unusual operating conditions that would adversely impact reliable operations. WECC expects to have adequate generation capacity, reserves, and transmission for the forecasted 2010 summer peak demands and energy loads. This is attributed to the combination of additional generation resources and transmission system enhancements.

Regional Reliability Self-Assessments


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RReeggiioonnaall RReelliiaabbiilliittyy SSeellff--AAsssseessssmmeennttss Introduction Regional Resource and Demand Projections The figures in the Regional self-assessment pages show the Regional historical demand, projected demand growth, Reserve Margin projections, and generation expansion projections reported by the Regions. Capacity Fuel Mix The Regional capacity fuel mix charts shown in each Region’s self-assessment presents the relative reliance on specific fuels27 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 (ES&D) database.

NERC Interconnections NERC Subregions

NNoottee:: TThhee hhiigghhlliigghhtteedd aarreeaa bbeettwweeeenn SSPPPP aanndd SSEERRCC ddeennootteess oovveerrllaappppiinngg RReeggiioonnaall bboouunnddaarriieess.. FFoorr eexxaammppllee,, ssoommee llooaadd sseerrvviinngg eennttiittiieess ppaarrttiicciippaattee iinn oonnee RReeggiioonn aanndd tthheeiirr aassssoocciiaatteedd ttrraannssmmiissssiioonn oorr

ggeenneerraattiioonn oowwnneerr//ooppeerraattoorrss iinn aannootthheerr..

27 Note: The category “Other” may include capacity for which the total capacity of a specific fuel type is less than 1% of the total

capacity or the fuel type has yet to be determined.



Texas Interconnection

TTeexxaass IInntteerrccoonnnneeccttiioonn EERRCCOOTT

Introduction The present uncertainty in economic conditions for the ERCOT Region is reflected in the relatively unchanged net internal peak demand forecast from the 2009 projection for 2010 of 62,781 MW to the current projection for 2010 of 62,994 MW. Currently, ERCOT has 74,817 MW of Existing-Certain generation at time of system peak, which includes the addition of 4,617 MW of generating capacity since last summer. In addition, net firm imports of 351 MW and future planned capacity additions of 50 MW are assumed, which results in anticipated capacity resources of 75,218 MW at time of system peak. This results in a reserve margin of 19.4 percent for the summer of 2010—well above the 12.5 percent minimum reserve margin—indicating that the ERCOT Region is projected to have sufficient resources to serve the peak demand in the Region this summer. Approximately 440 miles of new or rebuilt 345 kV transmission lines have been completed or are projected to be completed before the end of the 2010 summer period. There are no known transmission constraints that could significantly impact reliability across the ERCOT Region. Integration of additional wind generation continues to affect system operations; changes to requirements and processes continue to be implemented to mitigate these impacts. Several entities in the Region have recently announced their intention to mothball or retire several generating units this summer. As a result, ERCOT is evaluating the need to maintain

2010 Summer Projected Peak Demand MW On-Peak Capacity by Fuel TypeTotal Internal Demand 64,056

Direct Control Load Management 0Contractually Interruptible (Curtailable) 0Critical Peak-Pricing with Control 0Load as a Capacity Resource 1,062

Net Internal Demand 62,994

2009 Summer Comparison MW % Change2009 Summer Projected Peak Demand 63,103 -0.2%2009 Summer Actual Peak Demand 63,400 -0.6%All-Time Summer Peak Demand - July 2009 63,400 -0.6%

2010 Summer Projected Peak Capacity MW MarginExisting Certain and Net Firm Transactions 75,168 19.3%Anticipated Capacity Resources 75,218 19.4%Prospective Capacity Resources 75,218 19.4%NERC Reference Margin Level - 12.5%

Regional Assessment Summary

Nuclear7%

Hydro1%

Coal17%

Gas52%

Dual Fuel20%

Other4%

Nuclear7%

Hydro1%

Coal17%

Gas52%

Dual Fuel20%

Other4%



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operation of some of these units to maintain system reliability through Reliability Must Run agreements. Demand The 2009 summer actual peak demand set a new record for the ERCOT Region at 63,400 MW. This peak demand was set with above-normal temperatures in July. The 2010 summer peak demand is forecasted to be 64,056 MW, which is approximately the same as the 2009 summer peak demand forecast. This is primarily due to the insignificant changes in the projected growth for the underlying economic drivers. The average weather profile (50/50) is used for the ERCOT load forecast. The economic factors that drive the load forecast include per capita income, population, gross domestic product (GDP), and various employment measures that include non-farm employment and total employment. The actual demands used for forecasting purposes are coincident hourly values across the ERCOT Region. The data used in the forecast are differentiated by weather zones. The forecasted peak demands are produced by the ERCOT ISO for the entire ERCOT Region, which is a single Balancing Authority area, based on the Region-wide actual demands. While the forecasted peak demands produced using the average weather profile are used for resource assessments, alternative weather scenarios are used to develop extreme weather load forecasts to assess the impact of weather variability on the peak demand for ERCOT. One scenario is the one-in-ten-year occurrence of a weather event. This scenario is calculated using the 90th percentile of the temperatures in the database spanning the last 15 years. These extreme temperatures are input into the load-shape and energy models to obtain the forecasts. The extreme temperature assumptions consistently produce demand forecasts that are approximately five percent higher than the forecasts based on the average weather profile. Together, the forecasts from these temperature scenarios are usually referred to as 90/10 scenario forecasts. A 2007 Texas state law28 mandates that at least 20 percent of an investor-owned utility’s (IOU’s) annual growth in electricity demand for residential and commercial customers shall, by December 31, 2009, be met through energy efficiency programs each year. The IOUs are required to administer energy savings incentive programs, which are implemented by retail electric and energy efficiency service providers. Some of these programs, offered by the utilities, are designed to produce system peak demand reductions and energy use savings, and include the following: Commercial and Industrial, Residential and Small Commercial, Hard-to- Reach, Load Management, Energy Efficiency Improvement Programs, Low Income Weatherization, Energy Star (new homes), Air Conditioning, Air Conditioning Distributor, Air Conditioning Installer Training, Retro-Commissioning, Multifamily Water and Space Heating, Texas SCORE/City Smart, Trees for Efficiency, and Third Party Contracts. In general, utility savings, as measured and verified by an independent contractor, have exceeded the goals set by the utilities.29 According to the latest assessment, utility programs implemented in 1999–2008 had produced 1,125 MW of peak demand reduction and 3,014 GWh of electricity savings in the year 2008. Most of this demand reduction is accounted for within the load forecast

28 http://www.capitol.state.tx.us/tlodocs/80R/billtext/html/HB03693F.htm 29 http://www.texasefficiency.com/report.html




and only the projected incremental portion for the coming year is included as a demand adjustment for the summer season. Loads acting as a Resource (LaaRs) providing Responsive Reserve Service provide an average of approximately 1062 MW of dispatchable, contractually-committed Demand Response during summer peak hours based on the most recently available data. ERCOT’s Emergency Interruptible Load Service (EILS) is designed to be deployed in the late stages of a grid emergency prior to shedding involuntary “firm” load, and also represents contractually committed interruptible load. Based on average EILS commitments during 2009, approximately 237 MW of EILS can be counted on during summer peaks. Generation ERCOT has 74,817 MW of Existing-Certain generation projected at the time of the system peak, of which 89 MW is biomass, and approximately 9,199 MW is Existing-Other generation. Approximately 50 MW of Future-Planned capacity is projected to be in service prior to the summer peak, and an additional 13 MW30 of wind capacity that is projected to be in service before the end of the summer season. ERCOT has existing wind generation nameplate capacity totaling 8,916 MW; however, only 8.7 percent, or 776 MW, is included in the Existing-Certain amount used for margin calculations, which is based on a study of the effective load-carrying capability of wind generation in the Region. The remaining existing wind capacity amount is included in the Existing-Other. Less than one percent of the ERCOT generation capacity is hydro. These facilities are typically operated as run-of-river or planned release due to downstream needs, and are not operated specifically to produce electricity. As a result, hydro conditions should not have a reliability impact on the ERCOT Region this summer. In addition, ERCOT is not expecting any weather or fuel conditions to impact summer resource availability. There are 2,234 MW of Existing capacity considered inoperable due to its mothballed status, which includes units that are planned to be removed from service prior to or during the 2010 summer season. ERCOT market participants have announced plans to mothball or retire an additional 1,856 MW of older gas generating units at the end of September 2010. ERCOT is still evaluating whether there is a need to establish Reliability Must Run contracts for each of these units in order to maintain local transmission reliability; however, these units will still be available through the 2010 summer season. Capacity Transactions on Peak The ERCOT Region is a separate interconnection with only asynchronous ties to SPP and México’s Comision Federal de Electricidad (CFE) and does not share reserves with other regions. There are two asynchronous ties between ERCOT and SPP with a total of 820 MW of transfer capability, and three asynchronous ties between ERCOT and México with a total of 280 MW of transfer capability. The ERCOT Region does not rely on external resources to meet demand under normal operating conditions; however, under emergency support agreements, it

30 This 13 MW is the effective load carrying capacity of added wind generation having a nameplate capacity of 150 MW.



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may request external resources for emergency services more than the asynchronous ties or by transferring block loads. For the 2010 summer season, ERCOT has 458 MW of imports from SPP and 140 MW from CFE. Of the imports from SPP, 48 MW is tied to a long term contract for a purchase of firm power from specific generation. The remaining imports of 410 MW from SPP and 140 MW from CFE represent one-half of the asynchronous tie transfer capability, included to reflect emergency support arrangements. Several SPP members own 247 MW of a power plant located in the ERCOT Region, resulting in a firm export of that amount from ERCOT to SPP. There are no non-firm contracts signed or pending. There are also no known contracts under negotiation or under study. Transmission Several significant transmission improvements have been made throughout the ERCOT Region to meet reliability needs.31 Approximately 109 miles of new 345 kV transmission lines were completed since the 2009 summer (Table ERCOT-1). In addition, 348.3 miles of new and 92.4 miles of rebuilt 345 kV transmission lines are projected to be completed prior to the 2010 summer peak, including:

Table ERCOT-1: Transmission Projects

Transmission Project Name Voltage

(kV) In-Service

Date Description/ Status

Spruce-Skyline 345 Completed Add circuit Parker-Everman 345 Completed Line upgrade Killeen Switch-Salado Switch

345 Prior to Summer Peak

Add circuit

San Miguel to Lobo 345 Prior to Summer Peak

Add line

Hutto Switch-Salado Switch


Add line

W. Levee-Norwood 345 Prior to Summer Peak

Add line

Jacksboro Switch-Willow Creek


Line rebuild

Bowman-Jacksboro Switch 345 Prior to Summer Peak

Line rebuild

Divide to Twin Buttes 345 Prior to Summer Peak

Line rebuild

Twin Buttes to Brown 345 Prior to Summer Peak

Add circuit

31 Additional details on transmission projects can be found in the “Transmission Constraints and Needs Report 2009” located on

the following website: http://www.ercot.com/news/presentations/




Approximately 25.9 miles of new and 88.2 miles of rebuilt 138 kV transmission lines were completed since the 2009 summer and an additional 73.1 miles of new and 255.5 miles of rebuilt 138 kV transmission lines are projected to be completed before the end of the 2010 summer period. In addition to transmission lines, approximately 1,545 MVA of autotransformer capacity has been added since the 2009 summer and 4,861 MVA is scheduled to be complete by the end of the 2010 summer period (Table ERCOT-2).

Also, several reactive devices, including SVCs, have been added to the 138 kV system. There are no anticipated reliability concerns if transmission projects do not meet their target in-service dates as ERCOT will continue to operate reliably by employing congestion management techniques, and developing mitigation plans if necessary, to maintain reliability. ERCOT does not anticipate any significant transmission outages through the summer season, and there are no known transmission constraints that are projected to significantly impact reliability across the ERCOT Region. The outage coordination process addresses outages as well as potential constraints. As transmission constraints are identified, remedial action plans or mitigation plans are developed to provide for preemptive or planned responses to maintain reliability. Interregional transfer capabilities are not generally relied upon to maintain transmission reliability and address capacity shortages, although emergency support arrangements are in place that provide for mutual support more than the asynchronous ties or through block load transfers. Operational Issues For the 2010 summer season, no unusual operating conditions that could impact reliability for the upcoming summer are anticipated, and no significant special operating studies for 2010 have been performed for the ERCOT Region. ERCOT will utilize typical operational procedures related to variable resources during the summer season. ERCOT has implemented a wind power forecasting system to allow ERCOT ISO system operators to identify and take appropriate action when wind resource schedules may

Table ERCOT-2: Transformer Projects

Transformer Project Name Voltage

(kV) Description / Status

Eagle Mountain 345/138 Will be complete in Summer 2010 Whitney 345/138 Will be complete in Summer 2010 Sandow Switch 345/138 Will be complete in Summer 2010 Lobo 345/138 Will be complete in Summer 2010 Skyline 230/115 Will be complete in Summer 2010 Rothwood 345/138 Will be complete in Summer 2010 Hutto Switch 345/138 Will be complete in Summer 2010 Lytton Springs 345/138 Will be complete in Summer 2010 Meadow 345/138 Will be complete in Summer 2010



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not track projected changes in wind production. ERCOT has also recently implemented a wind ramp forecasting tool that provides a probabilistic assessment of the likelihood of varying amounts of increases and decreases in the aggregate output of ERCOT system wind generation over the upcoming 15, 60, and 180 minutes. ERCOT has also made several market rules over the past year that require wind generators to limit ramp rates when released from curtailment, require wind generators to use the ERCOT wind forecast in day-ahead resource plans used by ERCOT for unit commitment, address the reactive power requirements of wind generators, and require new wind generators to provide primary frequency response and voltage ride-through capabilities. In addition, ERCOT evaluates the impact of increased installed wind generation on ancillary services requirements on an ongoing basis and adjusts those requirements as appropriate. There are no anticipated reliability concerns resulting from high levels of Demand Response resources. ERCOT limits the participation of Demand Response resources, or LaaRs, to providing 50 percent of the Responsive Reserve Ancillary Service (currently 1150 MW), which is only deployed in response to large frequency excursions (below 59.7 Hz) or during system emergencies, such as Energy Emergency Alerts. Currently, there are no low water level concerns in the ERCOT Region for the assessment period, however, there may be generators with restricted output due to environmental regulations, such as emissions or high water temperatures. Any generator restrictions will be reflected in the Seasonal Net Dependable Capability values reported to ERCOT. The effects of these limitations are mitigated through procurement of ancillary services and Out of Merit Capacity (OOMC) deployments. At this time, these issues do not constitute a significant reliability concern for the Region. While no smart grid program has been fully implemented in the past year, entities in the ERCOT Region had installed 600,000 smart meters as of the beginning of March. New programs designed for the use of this equipment are beginning to roll out, but are not a reliability concern for the summer season. Reliability Assessment The reserve margin for the 2010 summer assessment period is projected to be 19.4 percent, which is 6.9 percent higher than the 12.5 percent minimum reserve margin level for ERCOT. The ERCOT minimum reserve margin target of 12.5 percent is based on Loss-of-Load Expectation (LOLE) assessment of no more than one day in ten years’ loss of load based on the latest loss of load probability (LOLP) study, which was completed in 2007.32 The projected anticipated capacity resources reserve margin for 2010 is 1.1 percent higher than the 15.9 percent reserve margin that was projected for 2009 in last year’s Summer Assessment. While there is only a slight increase in the peak demand forecast for the 2010 summer when compared to the forecasted peak demand for 2009 summer, this is offset by the increase in committed generation from 2009 to 2010, resulting in the higher projected reserve margin for 2010.

32 http://www.ercot.com/meetings/gatf/keydocs/2007/20070112-GATF/ERCOT_Reserve_Margin_Analysis_Report.pdf




In the ERCOT Region, independent generator owners and operators are responsible for their own fuel supply. In the event of forecasted extreme weather and possible fuel curtailments, ERCOT may request fuel capability information from qualified scheduling entities that represent generation to prepare operationally for potential curtailments. Gas curtailments do not typically occur in the summer season. In addition, ERCOT is a member of the Texas Energy Reliability Council, which helps to coordinate between the gas and electric industries and, if necessary, allocate deliveries of natural gas during periods of high demand. The 2009 Five-Year Transmission Plan included a steady-state voltage assessment of the ERCOT system for 2010 summer. Bus voltages were checked for NERC categories A and B contingency conditions. Results from a voltage stability study done on the 2010 summer network conditions indicate that the interconnection system has sufficient voltage stability margin when tested with NERC Categories A, B, and selected C contingencies. Other Region-Specific Issues 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 actions described in Section 5.6 of the ERCOT Protocols33 and Section 4 of the ERCOT Operating Guides,34 which describe Energy Emergency Alerts (EEA) and procedures for use of interruptible load, voltage reductions, procuring emergency energy over the asynchronous ties, and ISO-instructed Demand Response. Region Description The Electric Reliability Council of Texas (ERCOT) manages the flow of electric power to 22 million Texas customers - representing 85 percent of the state's electric load and 75 percent of the Texas land area (200,000 sq. mi.). As the independent system operator for the region, ERCOT schedules power on an electric grid that connects 40,000 miles of transmission lines and more than 550 generation units. ERCOT also manages financial settlement for the competitive wholesale bulk-power market and administers customer switching for 6.5 million Texans in competitive choice areas. The ERCOT Region is a separate electric interconnection located entirely in the state of Texas and operated as a single balancing authority. ERCOT is a summer-peaking Region responsible for about 85 percent of the electric load in Texas with an all-time peak demand of 63,400 MW set in July 2009. The Texas Regional Entity (Texas RE), a functionally independent division of ERCOT Inc., performs the Regional Entity functions described in the Energy Policy Act of 2005 for the ERCOT Region.

33 http://www.ercot.com/mktrules/protocols/current.html 34 http://www.ercot.com/mktrules/guides/operating/current



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WWeesstteerrnn IInntteerrccoonnnneeccttiioonn WWEECCCC

Introduction Western Electricity Coordinating Council (WECC) is one of eight electric Regional Entities in North America. WECC is responsible for coordinating and promoting Bulk Power System reliability in the Western Interconnection. WECC ensures open and nondiscriminatory transmission access among its members, provides a forum for resolving transmission access disputes, and provides an environment for coordinating the operating and planning activities of its members as set forth in the WECC bylaws. WECC is geographically the largest and most diverse of the eight Regional Entities that have Delegation Agreements with the North American Electric Reliability Corporation (NERC). WECC’s service territory extends from Canada to México. It includes the provinces of Alberta and British Columbia in Canada, the northern portion of Baja California in México, and all or portions of the 14 Western states in between. Due to the vast and diverse characteristics of the Region, WECC and its members face unique challenges in coordinating day-to-day interconnected system operations and long-range planning needed to provide reliable electric service across nearly 1.8 million square miles. WECC is divided into four subregions: Northwest Power Pool (NWPP), Rocky Mountain Power Area (RMPA), Desert Southwest Area (DSWA), and California/México Area (CA/MX). The NWPP is winter-peaking with a large amount of hydro resources. The RMPA’s peak occurs in


Direct Control Load Management 740Contractually Interruptible (Curtailable) 2,618Critical Peak-Pricing with Control 386Load as a Capacity Resource 404


2009 Summer Comparison MW % Change2009 Summer Projected Peak Demand 156,717 -8.0%2009 Summer Actual Peak Demand 146,650 -1.7%All-Time Summer Peak Demand - July 2006 161,131 -10.5%



Nuclear5%

Hydro28%

Coal18%

Gas37%

Dual Fuel6%

Other4%

PumpedStorage

2%

Nuclear5%

Hydro28%

Coal18%

Gas37%

Dual Fuel6%

Other4%

Pumped Storage

2%



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either the summer or the winter, and has a large amount of coal generation. The DSWA and CA/MX subregions peak in the summer and the majority of their resources are gas-fired. WECC expects to have adequate generation capacity, reserves, and transmission for the forecasted 2010 summer peak demands and energy loads. This is attributed to the combination of additional generation resources and transmission system enhancements. Demand The aggregate WECC 2010 summer total internal coincident demand is forecast to be 148,365 MW and is projected to occur in August 2010. The forecast is based on normal weather and reflects generally recessionary economic conditions. The forecast is 1.2 percent above last summer’s actual coincident peak demand, which was established under generally normal temperatures and poor economic conditions in the Region. The 2010 summer Total Internal Demand forecast is 7.7 percent less than the forecast non-coincident peak demand of 160,688 MW for 2009 summer.

Table WECC-1: WECC Region and Subregion Demand Comparisons

SUMMER PEAK WECC NWPP RMPA DSWA CA/MX 2009 Forecast 160,688 57,825 11,224 29,488 64,286 2009 Actual 146,650 62,344 10,565 27,968 59,418 Difference (MW) -14,038 4,519 -659 -1,520 -4,868 Difference % -8.7 % 7.8 % -5.9 % -5.2 % -7.6 % 2009 Actual 146,650 62,344 10,565 27,968 59,418 2010 Forecast 148,365 54,120 10,979 27,816 59,612 Difference (MW) 1,715 -8,224 414 -152 194 Difference % 1.2 % -13.2 % 3.9 % -0.5 % 0.3 % 2009 Forecast 160,688 57,825 11,224 29,488 64,286 2010 Forecast 148,365 54,120 10,979 27,816 59,612 Difference (MW) -12,323 -3,705 -245 -1,672 -4,674 Difference % -7.7 % -6.4 % -2.2 % -5.7 % -7.3 % Note: 2009 forecast demands are non-coincident

WECC specifically directs its balancing authorities to submit forecasts with a 50-percent probability of occurrence. These forecasts generally consider various factors such as population growth, economic conditions, and normalized weather so that there is a 50-percent probability of exceeding the forecast. The internal peak demand forecasts presented here are coincident sums of shaped hourly demands adjusted by demand forecasts provided by WECC’s balancing authorities. Comparisons with hourly demand data indicate that WECC non-coincident peak demands generally exceed coincident peak demands by two to four percent. The peak demand forecasting methods used by entities vary widely and range from not making any weather or economic assumptions to using a combination of the Electric Power Research Institute-developed Residential End-Use Energy Planning System and the Commercial End-Use Model to forecast the commercial sector energy demands by end-use and then using an



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econometric method by major Standard Industrial Classification codes. WECC does not assess the demand-forecasting methods of the various entities. Energy efficiency programs vary by location and are generally offered by the load-serving entity (LSE). Programs include: ENERGY STAR builder incentive programs, business lighting rebate programs, retail compact fluorescent light bulb programs, home efficiency assistance programs, and programs to identify and develop ways to streamline energy use in agriculture, manufacturing, water systems, etc. For purposes of verification, some LSEs retain independent third parties to evaluate their programs. Demand-side management (DSM) programs offered by LSEs vary widely. The 2010 internal demand forecast includes 740 MW of direct control load management (DCLM), 2,618 MW of interruptible demand capability, 404 MW of load as a capacity resource and 386 MW of critical-peak-pricing with control. DCLM programs largely focus on air conditioner cycling programs, while interruptible demand programs focus primarily on large water pumping operations and large industrial operations such as mining. The summer forecast DSM of 4,148 MW, which is 2.8 percent of Net Internal Demand, is down slightly from the DSM of 4,290 MW forecast for last summer. Each LSE is responsible for verifying the accuracy of its DSM and energy efficiency programs. Methods for verification include: direct end-use metering, sample end-use metering, and baseline comparisons of metered demand and use. Generation For the peak summer month of August, WECC expects a reserve margin of 28.1 percent (40,487 MW), which significantly exceeds a supply adequacy model planning reserve margin of about 14.3 percent. The anticipated capacity resources for this summer’s peak period are projected to be 184,704 MW compared to 199,310 MW for 2009 summer. The capacity resource change is not reflective of a reduction in installed capability. Rather, it is largely due to a revised hydro operation assumption. The present energy limitation representation reflects load-driven unused capacity rather than a simple adverse hydro derate assumption and is now consistent with the hydro generation representation used by WECC for other system-modeling studies. The net capacity resources include no firm capacity transactions with regions external to WECC. While more than 7,000 MW of plant outages for maintenance are scheduled during the peak month of August, no significant individual generating units are scheduled to be out of service or retired in the summer-peaking portions of WECC. The following table presents the existing and planned resources for the peak month of the summer period.




Table WECC-2: Existing and Future Resources (WECC at August 2010 peak)

Existing, Certain (MW)

Existing, Other (MW)

Future, Planned and Other (MW)

Total On-Peak Resources 183,172 0 1,532 Conventional Expected On-Peak 133,807 0 1,182 Wind Expected On-Peak 2,010 0 170 Solar Expected On-Peak 444 0 5 Hydro Expected On-Peak 45,925 0 175 Biomass Expected On-Peak 986 0 0Derates or Maintenance 25,256 280 Wind Derate On-Peak 7,123 236 Solar Derate On-Peak 98 0 Hydro Derate On-Peak 10,609 0 Biomass Derate On-Peak 167 44 Scheduled Outage—Maintenance 7,259 0 Transmission-Limited Resources 0 0Existing-Inoperable 0 0

The projected hydro levels for the 2010 summer season are below normal, but the hydro generation is projected to be sufficient to meet the summer peak demands and energy loads. Hydro resources have been derated to reflect low hydro conditions and are not projected to have any further impact on margins. WECC does not analyze possible fuel supply interruption. Historically, coal-fired plants have been built at or near their fuel source and generally have long-term fuel contracts with mine operators, or the power plant owners actually own the mines. Gas-fired plants are historically located near major load centers and rely on relatively abundant western gas supplies. Many of the older gas-fired generators in the Region have backup fuel capability and normally carry an inventory of backup fuel. WECC does not require verification of the operability of the backup fuel systems and does not track on-site backup fuel inventories. Most of the newer generators are strictly gas-fired plants. Some 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, maintaining back-up oil supplies, maintaining adequate coal supplies, or acquiring purchase power agreements for periods of possible adverse hydro conditions. Power plant operators indicate that their natural gas supplies largely come from the San Juan Basin in northwest New Mexico and the Permian Basin in western Texas, from the gas fields in the Rocky Mountains, and from the Sedimentary Basin in western Canada. Individual entities may have fuel supply interruption mitigation procedures in place, including on-site coal storage facilities. Extreme weather during peak load conditions is not projected to have a significant impact on the fuel supply.



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Capacity Transactions on Peak Some WECC entities rely heavily on short-term power markets, generally using the Western System Power Pool (WSPP) contracts. The WSPP Agreement is a set of FERC-approved standardized power sales contracts used by jurisdictional and non-jurisdictional entities. The most commonly used WSPP contract is the firm capacity/energy sale or exchange, which contains liquidated damage provisions and is heavily relied on as the template for such transactions. These contracts do not reference specific generating units or a system of units, and liquidated damages are the only remedy for non-delivery. Although some WECC entities have capacity import contracts with entities in the Eastern Interconnection, this assessment takes a conservative approach of not including capacity imports from external entities. However, the individual subregion resources include firm transfers between subregions within WECC. These transfers represent assumed firm purchases and, or sales and plant-contingent transfers from one subregion to another. The plant contingent transfers usually have transmission rights associated with them. Most balancing authorities are associated with one of the three reserve sharing groups within WECC. These reserve sharing groups do not cross the WECC Regional boundary and do not rely on outside assistance from other regions for emergency imports. Transmission Entities within WECC have processes in place to assess generation deliverability. WECC prepares an annual power supply assessment that is designed to identify major load zones within the Region that may experience load curtailments due to physically-constrained paths and internal resource limitations. In addition, extensive operating studies are prepared that model the transmission system under a number of load and resource scenarios, and operating procedures are developed to maintain safe and reliable operations. Also, major power system operators have internal processes for identifying and addressing local area resource limitations, and independent grid operators have formal procedures for obtaining reliability must-run capability—including voltage support capability—for resource-constrained areas. The resources reported in this assessment have been reduced by only a few megawatts to reflect deliverability constraints identified by transfer capability studies, interconnection agreement studies, etc. Most of the transmission facility additions scheduled to enter service prior to next fall relate to local area improvements or renewable energy delivery projects and are not particularly significant to overall interconnected system operation. However, the Gateway West 500 kV transmission project across portions of southern Wyoming and southern Idaho and the Miracle Mile to Ault 115 kV line upgrade to 230 kV are in the transmission-constrained Wyoming/Idaho/Utah/Colorado portion of the system and delays in their in-service dates could adversely impact economy energy transfers. Any such delays are not projected to degrade interconnected system performance during the summer peak period. The transmission system is considered adequate for all projected firm transactions and significant amounts of economy energy transfers. Reactive reserve margins are projected to be adequate for all projected peak load conditions in all areas. Close attention to maintaining appropriate voltage levels is projected to prevent voltage problems.




Table WECC-3: Transmission System Additions and Upgrades (115 kV & Above) January 2010 through September 2010

Transmission Project Name Length (Miles)

Voltage (kV)

In-Service Date(s) Description / Status

Northwest Power Pool

Selkirk Voltage Control Shunt 0 500 3/1/2010 Under Construction 416-SW 240 kV Transmission 296 240 5/26/2010 Under Construction 230 kV Line from Malaspina-East Toba, Montrose and Saltery Bay (2L48)

107 230 6/1/2010 Under Construction

Gateway West Transmission 8 230 6/1/2010 Under Construction

Gateway West Transmission 126 500 6/1/2010 Ckt #1 Midpoint S/S to

Hemingway S/S (loop of Midpoint-Summer Lake)

Gateway West Transmission 134 500 6/1/2010 Hemingway S/S to Burns

S.C. (loop of existing Midpoint-Summer Lake)

416-SW 240 kV Transmission 200.8 240 7/7/2010 Under Construction 416-SW 240 kV Transmission 76 138 7/7/2010 Under Construction Saltery Bay Substation Transformer


Bowmont Substation Auto-transformer


Gateway West Transmission Substation

500 230 6/1/2010 N/A

Keephills 3 Phase Shifter 500 240 9/1/2010 N/A

Rocky Mountain Power Area

South Rapid Cap Banks 0 230 2/5/2010 In-Service West Canon-Arequa Gulch 115 kV Line


Reader-Airport Memorial 115 kV Line


Miracle Mile-Cheyenne 230 kV line

35 230 5/1/2010 Replace an existing 115

kV line

Cheyenne-Ault 230 kV line 146 230 5/1/2010 Replace an existing 115

kV line Bayfield-Durango 115 kV Line Rebuild


Henry Lake 230 kV Addition 0 230 6/30/2010 Breakers Torrington transformer additions

115 34.5 3/1/2010 N/A

Erie 230-115 kV Sub Transformer

230 115 3/31/2010 N/A



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230 kV Portner Substation 230 N/A 5/1/2010 Planned Gladstone 230-115 kV Sub Transformer

230 115 6/30/2010 N/A

Desert Southwest Area

Pipeline-Picante 115 kV Line 9 115 5/1/2010 N/A Picante-Biggs 115 kV Line 5 115 5/1/2010 N/A Picante-Global Reach 115 kV Line

5 115 5/1/2010 N/A

Capacitors (Cholla-Saguaro 500 kV line)

0 500 5/1/2010 N/A

Capacitors (Westwing-VV1 500 kV line)

0 500 5/1/2010 N/A

Capacitors (Moenkopi-Yavapai 500 kV line)

0 500 5/1/2010 N/A

Reactor replacement (Reactor #4)

0 500 6/1/2010 N/A

Morgan-Pinnacle Peak 500 kV line

26 500 6/1/2010 N/A

Raceway 500/230 kV (500 kV loop in)

1 500 6/1/2010 N/A

Raceway-Avery 230 kV Line 9 230 6/1/2010 N/A Picante 345/115 kV Autotransformer


Flagstaff Interconnection Substation

345 69 6/1/2010 N/A

Raceway 500 kV Substation 500 230 6/1/2010 N/A

California/Mexico Area Victorville 2 -loop Victor-Lugo 220 kV line into Victorville power project

0 220 1/15/2010 Planned

Table Mountain-Rio Oso/Palermo-Colgate-Rio Oso 230 KV Line Reconductoring (T1030B)


South of Birds Landing 230 kV Reconductoring (T972A)


Mesa 115 kV Shunt Capacitors (T965)


El Centenario-La Rosita 8 230 6/1/2010 Planned El Centenario-Sanches Taboada

8 230 6/1/2010 Planned

Tehachapi Renewable Transmission Project Segments 1-3

82.7 500 6/1/2010 Planned




Buck Blvd-Julian Hinds 230 kV


Rector Substation SVS 0 230 6/1/2010 Conceptual Colusa Generating Station Interconnection

230 N/A 5/1/2010 In-service

Stone Substation Expansion (T1055)


7th Standard Substation Interconnection (D) (T1020)

115 N/A 5/31/2010 Planned

Carrizo Plain Solar Generation (Q194) Interconnection

230 N/A 5/31/2010 Planned

Calpine Russell City Energy Center (P02186, P02187, P02188) (Q45, Q67) Interconnection

230 N/A 6/30/2010 Planned

Operational Issues WECC does not expect any major scheduled generating unit outages, transmission facility outages, or unusual operating conditions that would adversely impact reliable operations. The balancing authorities and planning authorities coordinate the planning of long-range scheduled maintenance outages. This assures that there is sufficient generation available during scheduled transmission outages and that there is sufficient transmission available during scheduled generation outages to access other resources. No environmental or regulatory restrictions have been reported that are projected to adversely impact reliability. WECC does not anticipate reliability issues related to renewable generation during minimum demand periods and does not anticipate reliability issues related to high levels of demand-response resources. Unexpectedly high forced outage rates, near-term load under-forecast errors and, or near-term wind generation over-forecast errors may result in unexpectedly low operating margins and may even result in voluntary or involuntary demand curtailments. Solar resources are also subject to short-term generation forecast errors but solar penetration is not sufficient to be a significant issue this summer. Balancing authorities attempt to reduce the probability of curtailments by continually refining their forecasting tools and, as appropriate, increasing their operating reserve targets. Due to these ongoing activities, WECC does not expect to experience demand reductions due to variable generation forecast errors. Reliability Assessment The projected reserve margin for the peak month of August is 28.1 percent, nearly double the target margin of 14.3 percent. For the summer assessment, WECC requested information from its balancing authorities about any studies they have performed for the summer assessment period. WECC also requests balancing authorities to update any applicable data (actual loads, forecasts, outages, and future and existing resource status changes) that have been previously submitted to WECC. The submitted information and data is then reviewed and compiled into the resource assessment for the WECC Region and subregions.



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The loads and resources are compared against the target reserve margins that were developed for WECC’s Power Supply Assessment (PSA) and WECC’s Long Term Reliability Assessment. The target reserve margins were developed using 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 one-in-ten weather events. The building block values were developed for each balancing authority and then aggregated by subregions and the entire WECC Region for the PSA, Long Term Reliability Assessment (LTRA), and the seasonal reliability assessments. The aggregated summer season planning reserve margin target for WECC of 14.3 percent may differ from some of the state, provincial, or LSE requirements within WECC, but was developed specifically for use in the above mentioned assessments. 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 could impact the interconnected system. The details of this review procedure are located in Section III of the WECC Planning Coordinating Committee’s Handbook. 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. Transmission providers use the method and criteria contained in the appropriate standards including WECC Standard TOP-STD-007-0—Operating Transfer Capability and FAC-012-1—Transfer Capability Method. 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 Work Group help develop various base cases and studies as reported in the Annual Study Report. As part of the studies, WECC staff performs selective transient dynamics and post-transient analyses on the base cases and publishes the analyses in WECC’s Annual Study Report. WECC’s Annual Study Report provides an assessment of the transmission system in the Western Interconnection and 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 and Dynamics Data for Transmission System Modeling and 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 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 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 projected to meet NERC and WECC standards.



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California/México Area (CA-MX) Demand The California/México Area is a summer-peaking area. The 2010 summer coincident peak demand of 59,612 MW, which is projected to occur in August, is 0.3 percent greater than last summer’s actual coincident peak demand of 59,418 MW and is 7.3 percent less than last summer’s forecast non-coincident peak demand of 64,286 MW. The area’s 2009 summer peak demand occurred during a period of generally normal temperatures. For the 2010 summer period, direct control load management demand, contractually interruptible demand, critical peak-pricing with control demand, and load as a capacity resources demand total 2,591 MW. While area entities expect to serve all firm demand, it should be noted that a significant portion of California operates under a market system that includes load as a capacity resource that may be bid into the market. Hence, served non-firm demand may be less than 2,591 MW forecast by the amount of the capacity bids in effect during the peak hour. Generation California hydro generation is projected to be near normal. The following table presents the existing and planned resources for the peak month of the summer period.

Table WECC-4: Existing and Future Resources (CA/MX at August 2010 peak)

Existing-Certain (MW)

Existing- Other (MW)

Future-Planned and Other (MW)

Total On-Peak Resources 57,244 0 640 Conventional Expected On-Peak 48,843 0 585 Wind Expected On-Peak 46 0 10 Solar Expected On-Peak 433 0 5 Hydro Expected On-Peak 7,563 0 40 Biomass Expected On-Peak 359 0 0Derates 6,516 91 Wind Derate On-Peak 1,912 91 Solar Derate On-Peak 14 0 Hydro Derate On-Peak 3,224 0 Biomass Derate On-Peak 122 0 Scheduled Outage—Maintenance 1,244 0 Transmission-Limited Resources 0 0Existing, Inoperable 0 0 0

Transmission Although several major constrained transmission paths have been upgraded in recent years, path constraints can still exist. Operating procedures are in place to manage any high loading conditions that may occur during the summer. Many areas of California are prone to seasonal brush and forest fires that may impact the transmission system. While the fire-related transmission outages may temporarily affect local




areas, widespread and significant interruptions to electric power delivery are not projected to be an issue during the summer peak period. Operational Issues The San Francisco Bay area, San Diego area, and Los Angeles basin have been identified as reactive power limited areas. The California ISO has developed reactive power reserve monitoring tools and nomograms for each of those areas to ensure that adequate reactive power is available to protect against the next credible contingency. Entities in California have developed several ongoing annual programs to prepare for summer peak conditions. Programs used by the California ISO include:

Assess utility procurement plans to meet resource adequacy requirements Work with investor owned utilities to further refine execution of demand-response

programs Work directly with the power plant owners Maintenance procedures Test units prior to summer peak load period Work with transmission owners on maintenance programs Hold operator training workshops Bring together grid operators from all over the West Work with California fire authorities Review current conditions Review real-time notification procedures Participate in operator training workshops Coordinate with balancing authorities in the West Share information and prepare for contingencies Foster ongoing relationships to rely on each other during critical periods Coordinate with state energy agencies, Flex Your Power, and investor owned utilities to

promote conservation Reliability Assessment The projected reserve margin for the peak month of August is 30.2 percent compared to the target margin of 14.8 percent. Generation and transmission facilities are projected to be sufficient to provide reliable electric service throughout the area. Other Items All power plants in California are required to operate in accordance with strict air quality regulations. Some plant owners have upgraded emission control equipment to remain in compliance with stricter emission limitations while other owners have chosen to discontinue operating some plants. The effects of owners’ responses to environmental regulations have been accounted for in the area’s resource data and it is not projected that environmental issues will have additional adverse impacts on resource adequacy within the area during the upcoming summer season.



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The California Public Utilities Commission’s year-ahead and month-ahead resource adequacy program requires jurisdictional LSE to demonstrate a 15 percent planning reserve margin. The California ISO requires the non-jurisdictional LSEs to demonstrate a planning reserve margin that meets each LSE’s local regulatory authority’s planning criteria. For 2009, the aggregated planning reserve margin for August was 14.95 percent. The year-ahead requirement is 90 percent of the full 115 percent of total resource adequacy obligation, which has been met for 2010. The full 115 percent of total resource adequacy obligation needs to be demonstrated 30 days prior to the beginning of each month. California’s current 15 percent to 17 percent planning reserve margin was agreed on pending a more rigorous process to develop a replacement margin. The California Public Utilities Commission has an objective to establish a planning reserve margin based on an appropriate loss of load expectation method and an order instituting rulemaking has been assigned. An initial draft planning reserve study has been prepared but it is not projected that this activity will have any effect on reliability planning for the upcoming summer season. California entities are very aggressively pursuing a variety of smart grid and smart metering programs. These efforts include improvements to the collection of voltage and phase angle information to provide a more robust model and a more reliable smart grid. Smart metering programs for both active and passive demand control are either already implemented or are under active development, but it is not projected that such programs will significantly affect system operations during the summer period.




Desert Southwest Area (AZ-NM-SNV) Demand This is a summer-peaking area. The 2010 summer coincident peak demand of 27,816 MW, which is projected to occur in August, is 0.5 percent below last summer’s actual coincident peak demand of 27,968 MW. The 2010 peak forecast is 5.7 percent less than last summer’s forecast non-coincident peak demand of 29,488 MW. The area’s 2009 summer peak demand occurred during a period of generally normal temperatures. For the 2010 summer period, direct control load management demand, contractually interruptible demand, critical peak-pricing with control demand and load as a capacity resources demand total 527 MW. Generation The Lower Colorado River Basin is in the tenth year of an unprecedented drought. Due to low reservoir levels, current Hoover power plant capacity projections for this summer indicate an projected average capacity of 1,585 MW compared to a maximum plant output of 2,074 MW. The latest 24-month study projections developed by the U.S. Bureau of Reclamation indicate that reservoir elevations are sufficient to meet peak demand and daily energy demand throughout the 2010 summer period. The following table presents the existing and planned resources for the peak month of the summer period. Transmission Based on inter- and intra-area studies, the transmission system is considered adequate for projected firm transactions and a significant amount of economy electricity transfers. When necessary, phase-shifting transformers in the southern Utah/Colorado/Nevada transmission

Table WECC-5: Existing and Future Resources (DSWA at August 2010 peak)


Existing-Other (MW)

Future- Planned and Other (MW)

Total On-Peak Resources 38,773 0 14 Conventional Expected On-Peak 35,244 0 14 Wind Expected On-Peak 90 0 0 Solar Expected On-Peak 49 0 0 Hydro Expected On-Peak 3,366 0 0 Biomass Expected On-Peak 24 0 0Derates 404 0 Wind Derate On-Peak 256 0 Solar Derate On-Peak 38 0 Hydro Derate On-Peak 108 0 Biomass Derate On-Peak 0 0 Scheduled Outage—Maintenance 2 0 Transmission-Limited Resources 0 0Existing, Inoperable 0 0 0



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system will be used to help control unscheduled flows. Reactive reserve margins have been studied and are projected to be adequate throughout the area. The 2009–2010 winter period was especially wet and rainy, leading to accelerated underbrush growth and an anticipated significant fire hazard. Under such conditions, fire-induced outages of the power grid are of concern due to possible impacts on combinations of parallel 345 kV and 500 kV lines. Special operating studies are prepared to determine safe operating conditions for potential combined losses of these lines. In order to mitigate wildfire service interruptions, neighboring utilities in Arizona coordinate weekly or as needed to assess the potential fire hazard. Annual studies have been performed to determine the system import limit for the Phoenix metropolitan area with all local generation out of service, and to determine the maximum load-serving capability with local generation modeled as being in service. Operational Issues Fuel supplies are projected to be adequate to meet summer peak demand and energy load conditions. In addition, firm coal supply and transportation contracts are in place, and sufficient coal inventories are anticipated for the summer season. Balancing authorities in the area are members of the Southwest Reserve Sharing Group (SRSG). In addition to in-area balancing authorities, the SRSG serves California’s Imperial Irrigation District. Reliability Assessment The projected reserve margin for the peak month of August is 23.2 percent compared to the target margin of 13.6 percent. Generation and transmission facilities are projected to be sufficient to provide reliable electric service throughout the area.




Rocky Mountain Power Area (RMPA) Demand The Rocky Mountain Power Area peak demand may occur in either summer or winter. The 2010 summer coincident peak demand of 10,979 MW is projected to occur in July and is 3.9 percent greater than last summer’s actual coincident peak demand of 10,565 MW. The 2010 summer coincident peak forecast is 2.2 percent less than last summer’s projected non-coincident forecast peak demand of 11,224 MW. The area’s 2009 summer peak demand occurred during a period of generally cooler than normal temperatures. For the 2010 summer period, direct control load management demand, contractually interruptible demand, critical peak-pricing with control demand, and load as a capacity resources demand total 372 MW. Generation Hydro conditions for the 2010 summer period are projected to be below normal but the reservoir releases should be sufficient to meet contractual requirements. Under normal conditions, the Glen Canyon hydro plant is subject to water release restrictions. However, in a declared emergency condition, where power system reliability and stability are judged to be at risk, the restrictions may be waived. The following table presents the existing and planned resources for the peak month of the summer period.

Transmission The transmission system is projected to be adequate for all firm transfers and most economy energy transfers. However, the transmission path between southeastern Wyoming and Colorado often becomes heavily loaded, as do the transmission interconnections to Utah and New Mexico.

Table WECC-6: Existing and Future Resources (RMPA at July 2010 peak)




Total On-Peak Resources 14,268 0 100 Conventional Expected On-Peak 13,078 0 100Wind Expected On-Peak 188 0 0 Solar Expected On-Peak 4 0 0Hydro Expected On-Peak 998 0 0 Biomass Expected On-Peak 0 0 0Derates 1,339 0Wind Derate On-Peak 1,010 0 Solar Derate On-Peak 4 0Hydro Derate On-Peak 167 0 Biomass Derate On-Peak 0 0Scheduled Outage—Maintenance 158 0 Transmission-Limited Resources 0 0Existing, Inoperable 0 0 0



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WECC’s Unscheduled Flow Mitigation Plan35 may be invoked to provide line-loading relief for these paths, if needed. The RMPA, like several other areas in WECC, has bulk power system transmission lines that are potentially exposed to fire hazards that may adversely impact intra-Regional power transfers. Colorado entities have participated in the 2009 Colorado Coordinated Planning Group Study, WECC operating transfer studies, and the common use system (CUS) studies as required by FERC Order 890 (through CUS TCPC). Operational Issues Fuel supplies are projected to be adequate to meet summer peak demand and energy load conditions. In addition, firm coal supply and transportation contracts are in place, and sufficient coal inventories are anticipated for the summer season. Balancing Authorities in the area are members of the Rocky Mountain Reserve Sharing Group. Reliability Assessment The projected reserve margin for the peak month of July is 30.7 percent compared to the target margin of 12.3 percent. Generation and transmission facilities are projected to be sufficient to provide reliable electric service throughout the area.

35 http://www.wecc.biz/committees/StandingCommittees/OC/UFAS/Shared%20Documents/UFAS%20Mitigation%20Plan.pdf




Northwest Power Pool (NWPP) The Northwest Power Pool (NWPP) is comprised of all or major portions of the states of Washington, Oregon, Idaho, Wyoming, Montana, Nevada, and Utah; a portion of northern California; and the Canadian provinces of British Columbia and Alberta. This vast area covers 1.2 million square miles of WECC’s 1.8 million square miles. The NWPP, in collaboration with its members (20 Balancing Authorities), has conducted a reliability assessment to evaluate the ability of the NWPP to meet the load requirements during the 2010 summer. Since the NWPP covers a large and diverse area of the Western Interconnection, its members face unique issues in the day-to-day coordinated operations of the system. The NWPP area in aggregate is a winter-peaking area with a large amount of hydro resources. Analyses indicate that the NWPP will have adequate generation capacity and energy, required operating reserves (regulating reserve and contingency reserve), and available transmission to meet the forecasted firm loads for the 2010 summer operations, assuming normal ambient temperature and normal weather conditions. This assessment is valid for the NWPP area as a whole. However, these overall results do not necessarily apply to all subareas (individual members, Balancing Authorities, states, or provinces) when assessed separately. In 2007, the Sacramento Municipal Utility District (SMUD) and Turlock Irrigation District (TID) joined the NWPP. By late 2009, both of these northern California Balancing Authorities were fully integrated into the NWPP reserve sharing group and other operating programs, and are included in this NWPP assessment narrative. The NWPP has a publicly available document on its website that addresses 2010 summer conditions.36 Demand The NWPP 2009 coincident summer peak demand of 57,600 MW occurred on July 29, 2009. The 2009 coincident summer peak demand was 99.31 percent of the forecast; however, the coincident peak demand occurred during below-normal temperature conditions. Normalizing for temperature variance (50-percent probability), the 2009 coincident peak demand would have been 58,500 MW, or 100.9 percent of the forecast. The economic recession that began in 2007 has had an impact on the NWPP power use and future forecasts. The 2010 summer coincident peak demand forecast for the NWPP of 60,000 MW is based on normal weather, reflects the prevailing economic climate (no recovery), and has a 50-percent probability of not being exceeded. The NWPP has approximately 600 MW of interruptible demand capability and load management. In addition, the load forecast incorporates any benefit (load reduction) associated with demand-side resources not controlled by the individual utilities. Some of the entities within the NWPP area have specific programs to manage peak issues during extreme conditions.

36 http://www.nwpp.org/publications.html.



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Normally these programs are used to meet the entities’ operating reserve requirements and have no discernable impacts on the projected NWPP peak load. Under normal weather conditions, the NWPP does not anticipate dependence on imports from external areas during summer peak demand periods. However, if much lower than normal precipitation occurs, it may be extremely advantageous to use transfer capabilities from outside the NWPP to reduce reservoir drafts and aid reservoir filling. Generation Approximately 60 percent of the NWPP resource capability is from hydro generation. The remaining generation resources are conventional thermal plants and miscellaneous resources such as non-utility owned gas-fired cogeneration or wind. The following table presents the existing and planned resources for the peak month of the summer period.

NWPP power planning is done by subarea. Idaho, Nevada, Wyoming, Utah, northern California, 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. The Coordinated System hydro operation is based on critical water planning assumptions (currently the 1936–1937 water years). Critical water in the Coordinated System equates to approximately 11,000 average megawatts of firm energy load-carrying capability, when reservoirs start full. Under average water-year conditions, the additional non-firm energy available is approximately 3,000 average megawatts. April through July is the refill season when reservoirs store spring runoff. The March 2010 final forecast for the January through July runoff (Columbia River flows at The Dalles, Oregon) is 71.8 million acre-feet, which is 67 percent of the 30-year average. The water “fueling”

Table WECC-7: Existing and Future Resources (NWPP at July 2010 peak)

Existing- Certain (MW)



Total On-Peak Resources 75,503 809 Conventional Expected On-Peak 35,735 471 Wind Expected On-Peak 3,081 201 Solar Expected On-Peak 0 0 Hydro Expected On-Peak 36,099 137 Biomass Expected On-Peak 588 0Derates 13,715 90 Wind Derate On-Peak 2,650 46 Solar Derate On-Peak 0 0 Hydro Derate On-Peak 6,403 0 Biomass Derate On-Peak 60 44 Scheduled Outage – Maintenance 4,602 Transmission-Limited Resources 0Existing, Inoperable 0 0 0




associated with hydro-powered resources can be difficult to manage because there are several competing purposes including, but not limited to: current electric power generation; future (winter) electric power generation; flood control; biological opinion requirements resulting from the Endangered Species Act; and special river operations for recreation, irrigation, navigation, and the refilling of reservoirs each year. Any time precipitation levels are below normal, balancing these interests becomes even more difficult. With the competition for the water, power operations for the summer must be effective and efficient. The goal is to manage all the competing requirements while refilling the reservoirs to the greatest extent possible. Operators of the hydro facilities optimize the use of available water throughout the year while assuring all the competing purposes are evaluated. Although available reserve margin at time of peak can be calculated to be greater than 20 percent, this can be misleading. Since hydro can be limited due to conditions (either lack of water or imposed restrictions), the projected sustainable capacity must be determined before establishing a representative reserve margin. In other words, the firm energy load carrying capability (FELCC) is the amount of energy that the system may be called on to produce on a firm or guaranteed basis during actual operations. The FELCC is highly dependent on the availability of water for hydroelectric generation. The NWPP has developed the projected sustainable capacity based on the aggregated information and estimates that the members have made with respect to their own hydro generation. Sustainable capacity is for periods greater than two hours during daily peak periods assuming various conditions. This aggregated information yielded a reduction for sustained capability of approximately 7,000 MW. This reduction is more relevant to the Northwest in the winter; however, under summer extreme low-water conditions, it also impacts summer conditions. No thermal plant or fuel problems are anticipated. To the extent that existing thermal resources are not scheduled for maintenance, thermal and other resources should be available as needed during the summer peak period. Several states have enacted renewable portfolio standards that, by the mid-2010 decade, will require some NWPP members to satisfy at least 20 percent of their load with energy generated from renewable energy resources. This may result in a significant increase in variable generation within the NWPP, creating new operational challenges that will have to be addressed. Some of the safety net programs such as contingency reserve and under frequency load shedding will be re-evaluated for effectiveness. The NWPP estimated the installed wind generation capacity for the 2010 summer season will be approximately 6,500 MW, but the on-peak contribution is projected to be closer to 1,500 MW. With the increasing variable generation, conventional operation of the existing hydro and thermal resources will be impacted. The wind generation manufacturers’ standard operating temperature for wind turbines range from -10° C to +40° C (+14° F to +104° F). During the summer peak period, the temperature in the areas where the majority of the wind turbines are located can exceed 104° F, leaving no capability from the wind generation during those periods. In addition, there is a risk of over-



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generation in the spring and fall. When both the wind and hydro generation are in high-generation mode, and given the environmental constraints on dissolved gases in the river, there are times when desired generation may exceed projected load plus the ability to export. Operating procedures have been introduced to address this situation. The installed capacity of biomass generation within the NWPP is 670 MW, with projected on-peak amounts of 668 MW. Within the NWPP there is an underground natural gas storage facility. This storage is located near many of the gas plants located in the NWPP area, minimizing any effect that a Regional gas problem may cause. In addition, one entity in the NWPP area has more than 700 MW of generation that can be fired on diesel fuel. Capacity Transactions on Peak No reliance on resources external to the NWPP is assumed for the summer season. However, one balancing authority located in the NWPP area has an exchange agreement with an entity in California for additional energy, up to 300 MW. This exchange is backed up by firm generation for the duration of the summer period. Transmission Several balancing authorities are constructing new transmission within the NWPP area to address load service issues. No significant transmission lines are scheduled to be out of service during the summer season. Constrained paths within the NWPP area are known and operating studies modeling these constraints have been performed. As a result of these studies, operating procedures have been developed to assure safe and reliable operations. The inter-Regional transmission transfer capabilities, based on System Operating Limits (SOL) as determined by the Northwest Operational Planning Group, have been approved by WECC’s Operating Transfer Capability Policy Committee. These limits recognize transmission or generation constraints in systems external to the Region or subregion. The NWPP coordinated outage (transmission) system was designed to assure that outages could be coordinated among all stakeholders (operators, maintenance personnel, transmission users, and operations planners) in an open process. This process had to assure that proper operating studies were accomplished, and that transmission impacts and limits were known, to fulfill a requirement from the 1996 West Coast disturbances that the system be operated only under studied conditions. The WECC Reliability Coordinator is involved in the outage coordination process and has direct access to the outage database. The outage coordination process requires NWPP members to designate significant facilities that, if out of service individually or in conjunction with another outage, will impact system capabilities. The significant facilities are defined and updated annually by the NWPP members. The scheduled outage of these critical facilities is posted on a common database. All utilities post proposed significant outages on WECC’s Coordinated Outages System (COS). Outages are to be




submitted to the COS at least 45 days ahead of the month in which they are proposed to occur so they can be viewed by interested entities. The involved entities then facilitate the NWPP coordination of all these outages. Entities can comment on the preliminary impacts and schedules may be adjusted to maximize reliability and minimize market impacts. If coincidental outages cause too severe an impact, the requesting utilities work together to adjust schedules accordingly. A final outage plan is posted with estimated path capabilities 30 days prior to the month in which the outages will occur. Detailed operational transfer capability studies are then performed and the limits for each affected path are posted at least 15 days prior to the outage. Emergency outages can be requested outside of these schedule guidelines. Emergency outages are coordinated among adjacent utilities to minimize system exposure. Utilities can use the COS system to assure the system topology is correct for the next-day operating studies. As transmission operators increase the number of short-term outages in addition to the significant outages, the WECC Reliability Coordinator will be able to access the WECC COS database and use the final outage schedule in its real-time system assessment. This coordinated outage process has been very effective. The outage information is used by NWPP member utilities to perform system studies to maximize system reliability. The NWPP staff facilitates outage meetings every six months with each utility’s outage coordinator to discuss proposed longer-term outages. Utilities discuss anticipated outages needed for time-critical construction and periods where transmission capacity may need to be maximized. The outages are posted on the WECC COS and on the individual companies’ Open Access Same-time Information System (OASIS) sites. LRSOP responsibilities include:

Share outage information with all parties affected by outages of significant equipment (i.e., equipment that affects the transfer capability of rated paths). Information is shared two times each year for a minimum of a six-month period. The first meeting each year coordinates outages for July through December. The second meeting coordinates outages for January through June.

Review the outage schedules to assure that needed outages can be reliably accomplished with minimal impact on critical transmission use.

Outage coordinators are to post the outages on the Coordinated Outages System within the applicable timeframes.

Additional path curtailments may be required depending on current system conditions and outages. These curtailment studies are performed by the individual path operators based on the outage schedule developed through the COS process. According to the COS process, these studies are performed at least 15 days prior to the outage. Individual path operators and transmission owners may also perform updated next-day studies to capture emergency outage requests and current system conditions, such as generation dispatch, to determine if the SOL studies and limits are still accurate. Based on these studies, additional SOL curtailments may be determined by the path operators. The modified SOLs are posted on the individual transmission owner’s OASIS and the Reliability Coordinator is notified.



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The WECC Reliability Coordinator also performs system studies to ensure interconnected system reliability. The WECC Reliability Coordinator performs real-time system thermal studies to evaluate current operating conditions across the entire interconnection. The WECC Reliability Coordinator is in the process of incorporating real-time voltage tools to complement the thermal assessment currently being performed. Transient stability assessment capability is planned in the future. When the WECC Reliability Coordinator observes real-time reliability problems, it contacts the path operator to discuss the issue and work on a solution. The WECC Reliability Coordinator will issue a directive for action if there is an imminent reliability threat and the balancing authority does not eliminate the reliability issue within an appropriate time frame. The WECC-1-CR System Performance Criteria, requirement WRS3, is used to plan adequate voltage stability margin in the NWPP area as appropriate. Simulations are used to assure system performance is adequate and meets the required criteria. Operational Issues The NWPP area does not anticipate any operating issues for the 2010 summer season. The NWPP has developed an Adequacy Response Process whereby a team addresses the area’s ability to avoid a power emergency by promoting regional coordination and communications. Essential pieces of that effort include timely analyses of the power situation and communication of that information to all parties including—but not limited to—utility officials, elected officials, and the general public. In the fall of 2000, the area developed an Emergency Response Process (ERP) to address immediate power emergencies. The ERP remains in place and would be used in the event of an immediate emergency. The ERP would work with all parties in pursuing options to resolve the emergency including—but not limited to—load curtailment and, or imports of additional power from other areas outside of the NWPP. Reliability Assessment The projected reserve margin for the peak month of July is 31.9 percent, compared to the target margin of 14.8 percent. The NWPP area does not have one explicit method for determining an adequacy margin. The Bonneville Power Administration uses the Northwest Power and Conservation Council’s resource adequacy standard, which establishes targets for both the energy and capacity adequacy metrics derived from a loss of load probability assessment. Others utilize a reserve margin approach. Since no one method exists for the entire NWPP area, the NWPP has elected to use a reserve margin assessment for the summer assessment. The 2010 NWPP area generating capability is projected to be 85,000 MW, prior to adjusting for maintenance. In determining a planning margin for the current summer season one must further adjust for the operating reserve requirement, which is approximately 4,200 MW. At this point, based on a load of 50-percent probability of not being exceeded, the planning margin is approximately 24 percent. Further adjustment to reflect the ability to sustain peak associated with the hydro generation will drop the planning margin to approximately 16 percent.




As permitted by NERC and WECC criteria and standards, the Operating Committee of the NWPP has instituted a Reserve Sharing Program for contingency reserve. The reserve sharing process for the NWPP has been automated. A manual backup process is in place if communication links are down or the computer system for reserve sharing is not functioning correctly. The NWPP is designated as a reserve sharing group (RSG) as provided under WECC Operating Reliability Criteria. Each member of the RSG submits its contingency reserve obligation (CRO) and most severe single contingency (MSSC) to a central computer. The combined member CRO must be larger than the RSG MSSC. If not, then each member’s CRO is proportionally increased until this requirement is met. When any RSG member loses generation, they have the right to call on reserves from the other RSG members as long as they have first committed their own CRO. A request for contingency reserve must be sent within four minutes after the generation loss and the received contingency reserve can only be held for 60 minutes. A request is sent via the member’s energy management system to the central computer. The central computer then distributes the request proportionally among members within the RSG. Each member may be called to provide reserve up to its own CRO. Critical transmission paths are monitored in this process to ensure SOL limits are not exceeded. If a transmission path SOL is exceeded, the automated program redistributes the request among RSG members that are delivering reserve along non-congested paths. If a reserve request fails, backup procedures are in place to fully address the requirements. In view of the present overall power conditions, including the forecasted water condition, the area represented by the NWPP is estimating that it will be able to meet firm loads including the required operating reserve. Should any resources be lost to the area beyond the contingency reserve requirement or loads are greater than projected as a result of extreme weather, the NWPP area may have to look to alternatives—which may include emergency measures—to meet obligations.



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Regional Description WECC’s 287 members, including 37 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 website, www.wecc.biz.



Eastern Interconnection

EEaasstteerrnn IInntteerrccoonnnneeccttiioonn FFRRCCCC

Introduction Florida Reliability Coordinating Council (FRCC) expects to have adequate generating reserves with transmission system deliverability throughout the 2010 summer peak demand. In addition, Existing-Other merchant plant capability of 1,055 MW is potentially available as future resources of FRCC members and others. The transmission capability within the FRCC Region is projected to be adequate to supply firm customer demand and 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 these potential impacts to the bulk transmission system. For the 2010 summer assessment period, the FRCC will continue to work with its local Balancing Authorities (BAs), Generator Operators (GOPs) and regulatory partners to monitor and coordinate responses to the evolving situation in the Gulf of Mexico (GOM) with respect to potential impacts to FRCC Bulk Electric System (BES) facilities. The FRCC Operating Committee and its Reliability Coordinator functions will continue to develop BES assessments and response plans as warranted to identify any impacts due to oil contamination of cooling water serving coastal generating stations or fuel acquisition or delivery impacts due to the spill


Direct Control Load Management 2,565Contractually Interruptible (Curtailable) 649Critical Peak-Pricing with Control 0Load as a Capacity Resource 0


2009 Summer Comparison MW % Change2009 Summer Projected Peak Demand 42,531 0.7%2009 Summer Actual Peak Demand 44,152 -3.0%All-Time Summer Peak Demand - August 2007 46,739 -8.4%



Nuclear8%

Coal18%

Oil16%

Gas33%

Dual Fuel22%

Other3%

Nuclear8%

Coal18%

Oil16%

Gas33%

Dual Fuel22%

Other3%



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trajectories. Although there are no direct impacts by the GOM oil spill on FRCC capacity identified at this time, future and /or longer term impacts are to be determined, if any. Demand The FRCC is forecasted to reach its 2010 summer non-coincident peak Total Internal Demand of 46,034 MW in August, which represents a projected demand decrease of 1.5 percent compared to the actual 2009 summer demand of 46,712 MW. This projection for the 2010 summer is consistent with historical weather-normalized FRCC demand growth and is 0.7 percent higher than last year’s summer forecast of 45,734 MW. The small increase in the 2010 projected summer peak demand is attributed to a sluggish economy primarily driven by a declining housing market and higher energy prices.

Each individual Load Serving Entity (LSE) forecast takes into account historical temperatures to determine the normal temperature at the time of peak demand. The demand forecast for this summer takes into consideration the overall economy in Florida with emphasis on the price of fuel and electricity. Each individual LSE within the FRCC Region develops a forecast that accounts for the actual peak demand. The individual peak demand forecasts are then aggregated by summing these forecasts to develop the FRCC Region forecast. These individual peak demand forecasts are coincident for each LSE but there is some diversity at the region level. The entities within the FRCC Region plan their systems to meet the Reserve Margin criteria under both summer and winter peak demand conditions.

There are a variety of energy efficiency programs implemented by entities throughout the FRCC Region. These programs can include commercial and residential audits (surveys) with incentives for duct testing and repair, high efficiency appliance (air conditioning, water heater, heat pumps, refrigeration, etc.) rebates, and high efficiency lighting rebates.37 The 2010 net internal FRCC peak demand forecast includes the effects of 3,214 MW (7 percent of Net Internal Demand) of potential demand reductions from the use of direct control load management and interruptible load management programs composed of residential, commercial, and industrial demand. There currently is no critical peak pricing with control incorporated into the FRCC projection. Each LSE within the FRCC treats every Demand-Side Management load control program as “demand reduction” and not as a capacity resource. Entities within the FRCC use different methods to test and verify Direct Load programs such as actual load response to periodic testing, use of a time and temperature matrix and the number of customers participating. Projections also incorporate MW impacts of new energy efficiency programs. FRCC may assess the peak demand uncertainty and variability by developing regional bandwidths or 80-percent confidence intervals on the projected or most likely load (90/10). 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 actual observed load could exceed the high band. Likewise, there is a 10-percent probability that 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 loads is to quantify uncertainties of demand at the regional level. This would

37 Additional details can be found in the ten-year Site Plan filing for each entity at the following link https://www.frcc.com/Planning/Shared%20Documents/FRCC%20Presentations%20and%20Utility%2010-

Year%20Site%20Plans/2010/2010_TYSPs_ALL_LowRes.pdf




include weather and non-weather load variability such as demographics, economics, and price of fuel and electricity. The main factor driving the growth outlook for this summer’s forecast is a weak Florida economy. The FRCC Region reviews extreme summer conditions from a resource adequacy perspective as part of a Loss of Load Probability (LOLP) study by performing a load sensitivity assessment.38 Generation FRCC supply-side resources considered for the summer assessment are categorized as Existing-Certain, Existing-Other, and Existing-Inoperable. The total existing generation in the FRCC Region for this summer is 56,328 MW, of which 52,989 MW (465 MW of biomass) are Certain, 2001 MW are Inoperable, and 1338 MW are Other. The FRCC Region has a negligible amount of variable generation. The FRCC Region does not rely on hydro generation, therefore hydro conditions and reservoir levels will not impact the ability to meet the peak demand and the daily energy demand. For the 2010 summer period, no load serving concerns are anticipated due to fuel supply vulnerabilities. For extreme weather conditions, such as hurricanes affecting natural gas supply points, extreme temperatures, or impacts to pipeline infrastructure, alternate short-term fuel supply availability continues to be adequate for the Region. There are no additional fuel availability or supply issues identified at this time, and existing mitigation strategies continue to be refined. Based on recent studies, current fuel diversity, alternate fuel capability, and fuel study results, the FRCC does not anticipate any fuel transportation issues affecting resource capability during peak periods and/or extreme weather conditions this summer. The FRCC Region has not identified any unit retirements or planned unit outages that could have a significant impact on reliability. Capacity Transactions on Peak Currently, there are 2,168 MW of generation under firm contract that are available to be imported into the Region on a firm basis from the Southeastern subregion of SERC. No portions of these contracts are from Liquidated Damages or “make whole” contracts. These purchases have firm transmission service to ensure deliverability into the FRCC Region. No non-firm or Expected transactions are included in the assessment. 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 members and FRCC entities. Presently, the FRCC Region has 143 MW of generation under firm contract to be exported into the Southeastern Subregion of SERC. These sales have firm transmission service to ensure deliverability into the SERC Region. The FRCC does not consider non-firm or Expected sales to other regions as capacity resource reductions.

38https://www.frcc.com/Planning/Shared%20Documents/FRCC%20Load%20and%20Resource%20Plans/FRCC%202009%20Lo

ad%20and%20Resource%20Reliability%20Assessment.pdf



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Transmission Major additions to the FRCC bulk power system are mostly related to expansion in order to serve the growing demand and therefore maintain the reliability of the transmission system. The most notable transmission addition projected to be in service for the summer of 2010 includes the construction of a new 20.3-mile, 3,000A, 230 kV transmission line in the central Florida area, which is a significant enhancement from the existing 20.3-mile 230 kV, 1,235A line. A second 20.3-mile, 230 kV, 3,000A line has been delayed from May 2010 to September 2010 due to not having the ability to obtain the necessary clearances. The summer assessment was completed without this line in service and appropriate operational actions have been identified to remedy any reliability concerns. Presently no other significant transmission lines are projected to be out of service for maintenance during the summer period. Transmission constraints in the FRCC Region may require remedial actions depending on system conditions. Permanent solutions, such as the addition of new transmission lines and the rebuild of existing 230 kV transmission lines, have been identified and implementation of solutions is underway. In the interim, remedial operating strategies and specific remedies have been developed to mitigate thermal loadings and will continue to be evaluated to ensure system reliability. An inter-Regional transfer study is performed annually to evaluate the total transfer capability between FRCC and the Southeastern subregion of SERC. Joint studies of the Florida/Southeastern transmission interface indicate a summer seasonal import capability of 3,600 MW into the Region, and an export capability of 1,000 MW. These joint studies account for constraints within the FRCC and, or the Southeastern subregion of SERC. No other significant substation equipment additions are projected during the summer of 2010. Operational Issues FRCC expects the bulk transmission system to perform adequately over various system operating conditions with the ability to deliver the resources to meet the load requirements at the time of the summer peak demand. The results of the 2010 Summer Transmission Assessment, which evaluated the steady-state summer peak load conditions under different operating scenarios, indicates that any concerns with thermal overloads or voltage conditions can be managed successfully by operator intervention. Such interventions may include generation redispatch, system sectionalizing, reactive device control, and transformer tap adjustments. The operating scenarios analyses included the unavailability of major generating units within the FRCC. Therefore, various dispatch scenarios were evaluated to ensure generating resources within the FRCC are deliverable by meeting NERC Reliability Standards under these operating scenarios. No operational changes are needed to accommodate variable resources for the summer of 2010. Demand-Side Management load control programs within the FRCC are treated as “demand reduction” and not as a capacity resource. Therefore, high levels of demand reduction programs are considered to benefit reliability throughout the FRCC Region.




There are no foreseen environmental, regulatory restrictions, or unusual operating conditions that can potentially impact reliability in the FRCC Region during the 2010 summer period. For the 2010 summer assessment period, the FRCC will continue to work with its local Balancing Authorities (BAs), Generator Operators (GOPs) and Regulatory partners to monitor and coordinate responses to the evolving situation in the Gulf of Mexico (GOM) with respect to potential impacts to FRCC Bulk Electric System (BES) facilities. The FRCC Operating Committee and its Reliability Coordinator functions will continue to develop BES assessments and response plans as warranted to identify any impacts due to oil contamination of cooling water serving coastal generating stations or fuel acquisition or delivery impacts due to the spill trajectories. Although there are no direct impacts by the GOM oil spill on FRCC capacity identified at this time, future and /or longer term impacts are to be determined, if any. Entities within the FRCC Region may consider a wide range of programs to be smart grid programs. For example, some entities have been implementing programs that provide operational flexibility to minimize the number of customers potentially impacted during a distribution outage or manage distribution level feeder voltage control. Other entities may consider Demand-Side Management programs as a type of smart grid program. Implementation of these types of programs continues. No unusual operating conditions are projected that could impact reliability for the upcoming 2010 summer. The FRCC has a Reliability Coordinator agent that monitors real-time system conditions and evaluates near-term operating conditions of the bulk electric grid. The Reliability Coordinator uses a Region-wide state estimator and contingency assessment program to evaluate current system conditions. These programs are provided with real-time operating data from operating entities within the Reliability Coordinator footprint. These tools enable the FRCC Reliability Coordinator to implement operational strategies and procedures such as generation redispatch, sectionalizing, planned load shedding, reactive device control, and remotely controlled transformer tap adjustments to successfully mitigate potential or actual line loading and voltage concerns that may occur in real time. Reliability Assessment The FRCC Region is required by the state of Florida to maintain a 15 percent Reserve Margin (20 percent for Investor Owned Utilities). Based on the projected load and generation capacity, the calculated Reserve Margin for the summer of 2010 is 29.1 percent. This year’s calculated Reserve Margin is seven percent higher than last year’s calculation for the summer of 2009, primarily related to the availability of new generation. The 15 percent Reserve Margin was established based on a Loss Of Load Probability (LOLP) assessment that incorporated system generating unit information 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 assessment 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-



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availability of load control programs), the peninsular Florida electric system maintains a LOLP well below the criterion. Although the FRCC has reviewed various types of fuel supply 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 transportation service providers (pipeline operators) and generators within the Region. The FRCC Generating Capacity Shortage Plan39 includes specific actions to address potential or actual capacity constraints due to natural gas availability concerns and includes close coordination with the pipeline operators serving the Region. FRCC pipeline operators are included in various emergency contacts lists and are included in Regional communications as appropriate. The FRCC Operating Committee has also developed the FRCC Communications Protocols—Reliability Coordinator, Generator Operators and Natural Gas Transportation Service Providers40 procedure, to enhance the existing coordination between the FRCC Reliability Coordinator, Regional power plant operators and the natural gas pipeline operators operating within the FRCC Region (reference FERC Order 698). In addition, the Region continues to review and enhance fuel industry coordination through the work of the FRCC Fuel Reliability Working Group (FRWG), which serves as a Regional fuel reliability forum that studies the interdependencies of fuel availability and electric reliability and supports coordinated Regional responses to fuel issues and emergencies. No specific reactive power studies have been performed for the upcoming summer. However, the steady-state summer assessment incorporates an algorithm that can identify potential voltage limitations related to the outage of generation resources. Other Region-Specific Issues The FRCC is not anticipating any other reliability concerns for the 2010 summer conditions. Unexpected potential reliability real-time issues identified by the Reliability Coordinator can be resolved with existing operational strategies and procedures. Region Description FRCC’s membership includes 28 Regional Entity Division members and 25 Member Services Division members, which is composed of investor-owned utilities, cooperative systems, municipal utilities, power marketers, and independent power producers. The FRCC Region is divided into 11 Balancing Authorities. As part of the transition to the ERO, FRCC has registered 72 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).

39 https://www.frcc.com/handbook/Shared%20Documents/EOP%20-

%20Emergency%20Preparedness%20and%20Operations/FINAL%20FRCC%20Generating%20Capacity%20Shortage%20Plan.pdf

40 https://www.frcc.com/handbook/Shared%20Documents/EOP%20-%20Emergency%20Preparedness%20and%20Operations/FRCC%20Communications%20Protocols%20102207.pdf




MMRROO

Introduction The Midwest Reliability Organization’s (MRO) forecasted 2010 Non-Coincident Summer Peak Total Internal Demand is 48,797 MW. The Net Internal Demand is projected to be 45,481 MW. These projected demands are slightly lower than the 2009 demand projections due to the economic downturn. The Existing-Certain resources for 2010 summer are 57,204 MW. This is 810 MW lower than the existing Internal-Certain resources reported for the 2009 summer (58,014 MW). This drop in internal capacity is in part caused by a reduction in capacity assumed available at peak for wind generation (eight percent nameplate now used vs. 20 percent previously). 160 MW of planned generation capacity is projected to be placed in service prior to or during the 2010 summer season. Approximately 1700 MW of nameplate wind generation is projected to be placed in service prior to or during the 2010 summer season (since June 1, 2009). The projected MRO reserve margin is 26.2 percent, which is above the various target reserve margins established by the RTOs and Planning Authorities within the MRO Region. Numerous transmission reinforcements will be completed by or during the upcoming summer season. These reinforcements include: several rebuilt/reconductored transmission lines; several new 115 kV, 138 kV, and 161 kV lines; one new 230 kV line; four new 345 kV lines, four new bulk power transformers; three new substations, and various substation expansions and upgrades.


Direct Control Load Management 1,756Contractually Interruptible (Curtailable) 1,560Critical Peak-Pricing with Control 0Load as a Capacity Resource* 0


2009 Summer Comparison MW % Change2009 Summer Projected Peak Demand 46,750 -2.7%2009 Summer Actual Peak Demand 42,138 7.9%All-Time Summer Peak Demand - August 2007 47,629 -4.5%



*Note: MRO has classified an additional 23 MW of Demand Response as a supply resource which does not reduce Total Internal Demand.

Hydro10%

Wind2%

Coal46%

Nuclear8%

Gas15% Dual

Fuel7%

Other2%

Oil4%

Hydro10%

Wind2%

Coal46%

Nuclear8%

Gas15% Dual

Fuel7%

Other2%

Oil4%



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The MRO footprint will have about 7,700 MW of nameplate wind generation before or during the summer. Most of this wind generation is managed by the Midwest ISO Reliability Coordinator. At the present time, ramp rates, output volatility, and the inverse nature of wind generation with respect to load levels have been manageable. However, the Midwest ISO closely watches the ramp-down rate of wind generation during the morning load pickup period. The simultaneous output of wind generation within the MRO Region has historically reached 75 percent or more of nameplate rating for extended periods of time, and this can occur during off-peak hours during minimum load periods. Under these conditions, wind generation could potentially be serving about 13 percent of the Midwest ISO’s Balancing Authority footprint. The Midwest ISO is very actively exploring new and better ways to manage the wind generation within its footprint through stakeholder input from its various committees and subcommittees. Extensive assessment is being performed by the Midwest ISO regarding wind generation in areas such as regulation, load following, ramp rates, managing minimum load periods, forecasting, equitable participation during curtailments, and redispatch. The Midwest ISO is also addressing future aspects of wind, such as establishing appropriate capacity credits, day-ahead participation in market processes, and energy storage. Demand The Midwest Reliability Organization’s (MRO) forecasted 2010 Summer Non-Coincident Peak Total Internal Demand in the combined MRO-US and MRO-Canada is 48,797 MW, assuming normal weather conditions. This forecast is 2.3 percent lower than last summer’s forecasted total demand of 49,921 MW. Last year’s actual summer peak demand was 43,186 MW due to unusually cool weather. Any interruptible demand or DSM implemented during last year’s peak load is unknown. The MRO 2010 summer forecast Net Internal Demand is 45,481 MW, which is 2.8 percent lower than the 2009 summer forecasted Net Internal Demand of 46,750 MW. The economic downturn is one of the main reasons for the slight decline in demand forecasts. Peak demand uncertainty and variability due to extreme weather and/or other conditions are accounted for within the determination of adequate generation reserve margin levels. Both the MAPP Generation Reserve Sharing Pool (GRSP) members and the former MAIN members within MRO utilize a Load Forecast Uncertainty (LFU) factor within the calculation for the Loss of Load Expectation (LOLE) and, or the percentage reserve margin necessary to obtain a LOLE of 0.1 day per year, or one day in ten years.41 The load forecast uncertainty considers uncertainties attributable to weather and economic conditions. 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. Each MRO member uses its own forecasting method, meaning some may use a 50/50 forecast and some may use a 90/10 forecast. In general, the peak demand forecast includes factors involving recent economic trends (industrial, commercial, agricultural, residential) and normal weather patterns. From a Regional perspective, there were no changes in this year’s forecast assumptions in comparison to last year.

41 The former MAIN members are Alliant Energy, Wisconsin Public Service Corp., Upper Peninsula Power Co., Wisconsin

Public Power Inc., and Madison Gas and Electric.




MRO staff distributed the NERC 2010 summer data request spreadsheet to each LSE member within the MRO in the format it was received from NERC. The members populated these spreadsheets based on NERC and MRO instructions and submitted them back to the MRO for processing by a predetermined due date. Internally, MRO staff compiled the individual spreadsheet submissions into a set of regional spreadsheets representing the MRO Region as a whole as well as MRO-US and MRO-Canada. When the spreadsheet was initially distributed, MRO instructions emphasized to the LSEs that each MW of demand must be counted once and only once, and that LSEs should carefully coordinate with their neighboring LSEs to ensure that double-counting would not occur in the regional compilations. Interruptible Demand (1,756 MW, 3.6 percent) and Demand-Side Management (DSM) (1,560 MW, 3.2 percent) programs, amounting to 6.8 percent of the MRO’s Projected Total Internal Peak Demand of 48,797 MW, are utilized by a number of MRO members. A wide variety of programs, including direct load control (such as electric appliance cycling) and interruptible load, may be used to reduce peak demand during the summer season. Reductions in demand due to energy efficiency are not known at this time. Saskatchewan develops annual energy and peak demand forecasts based on a provincial econometric model and forecasted industrial load data.42 Weather can have a significant impact on the amount of electricity consumed by non-industrial customers. Due to this weather sensitivity, average daily weather conditions for the last thirty years are used to develop the energy forecast. 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 percent is attached to the likelihood of the load falling within the bounds created by the high and low forecasts. Saskatchewan has energy efficiency programs designed to help customers save power, save money, and help the environment. These programs include energy-efficiency, conservation, education, and load management programs. Residential programs focus on consumer education, energy efficiency, and market transformation of lighting, appliances, and furnace motors, including retailer/manufacturer partnerships and end-user incentives. Commercial and industrial programs include energy performance contracting, energy audits, and information services for facility operators. Additional programs are being developed for 2010. Saskatchewan is developing a measurement and verification program based upon International Performance Measurement and Verification Protocols (IPMVP) from the Efficiency Valuation Organization and DSM best practices.

42 Saskatchewan 2009 Load Forecast Report.



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Generation The existing internal certain resources for the MRO-US and -Canada 2010 summer are 57,204 MW. The Existing-Other and -Inoperable resources for the MRO-US and -Canada 2010 summer are 7,107 MW. Planned resources that are projected to be in service during this summer are 160 MW. These values do not include firm or non-firm purchases and sales. The month of July was used in all cases to be consistent. The nameplate capacity of the variable generation for the MRO is approximately 7,700 MW for 2010 summer. The variable resources for the MRO projected to be available at peak times is 563 MW, based on eight percent of nameplate capacity. Eight percent of nameplate wind generation is used for the MRO-US only. The eight percent of nameplate capacity rule is used by the Midwest ISO when determining capacity credits of variable generation. The biomass portion of resources for the MRO projected to be available at peak times is 315 MW. Reservoir water levels throughout Montana, North Dakota, and South Dakota have improved but continue to remain below normal. Generation on the hydro units is projected to be about 82 percent of normal. Limitations continue in the summer due to requirements for endangered species. The Manitoba water conditions are projected to be normal for summer. Saskatchewan reservoirs are projected to be below normal conditions but near-normal operating regimes are projected. Reservoir levels are sufficient to meet peak demand. Low reservoir levels are projected to result in reduced energy output, but will not impact system reliability. Saskatchewan reservoirs are sufficiently large to meet daily peak requirements, and current hydrological conditions are projected to be below normal during the upcoming season. The Manitoba water condition is normal and normal Manitoba-U.S. transfers are projected. Manitoba Hydro manages its reservoir levels in preparation for the summer season such that there is adequate energy to meet daily energy demand throughout the summer. Environmental and regulatory requirements restrict the operation of the Manitoba Hydro Brandon #5 generating unit (100 MW) except during certain emergency conditions. This, however, will not impact the reliability of the interconnected system since Manitoba Hydro has sufficient capacity without depending on Unit 5. Capacity Transactions on Peak For the 2010 summer season, the MRO is projecting total firm imports of 2,160 MW. These imports are from sources external to the MRO Region. The MRO has approximately 1,895 MW of total projected exports to load outside of the MRO Region. The net import/export of the MRO Region can vary at peak load, depending on system conditions and market conditions. Transfer capability from MRO-Canada (Saskatchewan and Manitoba) into the MRO-US is limited to 2415 MW due to the operating security limits of the two interfaces between these two provinces and the U.S. The forecasted firm transfers from Manitoba to the U.S. are 1,160 MW for 2010 summer.




Throughout the MRO Region, firm transmission service is required for all generation resources that are utilized to provide firm capacity. This means that these firm generation resources are fully deliverable to the load. The MRO is forecast 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 (LDC) according to their tariff policies. Most MRO members (except for Upper Michigan) are within non-retail access jurisdictions and therefore liquidated damages products are not typically used. Transmission Reliability Margins (TRM) are calculated and reserved by the transmission providers within the MRO Region to assure that operating reserves can adequately be delivered. These operating reserves can include resources outside of the MRO Region since most MRO members participate in the Midwest Contingency Reserve Sharing Group. Transmission The following reinforcements include projects that have projected service dates from October 1, 2009 through June 1, 2010 (Table MRO-1 and Table MRO-2)

Table MRO-1: Transmission Projects

Transmission Project Name Length (Miles)

Voltage (kV)

In-Service Date

Description/ Status

Franklin-Butler-Union Tap 42

161 May 2010 Reconductor to accommodate Whispering Willows wind

plant; increases line rating to 329 MVA and Butler-Union 161 kV rating to 322 MVA.

Duane Arnold-Vinton-Dysart-Washburn

0 161 Completed Line was upgraded to 446 MVA rating

Fernald-Story County 0 161 June 2010 Line upgraded to 159 MVA

summer rating; converted to 161 kV

Story County-Marshalltown 161 June 2010 Line upgraded to 161 kV Adams-Barton 161 Completed Line upgraded to 446 MVA Whispering Willows-Nuthatch

6.7 161 Completed Connects Whispering Willows 200 MW wind plant

Franklin-Nuthatch 2 N/A Complete Upgraded to 446 MVA Tower-Embarrass 15.7 115 Summer 2010 Badoura-Pine River 21 115 Summer 2010 Brookings County-Yankee 13 115 Summer 2010 #2 Line Brookings County-White 0.4 345 Summer 2010 #2 Line Rochester-Adams 0 161 Summer 2010 Upgraded to 335 MVA Beaver Creek-Harmony 0 161 Summer 2010 Upgraded to 335 MVA Aspen-Plains N/A 138 Completed Paddock-Rockdale N/A 345 Completed Oakridge-Verona N/A 138 June 2010 Poplar River-Pasqua 100 230 Summer 2010 South-Central Saskatchewan



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Further, a new Bittersweet Road 161 kV substation interconnects MidAmerican’s Grimes-Sycamore 161 kV line to ITC Midwest’s Perry-NE Ankeny 161 kV line. Phase 2 of Nebraska Public Power District’s Electric Transmission Reliability (ETR) Project for East-Central Nebraska was energized in October of 2009. Phase 2 of the ETR Project includes the construction of 12 miles of new 345 kV transmission line from Shell Creek to Columbus East and expansion of the Columbus East 345/230/115 kV Substation. Completion of this phase of the project improved local area voltage support. Phase 3 of the ETR Project includes the construction of 67 miles of new 345 kV transmission line from Columbus East to Lincoln Electric System’s NW68th & Holdrege Substation and the expansion of the NW68th&Holdrege 345 kV Substation. This final project phase was energized in December of 2009. The completion of this project addresses peak load voltage issues and enhances the reliability of the eastern Nebraska Regional transmission system. A 115 kV interconnection line between the Lincoln Electric System 20th & Pioneers Substation and Nebraska Public Power District Sheldon Substation is being rebuilt and will have a higher thermal capacity when completed prior to May of 2010. This is projected to reduce contingent overload issues in the local transmission area. Several transmission additions or upgrades have been or are projected to be completed in Minnesota and the Dakotas: Pleasant Valley substation upgrades:

A second 161 kV main bus, and the beginning of a full breaker and a half 161 kV substation configuration,

Dedicated 161 kV breaker position for the Grand Meadows wind plant. Increase the rating of the Bemidji 115 kV bus. 161 kV ring bus expansion will be completed at the Apple River substation for the

Chisago-Apple River 115/161 kV project. There continues to be significant load growth in North Dakota due to oil drilling and pumping. To accommodate the new load, construction is underway to build 230 kV lines.

Table MRO-2: Transformer Projects


(kV) Description / Status

Plainfield 161/69 Will be complete in Summer 2010 Carroll County 161/69 Projected May 2010 in-service date Teakwood Road substation 161/69 Projected July 2010 in-service date. Salem 345/161 Projected June 2010 in-service date. Grand Mound substation 161/69 Will be complete in Summer 2010 Pleasant Valley 345/161 500 MVA transformer Tioga 230/115 Upgraded to 150 MVA Neset 230/115 Will be complete in Summer 2010 Brookings County 345/115 448 MVA transformer




A 100-mile 230 kV transmission line in south-central Saskatchewan, interconnecting the Poplar River switching station and the Pasqua switching station, is projected to be in service for the 2010 summer. There are currently no significant planned outages in the WUMS footprint for the summer of 2010. The Minnesota Wisconsin Export (MWEX) interface is comprised of Arrowhead 230 kV phase shifting transformer and King-Eau Claire 345 kV line. The west-to-east transfer through the MWEX interface is constrained due to potential transient voltage recovery violation and voltage instability. The MWEX interface is managed as a reciprocal Interconnection Reliability Operating Limit (IROL) Flowgate of Midwest ISO and MAPP. An operating guide is in place that helps manage this constraint. The MWEX limits under system intact and various N-1 prior outage conditions are defined in this operating guide. The WUMS southern interface includes tie lines in the southwest and southeast interfaces. The southwest interface comprises the Wempletown-Paddock 345 kV line and Wempletown-Rockdale 345 kV line. The southeast interface comprises Zion-Arcadian 345 kV line, Zion-Pleasant Prairie 345 kV line and Zion-Lakeview 138 kV line. The WUMS southern interface is thermally limited for certain N-1 contingencies during periods of heavy transfer in either direction. The WUMS southern interface is also voltage stability limited for certain N-2 contingencies during periods of heavy imports through the interface. An operating guide is in place that helps to manage these constraints. The eastern portion of the Upper Peninsula (UP) of Michigan experiences flows in both west-to-east and east-to-west directions. Heavy flows in either direction can cause potential thermal and voltage violations in the eastern UP. These constraints are managed by opening the 69 kV lines between the eastern UP and the rest of the WUMS system, using procedures defined in an operating guide. Inter-Regional Transfers The following data is based on the MRO/RFC/SPP/SERC-W 2010 Summer Inter-regional Assessment. Non-simultaneous Total Import Capabilities into MRO from RFC-W, SERC-W, and SPP Regions are shown in Table MRO-3. The Total Import Capability (TIC) is equal to the net interchange of MRO (442 MW export for 2010 summer) in the ERAG 2010 summer model plus the First Contingency Incremental Transfer Capability (FCITC) obtained in the transfer assessment. These studies recognize constraints internal and external to the MRO.

Table MRO-3: Non-simultaneous Total Import Capabilities

Transfer Direction TIC (MW)

RFC_W TO MRO 3,158

SERC_W TO MRO 0

SPP TO MRO 1,458



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Operational Issues The Midwest ISO as a Reliability Coordinator and Balancing Authority does not expect any reliability concerns resulting from variable resources during minimum demand and over the range of generation conditions projected for the 2010 summer assessment period. At the present levels of nameplate wind generation, the Midwest ISO is able to manage ramp rates and volatility without any reliability concerns. The Midwest ISO’s Public Emergency Procedure RTO-EOP-003 Supply Surplus Procedure steps the Reliability Coordinator and Balancing Authority through necessary steps to continuously balance load and generation during minimum generation events, and this procedure includes variable resources as necessary. The maximum ramp down per hour in the MRO Region has been 1,344 MW thus far and is managed though Region-wide forecasting that has proven to be accurate to 10 percent out to 24 hrs. New wind plant owners within the MRO Region are routinely installing Special Protection Systems (SPS) to interconnect to the grid and to achieve the full output of their facility (pre-contingency). The contingencies associated with these SPSs are independent of one another, and the Reliability Coordinator does not consider them to be a risk to reliability. The MRO does not expect any reliability concerns resulting from high levels of Demand Response resources or from smart grid applications. There are no known environmental or regulatory restrictions that could impact reliability during the 2010 summer season. The MRO Region will have approximately 7,700 MW of nameplate wind generation by 2010 summer. There is a potential ambient temperature restriction (e.g., some wind turbines can be restricted to operating in ambient temperatures between -20° F and +104° F) with wind turbines. However, accurate forecasting will help to identify any near-term concerns regarding ambient temperature limits. Wind generation in Iowa will continue to cause implementation of congestion management procedures during high wind conditions. However, there are also benefits of having new wind plants in terms of improved voltage control, and at some locations, the ability to better manage congestion associated with prior outages or power transfers across Iowa. Some prior outage conditions will still require establishing limits on wind plant outputs or fast reduction of wind generation. Transmission Operators have good experience addressing post-contingent and real-time loading on underlying 69 kV facilities. Operating guides are in effect for all these wind plants. Midwest ISO Market LMP/binding procedures are used for congestion management when needed. Overall, the Iowa system is projected to operate in a reliable manner during 2010 summer.43 Nebraska Public Power District and Omaha Public Power District currently post five flowgates on the SPP-RTO OASIS that are impacted by heavy north-to-south and west-to-east transfers across the Nebraska system. Transfer limits on these flowgates can be reached during the summer season in Nebraska, especially during off-peak time periods. For those time periods in which heavy exports to the south do occur, NERC TLR is projected to be implemented to address system operating limits.

43 MEC-Operational and Outage Studies conducted by System Operations Department, February-March 2010.




With increased loads in the western Nebraska Region during the summer months, stability limitations associated with western Nebraska are less severe. High power transfers out of the western Nebraska Region are typically less during the summer months than in winter months. In the past several years, there has been a large increase in the number of days the DC ties are transferring power from east-to-west, which reduces the west-to-east flows that are normally seen across Nebraska. It is anticipated that this pattern of the DC ties flowing in the east-to-west direction will continue this summer. Overall, no significant operational concerns are projected in Nebraska during 2010 summer.44 The northern MRO area (Minnesota, Manitoba and the Dakotas) does not anticipate any significant transmission lines being out-of-service through the summer season. Standing operating guides for this Region are being reviewed and will be in place for 2010 summer. No significant unusual operating conditions are anticipated for 2010 summer that would impact the reliability of the bulk electric system. There are no operational issues projected during the upcoming summer in Saskatchewan.45 In the Wisconsin-Upper Michigan Systems (WUMS), American Transmission Company LLC participates in the Midwest ISO’s summer and winter seasonal assessment studies. The Midwest ISO’s 2010 summer seasonal assessment is underway. The objectives of these studies are to provide system operators with guidance as to possible but acute system conditions that would warrant close observation to ensure system security. American Transmission Company LLC also participates in the ERAG MRO-RFC-SERC West-SPP (MRSWS) and RFC summer and winter seasonal assessment studies. In addition to participating in these regional seasonal assessment studies, American Transmission Company LLC System Operations performs transmission system summer assessment annually. Reliable operation of the WUMS transmission system is projected during the 2010 summer season.46 It has been observed that the sudden increase in or decrease of, or the overall high or low levels, of wind generation in Iowa and Minnesota can have significant impact on driving the flows through the WUMS western and southern interfaces, MWEX and SOUTH TIE interface, respectively. American Transmission Company LLC and the Midwest ISO are monitoring this operational issue closely. An operational study performed hourly by the Midwest ISO anticipates the impacts of the sudden change in wind generation in Iowa and Minnesota on a number of selected flowgates. Operators will be alerted when the study results show the loading of any monitored flowgate comes within 95 percent of its rating. American Transmission Company LLC also analyzes the data and trend related to this operational issue monthly to be better

44 Summer Peak and Off-Peak Operational Studies performed by NPPD Transmission Planning Department, 2010. 45 Manitoba Hydro—Saskatchewan Power Seasonal Operating Guideline on Manitoba-Saskatchewan Transfer Capability;

SaskPower OASIS node: https://www.oatioasis.com/spc/. 46 2009—ATCLLC ten-year Transmission System Assessment Update, http://www.atc10yearplan.com; ATCLLC 2010

Transmission System Summer Assessment (ongoing); Midwest ISO Winter 2009/10 Coordinated Seasonal Transmission Assessment, http://www.midwestiso.org/home; Midwest ISO 2010 summer Coordinated Seasonal Transmission Assessment (ongoing), http://www.midwestiso.org/home; Eastern Interconnection Reliability Assessment Group (ERAG) 2010 summer Inter-regional Transmission Assessment (ongoing), MRO-RFC-SERC West-SPP (MRSWS) sub-group, ftp://compweb4.midwestreliability.org; ReliabilityFirst Corporation (RFC) 2010 summer Transmission Assessment Study (ongoing), http://www.maininc.org/.



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prepared for managing the potentially impacted flowgates, particularly the MWEX and SOUTH TIE interfaces. Reliability Assessment The MRO Reliability Assessment Committee is responsible for seasonal assessments. The MAPP Transmission Operations Subcommittee, the American Transmission Company LLC, Saskatchewan Power Corporation, and the Midwest ISO all contributed to this MRO seasonal Reliability Assessment. 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 seasonal request letter from Planning Authorities within the MRO Region. 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. The MRO’s projected 2010 summer Reserve Margin is 26.2 percent with Certain resources and is in excess of the Regional target Reserve Margins. This summer’s projected reserve margin of 26.2 percent, which includes Certain resources only and net interchange, can be compared with last summer’s projected reserve margin of 25.0 percent. Basin Electric and WAPA self impose a planning reserve margin as identified in the LOLE study performed and completed by MAPP on December 31, 2009.47 The MAPP LOLE study requires a 15 percent reserve margin for predominantly thermal systems, and 10 percent reserve margin for predominantly hydro systems. The projected MRO reserve margin of 26.2 percent for the 2010 summer season is in excess of the MAPP target reserve margins. The Midwest ISO has conducted a Loss of Load study establishing a 12 percent reserve margin requirement for all Midwest ISO load serving entities.48 Saskatchewan’s reliability criterion is based on annual projected unserved energy (EUE) assessment and equates to an approximate 13 percent reserve margin. The projected MRO reserve margin of 26.2 percent for the 2010 summer season is in excess of these target reserve margins. As in last year’s summer assessment, MRO staff attempted to include all IPP MW as an internal resource, not as a purchase. Most large IPPs that are registered as Generator Owners within the MRO were properly captured. However, there are smaller IPPs within the MRO that fall below registration criteria that have not been entirely captured. These additional IPPs would likely increase the projected capacity and reserve margins by a minimal amount. No specific assessment is performed to ensure that external resources are available and deliverable. However, to be counted as firm capacity, the various transmission providers require external purchases to have a firm contract and firm transmission service.

47MAPP Loss-of-Load Expectation (LOLE) Study for the ten-year Planning Horizon 2010-2019, http://www.mapp.org/ReturnBinary.aspx?Params=584e5b5f405c567900000002cb. 48 Midwest ISO 2010 LOLE Report, http://www.midwestmarket.org/publish/Document/13b9ea_1265d1d192a_-7b910a48324a.




The MRO Region considers known and anticipated fuel supply or delivery issues in its assessment. Because the Region has a large diversity in fuel supply, inventory management, and delivery methods, the MRO does not have a specific mitigation procedure in place should fuel delivery problems occur. The MRO members do not foresee any significant fuel supply and/or fuel delivery issues for the upcoming 2010 summer season. However, if problems occur, they will be addressed on a case by case basis. Transient voltage, and small signal stability studies are performed as part of the near-term/long-term transmission assessments. Voltage stability is also evaluated in the Midwest ISO’s seasonal assessment. Reactive power resources are considered in on-going operational planning studies. No transient voltage or small signal stability issues are projected that impact reliability during the 2010 summer season. Dynamic reactive margin is part of the American Transmission Company LLC Planning Criteria, which is determined using a reduction to the reported reactive capability of synchronous machines. A ten percent dynamic reactive margin is required in the intact system and a five percent dynamic reactive margin is required under NERC Category B contingencies. This criterion is applied in the American Transmission Company LLC planning ten-year assessment studies.49 Saskatchewan uses a probabilistic method of establishing planning reserve (Expected Unserved Energy, or EUE). An annual EUE assessment is performed to determine the requirement for adding new generation resources.50 This equates to a planning reserve target of about 13 percent. Saskatchewan’s projected planning reserve margin for the 2010 summer season ranges from 17 percent to 29 percent. Fuel-supply coordination or interruption in Saskatchewan is generally not considered to be an issue due to system design and operating practices.

Coal resources have firm contracts, are mine-to-mouth, and stockpiles are maintained at each facility in the event that mine operations are unable to meet the required demand of the generating facility. Typically there are 20 days of on-site stockpile for each of the coal facilities, which in total represent approximately 47 percent of total provincial installed capacity. Strip coal reserves are also available and only need to be loaded and hauled from the mine. These reserves range from 30 to 65 days depending on the plant.

Natural gas resources have firm on-peak transportation contracts with large natural gas storage facilities located within the province to back the contracts.

Hydro facilities/reservoirs are fully controlled. Typically, Saskatchewan does not rely on external generation resources.

Other Region-Specific Issues There are no other known reliability concerns anticipated within the MRO Region for 2010 summer.

49

2009—ATCLLC 10-Year Transmission System Assessment Update, http://www.atc10yearplan.com. 50 Saskatchewan 2009 Supply Development Plan.



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Region Description The MRO has 116 registered entities. There are seven Balancing Authorities: NPPD, OPPD, LES, SPC, MH, WAPA and Midwest ISO, which assumes all tariff members under Midwest ISO operate as one Balancing Authority. The MRO Region as a whole is a summer-peaking Region; however, both Canadian provinces are winter-peaking. 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. The MRO has six Planning Authorities registered within the footprint: the Midwest ISO, MAPP, American Transmission Company, Southwest Power Pool, Manitoba Hydro, and Saskatchewan Power Corporation. The Midwest ISO also spans into the RFC and SERC Regions. There are three Reliability Coordinators within the MRO footprint: the Midwest ISO, Southwest Power Pool, and Saskatchewan Power Corporation. The majority of Registered Entities within MRO are Midwest ISO tariff members and therefore participate in the Midwest ISO market operations. The Nebraska utilities fall under the Southwest Power Pool tariff and Reliability Coordinator.




RRFFCC

Introduction All ReliabilityFirst Corporation (RFC) members are affiliated with either the Midwest ISO or the PJM Interconnection (PJM) Regional Transmission Organization (RTO) for market operations and reliability coordination. Ohio Valley Electric Corporation (OVEC), a generation and transmission company located in Indiana, Kentucky, and Ohio, is not a member of either RTO and is not affiliated with their markets; however, PJM performs OVEC’s Reliability Coordinator services. Also, RFC does not have officially designated subregions. The Midwest ISO (Midwest ISO) and PJM each operate as a single Balancing Authority area. Since all RFC demand is in either Midwest ISO or PJM except for a small load (less than 100 MW) within the OVEC Balancing Authority area, the reliability of the PJM RTO and Midwest ISO are assessed and the results used to indicate the reliability of the RFC Region. This assessment provides information on the projected resource adequacy for the upcoming summer season across the RFC Region and relies on the reserve margin requirements determined for the PJM and Midwest ISO areas. Assessments were conducted by the Midwest LOLE Working Group and PJM to satisfy the ReliabilityFirst requirement for Planning Coordinators to determine the reserve margin at which the Loss of Load Expectation (LOLE) is one day in ten years (0.1 day/year) on an annual basis for their planning area. These analyses include demand forecast uncertainty, outage schedules, determination of transmission transfer capability, internal deliverability, other external emergency sources, treatment of operating reserves, and other relevant factors when determining the probability of firm demand exceeding the available generating capacity. The assessment of PJM resource adequacy was based on reserve


Direct Control Load Management 900Contractually Interruptible (Curtailable) 5,300Critical Peak-Pricing with Control 0Load as a Capacity Resource 0


2009 Summer Comparison MW % Change2009 Summer Projected Peak Demand 169,900 0.5%2009 Summer Actual Peak Demand 161,241 5.9%All-Time Summer Peak Demand - August 2006 187,893 -9.1%



Pumped Storage

2%

Coal47%

Nuclear15%

Gas20%

DualFuel8%

Other2%

Oil8%

Pumped Storage

2%

Coal47%

Nuclear15%

Gas20%

DualFuel8%

Other2%

Oil8%



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requirements determined from the PJM assessment. Similarly, the assessment of Midwest ISO resource adequacy was based on reserve requirements determined from the Midwest ISO assessment. ReliabilityFirst’s Resource Assessment Subcommittee believes that it is reasonable to assess the overall resource adequacy of the ReliabilityFirst Regional area by assessing the resource adequacy of the RTOs that operate within the Regional area. This is possible since the determination of each of the RTO reserve margin targets has been performed in a manner consistent with the requirements contained in regional reliability standard BAL-502-RFC-002. The Resource Assessment Subcommittee believes that when ReliabilityFirst has determined that each RTO is projected to have sufficient resources to satisfy their respective reserve margin requirement, the ReliabilityFirst area is projected to have adequate resources. The ReliabilityFirst Regional area is projected to have a Net Internal Demand of 170,800 MW in July, supplied from 219,600 MW of capacity resources. This 48,800 MW of reserves represents a 28.6 percent reserve margin. Since both PJM and Midwest ISO have adequate reserves this summer, the RFC reserve margin is also adequate. The 2010 summer ERAG studies have identified significantly lower first contingency incremental transfer capability (FCITC) values when simulating west-to-east transfers. These lower FCITC values can be attributed to high north-to-south flows through the Wisconsin-Illinois eastern interface and new generation in that area. PJM and Midwest ISO are evaluating the potential constraint as part of the joint Midwest ISO-PJM Cross Border Top Congested Flowgate Study to determine procedures to manage the potential flows. Demand In this assessment, the data related to the RFC areas of PJM (RFC-PJM) and Midwest ISO (RFC-Midwest ISO) are combined with the data from OVEC to develop the RFC Regional data. The demand forecasts used in this assessment are all based on the coincident peak demand of Midwest ISO’s local balancing authorities and the coincident peak of PJM’s load zones. Both PJM and Midwest ISO demand forecasts are based on an projected or 50/50 demand forecast. Actual data from the past four years indicates minimal diversity (less than 100 MW) between the RTO coincident peak demands and the RFC coincident peak demands. For this assessment, no additional diversity is included for the RFC Region; therefore, the RFC coincident peak demand is simply the sum of the PJM, Midwest ISO, and OVEC peak demands (rounded to the nearest 100 MW). The composite RFC Region forecast is considered a 50/50 demand forecast. PJM and Midwest ISO have not identified any demand reduction to the 2010 summer demand forecast explicitly due to Energy Efficiency (EE) programs. However, the categories of Direct Control Load Management and Interruptible are projected to provide for a combined potential Demand Response reduction of 6,200 MW within the RFC Region. The Direct Control during the summer is 900 MW, and the Interruptible Demand is 5,300 MW. The total demand reduction is the maximum controlled demand mitigation that is projected to be available during peak demand conditions.




Since demand reduction programs are a contractual management of system demand, utilization reduces the reserve margin requirement for the RTO. Net internal demand is Total Internal Demand less the demand reduction. Reserve margin requirements are based on Net Internal demand. The Net Internal Demand peak of the RFC Region for the 2010 summer season is 170,800 MW and is projected to occur during July 2010. This value is based on a Total Internal Demand forecast of 177,000 MW, with the full reduction of 6,200 MW (3.5 percent of Total Internal Demand) from the Demand Response programs within the Region (see Table RFC-1).

TABLE RFC-1: RFC Projected Peak Demands (MW)1 2010 Summer JUNE JULY AUGUST SEPTEMBERRFC Totals 2 TOTAL INTERNAL DEMAND 165,300 177,000 172,000 151,100 Direct Control Load Management (900) (900) (900) (900) Interruptible Demand (5,300) (5,300) (5,300) (5,300) NET INTERNAL DEMAND 159,100 170,800 165,800 144,900 1 - All demand totals are rounded to the nearest 100 MW. 2- The RFC Regional demand includes OVEC with the PJM and Midwest ISO areas of RFC.

Compared to the actual 2009 summer peak demand of 161,241 MW, the 2010 forecast Net Internal Demand is 9,559 MW (5.9 percent) higher than the actual 2009 summer peak demand. In addition, the 2009 forecast of 2010 summer Net Internal Demand peak demand was 172,200 MW, making this year’s summer Net Internal Demand peak demand forecast 1,400 MW (0.8 percent) lower than last year’s 2010 summer peak demand forecast.

Weather and economic conditions have significant influence on electrical peak demands. Any deviation from the original forecast assumptions for those parameters could cause the aggregate 2010 summer peak to be significantly different from the forecast. For the summer of 2010, high demand forecasts for PJM and Midwest ISO were combined with the OVEC demand to create a high demand forecast for the RFC Region. The forecast high demand is 182,200 MW, a 6.7 percent increase over the 50/50 demand forecast (see Table RFC-2).

TABLE RFC-2: Simulated Extreme Demand 2010 Summer (MW)

TOTAL RFC

EXTREME DEMAND1 TOTAL INTERNAL DEMAND 188,400 NET INTERNAL DEMAND 182,200 NET CAPACITY RESOURCES 219,600 NID RESERVE MARGINS —MW 37,400 —Percent of NID 20.5 % 1 - The combination of the 90/10 demand forecasts for the PJM and Midwest ISO areas of RFC is not a 90/10 forecast for RFC. These values are used to simulate conditions of extreme demand.

2 - These are the coincident LBA or Load Zone peak demands within the RFC Region.



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Generation There are two general categories used when analyzing seasonal capacity resources. Existing capacity represents resources that have been built and are in commercial service. Future capacity represents planned resources that are under construction, have an interconnection service agreement, and are projected to be in commercial service at the start of the planning period. The generating capacity in Table RFC-3 represents the capacity of the generation in the RFC Region. The capacity category of Existing-Certain represents existing resources in the RFC areas of PJM and Midwest ISO and the capability of OVEC generation. The RFC Region has 217,700 MW of capacity for this summer that is identified as Existing-Certain in this assessment.

Table RFC-3: Projected Capacity Resources 2010 Summer (MW)

Capacity as of June 1, 2009 EXISTING CAPACITY 227,100 Inoperable (Scheduled Maintenance) (900) Energy Only Resources (including variable gen) 0 Uncommitted Resources (8,500) Transmission Limited Resources 0 EXISTING-OTHER CAPACITY (9,400) EXISTING-CERTAIN CAPACITY 217,700

CAPACITY TRANSACTIONS—IMPORTS1 Purchases 2,400 Owned Capability outside the RFC Region 100 Import Total 2,500

CAPACITY TRANSACTIONS—EXPORTS1 Sales (600) Other Owner Capability transferred outside the RFC Region 0 Export Total (600)

NET INTERCHANGE 1,900 NET CAPACITY RESOURCES 219,600 1 - Intra-regional transfers reported by the RTOs (between RTOs and with OVEC) have been removed

The Existing-Other category includes the existing resources that represent projected on-peak wind/variable resource deratings, and other existing capacity resources within the RFC Region that are not part of the PJM or Midwest ISO markets. There is up to 8,500 MW of these types of capacity resources. Since these resources are not in the respective PJM and Midwest ISO markets, none of this capacity is included in the reserve margins. Only capacity additions that are in service prior to the planning year, which starts in June, are included in determining the summer reserve margins. Any Future-Planned capacity additions projected to go in-service during the summer period would not be included within the reserve




margin calculations. There are no Future-Planned capacity additions included in this summer assessment. The total nameplate amount of variable generation in RFC is about 4,200 MW. This is nearly all wind power (with about seven MW solar), with the amount of available on-peak variable generation capability included in the reserve calculations at about 500 MW. The difference between the nameplate rating and the on-peak projected wind capability rating is accounted for in the Existing-Other category. There is also 700 MW of biomass (renewable) resources included in the RFC reserve margins. Each generator operator is projected to coordinate with the fuel industry regarding fuel supplies and deliveries. Although PJM and Midwest ISO do not explicitly communicate with the fuel industry regarding fuel supply issues, their respective market rules encourage generator owners and operators to have adequate fuel supplies. RFC does not communicate directly with the fuel industry on supply adequacy or potential problems. However, RFC does periodically survey its generator owners and operators about relevant fuel issues. The last survey was in 2008. There are no known or projected conditions or situations regarding fuel supply or delivery, hydroelectric reservoirs, adverse weather, generator availability, environmental, regulatory, or capacity retirement that are anticipated to adversely impact system reliability during the 2010 summer. No new smart grid programs that would significantly influence reliability have been implemented in the last year. Capacity Transactions on Peak Expected and firm power imports into the RFC Regional area are forecast to be 2,500 MW. Firm power exports are forecast to be 600 MW. Therefore, net interchange is forecast to be a 1,900 MW power net import into the RFC. There are no transactions using Liquidated Damage Contracts (LDC) or make-whole contracts. Transmission A significant transmission facility that has been added to the bulk power system since last summer is the Linden Variable Frequency Transformer (VFT), which is a merchant transmission project that is an AC tie with 300 MW of transmission transfer capability.51 This project connects the Linden Cogen plant located in New Jersey and within PJM to the Goethals station on Staten Island in the New York system. The VFT is a transmission technology that provides for a continuously controllable, variable phase-shift connection to control the direction and magnitude of AC power flows. The Linden VFT is a transmission owner within PJM who has the operational authority over the facility. The VFT is in service with power flowing across it as of November 2009. The VFT is the first merchant transmission project with multiple parties holding the entitlements to the new transmission capacity. Developing this unique project involved numerous technical, economic feasibility, and interconnection studies by the developer,

51 See http://www.gepower.com/prod_serv/products/transformers_vft/en/downloads/C1_107_2008.pdf



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PJM, and the New York ISO (NYISO), which culminated in an auction process to sell the new transmission rights. The Highway 22 transmission project, spanning 28 miles of 345 kV line, was placed in service in October 2009 and has alleviated common constraints in the northern Wisconsin area. The Paddock-Rockdale transmission project, also in Wisconsin, added 35 miles of new 345 kV transmission. There are nine transformer installation and upgrade projects completed or nearing completion since the summer of 2009 (Table RFC-4). Of the new bulk power transformers, ATC LLC and Northern States Power Co. transformers have been in service since September and December 2009, respectively. The Great River Energy and Duke Energy Midwest transformers are currently under construction and are projected to be in service in March and June 2010, respectively.

There is currently a two-week outage request for the Conemaugh-Hunterstown 500 kV line in August 2010. PJM will study this outage to determine if there is a better opportunity to take this outage depending on weather and other factors. There are no other significant transmission outages planned through the summer season. The original ITC Transmission Bunce Creek (B3N) Phase Angle Regulating transformer that failed in March 2003 has been replaced by two (series) Phase Angle Regulating transformers. Installation of the transformers was completed in December 2009. Energizing the transformers is dependent upon completion of protective system work in coordination with Hydro One, which is anticipated to be completed after the second quarter of 2010. Until ITCTransmission and Hydro One are authorized to begin operating the B3N Phase Angle Regulating transformers to control flows, the Phase Angle Regulating transformers on the L4D and L51D interconnections will be placed in the by-pass mode. The PAR on the Ontario-Michigan J5D interconnection near Windsor will be operated to assist in the management of local system congestion and for the

TABLE RFC-4: TRANSFORMER ADDITIONS

Transformer Project Name

High-Side Voltage

(kV)

Low-Side Voltage

(kV)

In-Service Date(s)

Description/Status

Kammer 765 500 9 Oct Replace Existing/In-Service Decatur 161 138 9 Dec Serve Load/In-Service Don Marquis 345 138 9 Dec New Transformer T-3/In-Service Jug Street 345 138 9 Dec New Transformer T-5/In-Service Waugh Chapel 500 230 9 Dec Replace Transformer/In-Service Tangy 345 138 9 Dec Add Transformer T-5/In-Service Worthington 161 138 10 May Capacity Upgrade/Under Construction

Dresser 345 138 10 Jun Add third Transformer/Under

Construction Bunce Creek PAR

220 220 10 Jul Replace Failed PAR With 2-800 MVA

PARs In Series/Under Construction




optimization of power transfers. The Phase Angle Regulating transformers on the ITCTransmission-Hydro One interconnections will be used to control interconnection flows pending the receipt by ITCTransmission of an amended presidential permit from the U.S. Department of Energy and completion of various contractual and operational agreements between and among the respective Transmission Owners and Reliability Coordinators. The full list of transmission additions is shown below in Table RFC-5.

TABLE RFC-5: TRANSMISSION ADDITIONS

Transmission Project Name

Voltage (kV)

Length (Miles)

In-Service Date(s)

Description/Status

Pontiac-Wilton Center

345 10 Sep 09 Loop Into Cayuga Ridge South/In-Service

Waverly-Lick 138 13 Oct 09 Loop Into Don Marquis/In-Service Olive-Dequine 345 0.6 Oct 09 Loop Into New IPP/In-Service Remer Tap 120 1 Oct 09 Redirect To St. Clair/In-Service Crescent-Brunot Island

138 18 Nov 09 Loop Into New Sewickley/In-Service

Logans Ferry-Dravosburg

138 11.4 Nov 09 Reconfigure Existing Lines/In-Service

Gilbert Tap #2 138 0 Nov 09 Convert 69 kV Line/In-Service Bartonsville Tap 138 3.2 Nov 09 Convert 69 kV Line/In-Service Legionville-Hopewell

138 2.3 Dec 09 Build Second Line With Tap To Koppel

Steel/In-Service Logans Ferry-Highland

138 9.1 Dec 09 Convert 69 kV Line/In-Service

Durant-Genoa 120 20.9 Dec-09 Construct New Line/In-Service Dillerville to West Hempfield

138 0.2 Dec-09 Convert 69 kV Line/In-Service

Doubs-Monocacy 230 15 Dec-09 Construct New Line/In-Service Logans Ferry-Highland

138 9.1 Jan-10 Convert 69 kV Line/In-Service

Crescent-Brunot Island

345 17.1 Feb-10 Reconfigure Existing Lines/In-Service

Brunot Island-Arsenal

345 6.4 Apr-10 Convert 138 kV Line/Under Construction

Collier-Brunot Island

345 7.3 Apr-10 Convert 138 kV Line/Under Construction

IMPA Indiana Arsenal Jct-Clark-Maritime Center

138 8.5 Jun-10 Construct/Under Construction

Rockies Express 138 1.5 Jun-10 Construct Station/Under Construction F.B. Culley Station-Oak Grove

138 12.4 Jun-10 Construct/Under Construction

Westport-Orchard-Center

115 11.4 Jun-10 Construct Underground Lines/Under

Construction



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Operational Issues PJM requires generation owners to place resources into the “Maximum Emergency Category” if environmental restrictions limit run hours below pre-determined levels. Maximum Emergency units are the last to be dispatched. Midwest ISO does not anticipate any unusual operating conditions requiring high levels of Demand Response use that could significantly impact reliability for the upcoming summer. Further, Midwest ISO finds no environmental or regulatory restrictions that could impact reliability. Reliability Assessment The PJM projected reserve margin for 2010 summer is 26.7 percent, which is in excess of the required reserve margin of 15.5 percent. This is a 5.1 percentage increase over the 2009 forecast reserve margin. Therefore, the PJM RTO is projected to have adequate reserves for the 2010 summer peak demand. The reserve margin requirement calculated for the Midwest ISO is 15.4 percent of the Net Internal Demand of its market area. The projected reserve margin for Midwest ISO is 26,996 MW, which is 25.9 percent of the Net Internal Demand. Therefore, the Midwest ISO is projected to have adequate reserves for the 2010 summer peak demand. In Table RFC-6, the calculated reserve margin for RFC is 48,800 MW, which is 28.6 percent based on Net Internal Demand and Net Capacity Resources. This compares to a 25.4 percent reserve margin in last summer’s assessment. Since PJM and Midwest ISO are projected to have sufficient resources to satisfy their respective reserve margin requirements, the RFC Region is projected to have adequate resources for the 2010 summer period.

TABLE RFC-6: RFC Projected Reserve Margins 2010 Summer

JUNE JULY AUGUST SEPTEMBER NET INTERNAL DEMAND (MW) 159,100 170,800 165,800 144,900 NET CAPACITY RESOURCES (MW) 219,600 219,600 219,600 219,600 NID RESERVE MARGINS — MW 60,500 48,800 53,800 74,700 — Percent of NID 38.0 % 28.6 % 32.4 % 51.6 %

RFC stakeholder representatives and staff actively participate in all three of the Eastern Interconnection Reliability Assessment Group (ERAG),52 inter-Regional seasonal transmission assessment efforts. RFC also conducts its own summer transmission transfer capability analyses

52 See http://erag.info/




and assessment.53 Incremental transfer capability results from the ERAG studies are included within the separate RFC summer transmission assessment report and are shown in Table RFC-7. Simultaneous import capabilities are projected to be adequate for this summer. These values do reflect transmission and generation constraints external to RFC. The 2010 summer ERAG studies have identified significantly lower FCITC values limited by the [CE] Zion-[ATC] Pleasant Prairie 345 kV line when simulating west-to-east transfers. These lower FCITC values can be attributed to high north-to-south flows through the Wisconsin-Illinois eastern interface and a new generator connected to the [ATC] Oak Creek substation. These lower FCITC values indicate that this line will likely be a constraint this summer, and that PJM and Midwest ISO will need to manage flows on this constraint with Market-to-Market procedures. A scope of potential work that would up-rate this line includes replacement of a wave trap at [CE] Zion and ground clearance improvement of approximately 3.5 miles of the line in Wisconsin. Presently, PJM and Midwest ISO are evaluating this constraint as part of the joint Midwest ISO-PJM Cross Border Top Congested Flowgate Study. Other Region-Specific Issues ReliabilityFirst has no additional reliability concerns for this summer season. Region Description ReliabilityFirst currently consists of 48 Regular Members, 22 Associate Members, and four Adjunct Members operating within three NERC Balancing Authorities (Midwest ISO, OVEC, and PJM), which includes more than 350 owners, users, and operators of the bulk-power system. They serve the electrical requirements of more than 72 million people in a 238,000 square-mile area covering 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.54

53 See http://www.rfirst.org/Reliability/ReliabilityHome.aspx 54http://www.rfirst.org.

TABLE RFC-7: Incremental Transfer Capability

TRANSFER DIRECTION

2010 SUMMER RFC-MISO to PJM 3,600 MW

PJM to RFC-MISO No limit found at the 5,000

MW transfer level. SERC East to RFC-MISO 2,550 MW SERC East to PJM 2,850 MW NPCC to RFC-MISO 865 MW NPCC to PJM 800 MW MRO to RFC West 50 MW SPP to RFC West 250 MW SERC West to RFC West 2,200 MW SERC West to RFC East 700 MW



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SSEERRCC

Introduction SERC Total Internal Demand for 2010 summer is projected to be 199,617 MW. This projection is based on average historical summer weather and is the sum of non-coincident forecast data reported by utilities in the SERC Region. This projection is 0.9 percent lower than the 2009 summer forecast of 201,364 MW and 14,042 MW (7.6 percent) higher than the actual 2009 summer peak demand of 185,575 MW. Decreases in the forecast are attributed to the current economic recession. Utilities in the SERC Region expect 256,846 MW of existing capacity for the summer period. Of the projected resources, 245,859 MW will be considered Existing-Certain capacity. Since 2009 the amount of Existing-Certain capacity has increased by 3,853 MW. Additionally, 1,307 MW of future resources are projected to be in service through the end of the assessment period. No significant capacity additions or retirements are anticipated for the summer season. Aggregate 2010 summer reserve margins are 27.7 percent, indicating capacity resources in SERC are projected to be adequate to supply the projected firm summer demand. Reserve margins based on Existing-Certain and Net-Firm transactions are projected to be 26.9 percent. Reserve margins based on prospective capacity resources are 31.5 percent. SERC does not implement a regional or subregional planning reserve requirement; however, many utilities adhere to state commission regulations or internal business practices in order to maintain adequate resources. More detail on individual utility requirements can be found in the subregional sections of the report. Overall, entities within the various subregions of SERC expect no significant changes to the demand, capacity, or reserve margins for the summer season. Entities report they are recovering


Direct Control Load Management 1,140Contractually Interruptible (Curtailable) 4,291Critical Peak-Pricing with Control 0Load as a Capacity Resource 256





Hydro5%

PumpedStorage

4%

Coal36%

Nuclear14%

Gas22%

Dual Fuel16%

Oil3%

Hydro5%

PumpedStorage

4%

Coal36%

Nuclear14%

Gas22%

Dual Fuel16%

Oil3%




from the current economic recession that has affected load growth and capacity projections. Utilities within the Region continue to minimize reliability concerns in the near-term by increased monitoring of the system and through more rigorous operational planning studies. SERC members are also working to address industry issues that are important externally and internally to the Region. Capacity is considered adequate to meet the load and the transmission system is monitored continuously to address concerns. As a result of utility efforts, additional improvements and investments are planned to be in service for the summer season with the intent of increasing reliability. Utilities within SERC have the following miles of new transmission lines projected to be in service for the summer season: five miles of 100 kV, 11 miles of 115 kV, 19 miles of 138 kV, 110 miles of 161 kV, 62 miles of 230 kV, 82 miles of 345 kV, and 27 miles of 500 kV. In addition, entities within the SERC Region have plans to install or upgrade 13 transformers. Specific details of the new significant bulk power transmission facilities for the summer season are listed within the subregional sections of this report. These projects are projected to improve reliability within the Region for the summer peak period. If delays occur that result in reliability concerns, mitigating actions would be developed accordingly. Mitigating measures include re-dispatch of generation, operating procedures, and special protection systems. However, entities are not expecting any transmission reliability concerns that will significantly impact bulk power system reliability for the summer season. The following are the most common challenging operational issues: routine loop flows, congestion, and real-time transmission loading issues. These stresses on the transmission system are due to external and internal transactions within the Region. Entities have found that the availability of large amounts of excess generation and low-cost base-load generation during light load and peak conditions within the Southeastern and Gateway subregions have resulted in fairly volatile day-to-day scheduling patterns and exacerbate transmission loading concerns. The transmission flows are often more dependent on the weather patterns, fuel costs, or market conditions outside the Region than by loading within the respective areas. Entities individually handle these operational issues by re-dispatching generation, curtailing transactions, implementing transmission loading relief (TLR), or implementing operating guides as needed. These operational issues are not reliability concerns but are market issues for the summer season. Transmission constraints identified are studied and can be mitigated as needed to minimize reliability concerns on the bulk power system. Additionally, operational planning studies for the summer season were performed as needed. Reports show that utilities within SERC anticipate no significant operational issues, constraints, or other reliability concerns during the assessment period. Demand SERC is a summer-peaking Region. The SERC Total Internal Demand projected for the 2010 summer is forecast to be 199,617 MW, which is 9,491 MW (4.5 percent) lower than the all-time peak of 209,108 MW that occurred in August 2007 and is 1,747 MW (0.9 percent) lower than the forecast 2009 summer peak of 201,364 MW and 14,042 MW (7.6 percent) higher than the actual 2009 summer peak demand of 185,575 MW.



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This projection is based on average historical summer weather and is the sum of non-coincident forecast data reported by utilities in the SERC Region. Some entities have lowered their forecasts as compared to previous forecasts due to the current economic recession, reflecting a reduction in customer growth, energy use, and loss of industrial load. Forecasts within the Region are based on normal weather patterns as determined by historical system averages, below-normal load growth and economic forecasts (assumptions based on income for various state/national averages), regressing demographics, and reductions in projected sales. Overall forecasts show moderate positive economic trends and customer growth, but at slower rates than last year’s projections. This decrease in expectations results in a lower forecast for both summer energy use and peak demand. A number of utilities in the SERC Region have some form of efficiency program or demand-side management (DSM) effort in place or under development. Because of the varied nature of energy efficiency and DSM programs, they are provided in detail within the subregional sections of this assessment. Traditional load management and interruptible programs such as air conditioning load control and large industrial interruptible services are the most common programs within the Region. Interruptible demand and DSM capabilities for the summer are 7,060 MW as compared with 6,901 MW reported last summer. This year’s DSM contribution is 3.5 percent of the 2010 summer projected Total Internal Demand.

Table SERC-1: Demand Response Programs (MW)

Program 2009 Summer

(MW) 2010 Summer

(MW) Direct Control Load Management 960 1,140 Contractually Interruptible (Curtailable) 4,946 4,291 Critical Peak-Pricing (CPP) with Control 0 0 Load as a Capacity Resource 247 256 Energy-Efficiency Programs 748 1,373

Traditional Demand Response programs include monetary incentives to reduce demand during peak periods. Some examples are real-time pricing programs and voluntary curtailment riders. The programs are more fully described in each subregional section. To address measurement and verification of DSM programs, some entities use third parties to conduct impact/process evaluations for commercial programs. Other entities use load response statistical models to identify the difference between the actual consumption and the projected consumption absent the curtailment event. Demand Response may also be tracked and verified by the readings of meters, as well as testing residential and commercial summer load-control programs for verification of demand reduction through generation dispatch personnel. Evaluations may be conducted annually with a comprehensive report due at the end of a program cycle. Reports are projected to determine annual energy savings and portfolio cost-effectiveness. Utilities in the Region perform detailed extreme weather and/or load sensitivity analyses in their respective operational and planning studies to address projected demand.




While utility methodologies vary and are described in more detail within the subregional sections, many common attributes exist. They include:

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 high and low economic scenarios, and mild and severe

weather Development of a suite of forecasts to account for the variables mentioned above, and

associated studies utilizing these forecasts. In addition, many utilities in the Region use sophisticated, industry-accepted methodologies to evaluate load sensitivities in the development of load forecasts. When appropriate, utilities in the SERC Region adhere to their respective state commissions’ regulations, RTO requirements, and internal business practices for determining their forecast and reserve requirements. Generation In aggregate, utilities within the SERC Region expect to have 256,846 MW of resources, including 245,859 MW of Existing-Certain resources and 9,440 MW of Existing-Other resources during the summer period. The utilities within the SERC Region report 1,547 MW of inoperable resources and anticipate 1,307 MW of Future-Planned and 0 MW of Future-Other capacity resources during the assessment period. Portions of variable energy reported as projected on-peak are 251 MW of biomass, 11,522 MW of hydro, 0 MW of solar, and 22 MW of wind, etc. These totals are based on the aggregate responses of individual utilities within the Region. Wind development continues to be active in some subregions. With the exception of dams being repaired as noted in the Central subregion section, hydro conditions and reservoir levels are mostly at or near normal levels as the drought conditions have improved in many areas within the Region. This is not a reliability concern for the summer season. Entities do not anticipate unusual operating conditions or major generation outages that could impact the reliability of the utilities in the Region for the summer period. The general practice is to not schedule planned outages of major transmission lines or generation during the summer peak period. If outages occur during peak periods, entities explore options like generation re-dispatch, increased imports, or implementation of operating guides. Capacity Transactions on Peak Regional exports account for 9,956 MW and imports account for 9,781 MW. These firm imports have been included in the reserve margin calculations for the Region. The majority of the above imports/exports are backed with firm contracts for both generation and transmission. However, some Gateway entities have reported that the majority of their contracts (~34 percent–95 percent) are categorized as LDC. Entities within the Central subregion reported



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LDCs less than 200 MW and VACAR entities have LDCs at about 355 MW. All these LDC contracts are considered 100 percent “make-whole.” These contracts have been included in the aggregate reserve margin for the Region. Entities within the Region participate in various contingency reserve and emergency import programs that are internal/external to the Region. Resources are obtained from a variety of resources such as Midwest ISO (under Attachment RR of the Midwest ISO ancillary services market tariff), SPP reserve sharing group, and TEE Contingency Reserve Sharing Group (TCRSG). Entities may also have contract agreements with neighboring utilities within their subregion to provide capacity for outages of specific generation. Overall, utilities report that they do not depend on outside imports or transfers to meet the demands of the load in the Region. Transmission New significant bulk power transmission facilities are listed within the subregional sections. These projects are projected to improve reliability within the Region for the summer peak period. Very few projects have been reported to have delays. Of the potential delays, none are projected to cause reliability concerns for the assessment period. If delays occur that result in reliability concerns, mitigating actions would be developed accordingly. Available mitigating measures include re-dispatch of generation, operating procedures, and special protection systems. Entities have reported minor transmission outages during the summer season. Generally, these outages are planned within non-peaking periods. If outages occur during peak periods, entities explore options like generation re-dispatch, increases in imports, or implementation of operating guides. Transmission maintenance schedules are carefully reviewed and evaluated to ensure reliability concerns are addressed, and to permit as much prioritized maintenance as can be accommodated prior to the summer peak. There are no transmission constraints that significantly impact reliability of the utilities in the SERC Region during the summer assessment period. Discussions in subregional sections of the assessment for certain utilities indicate a few situations that require monitoring, though nothing significant. With load generally down as compared to prior years, the system has already been tested at greater load levels. Coordinated inter-Regional transmission reliability and transfer capability studies for the 2010 summer season are conducted among all the SERC subregions and with the neighboring regions. Preliminary results of these studies indicate the bulk transmission systems within the SERC Region have no issues that will significantly impact reliability. No significant limits to transfers were identified except for the Delta-SPP interface. This interface is undergoing planning review by the planning authority. Utilities within the SERC Region have extensive transmission interconnections between its subregions and extensive interconnections to the utilities in FRCC, MRO, RFC, and SPP

Table SERC-2: SERC Region Imports/Exports MW

Transaction Type

Imports (MW)

Exports (MW)

Firm 9,769 9,678Non-Firm 1 103Expected 186 0




Regions. These interconnections permit the exchange of firm and non-firm power and allow systems to assist one another in the event of an emergency. Approximately 316 miles of transmission at 115 kV and above are scheduled for completion by the end of this summer. There are no concerns with respect to the impact on reliability performance relating to the completion of these projects. SERC has 1,096 miles of transmission under construction, and 4,048 miles planned or in the conceptual stages at the time of this report. Phasor measurement equipment, SVC, advance-relay technology, new 500 kV transmission tower design, and new statcom technology continue to be researched and installed on the system. The deployment of smart grid technologies is being assessed in consultation with power distributors. Details of the implementation of these new technologies are explained in detail within the subregional sections. Operational Issues Operational planning studies for the 2010 summer were performed as needed. Details on specific study areas can be found in the subregional sections of this report. Overall, no operational problems or constraints are anticipated during the assessment period. In general there are no operational changes required of utilities in the SERC Region to implement the integration of variable generation. Most of the SERC Region is in the lowest wind resource area of the country. However, Gateway subregion members who are also Midwest ISO participants are studying the impacts of the availability of large amounts of low-cost base-load generation during off-peak load conditions. This scenario can result in congestion and real-time transmission loading issues. The addition of wind generation in the Gateway subregion and surrounding balancing areas to the north and west may exacerbate the transmission loading concerns in some areas. Impacts continue to be studied and mitigated to address any reliability concerns that may occur due to integrating large amounts of variable generating resources on the system. Overall, negative impacts from environmental restrictions, high levels of Demand Response, or unusual operating conditions are not projected to significantly impact operations in the SERC Region for the summer period. Reliability Assessment In aggregate, the utilities in the SERC Region expect 1,307 MW of planned capacity to be placed in service between January 1 and June 1, 2010. The projected summer reserve margin for SERC is 27.6 percent, indicating capacity resources within the Region are projected to be adequate to supply the projected summer demand. The reserve margin projected for 2009 summer was 23.9 percent. Margins are projected based on entity experiences of load reduction due to economic conditions. Increased demand-side management and generation also contributed to increases in margins. SERC does not implement a Regional or subregional planning reserve requirement. As described in more detail within the subregional reports, many utilities adhere to their respective state commission’s regulations or internal business practices regarding maintaining adequate resources. For example, a target margin is implemented by regulatory authorities in the state of Georgia, where the regulation is only applicable to the investor-owned utilities in that state. A



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recent review of resource adequacy assessment practices indicate that many utilities in the SERC Region use probabilistic generation, load modeling, and reserve requirements to determine that adequate resources are available and deliverable to the load. Within the SERC Region there are generally three methods used for resource adequacy assessment among the major utilities:

Deterministic — A stated, deterministic minimum-reserve guideline. In some cases the reserve guideline is derived explicitly from other measures, such as operating-reserve requirements, load-forecast uncertainty, or largest single contingency.

Probabilistic — A stated probabilistic guideline, which is usually translated into an equivalent minimum-reserve guideline for use in long-range planning studies.

Economic — An economically optimized probabilistic guideline, which is translated into an equivalent minimum-reserve guideline.

Among those utilities performing probabilistic reliability assessment, there are two general categories of models being used. Most of these models are in-house and held as proprietary. They are:

Conventional convolution-based or Monte Carlo models that treat hours independently, dealing with energy-limited resources and other time-constrained capacity resources mainly through application of external assumptions.

Chronological Monte Carlo applications that internally model energy-limited resources explicitly to estimate their utilization and the impact of energy limitations on reliability.

On March 25, 2009, the SERC Board Executive Committee authorized the performance of a Region-wide resource adequacy study. The SERC Resource Adequacy Working Group is working with various SERC study groups and contracted consultants to produce results of the study for the 2010 summer study period. Utilities with the SERC Region project that fuel supplies will be adequate this summer. This topic is covered in detail in the subregional reports of this assessment. Entities expect sufficient inventories (including access to salt-dome natural gas storage) with fuel-switching capabilities, alternate fuel delivery routes and suppliers, and emergency fuel delivery contracts to be important mitigation options to reduce reliability risks to fuel supply issues. Fuel deliverability problems are possible for limited periods of time due to extreme weather and flooding, resulting in disruptions to rail, pipeline, and other transportation systems. 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. Coupled with economic conditions that have reduced pressure on rail and pipelines, SERC anticipates that no fuel deliverability constraints would significantly impact the availability of capacity resources. The projected capacity mix reported by utilities in the SERC Region for the summer is well diversified at approximately 39.7 percent coal, 14.3 percent nuclear, 8.8 percent hydro/pumped storage, 36.9 percent gas and/or oil, and 0.3 percent for purchases and miscellaneous other




capacity. Generation with coal, nuclear, and hydro fuels continues to lead the regional fuel mix, accounting for roughly 62.8 percent of net operable capacity. Some utilities in the Region with large amounts of gas-fired generation connected to their systems have conducted electric-gas interdependency studies in past years. The studies simulated pipeline outages for near- and long-term study periods as well as both summer and winter forecasted peak conditions. Also included for each of the major pipelines was an assessment of the projected sequence of events for the pipeline contingency, replacing the lost generating capacity, and providing an assessment of electrical transmission system adequacy under the resulting conditions. Total dual fuel capabilities within the Region are 19,297 MW, or 7.9 percent of capacity. 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 different natural-gas pipeline systems, reducing the dependence on any single interstate pipeline system. Moreover, the diversity of generating resources further reduces the risk. Current assessments reveal that the fuel supply infrastructure and fuel inventories for the summer period are adequate even considering possible impacts due to weather extremes. Some companies within the SERC Region have both dynamic and steady-state reactive power supply and reserve criteria. The details of these criteria are discussed in the subregion reports. There are no reactive supply issues on a SERC-wide basis. To minimize reliability concerns within the Region, entities participate in a host of committees designed to perform system studies and address industry issues that are important to reliability. Assessment studies include steady-state power flow studies, dynamics/stability studies,55 and transmission transfer capabilities both external and internal to SERC. The Region relies on the SERC Near-term Study Group (NTSG), Long-term Study Group (LTSG), Dynamic Study Group (DSG), and Short Circuit Database Working Group (SCDWG) to coordinate these studies in order to ensure the system is adequate for projected summer peaks. Coordinated studies with neighboring regions and SERC subregions through the Eastern Interconnection Reliability Assessment Group (ERAG) indicate that transmission transfer capability will be adequate on all interfaces to support reliable operations for the summer assessment period. These processes and studies are discussed in more detail in the subregion reports. The Annual Report of the SERC Reliability Review Subcommittee (RRS) to the SERC Engineering Committee (EC) summarizes the work of the SERC subcommittees regarding the transmission and generation capabilities and provides the overview of the state of the systems within the SERC Region.56 Utilities within the Region are also working to improve the transmission system by implementing technologies, transmission lines, facilities, and upgrades. Entities spent approximately $1.9 billion on new transmission lines and system upgrades (includes transmission lines 100 kV and above and transmission substations with a low-side

55 Small signal damping is considered in the context of stability studies by some SERC subregions. 56 Because it is considered CEII, the SERC RRS Annual Report to the Engineering Committee is available only upon request

through the SERC website at www.serc1.org.



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voltage of 100 kV and above) in 2009 and plan to spend approximately $2.4 billion in 2010 and $2.3 billion in 2011. Utilities in the SERC Region are also planning for the system to have adequate capacity to meet the load and planned (annual) maintenance outages to keep generating resources reliable. The transmission system is monitored continuously and planned for additional improvements with the intention of increasing reliability.




Central Demand Projected Total Internal Demand for utilities in the Central subregion for the summer season is 42,364 MW. This is 369 MW (0.8 percent) lower than the forecast 2009 summer peak demand of 42,733 MW. The projected Total Internal Demand is 3,398 MW (8.7 percent) lower than the actual 2009 summer peak of 38,966 MW. The lower-than-projected summer peak in 2009 was due to lower temperatures and the prolonged effects of the economic slowdown on industrial demand. The change in demand from prior forecasts for 2010 also reflects the effects of the economic slowdown in lowering growth in customers, manufacturing plant closings, and energy use. As with other subregions in SERC, strong emphasis is placed on energy efficiency. Programs such as customer cost-saving energy surveys and audit evaluations, customer education, responsive pricing, residential/commercial conservation, electric thermal storage incentives, new construction (heat pump and geothermal), energy manufactured homes, air-source heat-pump programs (replacing resistance heat 10 years or older), low-income weatherization, low-income assistance, HVAC system improvements, industrial compressed-air programs, and various advanced lighting and third-party verification/measurement groups are in operation to target residential and commercial customers. Commercial/industrial/direct-served industry consumers have programs targeted to focus on efficiency improvements in HVAC, lighting, motors and controls, and other electrical-intensive equipment. For measurement and verification within these programs, entities have reported they may use third-party evaluators to review the performance of all programs on an ongoing basis to assure the programs continue to achieve the projected levels of energy and demand reductions. Some entities have reported that programs must pass a quantitative and a qualitative screening assessment to focus on customer acceptance, reliability, and cost effectiveness. The primary source of Demand Response for utilities within the Central subregion is the Direct Load Control (DLC) program and the interruptible product portfolio. These programs include a pilot program with interruptibles contracted to, and verified by, a third party, and include companies that have contractually agreed to reduce their loads within 60 minutes of a request. The estimate used in operational planning takes into account the amount of load available and is not a sum of total load under contract. Control devices are being installed by entities within the subregion on air conditioning units and/or water heaters in residences. The goal is to have 50,000 switches by 2013. Demand Response can be tracked and verified by the readings of meters. Other entities use generation dispatch personnel to test residential and commercial summer load-control programs for verification of demand reduction. Demand Response is projected to be 2.5 percent of Total Internal Demand. This percentage is projected to reduce peak demand on entity systems within the Central subregion. The 2010 summer demand forecast is based on normal weather conditions and projected economic data for the subregion population, projected demographics for the area, employment, energy exports, and gross Regional product increases and decreases. Economic data from the national level is also considered. Secondary forecasts are also developed for extreme and mild weather conditions and for optimistic and pessimistic economic scenarios.



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Subregional entities have a variety of techniques to address extreme summer conditions. Some companies report that they annually analyze the relationship between seasonal peak loads and temperature at and leading up to the time of the peak. The summer period is estimated for a response to each additional Cooling Degree Day (CDD) during the day of peak demand. Historical data is calculated for the typical (average) number of CDDs during a summer peak day (and the day prior). The range of CDDs on the day of the peak over a defined time period (20 years) is observed. From this range, the variability of peak demand due to extreme weather conditions can be determined. Other utilities within the subregion use forecasts assuming normal weather, and then develop models for milder conditions based on historical peaks; they then use demand models to predict variance. For the majority of the load in the subregion, peak information is developed as a coincident value for the subregion-wide model, and non-coincident values for each distribution delivery point. Generation Capacity within the Central subregion is reported for the following categories of Existing (-Certain, -Other, and -Inoperable) and Future (-Planned and -Other). This capacity is projected to help meet demand during the assessment period. Average hydro conditions for the summer are projected. Some generation estimates are based on an assessment of historic operating practices and flow conditions. Estimates this year are reported to be consistent with the latest long-term hydro forecast. The wind resource in the Central subregion is generally unsuitable for large-scale wind generation. There are 29 MW of wind turbines installed at Buffalo Mountain but only 2 MW is reported capacity expected on peak for the summer season, the remaining 27 MW of wind is not considered as capacity. Wolf Creek and Center Hill dams continue to experience operational restrictions. These restrictions have limited the availability of firm capacity within the subregion. However, entities have compensated for this lack of capacity by implementing other purchases in their portfolios for the season. Reservoir levels are reported to be sufficient to meet peak demand and the daily energy needs throughout the assessment period. Currently, the subregion does not anticipate conditions that would reduce capacity. Fuel levels for utilities within the subregion are not a concern for the summer. Western Kentucky and southern Indiana coal production levels remain strong, along with several new mining operations receiving permitting and initiating coal production. Utilities are confident that fuel deliveries will be made according to contractual agreements and forward forecasts for delivery. Many companies within the subregion have a diversified portfolio of coal suppliers from which they

Table SERC-3: Central Summer Capacity Breakdown

Capacity type Year 2010

(MW) Existing-Certain 49,345Nuclear 6,671Hydro/Pumped Storage 5,641Coal 24,722Oil/Gas/Dual Fuel 11,500Other/Unknown 26Solar 0Biomass 17Wind 2Existing-Other 48Existing-Inoperable 71Future capacity 444




can purchase high-sulfur coal. These purchases range from the northern and central Appalachia coal Region (West Virginia, east Kentucky), Ohio, and the Illinois Basin (west Kentucky, Indiana, Illinois). Several companies have internal departments that monitor coal supply conditions on a daily basis through review of receipts and coal burns. Daily interaction is common with both coal and transportation suppliers to review situations and foreseeable interruptions. Any identifiable interruptions are assessed with regard to current and desired inventory levels. Fuel transportation is also varied by river, rail, and truck delivery. Entities are also investigating external resource options to provide backup energy during unit outages for the period beginning 2010 summer. Utilities report that emergency procedures are in place and on file with the Kentucky Public Service Commission. These procedures detail varying levels of coal stockpiles at the power stations and expectations for future or continued supply disruptions, and the associated actions to take place such as reduction of power sales, increases in power purchases, curtailment of interruptible load, etc. The majority of the generating units within the subregion are not scheduled to be out of service during the upcoming summer season. However, there are some units (71 MW) that will be on inactive reserve this summer due to economic conditions. Other units are scheduled for planned maintenance (~483 MW) in September 2010. Reliability is not projected to be impacted due to these outages. Capacity Transactions on Peak Utilities within the Central subregion have reported the following imports and exports for the 2010 summer season. The majority of these exports/imports are backed by firm contracts. It was not reported if import assumptions are based on partial path reservations. The level of liquidated damage contracts associated with exports for 2010 is projected to be at or less than 200 MW. It was not reported what portion of these contracts are anticipated to include “make-whole provisions.” These imports have been included in the aggregate reserve margin for utilities in the subregion.

Table SERC 4: Central Subregion Imports/Exports

Transaction type 2010 Summer

(MW) Firm Imports (External Subregion) 2,541 Firm Exports (External Subregion) 495 Expected Imports (External Subregion) 186 Expected Exports (External Subregion) 0

Contingency reserves and emergency imports within the subregion are obtained from a variety of resources such as Midwest ISO (under Attachment RR of the Midwest ISO ancillary services market tariff), PJM, other entities internal to the subregion, and TEE Contingency Reserve Sharing Group (TCRSG). The TCRSG consists of three balancing authorities that are internal to the Central subregion of SERC. The TCRSG is intended to provide immediate response to contingencies enabling the group to comply with the DCS standard and assist in preventing the curtailment of native load. Even though some entities rely on internal/external resources for



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imports, there are some companies within the subregion that do not depend on short-term outside purchases or transfers from other regions or subregions to meet demand requirements. Transmission The following table shows new bulk power system transmission that is projected to be in service for the upcoming 2010 summer season.

Table SERC-5: Central Expected Transmission

Transmission project name Transmission type In-service

Date(s) Operating

Voltage (kV)

Pineville-West Garrard Completed 11/19/2009 161 Trimble County-Ghent-Speed Line

Completed 10/28/2009 345

J.L. Smith-West Garrard Completed 12/01/2009 345 East Franklin-Mufreesboro Completed 01/14/2009 161 Fontana-Santeetlah Completed 05/26/2009 161 Addition: Tilton-Resaca Completed 09/30/2009 115 Brown North – West Garrard

Under Construction 04/15/2010 345

Higby Mill- West Lexington


Middletown- Collins Under Construction 06/30/2010 138 Mill Creek-Hardin County Under Construction 06/30/2010 345 Maury- Rutherford Under Construction 04/30/2010 500 Rutherford- Almaville Under Construction 06/01/2010 161 Huntsville- McCreary Under Construction 05/07/2010 161

Table SERC-6: Central Transformer Additions

Transformer project name

High-side

voltage (kV)

Low-side

voltage (kV)

In-service date(s) Description/Status

Bull Run 500 161 05/28/2010 Addition — Under construction: Install a single phase 500-161-26.4-13.2 kV to replace failed transformer

Rutherford 500 161 06/01/2010 Addition — Under construction: Install four, single phase 500–161 kV transformers

A further delay of the new Mill Creek-to-Hardin 345 kV line installation such that the new in-service date would be after 2010/2011 winter may cause a variety of contingent overload concerns. This may limit generator output to local Regional load. The Mill Creek-to-Hardin 345 kV installation is currently scheduled for completion in June 2010. Outside of this project, there are no other potential reliability concerns or impacts that target transmission in-service dates




within the subregion. Additionally, no significant lines are anticipated to be out of service through the summer season. No major constraints have been identified within the subregion. However, heavy north-to-south flows and external constraints continue to impact the ability to import power. The recent upgrade of the Coleman-to-Newtonville 161 kV interconnection and a planned Vectren 345 kV project may help alleviate the constraints. Entities continue to evaluate the transmission system to identify any future constraints that could significantly impact reliability in the future. These future constraints and proposed solutions are annually published in plans similar to the Transmission Expansion Plan (Independent Transmission Organization [ITO] SPP). System conditions may at times dictate local area generation re-dispatch to alleviate anticipated next contingency overloads. Companies in these situations may invoke NERC TLR procedures to control scenarios that are not easily remedied by a local re-dispatch. Recent assessments have not shown significant changes since the 2009 assessment. Overall, there were no constraints to the bulk power system that should impact reliability for the summer season. Entities within the Central subregion continue to evaluate and consider new technologies that can be utilized to improve bulk power system reliability. The deployment of smart grid technologies is being assessed in consultation with power distributors, and some distributors are implementing programs. No significant substation equipment other than capacitor banks were added since the last summer season. Operational Issues Many entities within the subregion perform routine operating studies (bi-annual load forecast study; monthly, weekly, and daily operational planning efforts; annual assessment of summer peak and temperature) to assess the system. These studies take into consideration weather, demand, and unit availability. This helps to address any inadequacies and mitigate their risks. Based on the results of these studies, entities do not anticipate operational problems. The majority of the entities within the subregion have not included variable resources as firm capacity on their systems. Entities are not anticipating operational changes or concerns due to integration of wind contracts for the summer assessment period. Due to limited Demand Response in the subregion, reliability concerns from high levels of Demand Response resources are not a concern for this summer; there are also no environmental or regulatory restrictions that impact reliability. As for planning, the deployment of smart grid technologies is being assessed in consultation with power distributors in some areas of the subregion. However, no new transmission-level technologies have been installed since last summer. No unusual operating conditions are projected for the assessment period. Reliability Assessment Projected summer-peak reserve margin for the utilities in the subregion, as reported in February 2010, is projected to be 26.0 percent compared to 23.9 percent for 2009. The 2009 percentages reflect lower-than-projected load caused by economic conditions and cooler-than-normal weather conditions. However, the normalization of weather and economic recovery is projected



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for the summer season. Therefore, loads are projected to rebound slightly below what was originally projected. Additional capacity reported for the summer is also reflected in reserve margins. Entities within the Central subregion do not adhere to any regional/subregional targets or reserve margin criteria. However, some individual entity criteria are established based on the balancing authority’s criteria such as most severe single contingency, cost of unserved energy, unit availability, import availability/capability, load forecast, and loss of load probability studies (such as one day in ten years). TVA has recently implemented new study capabilities and completed a detailed probabilistic assessment that will be repeated annually. Resource adequacy studies performed by some entities within the subregion show that there is sufficient capacity to adequately supply the load. Variables within the studies are based on unit availability, import availability/capability, load forecast, and weather assumptions. The intent of these studies is to identify limitations or constraints that may impact seasonal adequacy, inform necessary decisions relative to resource acquisitions, and project development timelines to maintain system reliability. If resource inadequacies cause the reserves to be reduced below the desired level, companies within the subregion can make use of purchases from the short-term markets in the near-term, and various ownership options in the long-term, as necessary. There is no mandate or target reserve margin for the subregion. In order to ensure fuel delivery, the practice of having a diverse portfolio of suppliers, including the purchase of high-sulfur coal from the Northern and Central Appalachia coal Region (West Virginia, east Kentucky), Ohio and the Illinois Basin (west Kentucky, Indiana, Illinois) is common within the subregion. Fuels departments typically monitor supply conditions on a daily basis through review of receipts and coal burns, and interact daily with both coal and transportation suppliers to review situations and foreseeable interruptions. Any identifiable interruptions are assessed with regard to current and desired inventory levels. By purchasing from different regions, coal is projected to move upstream and downstream to various plants. Some plants have the ability to re-route deliveries between them. Some stations having coal delivered by rail can also use trucks to supplement deliveries. Utilities have reported that they maintain fuel reserve targets greater than 30 days of on-site coal inventory. Fuel supplies are adequate and readily available for the upcoming summer. Multiple contracts are in place for local coal from area mines. Companies within the subregion maintain individual criteria to address any problems with stability issues. Recent stability studies identified no stability issues that could impact the system reliability during the 2010 summer season. Criteria for dynamic reactive requirements are addressed on an individual company basis. Utilities employ study methodologies designed to assess dynamic reactive margins. Programs such as Reactive Monitoring Systems give operators an indication of reactive reserves within defined zones on the system. Voltage stability margins are also upheld by utilities on an individual basis. Some utilities follow the procedure of making sure the steady-state operating point be at least five percent below the voltage collapse point at all times to maintain voltage stability. Studies are performed on peak




cases to verify system stability margins. Other utilities follow guidelines to ensure that voltage stability will be maintained via Q-V assessment. Even though entities within the Central subregion anticipate no major impacts on reliability for the summer season, they continue to analyze and improve the system through continuous planning processes. Entities are looking into increasing the capacity ratings of transformers, CTs, upgrading transmission lines, replacing equipment, etc. As concerns are identified, real-time operating guides will be developed with the appropriate reliability coordinators, and system enhancements or upgrades will be considered as appropriate.



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Delta Demand Projected Total Internal Demand of the utilities in the Delta subregion for the summer season is forecast to be 27,944 MW based on normal weather conditions. This forecast is 79 MW (0.3 percent) higher than the forecast 2009 summer peak demand of 27,865 MW and is 235 MW (0.8 percent) higher than the actual 2009 summer peak demand of 27,713 MW. The year-over-year increase primarily reflects retail load growth and increases in wholesale load. The forecast assumes ten-year normal weather and anticipates a gradual economic recovery. The summer forecast is also based on a forecast study that produced new econometrically-based forecasts of commercial/industrial load, future economic/demographic conditions, and historical data. Distribution cooperative personnel assess the likelihood of these potential new loads and a probability-adjusted load is incorporated into the cooperative load forecast. DSM programs among the utilities in the subregion include interruptible load programs for larger customers, direct-control load management programs for agricultural customers, and a range of conservation/load management programs for all customer segments. There are no significant changes in the amount and availability of load management and interruptible demand since last year. Measurements and verification for interruptible Demand Response programs for larger customers are conducted on a customer-by-customer basis. These include an annual review of customer information and firm load requirements. Compliance is determined by a review of customer load data as related to the terms and conditions of the electric rate schedule. Demand Response is projected to be 2.7 percent of Total Internal Demand. This percentage is projected to reduce peak demand on entity systems within the Delta subregion. Utilities within the Delta subregion are implementing energy-efficiency programs to distribution cooperatives and the residential sector. A variety of programs ranging from home energy audits, CFL lighting, and Energy Star-rated washing machines and dishwashers, to Energy Star-rated heat pumps and air conditioners have been added into company portfolios for 2010. Utilities plan to offer these types of programs as long as they are determined to be cost-effective. Annual Measurement and Verification (M&V) programs measure energy savings and costs for each of these energy-efficiency programs. Information from these M&V programs will be used to fine tune energy-efficiency programs and to determine their cost effectiveness. The current forecast includes energy-efficiency programs that have received regulatory approval. As programs advance, they will be incorporated into retail sales and load forecasts. Load scenarios for outage planning purposes are developed regularly to address variability issues in demand. These load scenarios include load forecasts based on high and low scenarios for energy sales and scenarios for alternative capacity factors. Load scenarios for load flow analyses in transmission planning are also developed and posted to OASIS. Some of the scenarios developed within the subregion were reported to be based on an assumption of weather extremes that were more severe than the projected peaking conditions but less severe than the most severe conditions found in the historical records. Special analyses are performed to examine projected peak loads associated with cold fronts, ice storms, hurricanes, and heat waves. These




assessments are performed on an ad-hoc basis and may be conducted for various parts of the Delta subregion. Other entities use planning procedures to produce projected forecasts, which are based on normal weather/economic and demographic conditions. Optimistic/pessimistic economic and demographic conditions with normal weather, and severe and mild weather, are also accounted for in the forecast. Forecasts are produced on a regular basis to capture significant conditions annually. Generation Companies within the Delta subregion expect to have the following Existing (-Certain, -Other. and -Inoperable) and Future (-Planned and -Other) capacity on-peak. This capacity is projected to help meet demand during this time period. In addition, there are 1,223 MW of energy-only facilities in the subregion. Hydro conditions are projected to be normal for the summer assessment period based upon current reservoir levels and rainfall. Entities are also not expecting any conditions associated with weather, fuel supply, or fuel transportation that would reduce capacity. However, transmission system congestion has the potential to reduce the effective capacity of some resources. Due to mitigation plans and diverse resources, this is not considered a risk to reliability on the system or reserve margins for the summer season. Several existing generating units are scheduled to be out of service during the summer season. The capacity represented by these units is not necessary to meet installed capacity requirements. Capacity Transactions on Peak Delta subregion utilities expect the following imports and exports for the summer season. These imports and exports have been accounted for in the reserve margin calculations for the subregion.

Table SERC 8: Delta Subregional Imports/Exports


(MW) Firm Imports (External Subregion) 2,620 Firm Exports (External Subregion) 3,340 Expected Imports (External Subregion) 0 Expected Exports (External Subregion) 0

Table SERC 7: Delta Summer Capacity Breakdown

Capacity Type Year 2010

(MW) Existing-Certain 40,172Nuclear 5,251Hydro/Pumped Storage 262Coal 9,080Oil/Gas/Dual Fuel 25,578Other/Unknown 0Solar 0Biomass 0Wind 0Existing-Other 2,985Existing-Inoperable 1,378Future capacity 0



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All contracts for these imports/exports are backed by firm transmission and are tied to specific generators. No imports/exports have been reported to be based on partial path reservations. For the assessment period, there are no liquidated damage contracts and associated “make whole” contracts. The subregion is dependent on certain imports, transfers, or contracts to meet the demands of its load. Most entities within Delta are members of the Southwest Power Pool reserve sharing group. Group participants within SPP generally transfer reserves into the subregion to either replace (largest contingency) or supply generation to the subregion. These reserves are not relied on in the resource adequacy assessment, or for capacity, or reserve margins. System operators generally coordinate the scheduling and transmitting of the reserves. Transmission The following table shows bulk power system transmission categorized as under construction, planned, or conceptual that is projected to be in service for the summer season since 2009.

Table SERC-9: Delta Expected Transmission

Transmission project name Transmission type In-service date(s) Operating

voltage (kV) ANO-Russelville North planned 06/01/2010 161 Baxter Wilson-Ray Braswell under construction 06/01/2010 500 Bogalusa to Adams Ck #2 completed 01/18/2010 230 Bull Shoals to Bull Shoals SPA planned 06/01/2010 161 Camp Clark- Hyder Hill planned 06/02/2010 161 Camp Clark-Lamar under construction 06/02/2010 161 Dell-Manilla under construction 03/31/2010 161 Donaghey-Conway South under construction 04/20/2010 161 Edmonson- Gravois planned 06/02/2010 161 Frostcraft to Rilla under construction 06/04/2010 115 Indianola- Greenwood planned 06/02/2010 115 Harrison East to Everton completed 12/20/2009 161 Marion Tap-Spalding under construction 06/02/2010 161 Hot Springs to Bismark planned 06/30/2010 161 Park-Talequah under construction 03/02/2010 161 Hyder Hill-Stockton (AEC) under construction 06/02/2010 161 Troy-Lincoln planned 05/02/2010 161 Melbourn to Sage under construction 06/01/2010 161 North Warsaw-Edmonson planned 06/02/2010 161 North Warsaw-Edmonson planned 06/02/2010 161 Parkin to Twist planned 06/01/2010 161 Snakefarm to Kenner completed 03/24/2010 115 Stockton-Morgan planned 06/02/2010 161 Fairport-Winslow completed 01/14/2010 161 Higbee-Strugeon completed 01/15/2010 161 Thomas Hill-Yates completed 10/02/2009 161 Yates-Higbee completed 10/02/2009 161 Gulfway-Sabine completed 09/01/2009 230




Table SERC-10: Delta Transformer Additions


High-side

voltage (kV)

Low-side

voltage (kV)


Sportsman Acres

345 161 06/01/2010 Addition — Planned Transformer #1

Sportsman Acres

345 161 06/01/2010 Addition — Planned Transformer #2

Magee sub Auto 1

161 115 06/01/2010

Re-Ratings — Under Construction: Upgrade Magee Auto 1 to 336 MVA (Autos upgraded, switch replacement

awaiting outage from SMEPA) Magee sub Auto 2

161 115 06/01/2010

Re-Ratings—Under Construction: Upgrade Magee Auto 2 to 336 MVA (Autos upgraded, switch replacement

awaiting outage from SMEPA) Entities within Delta do not expect any delays in meeting in-service dates for projects scheduled for the summer assessment period. There are no significant transmission facility outages that impact bulk power system reliability. Prior to approval of any proposed maintenance outages, studies are completed to identify any impacts on reliability. No transmission constraints are projected to significantly impact bulk power system reliability for the summer peak season. Companies within the subregion regularly participate in SERC NTSG seasonal reliability studies. The NTSG 2010 summer Reliability Study preliminary results indicate that imports into the subregion can be limited due to the McAdams 500/230 kV autotransformer for the loss of the McAdams-Lakeover 500 kV flowgate. This flowgate, which is located near a 500 kV tie within the Central subregion, can be constrained due to excess generation on the interface along with transactions across the interface. Real-time operating limits have been addressed using the appropriate NERC operating procedures. Additional fans were added to the McAdams autotransformer in July 2008 to increase its rating. Additional upgrades have been identified for the area’s system improvement. These upgrades have a projected in-service date of 2011. Some utilities are expecting to replace existing transmission line protection systems with more modern protection equipment. Other entities have reported that they have installed two statcom units at the Natchez 115 kV station to automatically support local area reactive power requirements. The statcom system is a fully integrated, inverter-based reactive compensation system. Statcom systems are cost-effective solutions that can provide tight voltage regulation and power factor correction to alleviate fluctuating voltage and var demands. This, combined with normal switched capacitor banks in the area, is a very economical alternative to SVCs and is equally effective at solving common transmission grid problems such as voltage instability and voltage regulation. Utilities plan to continue to employ and research new technologies in order to improve and maintain bulk power system reliability.



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Operational Issues Entities within the subregion that are transmission dependent rely on operating studies that are performed by transmission operators. Transmission operators have not performed any special operating studies for the summer. Due to an insignificant amount of variable generation connected to the distribution system, there are no concerns about integrating these resources onto the system. The entities are not dependent upon distributed or variable resources. Additionally, they are not anticipating reliability concerns resulting from high levels of Demand Response resources and environmental or regulatory constraints that could potentially impact reliability. No reliability concerns are anticipated for the summer peak season as a result of smart grid implementation. There are no unusual operating conditions projected for the summer season that might impact reliability. Reliability Assessment Delta subregion utilities projected an aggregate 44.9 percent reserve margin in the subregion as compared to 44.3 percent last year. This is largely due to more complete reporting utilizing NERC’s new capacity definitions from 2009, which seem to have resolved prior concerns regarding generation adequacy. Entities have reported no significant changes to the reserve margin from 2009 reporting to the current summer season. Utilities within the Delta subregion do not adhere to any regional/subregional targets or reserve margin criteria. However, some individual entity criterions are established based on the balancing authority’s most severe single contingency, load forecast, and reserve requirement using historical allocations, and loss of load expectation studies (0.1 day/year). Various utility resource planning departments in the subregion conduct studies annually (either in-house or through contractors) to assess resource adequacy. Modeling of resources and delivery aspects of the power system are used throughout the subregion in all phases of the studies. The overall goal of the studies is to ensure resources (existing and owned) are available at the time of system peak. Studies may take into account potential resource deactivations and anticipated unit outages. Results help develop one-year and ten-year resource plans that meet target reserve margins. Some companies have reported that results are approved by their board of directors internally. Subregional transmission planning departments also conduct studies to ensure transfer capability is adequate under various contingency conditions. These studies evaluate the availability of firm transmission for resources. These resources were considered to meet the reference margin level for last summer and for this assessment period without any concerns being reported. Fuel supplies are anticipated to be adequate. Coal stockpiles are maintained at 45 days or more. Natural gas contracts are firm, with some plants having fuel oil back-up. Extreme weather conditions will not affect deliverability of natural gas. Typically, supplies are limited only when there are hurricanes in the Gulf of Mexico. There is access to local gas storage to offset typical gas curtailments. Many utilities maintain portfolios of firm-fuel resources to ensure adequate fuel




supplies to generating facilities during projected peak demand. Those firm-fuel resources include nuclear and coal-fired generation that are relatively unaffected by weather events. Various portfolios contain fuel oil inventories located at the duel fuel generating plants, approximately 10 Bcf of natural gas in storage at a company-owned natural gas storage facility, and short-term purchases of firm natural gas generally supplied from other gas storage facilities and firm gas transportation contracts. This mix of resources provides diversity of fuel supply and minimizes the likelihood and impact of potentially problematic issues on system reliability. Close relationships (contracts) are maintained with coal mines, gas pipelines, gas producers, and railroads that serve its coal power plants. These relationships ensure adequate fuel supplies are on hand to meet load requirements. Upon the occurrence of fuel interruption or forced outage within some entity facilities, it is common that exporting contracts out of the facility will be curtailed in coordination with the affected balancing authorities until operations can return to normal. Companies throughout the subregion individually perform studies 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 Delta subregion, the 2010 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 are no common subregion-wide criteria to address transient dynamics, voltage, and small-signal stability issues, some utilities have noted they adhere to voltage schedules and voltage stability margins. In addition, some utilities employ static var compensation devices to provide reactive power support and voltage stability. Undervoltage load shedding (UVLS) programs are also used to maintain voltage stability and protect against bulk power system cascading events. While Delta subregion companies do not employ a minimum dynamic reactive requirement or margin, companies in the Region do utilize a voltage stability criterion. The voltage stability criterion used by the Delta subregion companies is a voltage stability margin of five percent from the nose point (voltage collapse point) load on the P-V curve. Stability studies performed incorporated P-V curve assessments to ensure that this criterion is met on the system. If necessary, stability limits can be imposed on transmission elements in order to meet this criterion. Under transient conditions, the companies employ the following voltage dip criteria:

For the loss of a single transmission or generation component, with or without fault conditions, the voltage dip must not exceed 20 percent for more than 20 cycles at any bus; must not exceed 25 percent at any load bus; and must not exceed 30 percent at any non-load bus; and

for the loss of two or more transmission or generation components under three-phase normal-clearing fault conditions, or the loss of one or more components under single-phase delayed-clearing fault conditions, the voltage dip must not exceed 20 percent for more than 40 cycles at any bus; and must not exceed 30 percent at any bus.

A utility in the Delta subregion has identified a dynamic and static reactive power-limited area on the bulk power system. The western Region of the Entergy Texas, Inc. (ETI) service territory



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is defined by ETI as a load pocket, which is an area of the system that must be served at least in part by local generation. This load pocket requires importing power across the bulk power system in order to meet the real power demand. The reactive power requirements of this load pocket are supplemented by the use of capacitor banks, as well as a static var compensator. A major project to convert a 138 kV line to 230 kV operation and the addition of autotransformer capacity at Lewis Creek is under construction with an estimated in-service date of June 2011. This project will increase the real and reactive demand-serving capability of ETI’s western Region. To minimize reliability concerns for the summer period, entities are studying reliability with a critical and conservative approach. Any issues that result from the studies are addressed within the appropriate timeframe. Curtailment Processes and Emergency Response Plans are routinely updated. As necessary, transmission-wide and local area procedures, redispatch, and operating guidelines will be implemented to maintain reliability for the summer. Because Energy Emergency Alerts (EEA) have been issued in the past for the Acadiana area, the SPP Independent Coordinator of Transmission-Entergy will continue to monitor this area closely and implement mitigation plans as necessary as part of its reliability coordinator function. A two-phase joint project to construct a 230 kV overlay in the Acadiana load pocket is currently in the construction phase with targeted in-service dates of 2011 and 2012. Overall, there are no other anticipated reliability concerns for the summer season.




Gateway Demand Total internal aggregate demand for the utilities in the Gateway subregion for the summer season is forecast to be 19,113 MW based on normal weather conditions. This forecast demand is 867 MW (4.8 percent) higher than the actual 2009 summer peak demand of 18,246 MW, and is 48 MW (0.3 percent) higher than the forecast 2009 summer peak demand of 19,065 MW. Entities continue to experience decreases in economic conditions from 2009 to 2010. However, signs of moderate economic rebound and load growth are projected in 2010. The Gateway subregion’s peak demand is reported on a non-coincident basis and reserves are evaluated for summer conditions. Recent forecast assumptions are based on normal temperatures, decreased economic growth, and reductions in projected sales to the residential sector. Some entities use economic assumptions for the development of the 2010 forecast from Economy.com. Current forecasts call for a 0.8 percent growth in GDP for the St. Louis area in 2010. Demand Response programs within the subregion include residential, commercial, and industrial programs. Load management programs on the system reduce peak electric demand during hot summer temperatures when air conditioning load is at its peak and the cost of electricity is at its highest. Some programs reduce peak electric load for large commercial and industrial customers that have large demand levels during the summer. When customers are called on to participate, the load reduction can create savings for all parties involved in the program. Other programs such as Residential and Small Commercial Smart Thermostat Programs (direct-load control through smart thermostats) and voluntary price-responsive programs are in place to help reduce demand for the summer season. To address measurement and verification programs, some entities have contracted with third parties to conduct impact and process evaluations for residential and commercial programs. Evaluations are conducted annually with a comprehensive report due at the end of a program cycle. Reports should identify annual energy savings and portfolio cost-effectiveness of the programs. Demand Response is projected to be 0.6 percent of Total Internal Demand. This percentage is projected to reduce peak demand on entity systems within the Gateway subregion. Gateway utilities have experienced increased levels of participation in energy-efficiency programs since 2009. Energy-efficiency programs are numerous and active throughout the subregion. Entities promote programs such as Home Performance with Energy Star (low-income weatherization programs, water heater/AC replacements), Energy Star appliance rebate/loan programs, online energy audits, building operator certification programs (promoting efficient commercial buildings), lighting incentive programs, infrared thermography, leak detection programs, educational workshops, and solar programs. Energy-efficiency information is posted on some utility websites to inform and educate consumers to help manage rising energy costs and promote in-state economic development while protecting the environment. Independent third-party contractors have been retained by some utilities to perform all evaluation, measurement, and verification for the programs after they have been rolled out. Results are being reviewed to evaluate cost/energy savings. Web statistics and surveys supplied by customers and recent research help utilities measure the effectiveness of new and existing programs. Increased



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outreach by some of the smaller entities has doubled the participation of some customers in the efficiency rebate programs and tripled participation in loan programs. Entities that participate in the Midwest ISO market follow Midwest ISO’s new requirements regarding assessing peak demand forecast under its Module E tariff.57 Per this tariff, entities evaluate the standard error of the forecast, which simply reflects the statistical uncertainty around the forecast, as well as the elasticity of the peak demand with respect to weather. The forecast explicitly addresses extreme summer conditions only by consideration of high temperatures experienced on average over the period used to calculate normal weather (1971–2000). The weather elasticity mentioned above is developed with consideration of only the highest few points of the forecast, and therefore is applicable specifically to temperatures in the top of the projected summer temperature range. However, extreme temperatures beyond the normal annual high temperature are not explicitly considered beyond the application of the weather elasticity parameter. To develop these forecasts, some utilities use regression models, multiple forecast scenario models, and econometric models. Economic assumptions, alternative fuel pricing, electric pricing, and historical temperature and weather (pessimistic and optimistic conditions) pattern information are considered individually by each subregion utility. Generation Companies within the Gateway subregion expect to have the following aggregate capacity on-peak. This capacity is projected to help meet demand during this time period. Hydro and reservoir conditions are projected to be normal for the summer. Entities do not expect weather to impact the generating unit capability. Coal inventory levels are projected to be sufficient for coal-fired plants. Firm gas transportation also seems to be adequate for the generating units that use gas as their primary fuel supply. Overall, entities do not expect weather- or fuel-related issues to significantly restrict available capacity. CWLP’s Lakeside Units #6 and #7 were retired in October 2009, and Ameren’s Meredosia units #1 and #2 were removed from operation in November 2009. Both CWLP and Ameren followed the Midwest ISO’s Attachment Y58 procedure, which approved the retirement of these units based on a reliability assessment of the local transmission

57The MISO Business Practice Manual: BPM 011 – Module E – Resource Adequacy documents at http://www.midwestiso.org/page/Regulatory+and+Economic+Standards. 58Midwest ISO’s Transmission and Energy Markets Tariff Attachment Y is included in their Transmission Planning Business

Practice Manual (BPM-20) in section 7.2 electronically located at http://www.midwestmarket.org/publish/Folder/3e2d0_106c60936d4_-76850a48324a

Table SERC-11: Gateway Summer Capacity Breakdown

Capacity type Year 2010

(MW) Existing-Certain 24,369Nuclear 2,255Hydro/Pumped Storage 824Coal 14,054Oil/Gas/Dual Fuel 6,943Other/Unknown 273Solar 0Biomass 0Wind 2Existing-Other 846Existing-Inoperable 0Future capacity 0




system. Overall, no other existing significant generating units are anticipated to be out of service or retired during the summer season. Ameren’s Venice CTG #1 (26 MW) is unavailable for the summer. The Taum Sauk pump storage plant will be returned to service for the summer. New capacity for the summer includes CWLP’s Dallman unit #4 (208 MW), which attained commercial operation in November 2009. The Railsplitter wind farm (100 MW) went commercial last summer, though its capacity is limited to only 20 MW as shown in the above table. The Midwest ISO practice is to assume a maximum of 20 percent of wind capability as a network resource for the Gateway subregion. Capacity Transactions on Peak The Gateway subregion reported the following imports and exports for the summer season.

Table SERC-12: Gateway Subregional Imports/Exports


(MW) Firm Imports (external subregion) 2,741 Firm Exports (external subregion) 4,891 Expected Imports (external subregion) 0 Expected Exports (external subregion) 0

These firm imports and exports have been accounted for in the reserve margin calculations for the subregion. All capacity purchases and sales are on firm transmission within the Midwest ISO footprint and direct ties with neighbors. Day-to-day capacity and energy transactions are managed by Midwest ISO with security-constrained economic dispatch and LMP. Overall, the subregion is not dependent on outside imports or transfers to meet the demands of its load. Some entities report that the majority (~34 percent–95 percent) of their contracts include an LDC provision and also include a “make-whole” contract provision. Transmission The following table shows new bulk power system transmission additions for the summer assessment period and 2009, categorized as completed, under construction, or planned for the Gateway subregion.



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Table SERC-13: Gateway Expected Transmission


date(s)

Operating voltage

(kV) Baldwin Power Plant Substation- Rush Island Plant Substation


Baldwin Power Plant Substation-Prairie State Power Plant

Completed 11/24/2009 345

Baldwin Power Plant Substation-Prairie State Power Plant

Completed 12/22/2009 345

Joachim Substation-Tyson Substation Completed 12/05/2009 345 Loose Creek-Mariosa Delta Completed 06/17/2009 345 PrairieState Power Plant-Stallings Substation

Completed 12/22/2009 345

PrairieState Power Plant-W. Mount Vernon Substation

Completed 11/24/2009 345

Rush Island Plant-Joachim Substation Completed 12/05/2009 345 Interstate-East Springfield Completed 06/10/2009 138 Interstate-San Jose Rail Completed 06/04/2009 138 Cahokia-Ashley Planned 06/01/2010 138 Campbell Hill Tap-Steeleville Planned 06/01/2010 138

Table SERC-14: Gateway Transformer Additions


High-side voltage (kV)

Low-side voltage

(kV)


No projects reported for the summer assessment period Terminal equipment upgrade work related to a number of 138 kV outlet lines at the Hennepin Plant is being reviewed more closely in relation to scheduled generation outages at the plant. Near-term operating solutions are being investigated for implementation in the interim prior to completion of the upgrade work. These facilities are required to maintain a reliable transmission system. Each project is on schedule and is not anticipated to be delayed. No significant transmission outages are planned for the summer period. General practice is to not schedule planned outages of major transmission lines and equipment during the summer peak periods. Maintenance outages are generally scheduled during the off-peak times in the spring and fall. Operational studies are performed in the event that equipment failures occur. During these situations, system operators would re-dispatch generation and perform transmission switching to return all heavily loaded transmission facilities and out of range voltages to normal levels. The seasonal assessment performed by the SERC NTSG indicates favorable import capabilities from multiple entities. No constraints within the subregion have been identified that could significantly impact reliability during the summer season.




Continued use of the phasor measurement equipment installed at Ameren’s Callaway, Rush Island, and Newton plants is projected to help in providing post-disturbance data. These installations will be expanded in coming years to include phasor measurement equipment installations at other large plants and major substations on the Ameren system. With time, these installations, in combination with other such phasor measuring equipment installed elsewhere on the interconnected system, will provide another tool for operations personnel in assessing immediate near-term conditions on the interconnected system. Some members have upgraded distance relays at specific substations and switchyards to decrease outage time to their local customers. Distance relays provide better sectionalizing and quicker response time to transmission lines located in very rural areas. These relay additions do not directly improve bulk power system reliability, but they do improve the reliability of the power delivery system. Overall, no significant new technologies, systems, or transmission equipment have been added to the system since last summer. Operational Issues No special operating problems have been identified for the summer and no special operating studies have been performed. Past concerns for thermal discharge limits into Lake Springfield have been mitigated with the retirement of CWLP’s Lakeside units #6 and #7, and with the installation of a cooling tower for Dallman unit #4. Entities reported they are recognizing that voltage regulation on distribution systems with distributed generation is becoming a concern. However, entities within the subregion have very few distributed and Demand Response resources connected to the systems. The availability of large amounts of low-cost base-load generation during off-peak load conditions can result in congestion and real-time transmission loading issues. The addition of wind generation in the Gateway subregion and surrounding balancing areas to the north and west may exacerbate the transmission loading concerns in some areas. Midwest ISO members are currently studying the impacts of integrating large amounts of variable generating resources on the system. This issue of wind integration has been elevated to a higher level within the Midwest ISO as the amount of wind generation is projected to increase dramatically over the next several years. Generation re-dispatch may be required at some plants, subject to the security-constrained economic dispatch algorithm of the Midwest ISO, to maintain transmission loadings within ratings. Curtailment of some transactions may also be required. Some base-load generation may be forced off during minimum load conditions because of too much generation available to serve the load; however these would not be reliability concerns, but market issues. Several entities report that there are environmental regulations that limit the number of hours of operation, tons of emissions, and thermal discharges of some power plants. However, these entities are monitoring plant and unit operations to ensure that the regulatory limits do not constrain operations during summer peak conditions. Although some peaking plants have de minimus air permits that limit the hours of operation to approximately 950 hours per year, these limitations should not prevent these units from operating when needed for reliability or economic dispatch situations. The impact of hazardous air pollutant (HAP) regulatory restrictions is currently being studied. Entities are managing these restrictions and do not expect the restrictions to be detrimental to system reliability during the assessment period. Gateway subregion utilities do not expect any unusual operating conditions that could impact reliability for the summer season.



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Entities are researching the implementation of smart grid technology within the area. There are no reports of the new technology on the system for summer. Reliability Assessment Reported resource and load for the Gateway subregion utilities result in a projected summer peak reserve margin of 16.9 percent, compared to 9.1 percent last year. As all Gateway load-serving entities are members of the Midwest ISO, they follow the planning reserve requirements of the Midwest ISO. For 2010, the planning reserve margin requirement is 11.94 percent based on a Loss of Load Expectation metric of one day in ten years for loads in the Gateway subregion. Entities that participate in the Midwest ISO market generally have excess capacity, and use the LOLE reserve margins as a guideline for planning. Actual capacity margin surplus has occurred since last summer due to cooler temperatures and reductions in load. The Midwest ISO resource adequacy and operational procedures can be found in the Midwest ISO Resource Adequacy Business Practice Manual. A 50/50 load uncertainty was used in their latest LOLE assessment. A 90/10 load forecast was not done; however, if it were done, it is not projected to increase the reserve requirements significantly due to the geographical size and load diversity within the Midwest ISO. The use of a 90/10 forecast increases demand by about five percent above the 50/50 forecast level for the Gateway subregion. Assuming an 11.94 percent planning reserve margin for a 50/50 load level, the reserve margin for a 90/10 load level would be about 10.2 percent. A small amount of interruptible load may be available for curtailment, along with voltage reduction to reduce the system load. Appeals for voluntary load conservation from the Midwest ISO and Gateway utilities would also be available if needed to cover capacity shortages. Based on past experience, resources are projected to be adequate for the summer peak demand. Fuel supply in the area is not projected to be a problem, and policies considering fuel diversity and delivery have been put in place throughout the area to ensure that reliability is not impacted. Several entity policies take into account contracts with surrounding facilities and suppliers, alternative transportation routes, and alternative fuels. These practices help to ensure balance and flexibility to serve anticipated generation needs. To address transient stability modeling issues, most entities within the subregion participate in the SERC DSG to assess annual dynamic conditions on the system. The larger entities within the subregion use the models developed by the ERAG and DSG to perform their own transient stability studies. Some utilities consider winter or off-peak load levels to assess stability, which is a more conservative approach than using summer peak load levels. During 2009, a number of Category C transient stability simulations were performed for several selected plants and substations connected to the Ameren transmission system and considered 2009 light load, 2010 summer peak load, and 2014/15 winter peak-load conditions. A number of Category D transient stability simulations were also performed for several selected plants and substations connected to the Ameren transmission system and considered 2009 light load, 2009/10 winter peak load, 2010 summer peak load, and 2013/14 winter peak load conditions. No criteria have been set for voltage or dynamic reactive requirements within this subregion. Some utilities consider a steady state voltage drop greater than five percent (pre-contingency–post contingency) as a trigger to determine if further investigation is needed to ensure there are no widespread outages. Voltage




stability assessments have been performed for some load centers in Illinois. Some of these areas are subject to voltage collapse for some double-circuit tower outages during peak conditions, but widespread outages are not projected. Plans to build new transmission lines to mitigate the contingencies are proceeding. Public involvement has been solicited to develop possible line routes. Applications to the Illinois Commerce Commission for Certificates of Convenience and Necessity are projected to be filed in 2010 to build these new lines by summer of 2015. Overall, individual or SERC group studies have not reported any other major issues or concerns within this subregion. In order to minimize impacts on the system that cause reliability concerns, entities plan for the system to have adequate capacity to meet the load and planned (annual) maintenance outages to keep generating resources reliable. The transmission system is monitored continuously and facilities are planned and constructed to maintain or enhance reliability as needed. Overall, utilities within Gateway do not expect any significant reliability concerns for the summer season.



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Southeastern Demand Total aggregate internal demand for utilities in the Southeastern subregion for the summer season is forecast to be 48,472 MW based on normal weather conditions as determined by historical system average weather. This is 1,032 MW (2.1 percent) lower than the forecast 2009 summer peak demand of 49,504 MW and 2,641 MW (5.8 percent) higher than the actual 2009 summer peak demand of 45,831 MW. Growth rates are predicted to be less than last year’s rate due to lower economic assumptions, the recession, and loss of industrial load. Forecasts show continuing positive economic trends and customer growth but at slower rates than last year’s projections. The decreases in expectations result in a lower forecast for summer energies and peak demand. Demand Response programs within the subregion consist of programs ranging from real time pricing/critical peak pricing (reduce energy use based on price signaling) and interruptible demand programs (requests customers to reduce energy use) to direct load control programs (energy provider reduces customer energy use). Entities within the subregion have the ability to control various amounts of load when needed for reliability purposes. One example of a Demand Response program is the H2O Plus program, which utilizes the storage capacity of electric water heaters. This program allows entities to install load control devices that can be activated during peak periods, which promotes the following benefits:

Help reduce the need to build or purchase capacity Respond to volatile wholesale energy markets Improve the efficiency (load factor) as well as the utilization of generation, transmission,

and distribution systems Provide low-cost energy to member cooperatives Increase off-peak kWh sales

A total of 4,405 load control devices are projected to be installed by the end of June 2010 with a total of 5,287 being installed by December 2010. Each water heater has a peak reduction capability of 1.2 kW in the winter and .5 kW in the summer. Other programs in place allow entities to interrupt air conditioning systems during periods of peak demand, reduce line losses, regulate voltage drops across the circuit, and reduce the voltage on the distribution circuits at the voltage regulator/load tap transformer that results in customer demand reduction (Distribution Efficiency Program, Conservation Voltage Reduction). Demand Response is projected to be 3.4 percent of Total Internal Demand. This percentage is available to reduce peak demand on entity systems within the Southeastern subregion if needed for reliability. Within the subregion, various utilities have residential energy-efficiency programs that may include educational presentations, home energy audits, compact fluorescent light bulbs, electric water heater incentives, heat pump incentives, energy-efficient new-home programs, Energy Star appliance promotions, loans or financing options, weatherization, programmable thermostats,




and ceiling insulation. Commercial programs may include energy audits, lighting programs, and plan review services. Other programs such as business assistance/audits, weatherization assistance for low-income customers, residential energy audits, and comfort advantage energy-efficient home programs promote reduced energy use, supply information, and develop energy-efficiency presentations for various customers and organizations. Utilities are also beginning to work with states’ energy divisions on energy-efficiency planning efforts. Training seminars addressing energy efficiency, HVAC sizing, and energy-related end-use technologies are also offered to educate customers. To address measurement and verification of energy-efficiency and DSM programs, entities may use third parties to conduct impact/process evaluations for commercial programs, or entities may use load response statistical models to identify the difference between the actual consumption and the projected consumption absent the curtailment event. Response may also be tracked and verified by the readings of meters, as well as testing residential and commercial summer load-control programs for verification of demand reduction through generation dispatch personnel. Evaluations may be conducted annually with a comprehensive report due at the end of a program cycle. Reports are projected to determine annual energy savings and portfolio cost-effectiveness. To assess variability, some subregion entities develop forecasts using econometric assessment based on approximately 40-year (normal, extreme, and mild) weather, economics, and demographics. Others within the subregion use the assessment of historical peaks, reserve margins, and demand models to predict variance. Generation Utilities within the Southeastern subregion expect to have the following aggregate capacity on-peak to help meet demand during this time period. Below are the Existing (-Certain, -Other, and -Inoperable) and Future (-Planned and -Other) resources in the subregion.

Hydro conditions are anticipated to be normal and reservoir levels are sufficient to meet peak demand throughout the summer. Normal rainfall and inflows are anticipated during the summer. Daily system load demands will be met by combining available hydro generation with other resources. Overall the subregion is not experiencing, and does not anticipate, any conditions that would reduce capacity for the summer. Entities also do not anticipate any existing significant generation units being out of service or retired during the summer season.

Table SERC-15: Southeastern Summer Capacity Breakdown


(MW) Existing-Certain 61,779Nuclear 5,772Hydro/Pumped Storage 5,041Coal 24,529Oil/Gas/Dual Fuel 26,408 Other/Unknown 13 Solar 0Biomass 17 Wind 0 Existing-Other 3,281 Existing-Inoperable 0Future capacity 822



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Capacity Transactions on Peak Southeastern utilities reported the following imports and exports for the summer assessment period.

Table SERC-16: Southeastern Subregional Imports/Exports


(MW) Firm Imports (external subregion) 6,467 Firm Exports (external subregion) 5,460 Non-Firm Imports (external subregion) 0 Non-Firm Exports (external subregion) 0 Expected Imports (external subregion) 0 Expected Exports (external subregion) 0

The majority of these imports/exports are backed by firm contracts for both generation and transmission, but none are associated with LDCs or considered “make whole.” These firm imports and exports have been included in the reserve margin calculations for the subregion. Entities maintain emergency-reserve sharing agreements with organizations such as SPP Reserve Sharing Group. Contract agreements with neighboring utilities in the subregion provide capacity for outages of specific generation. Overall, the subregion is not dependent on outside imports or transfers to meet the demands of its load. Transmission The following table shows bulk power system transmission (categorized as under construction or planned) that is projected to be in service for the summer season and since 2009.

Table SERC-17: Southeastern Expected Transmission


date(s) Operating

voltage (kV) AJIN Tap-AJIN completed 04/23/2009 115 Bucks SS-Tensaw SS completed 09/28/2009 230 Calvert SS-Tensaw SS completed 03/12/2009 230 Tensaw SS-TK EAF(2) completed 06/24/2009 230 Tensaw SS-TK EAF(2) completed 06/24/2009 230 Tensaw SS-TK EAF(3) completed 06/24/2009 230 Tensaw SS-TK Rolling Mill(1) completed 03/24/2009 230 Tensaw SS-TK Rolling Mill(2) completed 03/24/2009 230 Bio-Airline completed 04/29/2009 115 Dum Jon-Thomson completed 01/15/2010 230 Plant McDonough-Smyrna completed 12/17/2009 230 Chevron Cogen-Chevron PRCP completed 07/02/2009 115 Heidelberg Denbury-Laurel North-Pachuta completed 06/29/2009 115 NASA Satum Dr-NASA North completed 01/26/2010 115 Salem-Necaise completed 10/21/2009 230 Murphy Mill Jct-Murphy Mill completed 12/16/2009 115




Florida Gas Tap-Florida Gas under construction 08/01/2010 115 Providence-West Grelot planned 06/01/2010 115 Sokol Park DS-Carrolls Creek Tp planned 06/01/2010 115 Pegamore-Huntsville planned 06/01/2010 230 Bethabara- Clarksboro under construction 06/01/2010 230 East Lake Road-Jackson Creek under construction 06/01/2010 230 Jim Moore Road-Sharon Church under construction 06/01/2010 230 East Lake Road-Ola under construction 06/01/2010 230 CAES Unit 4-CAES Sw under construction 04/01/2010 115 CAES Unit 5-CAES Sw under construction 04/01/2010 115 Coffee Springs Jct-Coffee Springs under construction 09/01/2010 115 Trickem Jct-Trickem under construction 03/02/2010 115 White Oak SS-Polkville under construction 06/01/2010 161 CAES-McIntosh (1) under construction 03/01/2010 115 Lay Dam-Mitchell Lake under construction 05/01/2010 115 Mitchell Lake-Mitchell Dam under construction 05/01/2010 115 CAES-McIntosh (2) under construction 06/01/2010 115 Morrow-Murray Lake Tap conceptual 05/01/2010 115 Swainsboro-Altma Jct planned 05/01/2010 115 East Social Circle-East Social Circle Jct under construction 06/01/2010 115 Three Rivers Road-Vestry Tap under construction 05/01/2010 115 MS Chemical-Chevron Cogen planned 05/01/2010 115 Thomson-Warthen under construction 06/01/2010 500

Table SERC 18: Southeastern Transformer Additions


High-side

voltage (kV)

Low-side

voltage (kV)


East Palham 230 115 10/01/2009 Installed Thomasville

230 115 12/17/2009 Implemented new calculated

contingency ratings Thomson

500 230 06/01/2010 Under construction: New 1344 MVA 500/230 kV transformer at Thomson

Thomson 230 115 06/01/2010

Under construction re-rating: replace 140 MVA, 230/115 kV transformer with

300 MVA transformer Evans Primary

230 115 06/01/2010 Under construction re-rating: replace

125 MVA, 230/115 kV transformer with 300 MVA transformer

Ola 230 115 06/01/2010

Under construction: Expand existing 115 kV substation for 230 kV operations

Purvis Bulk Transformer Replacement

230 161 06/01/2010 Addition-under construction: upgrading

tie transformer at Purvis bulk



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There is a reliability concern for the Bethabara-Clarksboro 230 kV line project in that its targeted in-service date (June 1, 2010) will not be met. The project is scheduled for completion one month later (July 1, 2010). Georgia Transmission Corporation (GTC) will address this concern by working with GPC operations and Walton EMC to create an operational solution to ensure that reliability will be maintained in the area for this delay. Overall, there are no other major concerns currently with meeting in-service dates for transmission improvements. The economic environment is resulting in reduced load forecasts, which in turn tend to delay the needs for some of these improvements. Entities do not currently have any significant transmission outages scheduled for the summer operating season. Transmission operators may schedule transmission outages during the summer operating season as system conditions allow. Every planned transmission outage is thoroughly and repeatedly analyzed for any reliability impacts prior to approval and execution. There are no unusual anticipated transmission constraints that could significantly impact reliability. Additionally, there were no significant technologies that were added in the past year to improve bulk power system reliability. However, GTC and Southern Company developed a new 500 kV transmission tower design (Delta) for GTC’s Thomson-Warthen 500 kV line project, which was completed in November of 2009. The new design could potentially impact reliability in a positive way in that it is more easily maintained and, in the event of an unplanned outage, it can enable restoration of a 500 kV line quicker than the steel lattice type structure. The new design is now the standard for new 500 kV lines for GTC and Southern Company. Operational Issues Subregional utilities perform studies of operating conditions for 12 to 13 months into the future. These studies include the most up-to-date information regarding load forecasts, transmission, generation status. and firm transmission commitments for the time period studied and are often updated on a monthly basis. Additionally, reliability studies are conducted on two-day-out and next-day conditions. Studies are updated as changing system conditions warrant. The current operational planning studies do not identify any unique operational problems for the summer season. While the planning assessment has not been conducted for 2010 at this time, entities may annually conduct an assessment assuming the summer peak loads are approximately 105 percent of the forecasted peaks. This assessment is done to support operations for the summer. Currently there are no significant amounts of distributed resources installed on the system; therefore, there are no anticipated operational changes, concerns, or special operating procedures related to distributed resource integration. Demand Response programs currently in place do not negatively impact reliability. All programs are well coordinated with transmission and generation operations. Fossil generating units in the Southern control area have operating limits related to air and/or water quality. These are derived from both federal and state regulations. A number of these units have unique limits on operations and/or emissions; some are annual limits while others are seasonal. These restrictions are continually managed in the daily operation of the system while maintaining reliability. Overall, no existing conditions are projected to impact the reliability on the bulk power system as a result of environment restrictions.




The Southern control area routinely experiences significant loop flows due to transactions external to the control area itself. The availability of large amounts of excess generation within the southeast results in fairly volatile day-to-day scheduling patterns. The transmission flows are often more dependent on the weather patterns, fuel costs, or market conditions outside the Southern control area rather than by loading within the control area. Significant changes in gas pricing dramatically impact dispatch patterns. All transmission constraints identified in current operational planning studies for the summer assessment period can be mitigated through generation adjustments, system reconfiguration, or system purchases. Reliability Assessment The projected reserve margin in the Southeastern subregion is 35.9 percent compared to 23.1 percent last year. The projected summer reserve margin increased due to reduced load projections caused by economic conditions. The actual reserve margin last summer was higher than anticipated because the peak load was well below forecast due to the recession and mild weather. Utilities within the Southeastern subregion do not adhere to any regional/subregional targets or reserve margin criteria. However, the state of Georgia requires maintaining at least 13.5 percent near-term (less than 3 years) and 15 percent long-term (3 years or more) reserve-margin levels for investor-owned utilities. Recent analyses of load forecasts indicate that projected reserve margins remain well above 15 percent for the summer season for most utilities in the subregion. Analyses account for planned generation additions, retirements, deratings due to environmental control additions, load deviations, weather uncertainties, and forced outages and other factors. Resource adequacy is determined by extensive assessment of costs associated with projected unserved energy, market purchases, and new capacity. These costs are balanced to identify a minimum cost point, which is the optimum reserve-margin level. The latest resource adequacy studies show that reserve margins for the summer period are projected to be within the range of 15 percent to 34 percent for utilities within the subregion. Even though some utilities make use of purchases and reserve sharing agreements, they are not relying on resources from outside the subregion or Region to meet load. Additionally, post-peak assessments are conducted on an as-needed basis to evaluate system capability resulting from an extreme peak season. Information such as updates to load forecasts, outage information, fuel costs, and other inputs are re-evaluated as well. The evaluation is performed for the current year through a 20-year planning horizon. Sensitivities addressing criteria such as impacts projected from future environmental standards or law are evaluated as needed. The fuel supply infrastructure, fuel delivery system, and fuel reserves are all adequate to meet peak gas demand. Various companies within the subregion have firm transportation diversity, gas storage, firm pipeline capacity, and on-site fuel supplies to meet the peak demand. Many utilities reported that fuel vulnerability is not an projected reliability concern for the summer reporting period. The utilities have a highly diverse fuel mix to supply the demand, including nuclear, PRB coal, eastern coal, natural gas, and hydro. Some utilities have implemented fuel storage and coal conservation programs, and various fuel policies, to address this concern. Policies have been put in place to ensure that storages are filled well in advance of hurricane season (by June 1 of each year). These tactics help to ensure balance and flexibility to serve



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anticipated generation needs. Relationships with coal mines and coal suppliers, daily communication with railroads for transportation updates, and ongoing communication with the coal plants and energy suppliers ensures that supplies are adequate and potential problems are communicated well in advance to enable adequate response time. The Southeastern subregion does not have subregional criteria for dynamics, voltage, and small signal stability; however, various utilities within the subregion perform individual studies and maintain individual criteria to address any stability issues. A criterion such as voltage security margins of five percent or greater in MW has been put in place within various utility practices. To demonstrate this margin, the powerflow case must be voltage stable for a five percent increase in MW load (or interface transfer) over the initial MW load in the area (or interface) under study with planning contingencies applied. Studies are made each year for the summer and generally for a future year case. The studies did not indicate any issues that would impact reliability this summer season. Other utilities use an acceptable voltage range of 0.95 p.u. to 1.05 p.u. on their transmission system. During a contingency event the lower limit decreases to 0.92 p.u. with the upper limit remaining the same. The acceptable voltage range is maintained on the system by dispatching reactive generating resources and by employing shunt capacitors at various locations on the system. To address dynamic reactive criterion, some utilities follow the practice of having a sufficient amount of generation on-line to ensure that no bus voltage is projected to be subjected to a delayed voltage recovery following the transmission system being subjected to a worst-case, normally cleared fault. Studies of this involve modeling half of the area load as small motor load in the dynamics model. Prior to each summer, an operating study is performed to quantify the impact of generating units in preventing voltage collapse following a worst-case, normally cleared fault. The generators are assigned points, and the system must be operated with a certain number of points on-line depending on current system conditions including the amount of load on-line and the current transmission system configuration. The study is performed over a range of loads from 105 percent of peak summer load down to around 82 percent of peak summer load conditions. To minimize impacts on the system, utilities within the Southeastern subregion annually perform regional assessments of the transmission system. Reliability concerns are addressed through the development of projects for a ten-year period. Transmission expansion plans include projects that exceed the requirements of current standards. The inclusion of these projects will assure that the reliability concerns are met during the next 10 years. Several of the proposed climate legislations or anticipated EPA regulation could lead to potential unit retirements in the planning horizon. Entities continue to evaluate reliability impacts of these concerns and solutions have been developed to address them. Overall, this is not seen as a reliability concern. However, if the impact of legislation and regulation results in the inability to distribute significant amounts of existing generation across the nation, then the ability to procure and/or construct replacement generation within a given timeframe could present a reliability concern.




VACAR Demand The sum of the Total Internal Demands of the utilities in the VACAR subregion for the summer season is forecast to be 63,456 MW based on normal weather conditions. This is 112 MW (0.2 percent) lower than the forecast 2009 summer peak demand of 63,568 MW and 3,183 MW (5.3 percent) higher than the actual 2009 summer peak demand of 60,275 MW. In 2009 entities experienced a slowdown in growth in residential and commercial sales. This was due to national/local economic conditions that were growing at a much slower rate as compared to the past several years. This trend is projected to continue into 2010. Utilities in the subregion use a variety of methods to predict load. These may include regressing demographics, specific historical weather assumption, or the use of a Monte Carlo simulation using multiple years of historical weather. The economic recession is projected to cause slowed load growth and a significant increase in load management within this subregion. One method uses three weather variables to forecast the summer peak demands. The variables are (1) the sum of cooling degree hours from 1 p.m. to 5 p.m. on the summer peak day, (2) minimum morning cooling degree hours per hour on the summer peak day, and (3) maximum cooling degree hours per hour on the day before the summer peak day. Economic projections can be obtained from Economy.com, and through the development of demand forecasts. The utilities in the subregion have a variety of programs offered to their customers that support energy efficiency and Demand Response. Some of the programs are current energy-efficiency and demand-side management programs that include interruptible capacity, load control curtailing programs, residential air conditioning direct loads, energy products loan programs, standby generator controls, residential time-of-use, Demand Response programs (interruptible and related rate structures), Power Manager PowerShare conservation programs, residential Energy Star rates, Good Cents new home program, commercial Good Cents program, thermal storage cooling program, H20 Advantage water heater program, general service and industrial time-of-use, and hourly pricing for incremental load interruptible, etc. These programs are used to reduce the affects of summer peaks and are considered part of the utilities’ resource planning. The commitments to these programs are part of a long-term, balanced energy strategy to meet future energy needs. Load response will be measured by statistical models that identify the difference between the actual consumption and the projected consumption absent the curtailment event. Demand Response is projected to be 5.6 percent of Total Internal Demand. This percentage is projected to reduce peak demand on entity systems within the VACAR subregion. To assess demand variability, some utilities within the subregion use a variety of assumptions to create forecasts. These assumptions are developed using economic models, historical weather (normal/extreme) conditions, energy use, and demographics. The forecast is based on an assessment of historical events that occurred over the previous 10 years and on assumptions regarding the future. These assumptions relate to key factors known to influence energy use and peak demand (i.e., economic activity, price of electricity, weather conditions, and local area demographics). Non-weather sensitive industrial energy forecasts may be developed subjectively based on historical trends and information provided by individual industrial customers.



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Projections of peak demand are developed for the summer season and are based on equations that incorporate total energy requirements and long-term peak demand. In addition to the peak-demand base-case forecast, high and low-range scenarios are developed to address uncertainties regarding the future and extreme weather conditions. Simulations for both energy and peak demand address the uncertainty associated with those factors and are included in econometric models. Results from the simulations are used to produce probabilistic high- and low-range forecasts. Model inputs include probability distributions of total personal income, heating and cooling degree days, and peak day average temperatures. Outputs for each year of the forecast period include energy and peak demand distributions including projections from the 0- to 100-percent probability levels in increments of five percent. The high and low-range forecasts are represented by the 5th and 95th percentiles. Results provide peak demand estimates for given temperatures and the probabilities that peak demand will rise or fall to specific levels around the base case forecast. Daily load forecasts may be prepared using software such as Neural Electric Load Forecaster (NELF), which takes into account daily temperature forecasts for service areas. Daily load forecasts are used to perform next day studies and daily switching studies. It is not common for extreme weather conditions to be addressed other than the variations of temperatures in the models (as described above). However, some entities reported that they address extreme forecast based on 90/10 conditions or in the representation of historical data within the models. Generation Companies within the VACAR subregion expect to have the following aggregate capacity on-peak. This capacity is projected to meet demand during this time period. Ample rainfall and seasonal snow have produced significant inflows, contributing to near-full reservoir pools in mid-January, and indications are that drought conditions no longer exist. Management of hydro resources continues to optimize lake levels into the summer months. Forecast information indicates equal chances of below- or above-normal precipitation. Coupled with other resources in the portfolio, projected hydro generation and reservoir levels are projected to be adequate to meet both normal and emergency energy demands for the summer peak. There are no known or projected significant conditions or generator outages that would reduce capacity in the subregion. Therefore, no peak capacity reductions are projected for the summer season.

Table SERC-19: VACAR Summer Capacity Breakdown


(MW) Existing-Certain 70,870 Nuclear 14,953 Hydro/Pumped Storage 9,717 Coal 25,522 Oil/Gas/Dual Fuel 20,199 Other/Unknown 261 Solar 0 Biomass 218 Wind 0 Existing-Other 1,842 Existing-Inoperable 98 Future capacity 41




Capacity Transactions on Peak Utilities within the VACAR area reported the following imports and exports for the summer season. These sales and purchases are external and internal to the Region and subregion and help to ensure resource adequacy for the utilities within the VACAR area. All purchases are backed by firm contracts for both generation and transmission and are not considered to be based on partial path reservations. Of the imports/exports below, very few are associated with LDC (~355 MW) in which the contracts are considered 100 percent “make-whole.”

Table SERC-20: VACAR Subregional Imports/Exports


(MW) Firm Imports (External Subregion) 2,438 Firm Exports (External Subregion) 2,217 Expected Imports (External Subregion) 0 Expected Exports (External Subregion) 0

Transmission Several improvements to transmission facilities of utilities within VACAR have been completed or are planned to be completed by this summer. The following table shows bulk power system transmission categorized as completed, under construction, planned, or conceptual that is projected to be in service for the summer season or since 2009.

Table SERC 21: VACAR Expected Transmission


date(s)

Operating voltage (kV)

Piercetown- Plainview Ret under construction 07/01/2010 100 Aquia Harbor-Garrisonville under construction 05/31/2010 230 Bear Garden-Bremo under construction 06/01/2010 230 Bremo- Bear Garden planned 07/01/2010 230 Gallows-Ox planned 05/28/2010 230 Nantahala Hydro-Santeetlah and Fontana

completed 01/09/2010 161

Brambleton-Greenway completed 05/31/2009 230 Bristers-Gainesville completed 06/11/2009 230 Central Toe-Greenlawn Sw Sta completed 02/15/2010 100 EU #6 Tap-Conley Tap completed 12/16/2009 100 Harrisburg Tie-Concord City #3 completed 04/17/2009 100 Brambleton-Loudoun completed 12/31/2009 230



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Table SERC 22: VACAR Transformer Additions


High-side

voltage (kV)

Low-side voltage

(kV) In-service

date(s) Description/Status b0342

230 115 05/01/2010 Planned Addition — Trowbridge

second transformer b0772

230 115 06/01/2010 Planned Addition — Second

transformer at Elmont b0770

230 115 05/28/2010 Addition — Under Construction:

second transformer at Lanexa Delays with the above in-service dates have not been identified as a risk. If delays occur that would result in reliability concerns, mitigating actions would be developed accordingly. Mitigating measures include re-dispatch of generation, operating procedures, and special protection schemes. There is currently a two-week outage request in August for the Conemaugh-Hunterstown 500 kV line. This request will be studied to determined if the delay should occur; taking into account weather conditions and other factors. Transmission maintenance schedules are carefully reviewed and evaluated to insure reliability concerns are addressed while permitting as much prioritized maintenance as can be accommodated prior to seasonal peak period. No summer transmission constraints have been identified since the 2009 assessment studies. Regional studies are performed on a routine basis internally and externally. Coordinated single transfer capability studies with external utilities are performed quarterly through the SERC NTSG. Projected seasonal import and export capabilities are consistent with those identified in this assessment. Constraints external to the SERC subregions are evaluated as part of the SERC East-RFC seasonal study group efforts. There are no anticipated transmission constraints identified that significantly impact reliability. Utilities in the subregion have employed SVC technology in the past and would consider its use again in the future. Other utilities are actively investigating the potential application of smart grid technology for future implementation. Operational Issues Entities did not identify any need to perform special operating studies for the summer season. No operational problems or constraints are anticipated during the assessment period. For the projected and any extreme summer peaks, reserve margins are such that the loss of multiple units can be accommodated without threatening reliability. The VACAR reserve sharing agreement is in place to support recovery from such extreme events. Since both the amounts of distributed and variable generation are very small in the subregion and entities within it hold a diverse amount of resources, special operating procedures are not needed for the integration of variable resources or to mitigate concerns resulting from high levels of Demand Response resources.




There are no environmental or regulatory restrictions projected within the subregion. PJM requires generation owners to place resources into the “Maximum Emergency Category” if environmental restrictions limit run hours below pre-determined levels. For mitigation purposes, this entity dispatches these maximum emergency units the last. Overall, there are no anticipated unusual operating conditions that could impact reliability for the summer season. Reliability Assessment The projected aggregate reserve margin of the utilities within the VACAR area is 16.0 percent, compared to 19.6 percent last summer. Entities continue to project margins based on load reductions due to the economy, increased demand-side management, significant increases in generation, and mild weather. It is anticipated that capacity in the subregion should be adequate to supply forecast demand. Utilities within the VACAR subregion do not adhere to any Regional/subregional targets or reserve margin criteria. However, some utilities within this subregion adhere to North Carolina Utilities Commission regulations. Other utilities within the subregion established individual target margin levels to benchmark margins that will meet the needs for peak demand. Some assumptions used to establish the individual utilities’ reserve/target margin criteria or resource adequacy levels are based on prevailing expectations of reasonable lead times for the development of new generation, procurement of purchased capacity, siting of transmission facilities, and other historical experiences that are sufficient to provide reliable power supplies. Other assumptions include levels of potential DSM activations, scheduled maintenance, environmental retrofit equipment, environmental compliance requirements, purchased power availability, or peak-demand transmission capability/availability. Risks that would have negative impacts on reliability are also an important part of the process to establish assumptions. Some of these risks would include the deteriorating age of existing facilities on the system, significant amount of renewables, increases in energy-efficiency/DSM programs, extended base-load capacity lead times (for example, coal and nuclear), environmental pressures, and derating of units caused by extreme hot weather/drought conditions. In order to address these concerns, companies continue to monitor these risks in the future and make any necessary adjustments to the reserve margin target in future plans. Other utilities have adopted LOLE standards of one occurrence in ten years to address reserve margin targets. Annual LOLE studies help to determine the reserve margin required to satisfy this criterion. The study recognizes, among other factors such as load forecast uncertainty due to economics and weather, generator unavailability, deliverability of resources to load, and the benefit of interconnection with neighboring systems. Uncertainties may also be addressed through capacity margin objectives and practices in other resource assessments at the operational level. These studies may be performed at least twice daily using input provided from generator operators. As conditions warrant, entities may see the need to perform additional assessments to mitigate challenging conditions on the system. The latest resource adequacy studies performed within the subregion were reported to be completed in the winter of 2009. These studies examined the resource availability for multiple



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years. Resource adequacy is assessed using various methods and assumptions that range from LOLE studies (one occurrence in ten years), loss of multiple unit studies, new environmental requirements, renewable energy, new generation technologies and rising commodity costs, forecasts for normal/severe weather cases with additional firm capacity (existing, future and outage models included), and forecasted demand plans on an annual/seasonal basis. In addition, forecast of peak demand is generally made under a variety of weather and economic conditions as required under RUS 1710 requirements. From this assessment, resources are planned accordingly. Studies for 2010 are projected to show the system to be adequate based on the current forecast, generation and demand side resources. Margins from the studies show that entities within the subregion are adequate with percentages in the range of 15 percent. Overall, operational problems are not anticipated for the summer season. Utilities within the VACAR area have reported that their generation facilities expect to maintain enough diesel fuel to run the units for an order cycle of fuel. Fuel supply or delivery problems during the projected summer are not anticipated. Entities have ongoing communications with commodity and transportation suppliers to communicate near-term and long-term fuel requirements. These communications take into account market trends, potential resource constraints, and historical and projected demands. These discussions are framed to ensure potential interruptions can be mitigated and addressed in a timely manner. Exchange agreements, alternative fuel, or redundant fuel supplies may also be used to mitigate emergencies in the fuel industry or economic scenarios. Onsite fuel oil inventory allows for seven-day operations on some units. This was considered to be ample time to coordinate with the industry to obtain adequate supplies. Contracts are in place months, and often years, into the future. Vendor performance is closely monitored and potential problems are addressed long before issues become critical. Stability and dynamics assessments/criteria are performed and produced on an individual company basis within the VACAR area. However, most entities within the subregion participate in the SERC DSG to assess annual dynamic conditions on the system. The DSG will not have cases completed for the 2010 dynamic data submittal year until the fall of 2010. Some utilities individually follow practices such as utilizing a reactive power supply operating strategy based on adopted generating station voltage schedules and electric system operating voltages managed through real-time Reactive Area Control Error (RACE) calculations. Through this operating practice, primary support of generator switchyard bus voltage schedules using transmission system reactive resources, dynamic reactive capability of spinning generators may be held in reserve to provide near-instantaneous support in the event of a transmission system disturbance. Other utilities may develop Reactive Transfer Interfaces to ensure sufficient dynamic Mvar reserve in load centers that rely on economic imports to serve load. Day-ahead and real-time security assessment ensures sufficient generation is scheduled/committed to control pre- and post-contingency voltages and voltage drop criteria within acceptable predetermined limits. Reactive transfer limits are calculated based on a predetermined back-off margin from the last convergent case. Overall, no stability or dynamics issues have been identified as impacting reliability during the summer season.




To minimize reliability concerns on the system, entities regularly study and review annual and seasonal assessments. These assessments serve to develop a seasonal strategy for maintaining adequate system operating performance. Construction schedules are pre-arranged to avoid impacts to transmission system reliability, but unplanned delays to these schedules may result in transmission element outages that extend into the winter season. Should construction delays be unavoidable, operational risks and steps to mitigate these risks will be evaluated. Overall, there are no other anticipated reliability concerns that have been identified for the summer.



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Region Description The SERC Region is a summer-peaking Region covering all or portions of 16 central and southeastern states59 serving a population of more than 60 million. Owners, operators, and users of the bulk power system in these states cover an area of approximately 560,000 square miles. 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), and investor-owned operations. In the SERC Region there are 30 Balancing Authorities and more than 200 Registered Entities under the NERC functional model. SERC Reliability Corporation serves as a Regional Entity with delegated authority from NERC for the purpose of proposing and enforcing reliability standards within the SERC Region. The SERC Region is divided geographically into five subregions that are identified as Central, Delta, Gateway, Southeastern, and VACAR. Additional information can be found on the SERC website: www.serc1.org.

59 Alabama, Arkansas, Florida, Georgia, Iowa, Illinois, Kentucky, Louisiana, Missouri, Mississippi, North Carolina, Oklahoma,

South Carolina, Tennessee, Texas, and Virginia




SSPPPP

Introduction The Southwest Power Pool, Inc. Regional Entity’s (SPP RE) demand for the 2010 summer is projected to be higher than the 2009 actual summer demand. Existing capacity resources in the SPP RE footprint are projected to be 55,387 MW; of those, 49,777 MW are Existing-Certain resources. No new Existing-Certain resources have been added since the 2009 Summer Assessment in the SPP RE footprint. Future-Planned resources projected to be in service during the assessment timeframe total 266 MW. The SPP RE’s minimum required capacity margin requirement is 12 percent, which translates to a reserve margin of 13.6 percent.60 For 2010 summer, the reserve margin for the SPP RE Region, based on Existing-Certain, and Net-Firm Transactions, is 19.2 percent. The 2010 summer reserve margin based on Anticipated Capacity Resources is 20.4 percent. This is well above the SPP RE’s minimum required capacity margin. Overall, there are no known reliability concerns identified for 2010 summer. There have been no significant transmission line additions since the previous reporting year. However, five bulk power transformers with 345 kV high voltage side are projected to be added to the SPP Regional Transmission Organization (RTO) grid. There are no known transmission reliability concerns identified during the assessment timeframe.

60 SPP Criteria 2.1.9 http://www.spp.org/publications/Criteria02042010-with%20AppendicesCurrent.pdf


Direct Control Load Management 15Contractually Interruptible (Curtailable) 442Critical Peak-Pricing with Control 9Load as a Capacity Resource 160





Nuclear2%

Hydro6%

Coal38%

Gas43%

Dual Fuel7%

Other2%Oil2%

Nuclear2%

Hydro6%

Coal38%

Gas43%

Dual Fuel7%

Other2%Oil2%



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In anticipation of a surge in renewable resources on the western part of its grid, the SPP RTO published the SPP Wind Integration Task Force (WITF) Study in early 2010. This study reinforced the criticality of coordinating transmission expansion plans with plans for building infrastructure to accommodate wind energy. Study recommendations will allow SPP to prepare for continued growth in the Region’s renewable wind resources. The study recommended significant bulk EHV transmission additions (e.g., 230 kV, 345 kV and/or 765 kV) for 20 percent wind scenario. If the needed transmission upgrades were completed, there would be no significant technical barriers or reliability impacts to integrating wind energy levels up to 20 percent. For the near term, the study identified the need to develop a sophisticated process for determining what generating units are utilized throughout the Region, explicitly addressing the uncertainty associated with wind forecast errors. The implementation of a centralized wind energy forecasting system was also recommended. Demand The projected non-coincident Total Internal Demand forecast for the 2010 summer peak is 43,426 MW, which is five percent higher than the 2009 actual summer peak non-coincident Total Internal Demand. The actual 2009 summer demand of 41,209 MW was seven percent lower than the forecasted projection of 44,342 MW. In 2009, the SPP RE experienced a slight decrease in demand from the normal forecast due to mild temperatures in the summer and the economic downturn. Since the SPP RTO footprint was not significantly impacted by the recent economic downturn, the lower demand was a result mainly of wet and mild 2009 summer conditions. The 2010 summer forecast is based on 2009 actual demand adjusted for normal weather. Forecast data is collected from each reporting member61 as monthly non-coincident values, then summed to produce the total forecast for the SPP RE footprint. The summer peak is the system condition upon which the SPP RE Region bases its resource evaluations. The SPP RE’s reporting members review and adjust their forecasts based on the actual demand for the previous year. Although actual demand is very dependent on weather conditions and typically includes interruptible loads, forecasted Net Internal Demands are based on ten-year average summer weather, or 50/50 weather. Some SPP RE members determine peak forecast based on a 50-percent confidence level as approved by their respective state commission(s). This means that the actual weather on the peak summer day is projected to have a 50-percent likelihood of being hotter and a 50-percent likelihood of being cooler than the weather assumed in deriving the load forecast. The SPP RTO does not develop load forecasts based on 90/10 weather scenario, but has a 13.6 percent reserve margin requirement to address this. The SPP RTO’s bandwidth working group performed a study62 that included the 2010 summer timeframe and determined the 13.6 percent reserve margin is adequate to cover any extreme load forecast for the SPP RE footprint. SPP RE-reporting members provide data from their Demand Response programs and subtract those values from their load forecasts to report net load forecast. Based on these inputs, the SPP RE footprint currently reports 442 MW of interruptible demand, 15 MW of load management, nine MW of critical peak pricing and 160 MW of load as a capacity resource. The SPP RE does

61 Currently, SPP reporting members consist of mainly Balancing Areas and some Load Serving Entities. 62 http://www.spp.org/section.asp?group=320&pageID=27




not have a way to measure or verify Demand Response programs due to their minimal amount of MW. The percentage of the Demand Response programs (which are voluntary by individual member companies) that can reduce peak demand against the Total Internal Demand is 1.6 percent. At this time, SPP RTO does not have a system-wide Demand Response program. Generation The SPP RE expects to have 55,292 MW of total internal capacity for 2010 summer. This consists of Existing-Certain Capacity of 49,777 MW; Existing-Other Capacity of 5,092 MW; Existing-Inoperable Capacity of 517 MW; and Future-Planned Capacity of 266 MW. The projected on-peak capacity reported from variable generation plants (mostly wind) is 52 MW of the 3,485 MW connected to the SPP RTO footprint. SPP has developed detailed criteria to establish the net capability rating of the wind generation based on a five-year history of peak load data. The reported biomass portion is two MW and consists of landfill gas. The SPP Region’s hydro capacity represents a small fraction of the total resources (approximately one percent). SPP monitors potential fuel supply limitations for hydro and gas resources by consulting with its generation owning/controlling members at the beginning of each year. Hydro capacity is only a small fraction of the SPP RE’s resources; reservoir levels do not materially impact the SPP RE’s reserve margins. There are no anticipated issues concerning sufficient reservoir levels that would impact meeting the peak and daily energy demands during the 2010 summer season. The SPP RE Region is experiencing above-average rainfall and is not anticipating drought conditions for the summer season. The SPP RE Region is not experiencing any other conditions that would reduce capacity within the Region. No significant generating units are anticipated to be out of service or retired prior to summer. Capacity Transactions on Peak SPP RE has 4,742 MW of projected purchases within and external to the SPP RE Region; 4,266 MW is backed by firm contracts, and 425 MW is backed by projected or non-firm contracts. Approximately 133 MW are firm contract from WECC, administered under Xcel Energy’s OATT. None of the purchase contracts are a Liquidated Damages Contract. All firm power contracts are backed by transmission and generation. The SPP RE has 3,041 MW backed by firm sales for the 2010 summer within and external to the SPP RE Region. None of the sales contracts are a Liquidated Damages Contract. All firm power contracts are backed by transmission and generation. SPP RTO members, along with some members of 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. However, the group does not require support from generation resources outside the SPP RTO Region. The SPP’s Operating Reliability Working Group (ORWG) sets the Minimum Daily Contingency Reserve Requirement for the SPP Reserve Sharing Group. The SPP Reserve Sharing Group maintains a minimum first Contingency Reserve equal to the generating capacity of the largest unit scheduled to be on line.



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Transmission The SPP RTO has two projects that are either under construction or are scheduled to be in service before the current assessment timeframe is over. These projects include a 120-mile. 345 kV line from Northwest to Woodward District EHV in northern Oklahoma. There are also several new transformers scheduled to go in service. The details of these projects are in the table below.

Table SPP-1: Transmission Projects

Transmission Project Name Voltage

(kV) Length (miles)

In-Service Date

Description/ Status

Northwest to Woodward District EHV

345 120 03/30/10 New 345 kV line

Table SPP-2: Transformer Projects


(kV) In-Service

Date Description / Status

New (2nd) Stranger Creek 345/115 09/15/09 Complete—new transformer

Reno County (2nd) 345/115 09/21/09 Complete—new transformer

Hitchland 345/230 06/01/10 New transformer

Yoakum County Interchange (2nd) 230/115 10/16/09 Complete—new transformer

Seminole (upgrade) 230/115 11/20/09 Complete—upgrade two transformers

The two projects (the 345 kV line and the Hichland Transformer) listed above are projected to be in service as planned. If there are any delays, the SPP Reliability Coordinator will coordinate with transmission owners to ensure a mitigation plan is in place to address any reliability issues. The SPP RTO is not aware of transmission constraints that have not been addressed by mitigation plans or with local operating guides for 2010 summer. However, SPP will continue to monitor the western part of the grid as described in the previous year’s assessment reports, as this area has experienced some reliability issues and challenges in the recent past. No known significant transmission facilities are scheduled to be out of service during the summer. SPP RTO staff participates in the Eastern Interconnection Reliability Assessment Group’s inter-Regional study effort. This study is conducted to examine the potential constraints on the SPP RTO Region as a result of simulated import and export with neighboring regions. The preliminary results of the study indicate that the SPP imports are limited due to the 161 kV facilities across the Arkansas-Oklahoma border. This has been a known issue for the last several years, and the SPP RTO is working with SERC members on mitigating this in the near future. In the meantime, the SPP RTO does not expect any reliability issues for 2010 summer as it does not




rely on the incremental transfer capability from neighboring regions to meet the projected demand. There is a new 345/161 kV sub projected to be built at Iatan near Kansas City, Missouri, during the first quarter of 2010. Operational Issues There are no known unusual operating conditions projected to impact the reliability of the Region for the 2010 summer assessment timeframe. The SPP RTO completed the Wind Integration Task Force Study63 in January 2010, indicating that the SPP RTO would need significant transmission addition to accommodate 10 percent or higher wind capacity. The SPP RE projects to have approximately four percent of installed wind capacity on the grid for 2010 summer; grid operators will continue to monitor any operating challenges for this assessment period. SPP RTO operations staff does not anticipate any environmental and/or regulatory restrictions that could potentially impact reliability. Flowgate assessment does not indicate any unusual operating conditions projected for the summer months. There are no known reliability concerns resulting from high levels of Demand Response resources, as Demand Response programs in the SPP RE Region are minimal at this time. No anticipated transmission and generation outages or temporary operating measures are anticipated for 2010 summer. No new coordinated smart grid programs have been fully implemented within the past year that will impact Regional reliability. Reliability Assessment An SPP RTO criterion requires that its members maintain a minimum capacity margin of 12 percent (13.6 percent Reserve Margin). SPP RTO members, by meeting this requirement, adequately cover a 90/10 weather scenario. The SPP reserve margin based on Certain resources is projected to be 19.2 percent for 2010 summer, which is higher than the 2009 summer reserve margin of 13.1 percent. The 19.2 percent reserve margin is based on projected data for August 2010 with Existing-Certain and net firm transactions. On an anticipated capacity resource basis, SPP has sustained around a 20.4 percent reserve margin. The reserve margin with prospective capacity resources for the same month is 31.5 percent. The SPP RTO is currently performing a Loss-of-Load Expectation (LOLE) and Expected Unserved Energy study for the 2016 time period. Results of these studies are projected during 2010 summer. The studies will evaluate the need to adjust SPP’s 12 percent Regional capacity margin or 13.6 reserve margin. The study estimates the reserve margin required to achieve an LOLE of no more than one occurrence in ten years. Based on the LOLE study performed by SPP RTO staff in 2009 for 2010 summer, the capacity or reserve margin requirement for the SPP RTO remained unchanged. Additionally, the 12 percent capacity margin and 13.6 reserve margin requirements are checked annually in the EIA-411 reporting, as well as through supply adequacy audits of regional members conducted every five years by the SPP RTO. The last supply adequacy audit was conducted in 2007.

63 Wind Integration final study: http://www.spp.org/section.asp?group=1385&pageID=27



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Due to SPP’s diverse generation portfolio, there is no concern of the fuel supply being affected by the extremes of summer weather during peak conditions. If a fuel shortage is anticipated, it is communicated to SPP operations staff in advance so 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 an EEA (Energy Emergency Alert) or OEC (Other Extreme Contingency) and post as needed on the RCIS (Reliability Coordinator Information System). SPP does not expect any immediate impact on the reliability of the Region due to the current economic conditions. The SPP RTO conducted a 2009 SPP Stability Study for the 2010 seasonal light load model, and believes the 2010 light load model represents the worst-case scenario from a stability perspective. This assessment provides findings on potential events that could lead to instability within the SPP RTO footprint for NERC defined categories (A, B, C, and D) of events submitted by SPP RTO members. One category B, two category C, and three category D events are required to have mitigations plans before they are found to be stable. The SPP RTO also conducted a transient stability screening of the SPP RTO footprint on the previously mentioned case. These events were mitigated by applying the proper fault clearing times and/or system generation re-dispatch to maintain system stability. The SPP RTO conducted Power-Voltage (P-V) assessment study for the nine potential load pockets within the SPP RTO footprint based on a 2014 summer peak load condition. SPP staff will coordinate any potential reactive reserve issues and associated mitigation plans during its annual reliability assessment effort. The SPP’s Independent Coordinator of Transmission’s Reliability Coordinator will continue to monitor the Acadiana area load pocket in southwest Louisiana since this area has experienced some reliability issues in the recent past. Other Region-Specific Issues There are no known other reliability issues at this time in the SPP Region.




Region Description The Southwest Power Pool, Inc. Regional Transmission Organization (SPP RTO) Region covers a geographic area of 370,000 square miles and has members in nine64 states: Arkansas, Kansas, Louisiana, Missouri, Mississippi, Nebraska, New Mexico, Oklahoma, and Texas. SPP’s footprint includes 29 balancing authorities and more than 50,000 miles of transmission lines. SPP typically experiences peak demand in the summer months. SPP has 57 members that serve more than five million customers. SPP’s membership consists of 14 investor-owned utilities, 11 generation and transmission cooperatives, ten power marketers, nine municipal systems, six independent power producers, four state authorities, and three independent transmission companies. SPP was a founding member of the North American Electric Reliability Corporation in 1968, and was designated by the Federal Energy Regulatory Commission as an RTO in 2004 and a Regional Entity (RE) in 2007. As an RTO, SPP ensures reliable supplies of power, adequate transmission infrastructure, and competitive wholesale prices of electricity. The SPP RE oversees compliance enforcement and reliability standards development. Additional information can be found at www.SPP.org.

64 The SPP RE footprint does not include Nebraska.



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MMIISSOO

Introduction The Midwest ISO estimates the coincident Net Internal Demand to peak at 104,288 MW over the entire Midwest ISO Market Area during the month of July in the 2010 summer season. As a result of the Iowa integration on September 1, 2009, and Dairyland on June 1, 2010, Iowa members added five percent and Dairyland contributed 0.9 percent for a combined 5.9 percent increase in the coincident Net Internal Demand. Without these new member integrations, the coincident Net Internal Demand would have decreased by 1.7 percent, primarily due to the current economic downturn. The overall result is a 4.2 percent increase in coincident Net Internal Demand compared to the 2009 summer season. The Midwest ISO forecasts the total designated capacity to be 131,284 MW for the 2010 summer season, an 11.2 percent increase compared to the prior summer season. Although this increase was also driven by the Iowa and Dairyland integrations, in contrast to demand, the total designated capacity would have increased by six percent regardless of the new member integrations. This increase is due to a combination of new resources added and more commitments. The Iowa integration added 4.4 percent and Dairyland contributed 0.8 percent for a combined 5.2 percent increase to the 2010 total designated capacity. The 2010 summer’s projected reserve margin of 25.9 percent exceeds both the 15.4 percent Midwest ISO system planning reserve margin for 2010 and the 18 percent reserve margin forecast in 2009. In light of a strong reserve margin forecast, firm load curtailment is a very low probability event for the 2010 summer period. Nameplate capacity refers to the maximum output of units in the commercial model. Since the 2009 summer season, 10,370 MW of nameplate capacity has been added to the Midwest ISO market where 61 percent is attributed to coal, 19 percent comes from wind, and 14 percent represents oil/gas units. With respect to future capacity additions, the Taum Sauk pumped storage plant, which encountered a catastrophic failure on December 14, 2005, has undergone reconstruction, replacing the upper reservoir dam. The construction is projected to be completed by May 2010 and the two generators are each are capable of producing approximately 225 MW. New 345 kV transmission lines are projected to be in service within the Midwest ISO before the 2010 summer season. Transmission lines spanning 54.6 miles will be added to the American Transmission Co. (ATC LLC) area. Four new bulk power transformers are also projected to be in service before the 2010 summer season. These will be in areas of American Transmission Co., Northern States Power Co., Great River Energy, and Duke Energy Midwest. There are no significant transmission additions projected to be placed in service during the 2010 summer season and there have been no transmission reliability concerns identified in the coordinated seasonal assessment currently in progress.




With respect to Operations, there are no foreseeable challenges facing the operation of the bulk power systems within the Midwest ISO footprint. The Midwest ISO Summer Resource Assessment was performed for the 2010 summer season65 Demand The unrestricted non-coincident demand projected for the 2010 summer of 112,701 MW is the sum of individual coincident forecasts from the Load Serving Entities (LSE) in the Midwest ISO. The Regional breakout of the unrestricted non-coincident peak data is 62,519 MW in RFC 31, 277 MW in MRO, and 18,905 MW in SERC. Taking a four-year average of the estimated diversities reported from the summer seasons in 2006–2009 and deducting this average from the unrestricted non-coincident demand establishes the Total Internal Demand of 107,629 MW. The 5,072 MW difference between unrestricted non-coincident demand and Total Internal Demand reflects the prior four-year average of estimated diversities and amounts to 5,072 MW. The Demand Response forecast estimates 467 MW of Direct Controlled Load Management (DCLM) and 2,874 MW of interruptible load. Interruptible load is the magnitude of customer demand (usually industrial) that, in accordance with contractual arrangements, can be interrupted at the time of peak by direct control of the system operator (remote tripping) or by action of the customer at the direct request of the system operator. DCLM is the magnitude of customer service (usually residential) that can be interrupted at the time of peak by direct control of the applicable system operator. DCLM is typically used for “peak shaving.” The Midwest ISO does not currently track energy efficiency programs; however, they may be reflected in individual LSE load forecasts. Taking the Total Internal Demand less DCLM and interruptible load arrives at the coincident Net Internal Demand of 104,288 MW. The 2010 summer coincident Net Internal Demand peak has increased by 4.2 percent above the prior summer season’s actual peak demand primarily because of the new member integrations, which is in the MRO area. The Midwest ISO market participants developed their demand forecasts individually and at different times, hence, weather and economic assumptions are encompassed within the data each market participant submitted to the Midwest ISO. Generation The entire MISO RTO has 121,644 MW of internal designated capacity resources, 4,042 MW of Behind-the-Meter Generation (BTMG), and 49 MW of Demand Response Resources for a total of 125,735 MW identified as “Existing, Certain” for the 2010 summer season. The regional breakout of the internal designated capacity is 68,750 MW in RFC, 31,448 MW in MRO and 21,446 MW in SERC. Although the nameplate for wind is 7,644 MW, only 197 MW is designated by the market participants which is 2.5 percent of the maximum 8 percent capacity credit that could be used on peak. The market participants also designate capacity in a category classified as “Waste” and “Other” which together represent a nameplate of 390 MW and a

65 http://www.midwestmarket.org/publish/Document/ff6bb_1280201754d_-7db20a48324a.



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designated value of 224 MW. Biomass capacity is included in this category, but is not specifically identified. There are no significant generating units projected out-of-service or retired, and there are no foreseeable issues with weather, hydro conditions, or fuel-related conditions for the summer period. Capacity Transactions on Peak Midwest ISO only reports power imports to the Midwest ISO market or reported interchange transactions into the Midwest ISO market. The forecast reflects 5,549 MW of power imports. All these imports are firm and fully backed by firm transmission and firm generation. No imports are based on partial path reservations. There are no transactions with Liquidated Damages Contract (LDC) clauses or “make-whole” contracts that are included as firm capacity. Transmission The Morgan-Highway 22 transmission project, spanning 28 miles of 345 kV lines, was placed in service in October 2009 and has alleviated common constraints in the northern Wisconsin area. The Paddock-Rockdale transmission project, also in Wisconsin, added 35 miles of new 345 kV transmission. Of the new bulk power transformers, ATC LLC and Northern States Power Co. transformers have been in service since September and December 2009, respectively. The Great River Energy and Duke Energy Midwest transformers are currently under construction and are projected to be in service in March and June 2010, respectively. With respect to bulk power transformer upgrades, there were two upgrades performed on Ameren and Montana-Dakota Utilities Co. transformers and both were placed in service in December 2009. A 345/138 kV transformer within RFC is projected to be installed in May 2010 to mitigate any reliability impacts during system peak conditions. However, other Midwest ISO analyses have shown that there are no other reliability impacts that need such mitigation measures. Operational Issues Midwest ISO has calculated 1,824 MW of planned outages after applying an outage rate to account for the number of hours each unit is out within the summer season. After considering these outages, Midwest ISO does not anticipate any unusual operating conditions requiring high levels of Demand Response sources that could significantly impact reliability for the upcoming summer. Further, Midwest ISO finds no environmental or regulatory restrictions that could impact reliability. There are no significant operating studies for 2010 conducted by the Midwest ISO to identify unique operational problems with respect to extreme weather conditions, droughts, etc. In addition, currently no special operating procedures have been identified resulting from the integration of variable resources.




There are no smart grid programs to mention that have been fully implemented in the past year that may significantly influence reliability. However, Midwest ISO became the first Regional transmission organization (RTO) to enter into an agreement with the Unites States Department of Energy to implement more than 150 phasor measurement units (PMUs), also known as synchrophasors. PMUs are an integral element in modernizing the grid. The high-tech devices will monitor the state of the electrical grid 30 times per second, instead of the current once every four seconds, increasing the efficiency and reliability of power delivery. The data is then GPS time-stamped. This allows the data to be “synchronized,” which enables enhanced grid visualization, operational awareness, stability monitoring, state estimation, and after-the-fact assessment. Reliability Assessment The goal of a Loss of Load Expectation (LOLE) study is to determine a level of reserves that would result in the Midwest ISO system experiencing one loss of load event every ten years. As modeled within the GE MARS software, the system would achieve this reliability level when the amount of installed capacity available is 1.154 times that of the Midwest ISO system coincident peak. Under the current Resource Adequacy section of Midwest ISO’s Energy Markets Tariff (Module E), the reserve margin requirement calculated for the Midwest ISO is 15.4 percent of the Net Internal Demand of its market area. In addition to the 121,644 MW of internal designated capacity resources, there are 4,042 MW of Behind-the-Meter Generation (BTMG), 49 MW of Demand Response Resources (DRR), and 5,549 MW of external resources that are available to serve load during peak conditions. This additional capacity arrives at the total designated capacity of 131,284 MW and brings the projected reserve margin for Midwest ISO to 26,996 MW, which is 25.9 percent of the Net Internal Demand. Exports are not taken into account within this reserve margin; however, it is assumed that due to the diversity between the Midwest ISO and surrounding systems, any external commitments would be served during extreme peaks. Therefore, the reserves are adequate within the Midwest ISO since the available reserves are greater than the reserve requirement. For inclusion in seasonal assessments, the Midwest ISO utilizes Energy Information Administration fuel forecasts to identify any system-wide fuel shortages; there are none projected for the 2010 summer period. In addition to the seasonal assessments, the Midwest ISO’s Independent Market Monitor submits a monthly report to the Midwest ISO’s Board of Directors that covers fuel availability and security issues. During the operating horizon, the Midwest ISO relies on market participation to anticipate reliability concerns related to the fuel supply or fuel delivery. Since there are no requirements to verify the operability of backup fuel systems or inventories, supply adequacy and potential problems must be communicated appropriately by the market participants to enable adequate response time. Other Region-Specific Issues The Midwest ISO has no additional reliability concerns for this summer season.



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RTO Description The Midwest ISO has four Balancing Authorities in the Region including the Midwest ISO Balancing authority and experiences its annual peak during the summer season. Midwest ISO’s scope of operations covers 750,000 square miles, which includes 13 states and one Canadian province. Midwest ISO’s Midwest Energy and Operating Reserves market includes 300 market participants, which serve more than 40 million people.




PPJJMM Introduction The projection for the 2010 PJM RTO summer peak is 135,750 MW, an increase of 1,970 MW, or 1.5 percent, from the 2009 weather normalized peak. The new 2010 forecast is 0.2 percent less than the 2010 forecast projected in 2009 and is about one percent higher than the 2009 forecast. The total PJM generation resources projected to be in service during the 2010 summer peak period are approximately 167,000 MW, an increase of approximately 1,500 MW over last summer. No planned resources will be added during the summer. Significant additions since last year include Dresden at 580 MW, Potomac River at 297 MW, and Kearney 13 at 132 MW. The PJM projected reserve margin for 2010 summer is 26.7 percent. This level is well in excess of the PJM required reserve margin of 15.5 percent. Upgrades in the Duquesne and Waugh Chapel areas are projected to be complete by 2010 summer. The Kammer 765/500 kV transformer has been on line since October 2009. The Linden Variable Frequency Transformer has been on line since fall 2009. There are no reliability concerns in meeting target in-service dates for new transmission additions and their impacts. No operational challenges are projected nor have any special assessments been performed for the summer season. Demand The PJM RTO 2009 summer peak was 126,805 MW. On a weather-normalized basis, the PJM RTO 2009 summer peak was 133,780 MW. The projection for the 2010 PJM RTO summer peak is 135,750 MW, an increase of 1,970 MW, or 1.5 percent, from the 2009 weather normalized peak. The new 2010 forecast is within 0.2 percent of the 2010 forecast projected in 2009. The PJM load forecast did not use a specific weather assumption, but applied a Monte Carlo simulation using 35 years of historical weather from 1974 to 2008. The economic variable used in the PJM load forecast is Real Gross Metropolitan Product (GMP) for major metropolitan areas within the RTO. The current forecast uses the November 2009 economic forecast release from Moody’s Economy.com. The 2010 forecast uses economic growth assumptions that expect an economic rebound, which started late in 2009, to accelerate in 2010. PJM forecasts the load of the entire RTO and the individual transmission zones on a coincident basis. Since PJM is summer-peaking, the coincident 50/50 summer peaks are used in resource adequacy evaluations, but extreme peak forecasts (90/10) are also published and used in reliability assessment. For the 2010/2011 delivery year PJM has contractually interruptible Demand-Side Management of 3,923 MW. Since the PJM market for Demand-Side Management will close on June 15, 2010, which is after the publication date for this report, PJM has forecasted the amount of Demand-Side Management for the summer. The forecast is pessimistic and the amount of Demand-Side Management will likely be greater, which will subsequently increase the amount of the PJM Reserve Margin. This 3,923 MW of Demand-Side Management is 2.9 percent of PJM’s projected peak demand. Participants submit load data from the Electric Distribution Company meters used for retail service or from meters meeting PJM’s standards (Manual 11, Section 10.6). Participants may be audited. No energy efficiency programs are included in the 2010 load forecast.



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Generation The total PJM generation resources projected to be in service during the 2010 summer peak period are approximately 167,000 MW. Variable generation amounts to 3,580 MW nameplate and 465 MW projected on-peak. Variable resources are only counted partially for PJM resource adequacy studies. Both wind and solar initially utilize class average capacity factors as the on-peak capacity credit, which are 13 percent for wind and 38 percent for solar. Performance over the peak period is tracked and the class average capacity factor is supplanted with historic information. After three years of operation, only historic performance over the peak period is used to determine the individual unit’s capacity credit. Over 900 MW of biomass capacity exists in PJM and no additional capacity is planned before this summer. PJM has very little hydro generation, and reservoir levels are adequate. PJM expects no problems with warm cooling water. There are no anticipated fuel delivery problems during the summer. No significant generation is projected to be out of service over the summer peak period. Capacity Transactions on Peak Firm Imports with signed contracts amount to 3,229 MW. No Expected or projected imports are considered in this summer’s reliability assessment. All transactions are firm for both generation and transmission. No imports are based on partial path reservations. There are no transactions with Liquidated Damages Contract (LDC) clauses or “make-whole” contracts that are included as firm PJM capacity. Firm Exports with signed contracts amount to 2,806 MW. No Expected or projected exports are considered in this summer’s reliability assessment. All export transactions are firm for both generation and transmission. No exports are based on partial path reservations. There are no transactions with LDC clauses or make-whole contracts. Transmission Upgrades in the Duquesne and Waugh Chapel areas are projected to be complete by 2010 summer. Kammer 765/500 transformer has been on line since October 2009. Linden Variable Frequency Transformer has been on line since fall 2009. There no reliability concerns in meeting target in-service dates for new transmission additions and their impacts. There is currently a two-week outage request for Conemaugh-Hunterstown 500 kV line in August. PJM Operations Planning will study this outage and determine if there is a better window to take this outage depending on weather and other factors if necessary. No significant transmission constraints are anticipated. There are no significant changes from last year’s assessment. RFC and SERC inter-Regional studies are ongoing under the Easter Interconnection Reliability Assessment Group, but no results are available yet. These studies monitor transmission and generation constraints in all the regions under study. The 2009 inter-Regional study results are presented below. 2010 results are projected to be similar.




The Linden Variable Frequency Transformer has gone into operation since last summer. Operational Issues The PJM Operations Analysis Task Force (OATF) summer assessment is being performed with results projected in April. No problems are anticipated. No special operating procedures should be required for reliable operation this summer. PJM has developed a Wind Power Forecast tool and visualization to assist operations. Demand Response resources will assist in maintaining reliable system operations. No negative consequences are projected. PJM requires Generation Owners to place resources into the “Maximum Emergency Category“ if environmental restrictions limit run hours below pre-determined levels. There are no significant environmental restrictions projected to affect reliability this summer. Max Emergency units are the last to be dispatched. There are no new smart grid programs in the PJM RTO. No other anticipated unusual operating conditions are projected to significantly impact reliability for the upcoming summer. Reliability Assessment The PJM projected reserve margin for 2010 summer is 26.7 percent. This level is well in excess of the required reserve margin of 15.5 percent.66 PJM has adopted a Loss of Load Expectation (LOLE) standard of one occurrence in ten years. PJM performs an annual LOLE study to determine the reserve margin required to satisfy this criterion. The study recognizes, among other factors, load forecast uncertainty due to economics and weather, generator unavailability, deliverability of resources to load, and the benefit of interconnection with neighboring systems. The methods and modeling assumptions used in this study are available in PJM Manual 20.67 The latest resource adequacy study was completed in November, 2009. This study examined the period 2009–2019.68 The required reserve margins to satisfy an LOLE of one day in ten years are summarized in Table I-2 on page 6 of that report. The reserve requirement for 2010 summer is 15.5 percent. Based on study results, this margin will satisfy an LOLE standard of 0.1 per year.

66Reserve margin information is available at the following link: http://www.pjm.com/planning/resource-adequacy-

planning/~/media/planning/res-adeq/res-reports/20100120-forecasted-reserve-margin.ashx. 67 http://www.pjm.com/documents/~/media/documents/manuals/m20.ashx. 68 The study report is available at the following link: http://www.pjm.com/planning/resource-adequacy-

planning/~/media/documents/reports/2009-pjm-reserve-requirement-study.ashx.

Table PJM-1: 2009 PJM Interregional Transfer Capabilities—Non-Simultaneous First Contingency Total Transfer Capability

Transfer Limit PJM to NPCC 1,350

NPCC to PJM 5,072

PJM to RFC-MISO 7,000

RFC-MISO to PJM 2,400

PJM to SERC East 5,250

SERC East to PJM 3,600



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Reserve margins have significantly increased due to lower load forecasts, increased Demand-Side Management and increases in generation. The projected 2009 reserve margin was 21.6 percent; the projected 2010 reserve margin is 26.7 percent. PJM has established rules and procedures to ensure fuel is conserved to maintain an adequate level of on-site fuel supplies under forecasted peak load conditions. PJM coordinates with neighboring entities and gas pipelines to quickly address fuel issues. PJM has developed Reactive Transfer Interfaces to ensure sufficient dynamic reactive reserves. PJM’s day-ahead and real-time Security Analysis ensures sufficient generation is scheduled to control pre- and post-contingency voltages and voltage drop within acceptable, predetermined limits, as outlined in M-3, section 3.69 Other Region-Specific Issues There are no reliability concerns for the 2010 summer season. RTO Description

569 members 168,500 square miles of service territory 1,271 generation resources with diverse fuels Single Balancing Authority Summer peaking In two NERC Regional Entity Organizations (RFC and SERC) 51 million people served Covering Washington, D.C. and 13 states (Delaware, Illinois, Indiana, Kentucky,

Maryland, Michigan, North Carolina, New Jersey, Ohio, Pennsylvania, Tennessee, Virginia, and West Virginia)

69 http://www.pjm.com/~/media/documents/manuals/m03.ashx




NNPPCCCC

Introduction The five NPCC Areas, or subregions, are defined by the following footprints:

the 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).

The following Table, NPCC-1, provides 2010 summer projections of NPCC Area demands and reserve margins, and 2009 summer projections of demands and reserve margins and actual demands. The Maritimes Area and the Québec Area are winter-peaking systems; Ontario, New York and New England are summer-peaking systems. Peak demands last summer were lower than forecast in four of the NPCC Areas due to milder weather than forecast and economic activity slowdowns. Demand forecasts for 2010 summer are all lower than last summer’s forecasts, mainly due to economic activity slowdowns.


Direct Control Load Management 0Contractually Interruptible (Curtailable) 364Critical Peak-Pricing with Control 0Load as a Capacity Resource* 2,251





*Note: NPCC has classified an additional 2,803 MW of Demand Response as a supply resource which does not reduce Total Internal Demand.

**Refer to the NPCC LOLE criterion imposed on each subregion as presented in the NPCC Resource Adequacy Assessment Section

Hydro34%

Coal8%

Nuclear14%

Gas14% Dual

Fuel17%

Other6%

Oil8%

Hydro34%

Coal8%

Nuclear14%

Gas14% Dual

Fuel17%

Other6%

Oil8%



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When compared with projections for the 2009 summer in the following table, the New England and Québec reserve margins are very similar to 2009, the New York and Maritimes reserve margins are lower, and the Ontario margin is higher. The Maritimes Area reserve margin is lower due to the outage of the Point Lepreau nuclear unit, however, the Maritimes reserve margin is still well above 50 percent.

Table NPCC-1: Demands and Reserve Margins

NPCC Balancing Authority

Area

2010 Summer Forecasted

Peak (MW)

2010 Summer Forecasted

Reserve Margin

(%)

2009 Summer

Forecasted Reserve Margin

(%)

2009 Summer

Forecasted Peak

(MW)

2009 Summer Actual Peak

(MW) Maritimes 3,610 55.0 73.6 3,529 3,440New England 27,190 19.6 20.1 27,875 25,100New York 33,025 15.1 30.4 33,452 30,844Ontario 23,556 26.4 12.6 24,998 24,380Québec 20,677 44.6 46.6 20,998

21,141

Table NPCC 2, shown below, indicates the Existing-Certain and projected resources in the NPCC subregions for the 2010 summer months.

Table NPCC-2: Existing-Certain and Projected Resources (MW)

NPCC Balancing

Authority Area June July August September Maritimes 5,497 5,621 5,617 5,216New England 34,056 34,056 34,056 34,056New York 37,736 37,736 38,371 31,548Ontario 28,234 29,770 29,952 28,561Québec 32,158 33,864 30,756 32,195

The notable capacity resource additions and retirements are indicated below. In New England, 225 MW of new supply-side capacity resources are projected to commercialize prior to the summer season, and there are no projections for capacity attrition. Since the summer of 2009, 1,163 MW of additional resources have been added to the New York system. There has been approximately 471 MW of new wind generation added since last summer. The Gilboa 4 up-rate is 30 MW. The Empire Project, which consists of 635 MW of additional generation, is projected in-service this summer. There is also an additional 27.2 MW of generation from the River Bay and Fulton Co. Projects.




There were three retirements in New York during the winter of 2009–2010 that will impact 2010 summer generation: Poletti 1 with 890 MW of generation (retired January 31, 2010), Greenidge 3 with 55 MW, and Westover 7 with 40.1 MW (both retired December 31, 2009) for a total of 985.1 MW of retirements. In Ontario before June 2010, a new hydroelectric generator (16 MW) will be added to Healy Falls station. During the summer months, Thorold Cogeneration (236 MW) is planned to come into service, and an additional 46 MW of demand measures will be added. Through numerous studies and reviews, the NPCC Task Force on Coordination of Planning (TFCP) ensures that the proposed resources of each NPCC Area will comply with NPCC Directory #1, “Design and Operation of the Bulk Power System”.70 This defines the criterion for resource adequacy for each NPCC subregion as follows: Resource Adequacy — Design Criteria The probability (or risk) of disconnecting firm load due to resource deficiencies shall be, on average, not more than one day in ten years as determined by studies conducted for each Resource Planning and Planning Coordinator Area. 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 de-ratings, forced outages and de-ratings, assistance over interconnections with neighboring Planning Coordinator Areas, transmission transfer capabilities, and capacity and/or load relief from available operating procedures. The Northeast Power Coordinating Council has in place a comprehensive resource assessment program directed through NPCC Directory #1, Appendix D.71 This charges the TFCP to assess periodic reviews of resource adequacy for the five NPCC Areas (subregions). 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. Directory #1, Appendix B 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 de-ratings and

forced outages;

70 (http://www.npcc.org/documents/regStandards/Criteria.aspx) 71 http://www.npcc.org/documents/regStandards/Directories.aspx



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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 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, which 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 that 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 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 adequacy 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. Transmission Significant transmission additions are noted below:

In New England there is only one new significant transmission facility anticipated to be placed in service during the 2010 summer period: one 345 kV 160 Mvar variable shunt reactor at West Walpole, Maine, used to control high voltage during light demand periods.

In New York the Ithaca Transmission Project has an in-service date of 6/15/2010. This project includes: 1) a new Clarks Corners substation, which will consist of two 345/115 kV LTC transformers, 2) the 14.8-mile existing 115 kV Line #947 rebuild, 3) a new 15-mile 115 kV line from Etna substation to the new Clarks Corners substation, and 4) installation of new 50 Mvar capacitor banks at the State Street substation, Wright Avenue, and the new Clarks Corners substations. The additions are scheduled to go into service during 2010 summer.




In northern New York, the Duley and Ryan 230 kV stations were added during the summer of 2009 to the Willis-Plattsburgh WP1 and WP2 lines, respectively. Ryan and Duley 230 kV stations serve to connect the following wind plants: Clinton, Ellenburg, Altona, and Chateauguay. High Sheldon, Wethersfield, and Canandaigua 230 kV stations were added during the summer of 2009 to the Stolle-Meyer-Hillside 230 kV path on the Southern Tier to connect the following wind plants: High Sheldon, Wethersfield, and Canandaigua. The Millwood 345 kV 240 Mvar capacitor bank was added during the summer of 2009 for added voltage support in the lower Hudson Valley. The Watercure 345/230 kV transformer bank remains out of service with a possible in-service date of fall 2011. The BP76 Beck2-Packard 230 kV tie with Ontario will remain out of service this summer.

In Ontario, a 200 Mvar shunt capacitor is anticipated to be placed in service at the 230 kV Buchanan Transmission Station (TS), and a new 230 kV Hurontario switching station is scheduled to be completed before the 2010 summer.

The forced outage in 2008 of the 230 kV circuit BP76 on the Ontario-New York interconnection at Niagara reduces the total Ontario-New York import and export capability until its scheduled return to service in the last quarter of 2012.

Since 2009 summer in Ontario several shunt capacitor additions were made including: 1) four 230 Mvar shunt capacitor banks at the Middleport 230 kV Transmission Station; 2) one 230 Mvar shunt capacitor bank at the Buchanan 230 kV Transmission Station and 3) two 250 Mvar shunt capacitor banks at the Nanticoke 230 kV Transmission Station.

In Québec during summer and autumn 2009, TransÉnergie commissioned the first and second 625 MW HVdc converters of the new Outaouais interconnection with the IESO. However, the full 1,250 MW interconnection capability was not available full time due to Regional system limitations. In June 2010 a new double-circuit 315 kV line from Chénier (North of Montréal) to Outaouais will be placed in service along with a fourth 735/315 kV, 1,650 MVA transformer and a third 315 kV, 345 Mvar capacitor bank at Chénier, which will held to more fully utilize the capacity of the HVdc interconnection

Table NPCC-3: Transmission Additions for 2010 Summer

NPCC Area Transmission Project Voltage In Service Maritimes No significant additions. New England West Walpole 160 Mvar variable shunt reactor 345 kV 2010 summerNew York Ithaca Transmission Project: two 345/115 kV LTC

transformers, a 14.8 mile 115 kV Line #947 rebuild, a new 15-mile 115 kV line from Etna to the New Clarks Corners substation, and installation of new 50 Mvar capacitor banks at the State Street, Wright Avenue, and the new Clarks Corners Substations.

115 kV June 2010

Ontario Hurontario Substation 230 kV 2010 summerOntario Buchanan TS200 Mvar shunt reactor 230 kV 2010 summerQuébec New double-circuit 315 kV line from Chénier to

Outaouais, fourth Chenier 735/315 kV, 1,650 MVA transformer and a third Chenier 315 kV, 345 Mvar shunt capacitor

315 kV June 2010



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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 program directed through NPCC Directory #1, Appendix B.72 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 projected 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 assessment 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 assessment 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 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:

the steady state performance of the system; the dynamic performance of the system; the response of the system to selected extreme contingencies; and the 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 assessment required in the NPCC transmission review fully complies with, or exceeds, the obligations of the existing 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”

NPCC-specific criteria requires system operation and system design to the following contingencies, which exceed what is required in the TPL standards:

72 http://www.npcc.org/documents/regStandards/Guide.aspx




Simultaneous permanent phase-to-ground faults on different phases of each of two adjacent transmission circuits on a multiple circuit tower, with normal fault clearing.

A permanent phase-to-ground fault on any transmission circuit, transformer, or bus section with delayed fault clearing.

Operational Issues The following are highlights that should be noted with regard to operations within NPCC during 2010 summer:

There are reductions in the forecast peak demands in several NPCC subregions compared to 2009 summer due to various reasons, including conservation initiatives/energy efficiency, the on-going recession, time of use rates, and the growth of embedded generation. Phase angle regulators (PARs) are installed on the four Ontario-Michigan interconnections. One PAR, on the Keith to Waterman 230 kV circuit J5D, has been in service and regulating since 1975. The next two available PARs are located on Lambton to St. Clair 230 kV circuits L4D and L51D. These are currently bypassed; however, these PARs can be placed in service and operated to control flows during emergency conditions. The last PAR, on Scott to Bunce Creek 230 kV circuit B3N, is being replaced and it is projected to be available by the end of Quarter 2 in 2010. An agreement between the IESO, the Midwest ISO, Hydro One, and International Transmission Company is being negotiated for the operation of the PARs.

The Regional Greenhouse Gas Initiative (RGGI) became effective January 1, 2009. The program is an agreement among ten northeast states designed to reduce the emissions of carbon dioxide from power plants greater than 25 MW. The RGGI system is administered through the use of permits known as allowances. One allowance is required for each ton of CO2 that has been emitted by an affected facility. RGGI established an annual emissions cap for each of the member states that approximates recent emission patterns. The allowances are mostly distributed through a series of auctions. NPCC does not expect that the presence of RGGI would result in reliability impacts to the Region.

Ontario is expecting to experience surplus base load generation (SBG) under minimum demand conditions. Such SBG conditions are prevalent over the spring, summer, and fall months. Intermittent variable generators can be curtailed for reliability reasons. The IESO expects that any SBG conditions would be addressed through current processes.

IESO is expecting to start a centralized wind forecasting pilot in 2010, ultimately leading to a wind forecasting service to improve the accuracy of wind generation forecasts. This will assist with the management of wind variability and its influence on load-generation balance.

The Green Energy and Green Economy Act passed by the Ontario legislature in May 2009 enables the implementation of a smart grid and imposes a regulatory obligation on distributors and transmitters to provide smart grid plans to the regulator. The feed-in tariff (FIT) program for renewable generation has attracted more than 8,000 MW in new project applications, but most approved projects will not start to commission until at least 2011.

March of 2010, NPCC adopted a revision to the NPCC underfrequency load shedding program, modifying the frequency steps and amounts of load to be shed at each step. Implementation will take place over several years.



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Subregions Maritimes The New Brunswick System Operator (NBSO) is the Reliability Coordinator for the Maritime Area, which consists of four sub-regions. It should be noted that the Maritime Area is a winter-peaking system and as such does not expect to experience any reliability issues. The net monthly reserve margins for this summer operating period range from 55 percent to 73.6 percent. Demand The Maritime Area load is the mathematical sum of the forecasted weekly peak loads of the subareas (New Brunswick, Nova Scotia, Prince Edward Island, and the area served by the Northern Maine Independent System Operator). As such, it does not take the affect of load coincidence within the week into account. It should be noted that the Maritime Area is a winter-peaking system. Based on the Maritime Area 2010 demand forecast, a peak of 3,610 MW is predicted to occur for the summer period, June through September. The actual peak for 2009 summer was 3,440 MW on August 18, 2009, which was 89 MW (2.5 percent) lower than last year’s forecast of 3,529 MW. For the reporting period used for the NPCC CO-12 Reliability Assessment, May to September, the forecast peak is 3,898 MW. That peak is forecast to occur the week beginning May 2, 2010. The actual peak for May-September period for the summer of 2009 was 3,556 MW. For the New Brunswick System Operator (NBSO), the load forecast is based on an End-use Model (sum of forecasted loads by use [e.g., water heating, space heating, lighting, etc.]) for residential loads and an Econometric Model correlating forecasted economic growth and historical loads for general service and industrial loads, correlating forecasted economic growth and historical loads. Each of these models is weather adjusted using a 20-year historical average. For Nova Scotia, the load forecast is based on a ten-year average measured at the major load center, along with analyses of sales history, economic indicators, customer surveys, technological, demographic changes in the market, and the price and availability of other energy sources. For Prince Edward Island, the load forecast uses average long-term weather for the peak period (typically December) and a time-based regression model to determine the forecasted annual peak. The remaining months are prorated based on the previous year. The Northern Maine Independent System Administrator performs a trend assessment on historic data in order to develop an estimate of future loads. Load Management is not included in the resource adequacy assessment for the Maritime Area. In the Maritime Area there is between 364 MW and 387 MW of interruptible demand available during the assessment period; there is 356 MW forecast to be available at the time of the Maritime Area seasonal peak. This is approximately 10 percent of the Total Internal Demand.




The interruptible load demand that is used is from industrial loads that are metered and therefore can be monitored to determine what level of load would be available to curtail under emergency operating conditions. The Maritimes Area is broken up into subareas, and each subarea has its own energy efficiency programs. These programs are primarily aimed at the residential consumer to help reduce their heating costs. Programs are generally geared towards heating, as the Maritimes Area is a winter-peaking system. Further information on the energy efficiency programs can be found online.73 The Maritimes Area does not address quantitative analyses to assess the variability in projected demand due to weather, the economy, or other factors. In addition, the Maritimes does not develop an extreme (e.g., 90/10) summer forecast in its seasonal assessment. Generation The Maritimes Area resources consist of 7,479 MW of existing capacity and 30 MW (nameplate rating) of planned wind generation scheduled to come on line during the summer assessment period. The Maritimes Area does not consider conceptual, future, or inoperable resources when conducting its seasonal assessment. During this time period there is 116 MW of existing wind with a nameplate rating of 537 MW. If the 30 MW of planned wind generation is included, there will be 125 MW of wind with a nameplate rating of 567 MW (effective summer capacity factor of approximately 22 percent; the subareas within the Maritimes each do their own calculation to determine their wind derated values). Wind project capacity is derated to its demonstrated or projected average output for each summer or winter capability period. This de-rating of wind capacity in the Maritimes Area is based upon results from the Sept. 21, 2005 NBSO report “Maritimes Wind Integration Study.”74 This wind study showed that the effective capacity from wind projects, and their contribution to LOLE, 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. Wind is the only variable resource currently considered in the Maritimes Area resource adequacy assessment. During this time period there is 130 MW of existing biomass with a nameplate rating of 133 MW. The Maritimes Area is forecasting normal hydro conditions for the 2010 summer assessment period. The Maritime Area hydro resources are run-of-the-river facilities with limited reservoir

73 www.maritimeelectric.com

www.nppower.com www.mainepublicservice.com www.emec.com www.nspower.ca/energy_efficiency/programs/

74 http://www.nbso.ca/Public/_private/2005%20Maritime%20Wind%20Integration%20Study%20_Final_.pdf



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storage facilities. These facilities are primarily utilized as peaking units or for providing operating reserve. The Maritimes Area does not expect to experience any conditions that would cause any capacity reductions. The Point Lepreau generation station will be out of service during the entire Summer Assessment period. Since the last assessment there has been a 2 MW hydro facility retire and there is a 57 MW coal-fired facility scheduled to retire in June 2010. These outages and retirements are not anticipated to cause any reliability issues as the Maritimes are a winter-peaking load. Capacity Transactions on Peak No firm import transactions are scheduled at this time. There is a firm sale of 200 MW to Hydro Québec that is tied to specific generators within New Brunswick. The Maritimes Area does have agreements in place for the purchase of emergency energy with other subregions as well as a reserve sharing agreement within NPCC. But the Maritime Area does not rely on this assistance when conducting its summer assessment and no portion of any transaction includes a provision for a Liquidated Damage Contract (LDC). Transmission There has been no significant new bulk power transmission addition since the 2009 summer reporting period. No significant transmission lines are projected to be out of service during the summer reporting period. There is an on-going transformer outage (T4) at Eel River HVdc that prevents the transfer of radial load at Eel River (MW varies between 36 MW and 40 MW depending on local loading) from New Brunswick to Hydro Québec. This outage also lowers the NB to HQ HVdc total transfer capability (TTC) from 735 MW to 400 MW. The T4 transformer is projected to be out of service throughout the summer assessment period. Whereas the Maritime Area is a winter-peaking system this outage is not anticipated to cause any reliability issues. For the 2010 summer season the inter-Regional transmission transfer capabilities include the following:

NB to Maine Electric Power Company (MEPCO): 1,000 MW MEPCO to NB: 550 MW (ISO-NE is limiting the interface to 510 MW due to the

possibility of overloading a transformer in New England under certain system conditions. This limit may lower even more once the warmer summer temperatures arrive).

HQ to NB: HVdc + Radial Load = Between 849 MW and 877 MW. (The reason for the range is due to the varying radial load in the Madawaska area during the summer reporting period). The HVdc stations give a total 741 MW (Madawaska: 391 MW + Eel River: 350 MW).

NB to HQ: 400 MW (Lowered to 400 MW from 735 MW due to T4 outage) The latest studies would be those on the NB / ISO-NE interface conducted in association with the second 345 kV interconnection between New England and New Brunswick. The Region’s




import capabilities are based on real time values based on transmission and generation being in/out of service. NBSO has rules based on study results for simultaneous transfer capability with our interconnections. Transmission or generation constraints are recognized that are external to the Maritimes Area. No other significant substation equipment has recently been added. Operational Issues The amount of wind generation presently operating does not require any special operational changes. The only Demand Response considered in resource adequacy assessment for the Maritimes Area is interruptible load. The Maritimes Area uses a 20 percent reserve criterion for planning purposes, equal to 20 percent x (Forecast Peak Load MW-Interruptible Load MW). There are no environmental or regulatory restrictions that could impact reliability in the Maritimes Area during the assessment period. No smart grid programs have been implemented. There are no unusual operating conditions anticipated for the summer that will impact reliability in the Maritime Area. Reliability Assessment The Maritime Area assesses its seasonal resource adequacy in accordance with NPCC Directory #1 Appendix F Procedure for Operational Planning Coordination. This criterion requires that the probability (or risk) of disconnecting firm load due to resource deficiencies shall be, on average, not more than one day in ten years. The Maritime Area operates its system in accordance with NPCC Document A-06, “Operating Reserve Criteria,” 75 which requires operating reserves equal to 100 percent of the largest single contingency and 50 percent of the second largest contingency. When allowances for unplanned outages (based on a discreet MW value representing an historical assessment of the total forced outages in MW typically realized at the time of peak for the given operating season) are considered, the Maritime Area is projecting large capacity margins above its operating reserve requirements for the 2010 summer assessment period. The projected monthly reserve margins for the 2010 summer period range from 55 percent to 73.6 percent as compared to the projected monthly reserve margin range for the 2009 summer of 69.9 percent to 82.8 percent. The Maritime Area does not consider potential fuel-supply interruptions in the Regional assessment. The fuel supply in the Maritimes Area is very diverse and it includes nuclear, natural gas, coal, oil (both light and residual), pet-coke, hydro, tidal, municipal waste, and wood.

75 http://www.npcc.org/documents/regStandards/Criteria.aspx



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The NB transmission system is robust, comprised of a 345 kV transmission ring with additional supporting 230 kV transmissions. For those areas that may suffer low voltage post-contingency, there are specific “must run” procedures that require generation be online to meet necessary reactive reserves for contingencies. This requirement is applied for generation assessments as well as the day ahead review to ensure that there are sufficient reactive reserves. Other Region-Specific Issues The Maritimes Area is not anticipating any reliability concerns during the 2010 summer. Therefore, no actions are required to be taken. Subregion Description The Maritimes Area is a winter-peaking system. This area covers approximately 57,800 square miles serving a population of approximately 1,910,000. It includes New Brunswick, Nova Scotia, Prince Edward Island, and the area served by the Northern Maine Independent System Operator (parts of northern and eastern Maine). In the Maritimes Area, New Brunswick and Nova Scotia are Balancing Authorities. The New Brunswick System Operator is the Reliability Coordinator for the Maritimes Area.




New England ISO New England Inc. (ISO-NE) is the Regional Transmission Organization (RTO) for the six-state New England Region. ISO-NE is responsible for the reliable operation of the bulk power system, administration of the Region’s wholesale electricity markets, and management of the comprehensive planning process. ISO-NE reports that due to the ongoing effects of the recession, this year’s forecast for peak demand, as well as energy, has been reduced from last year’s forecast levels. On June 1, 2010, implementation of a new Forward Capacity Market (FCM) will bring a large influx of both Energy Efficiency (EE) and Demand Resources (DR) into the supply mix. These demand-side resources will account for more than 6 percent of the Regional capacity contracted (under FCM) to serve the 2010 summer demands. In addition, 225 MW of new supply-side capacity resources are projected to commercialize prior to the summer season, and there are no projections for capacity attrition. Although the Region has no specific or fixed reserve margin requirements,76 the reserve margin entitled “Existing-Certain Capacity & Net Firm Transactions” reflects a reserve margin of 5,327 MW (19.6 percent) for the reference case demand forecast and a reserve margin of 3,207 MW (10.9 percent) for the extreme case demand forecast. These reserve margins are slightly down from those forecast to serve the 2009 summer peak demand and energy. This set of circumstances produces a very positive forecast for ISO-NE to reliably serve the 2010 summer peak and energy demands. During the 2010 summer, there are no projections of any significant transmission lines being out of service and no transmission constraints are anticipated that would significantly impact Regional reliability. There is only one new significant transmission facility anticipated to be placed in service during the 2010 summer period, one 345 kV 160 Mvar variable shunt reactor at West Walpole, Maine, used to control high voltage during light demand periods. As noted earlier, the New England Region is projecting positive reserve margins for the 2010 summer period. There are no fuel supply concerns, environmental restrictions, transmission constraints, or other operational issues projected for this summer. The key points contributing to this positive forecast include:

a reduction in the forecast peak demand due to energy efficiency and the on-going recession for both the reference case (50/50) and the extreme case (90/10);

additional natural gas supply with the completion of the Canaport LNG facility; improvements to the Regional gas pipeline system, improved access to fuel supplies for

gas-fired generation, comprising approximately 41 percent of the Region’s installed capacity; and

the additional demand-side resources made available with the June 1, 2010 implementation of the new Forward Capacity Market (FCM).

Projections for the 2010 summer season have put New England in very good shape with respect to system reliability. Therefore, no special studies or assessments have been performed by ISO-NE.

76

This is because New England’s resource adequacy criterion is based on the one day in ten years Loss of Load Expectation (LOLE) and it is not based on a fixed reserve margin.



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Demand The forecast reference case is the 50/50 forecast (50 percent chance of being exceeded), corresponding to a New England three-day weighted, temperature-humidity index (WTHI) of 79.9, which is equivalent to a dry bulb temperature of 90 degrees Fahrenheit and a dew point temperature of 70 degrees. The 79.9 WTHI is the 95th percentile of a weekly weather distribution and is consistent with the average of the WTHI value at the time of the summer peak over the last 30 years. The reference demand forecast is based on the reference economic forecast, which reflects the Regional economic conditions that would “most likely” occur. ISO-NE’s actual 2009 summer peak demand occurred on August 18, 2009, and was 25,100 MW. This peak demand occurred at hour ending 15:00 at a temperature of 90o F and a 63o dew point. This actual 2009 peak demand was 3.9 percent lower than the actual 2008 summer peak demand of 26,111 MW, which occurred on June 1, 2008. The reference peak demand forecast for the 2009 summer was 27,875 MW. The reference case 2010 summer peak demand forecast is 27,190 MW,77 which is 685 MW (2.5 percent) lower than the 2009 forecast reference case forecast of 27,875 MW. The key factors leading to this change in the forecast are energy efficiency and the ongoing economic recession. The extreme case 2010 summer peak demand forecast is 29,310 MW, which is 470 MW (1.6 percent) lower than the 2009 extreme case forecast of 29,780 MW. ISO-NE develops an independent load forecast for the Balancing Area. ISO-NE uses historical hourly demand data from individual member utilities, which is based upon Revenue Quality Metering (RQM). This data is then used to develop historical demand data upon which the Regional peak demand and energy forecasts are based. From this, ISO-NE develops a forecast of both state and monthly peak and energy demands. The peak demand forecast for the Region and the states can be considered a coincident peak demand forecast. For the 2010 summer, there are 1,898 MW (approximately seven percent of Total Internal Demand) of demand resources. Within this total are 1,329 MW of active demand resources and 569 MW of energy efficiency. The active demand resources are Real-Time Demand Response and Real-Time Emergency Generation, which can be activated with the implementation of ISO-NE Operating Procedure No. 4 — Action during a Capacity Deficiency (OP-4).78 Some assets in the Real-Time Demand Response programs are under direct load control by the Load Response Providers (LRP). The LRP implements direct load control of these assets upon dispatch instructions from ISO-NE, for example, interruption of central air conditioning systems in residential and commercial facilities. An approved FCM Measurement and Verification (M&V) Plan will be used for the purpose of Demand Response performance evaluation. Commercial operation and seasonal audits will be conducted, consistent with ISO-NE operating manuals, to ensure that all active FCM Demand Resources are capable of providing their contractual demand reductions.

77

This value is the same for the Unrestricted Non-Coincident Peak Demand (Line 1), the Total Internal Demand (Line 2), and the Net Internal Demand (Line 3) from the corresponding NERC 2010 Summer Assessment Spreadsheet, July and August 2010, values. 78 http://www.iso-ne.com/rules_proceds/operating/isone/op4/index.html




The 569 MW of energy efficiency programs, projected to be in service by the 2010 summer, are considered capacity resources within the FCM. Under the FCM, energy efficiency can be included in the category of on-peak and seasonal peak demand resources.79 This 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 used during on-peak hours. An approved FCM M&V Plan will be used for the purpose of Energy Efficiency performance evaluation. Commercial operation and seasonal audits will be conducted, consistent with ISO-NE operating manuals, to ensure that all FCM energy efficiency projects are capable of providing their contractual demand reductions. Not included in this assessment is voluntary demand that may interrupt based on the price of wholesale energy. As of December 31, 2009, there were approximately 71 MW enrolled in the ISO-NE’s Price Response Program (PRP). The actual value of the demand that response is captured in collected Demand Response data; at the time of the peak in 2009, this amount was about 77 MW. ISO NE addresses peak demand uncertainty in two ways:

Weather — peak demand distribution forecasts are made based on 38 years of historical weather data, which includes the reference forecast (50 percent chance of being exceeded), and extreme forecast (10 percent chance of being exceeded); and

Economics — alternative forecasts are made using high and low economic scenarios. ISO-NE also reviews the projected 2010 summer conditions using the extreme 90/10 peak demand forecast based on the reference economic forecast. For the 2010 summer, that value is 29,310 MW. Generation ISO-NE’s Existing-Certain generating capacity amounts to approximately 32,229 MW based on summer ratings. An additional 1,827 MW within the Existing-Other category consists of three categories of additional capacity. The first category consists of the amount of capacity exceeding 1,200 MW, for those units/stations that exceed the 1,200 MW level as a “single loss-of-source contingency.” In real time operations, New England may be required to limit its largest, single loss-of-source contingency to 1,200 MW in order to respect operating agreements with PJM and NYISO. The amount of capacity identified within this first category is approximately 149 MW. The second category of capacity is the amount of nameplate capacity that exceeds the FCM Regional Capacity Supply Obligation (CSO),80 which is approximately 1,334 MW. The third category of capacity is the existing energy-only capacity, which is not part of the CSO. This amount totals approximately 344 MW. The Existing-Inoperable category identifies 0 MW of capacity. A total of 225 MW of Future Capacity Additions is projected for the summer peak demand period. This includes 0 MW of Future-Planned capacity and 225 MW of Future-Other capacity. 79

The rules addressing the treatment of demand resources in the Forward Capacity Market (FCM) may be found in Section III.13.1.4 of ISO New England’s Market Rule 1, Standard Market Design, located at www.iso-ne.com/regulatory/tariff/sect_3/2-16-09_mr1_sect_13-14.pdf.

80 The CSO is the FCM contracted capacity, which will receive payments for reliably serving the 2010 summer peak and energy demands.



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Approximately five MW of the Existing-Certain capacity is wind generation projected to be available at the time of peak demand. This reflects a 68 MW derate on-peak, from the total nameplate capability of 73 MW. Wind capability under ISO-NE’s Forward Capacity Market (FCM) is rated seasonally. FCM wind capability during the summer and winter seasons is equal to the average of a median calculation performed for each year over the previous five years. For the summer season, the median calculation is the median capacity (MW output) during the hours ending 14:00 through 18:00 each day of June through September, and any summer hour with a “shortage event.”81 For the winter season, the median calculation is the median capacity (MW output) during the hours ending 18:00 through 19:00 each day of October through May, and any winter hour with a shortage event. Non-FCM wind capability is seasonally rated from either the sustained maximum net output averaged over a four consecutive hour period (measured for the summer and winter capability periods each year), or the unit’s nameplate rating adjusted for engineering data that projects a unit(s) output at the time of peak demand. Approximately 1.5 MW of Existing-Certain capacity is solar generation that is projected to be available at the time of peak demand. Biomass capacity within the Existing-Certain category totals 914 MW. This reflects a 67 MW derate on-peak from the total nameplate capability of 981 MW. The Existing-Certain capacity also includes 1,495 MW of hydroelectric resources. This reflects a 382 MW derate on-peak from the total nameplate capability of 1,877 MW. Monthly ratings for hydroelectric resources with little or no storage capability are calculated based on the maximum capacity of the unit(s), adjusted for historical hydrological conditions and upstream storage. Those hydroelectric units with pondage and storage of at least ten times their seasonal claimed capability rating must annually demonstrate their summer and winter capability. Hydrological conditions for New England during the 2010 summer are projected to be slightly drier than normal. The 26 MW of wind capacity and 199 MW of combustion turbine capacity are included within the 225 MW of future capacity additions that are projected to go into service prior to the 2010 summer. ISO-NE is not projecting any disruptions to Regional fuel supply chains serving the electric power sector. The future resources that ISO-NE includes in its reliability analyses and reserve margin calculations are those that have either a signed Interconnection Agreement (IA) or have received approval of their Proposed Plan Application (PPA), or those that have begun discussions with ISO-NE Market Services indicating that the project is nearing completion and is preparing to become an ISO-NE generator asset. No major existing generating facilities are projected to be out of service during the 2010 summer peak demand period.

81

These are events under which ISO-NE Operations is currently experiencing either an operating reserve or capacity deficiency.




Capacity Transactions on Peak The forecast for 2010 Summer Capacity Imports is 472 MW. This includes 84 MW of Non-Firm Capacity Imports and 388 MW of Firm Capacity Imports. The 388 MW of Firm Capacity Imports are Full-Responsibility Purchase, which includes 226 MW from Hydro-Québec and 162 MW from New York. Only Firm, Full-Responsibility Purchases that have been contracted for delivery within the 2010/2011 FCM Capability Period82 are included as Firm Capacity Imports. While the entire 388 MW of Firm Capacity Imports are backed by firm Forward Capacity Market (FCM) contracts for generation, there is no requirement for those purchases to have firm transmission service. However, it is specified that deliverability of external capacity imports must meet the FCM 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 energy associated with the FCM capacity import, but that market participant bears the associated risk of FCM penalties if it chooses to use non-firm transmission. There are no Capacity Import contracts that can be characterized as “liquidated damage contracts” or “make-whole” contracts as defined by FERC Order 890. The forecast for 2010 summer Capacity Exports is 100 MW. The 100 MW of Firm Capacity Exports are Full-Responsibility Sales to New York (Long Island) via the Cross-Sound Cable. Only Firm, Full-Responsibility Sales that have been contracted for delivery within the 2010/2011 FCM Capability Period are included as Firm Capacity Exports. Although the Capacity Export is backed by a firm generation contract, FCM rules will dictate whether the capacity and associated energy can be considered recallable by ISO-NE. There are no Capacity Export contracts that can be characterized as “liquidated damage contracts” or “make-whole” contracts as defined by FERC Order 890. The Capacity Import contracts that have a Capacity Supply Obligation (CSO) under FCM can be characterized as having reliance on external resources that the Region counts on as part of fulfilling its portion of the overall Installed Capacity Requirement (ICR). However, these contracts are not characterized as emergency imports, but as “tie benefits” within the ICR calculation. The combined amount of tie benefits from the three external regions is 1,860 MW, which are sub-categorized as 1,400 MW from Québec, 100 MW from New York, and 360 MW from the Maritimes (New Brunswick). Transmission There is only one new major transmission facility anticipated to be placed in service for 2010 summer. This involves the installation of one 345 kV 160 Mvar variable shunt reactor at West Walpole, Maine. The shunt reactor (70 Mvar fixed and 90 Mvar variable) is used to control high voltage during light demand conditions following contingencies of the existing Stoughton and K-Street 345 kV reactors. This project is not required for reliable operations for 2010 summer.

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The 2010/2011 FCM Capability Period is from June 1, 2010, to May 31, 2011.



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There are no reliability concerns in meeting the projected in-service dates for the new transmission additions noted above. Mitigation plans have been developed to address identified future needs. The current ISO-NE Regional System Plan (RSP)—Transmission Project List includes a number of major new projects that have projected in-service dates over the next three to five years. Several of these projects are progressing through the state siting process, where any major delays experienced within the siting process would put pressure on meeting the projected in-service dates of these projects. All significant transmission lines are projected to be in-service through the 2010 summer season. Upon a major outage of a significant transmission line or facility, operating procedures are in place to maintain system reliability. During the 2010 summer, no transmission constraints that would significantly impact Regional reliability are anticipated. However, there are localized system requirements dependent upon the operation of local area generation under certain operating conditions. Operating procedures and guides are in place to address outages of this generation. Where system upgrades are required for a long-term solution, they are listed in the RSP projects list as referenced above. The import capabilities to New England and the studies on which they are based are listed in Table NPCC-4. The studies are reviewed and updated on a regular basis. All of the studies recognize transmission and generation constraints in power systems external to New England.

83

The Hydro-Québec Phase II interconnection is a DC tie with equipment ratings of 2,000 MW. Due to the need to protect for the loss of this line at full import level in the PJM and NY Control Areas’ systems, ISO-NE has assumed its transfer capability for capacity and reliability calculation purposes to be 1,200 MW to 1,400 MW. This assumption is based on the results of loss of source analyses conducted by PJM and NY. 84

The capability of the Cross Sound Cable is 346 MW. However, losses reduce the amount of MW that are actually delivered across the cable. When 346 MW is injected into the cable, 330 MW is received at the point of withdrawal. Recent study work has shown that the actual transfer capability from New York (Long Island) to New England (Connecticut) is very dependent on the specific generation dispatch at New Haven and reduces to zero with the plant(s) in full operation.

Table NPCC-4: New England’s External Transmission Interface Limits

Interface

Transfer Capability

(MW) Interface Limit

New Brunswick -New England 1,000 Second New Brunswick Tie

Study

Hydro-Québec-New England Phase II83 1,200–1,400

PJM and NYISO Loss of Source Studies

Hydro-Québec-Highgate 200 Various Transmission

Studies

New York-New England 1,400 NYISO Operating Studies

Cross-Sound Cable84 346 Cross-Sound Cable System

Impact Study




Recently, the construction of the new Wakefield 345/115 kV substation in northeast Massachusetts was completed. The breaker-and-a-third substation consists of four 345/115 kV 448 MVA autotransformers and connects to the 345 kV 339 Line (Tewksbury-Golden Hills). This is part of the Merrimack Valley-North Shore Project that provides additional transformation in the area to address various thermal and voltage issues. No other significant substation equipment such as SVCs, FACTS devices, or HVdc has recently been added. Operational Issues There are no significant anticipated unit outages, environmental restrictions, variable resources, transmission constraints, or temporary operating measures that would adversely impact system reliability during the 2010 summer period. During extremely hot summer days and, or low hydrological conditions, there may be environmental restrictions on coastal or river-based generating units due to cooling water discharge temperatures. Such conditions have occurred several times in the past, resulting in temporary reductions in capacity ranging, in aggregate, anywhere from 50 MW to 500 MW. These environmental restrictions/reductions are reflected in ISO-NE’s forced outage assumptions. The ISO monitors these potential situations and anticipates that additional resources should be available to cover these forced outages or temporary reductions in generating capacity. On a monthly basis, ISO-NE uses a weekly operable capacity assessment to assess the reliability and adequacy of the Region.85 These analyses take into consideration the qualified capacity of FCM supply and demand-side resources, the net of firm capacity imports and exports, the forecast peak demand (both 50/50 and 90/10 forecasts), operating reserve requirements, all known or planned outages, and the potential for the temporary unplanned outages of generation or transmission facilities. In order to be prepared for a peak at any time during the summer, ISO-NE takes the approach of applying the forecasts for the peak summer demand not only to the months of July and August, but to the month of June as well. The operating reserve requirement is typically 1,800 MW and the total aggregate unplanned outages are assumed to be 2,800 MW in June and 2,100 MW in July through September under both the 50/50 and 90/10 demand forecasts. The results are then used by ISO-NE to identify the means to mitigate problems if projected. To date, there are no special operating procedures that are a result of the recent integration of variable or intermittent resources such as wind, solar, etc. Since ISO-NE has just over one MW of solar capacity within its system, there is no need to forecast the output of solar resources. The implementation of the new FCM has enhanced the integration of demand resources into the operation of the system. Operating Procedures to dispatch the demand resources have been developed. In addition, enhancements to the study tools used by the operators to anticipate system impacts as a result of the demand reduction will also be in place.

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The operable capacity assessments, which are included with ISO-NE’s Annual Maintenance Schedule, are posted at http://www.iso-ne.com/genrtion_resrcs/ann_mnt_sched/index.html.



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There are no environmental or regulatory restrictions currently being discussed or forecast for the Region that may impact system reliability. Two smart grid programs have recently been implemented. The first program is the Alternative Technology Regulation (ATR) Pilot program, which is an 18-month program in response to FERC Order 890, which will test the impact of non-generating technologies on the Regulation Market and allow owners of ATR resources to evaluate the technical and economic suitability of their technologies as possible regulation-service sources. The ATR Pilot Program is limited to 13 MW of participation, and no single entity will be allowed to provide more than five MW of regulation service. Eligible non-generating resources include flywheel technology, battery technology, and certain demand-response resources. Resources must have been commercial by November 1, 2009.86 The second program is the North America Synchrophasor Initiative (NASPI), which is a program sponsored by U. S. DOE’s Pacific Northwest National Laboratory (PNNL) to improve the planning, operation, and reliability of the electric power system through wide-area measurement, monitoring, and control. The mission of the group is to create a robust, widely available, and secure synchronized data measurement infrastructure for the interconnected North American electric power system with associated assessment and monitoring tools. Under the DOE sponsored project, independent of NASPI, more than 40 synchronized phasor-measurement units (PMU) have been dispersed across the eastern United States electric grid. A super-phasor data concentrator (super PDC) collects real-time phasor data at the Tennessee Valley Authority (TVA), which makes tools available to view and analyze the detailed information. ISO-NE has installed two PMUs and is planning to install more as part of this project. Control Room Operators will be able to view accurate phasor information, which will assist in understanding system dynamics in real time. The phasor data also will be integrated with the State Estimator (SE) to improve its performance. There are no unusual operating issues or concerns that are anticipated to impact the reliable operation of the New England transmission system for the coming summer period. Reliability Assessment ISO-NE bases its capacity requirements on a probabilistic loss-of-load expectation assessment that calculates the total amount of installed capacity needed to meet the Northeast Power Coordinating Council’s (NPCC) once-in-ten-year requirement for preventing the disconnection of firm load due to a capacity deficiency. This value, known as the Installed Capacity Requirement (ICR), was calculated for the 2010/2011 Capability Period to be 33,537 MW.87 After taking into account emergency purchases from the interconnections, the net amount of capacity needed to meet the resource adequacy criterion is 32,137 MW.

86

http://www.iso-ne.com/support/faq/atr/index.html. 87

The 33,537 MW Installed Capacity Requirement value does not reflect a reduction in capacity requirements relating to HQICCs that are allocated to the Interconnection Rights Holders, as required by Market Rule 1. After deducting the HQICC value of 1,400 MW per month, the net Installed Capacity Requirement for use in the 2010/2011 third annual reconfiguration auction is 32,137 MW.




Tables NPCC-5 through Table NPCC-8 show the make-up of the capacity resources with Capacity Supply Obligations (CSOs), which include:

28,768 MW of Native Generating Capacity with CSO (Table NPCC-5),

1,052 MW of Intermittent Power Resources with CSO (Table NPCC-6),

807 MW of Import Capacity with CSO (Table NPCC-7), and

2,173 MW of Demand Resources with CSO (Table NPCC-8).

ISO-NE’s latest resource adequacy studies are detailed in the January 30, 2009 FERC Filing entitled, “ISO New England Inc. and the New England Power Pool, Filing of (1) Installed Capacity Requirement, Hydro Québec Interconnection Capability Credits and Related Values for the 2010/2011 Capability Year and (2) Related Market Rule Revisions; Docket No. ER09-640-000.” The model used for conducting the 2010/2011 system-wide ICR calculations for New England accounts for all known external firm capacity imports and exports, which amount to a net value of approximately 807 MW. In addition, 1,860 MW of tie benefits from neighboring systems were included within the ICR modeling for the 2010 summer period. ISO-NE assumes that it will be able to obtain 1,860 MW of emergency assistance, also referred to as tie benefits, from other neighboring areas within the NPCC Region during possible capacity shortage conditions within New England. That assumed amount is based on the results of a 2009 probabilistic tie benefits study. In addition to the tie benefits study, the ISO has analyzed projected 2010/2011 system conditions of the neighboring Balancing

Table NPCC 5 — Generating Capacity with CSO by Load Zone

Load Zone MW Maine 2,854New Hampshire 3,835Vermont 879Connecticut 6,695Rhode Island 2,286South East Massachusetts 5,653West Central Massachusetts 3,506North East Massachusetts and Boston 3,060

Total New England 28,768

Table NPCC-6: Intermittent Power Resources with CSO by Load Zone (MW)

Load Zone Summer (MW)

Winter (MW)

Maine 260 289New Hampshire 123 147Vermont 59 103Connecticut 419 434Rhode Island 4 9South East Massachusetts 80 87West Central Massachusetts 40 63North East Massachusetts and Boston 67 70Total New England 1,052 1,202

Table NPCC-7: Import Capacity Resources with CSO

Resource Name Interface MW NYPA-CMR NY AC Ties 68,800NYPA-VT NY AC Ties 12,200VJO-Highgate HQ Highgate 200,000Erie Boulevard Hydropower-Import

NY AC Ties 525,959

Total Imports 806,959



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Areas, as reflected in the most recent NPCC Resource Adequacy Assessment (RAA), and determined that the 1,860 MW total tie benefits are reasonable and achievable. The areas assumed to be providing the tie benefits are the Maritimes, New York, and Québec. The tie benefits amount to about 50 percent of New England’s total import capability. The 2010 reference case (50/50) summer peak demand (Net Internal Demand) is 27,190 MW. The amount of summer capacity to serve that demand (Existing-Certain Capacity and Net Firm Transactions) is 32,517 MW. The resultant 2010 summer (reference case) reserve margin is 5,327 MW, which equates to a 19.6 percent summer (reference case) reserve margin. The 2010 extreme case (90/10) summer peak demand (Net Internal Demand) is 29,310 MW. The amount of summer capacity to serve that demand (Existing-Certain Capacity and Net Firm Transactions) is 32,517 MW. The resultant 2010 summer (extreme case) reserve margin is 3,207 MW, which equates to a 10.9 percent summer (extreme case) reserve margin. Both 2010 summer margins, reference and extreme case, are sufficient to cover the New England operating reserve requirement, which is approximately 1,800 MW; however, higher than projected unit outages and/or higher than anticipated demand could adversely affect the forecast for reserve margins. The projected 2009 and 2010 summer reserve margins are summarized in Table NPCC-9. For the previous year, the 2009 summer peak demand period, the projected reserve margin under the 50/50 peak demand forecast was approximately 5,600 MW (20.1 percent), and the reserve margin under the 90/10 peak demand forecast was approximately 3,695 MW (12.4 percent). The 50/50 and 90/10 margins forecast for the 2010 summer are about 273 MW and 488 MW lower, respectively, than the 50/50 and 90/10 reserve margins forecast for the 2009 summer (Table NPCC 9, below).

Table NPCC-9: 2009 and 2010 Summer Reserve Margins

Weather Forecast 2009 Summer (MW and %)

2010 Summer (MW and %)

Reference Case (50/50) 5,600 (20.1) 5,327 (19.6) Extreme Case (90/10) 3,695 (12.4) 3,207 (10.9)

Demand response is treated as capacity in ISO-NE’s FCM and within these resource adequacy assessments. Demand response availability assumptions used in the assessments are based on

Table NPCC-8: Demand Resources with CSO by Load Zone

Load Zone (MW)

Maine 229New Hampshire 101Vermont 85Connecticut 733Rhode Island 143South East Massachusetts 203West Central Massachusetts 279North East Massachusetts and Boston 401Total New England 2,173




performance during ISO-NE OP-4 events or, if no New England-wide OP-4 events occurred during a particular year, on the results of annual response audits. Control Room Operators can monitor the performance of demand-side resources in real time, and the actual performance of these resources, during each activation, affects their forward-going FCM compensation. If ISO-NE does not activate all the Demand Response programs in all load zones by August 15 of each calendar year, then ISO-NE will initiate pre-defined audits of those programs within the necessary load zones. No fuel supply or deliverability concerns for the 2010 summer period have been identified. Historically, many fuel supply and delivery options have been readily available to generators within New England during the summer months. ISO-NE routinely gauges the impacts that fuel supply disruptions could have upon system or subregional reliability. Because natural gas is the predominant fuel used to produce electricity in New England, ISO-NE continuously monitors the Regional natural gas pipeline systems, via their Electronic Bulletin Board (EBB) postings, to ensure that emerging gas supply or delivery issues can be incorporated into the daily or next-day operating plans. Should natural gas issues arise that may impact fuel deliveries to Regional power generators, ISO-NE has predefined communication protocols in place with the Gas Control Centers of both Regional pipelines and local gas distribution companies (LDCs), in order to quickly understand the emerging situation and then implement mitigation measures. ISO-NE’s Operating Procedure No. 21—Action during an Energy Emergency88 (OP21)—is designed to help mitigate the impacts on bulk power system reliability resulting from Regional fuel supply deficiencies. Transmission planning studies have demonstrated that adequate reactive resources are provided throughout New England. In instances where dynamic reactive power supplies are needed, devices such as STATCOMs, SVCs, synchronous condensers, and DVARs have been employed to meet the required need. If additional reactive power support is necessary in real time, generation will be committed to meet the requirement. Operational dynamic studies are performed in the near-term to develop and update operating guides supporting adequate voltage/reactive performance. Other Region-Specific Issues There are no other Region-specific issues that were not mentioned above. Subregion Description ISO New England Inc. is a Regional Transmission Organization (RTO) serving Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island, and Vermont. It is responsible for the reliable operation of New England’s bulk power generation and transmission system, administering the Region’s wholesale electricity markets, and managing the comprehensive planning of the Regional bulk power system. The New England Regional electric power system serves 14 million people living in a 68,000 square-mile area. New England is a summer-peaking electrical system, which recorded its all-time peak demand of 28,130 MW on August 2, 2006.

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Operating Procedure No. 21 is located on the ISO’s website at: http://www.iso-ne.com/rules_proceds/operating/isone/op21/index.html



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New York The NYISO is the only Balancing Authority in the New York Control Area (NYCA), and it also serves as the Reliability Coordinator for the New York Control Area. The NYCA is more than 48,000 square miles, serves a total population of about 18.5 million people, and peaks annually in the summer. Demand The peak demand is the sum of the coincident peak demands of each transmission district in the control area. Each transmission district develops its own Regional load growth factor, based on the economic outlook in the district. All transmission districts considered the economic downturn when developing their 2010 forecast. In addition, most transmission districts considered energy conservation when developing their load growth projections. The actual summer peak demand for the New York Control Area in 2009 was 30,844 MW; the forecasted peak was 33,930 MW. Compared to 2009 summer, 2010 summer forecasted peak of 33,025 MW is 2.74 percent lower. Most transmission districts use a 50th percentile for the projected peak-producing temperature variable or heat index, for which the chance of being over or under is equal in the next year. Two transmission districts use a 67th percentile to select their heat indexes, for which the chance of being under is 2/3 and the chance of being over is 1/3. This produces a higher, more conservative forecast in these districts. The New York Control Area peak forecast is a coincident forecast, such that the highest load for any given hour over the entire control area is defined as the peak. As discussed in the response to Part a), resource evaluations are conducted for the projected coincident peak demand at a 50th percentile for some transmission districts and at a 67th percentile for others. The NYISO has two Demand Response programs: the Emergency Demand Response Program (EDRP) and ICAP Special Case Resources (SCR) program. Both programs can be deployed in energy shortage situations to maintain the reliability of the bulk power grid. The Emergency Demand Response Program is designed to reduce power use through the voluntary shutting down of businesses and large power users. Companies, mostly industrial and commercial, sign up to take part in the EDRP. The companies are paid by the NYISO for reducing energy use when asked to do so by the NYISO. Special Case Resources is a program designed to reduce power use through the shutting down of businesses and large power users. Companies, mostly industrial and commercial, sign up to become SCRs. The companies must, as part of their agreement, curtail power use, usually by shutting down when asked by the NYISO. In exchange, they are paid in advance for agreeing to cut power use upon request. The NYISO’s Day-Ahead Demand Response Program (DADRP) allows energy users to bid their load reductions, or “negawatts,” into the Day-Ahead energy market as generators do. Offers




determined to be economic are paid at the market clearing price. DADRP allows flexible loads to effectively increase the amount of supply in the market and moderate prices. For the summer of 2010, Participation in the Emergency Demand Response Program (EDRP) and Special Case Resources (SCR) programs represents an additional 2,251 MW from SCR and 213 MW of EDRP available through the market for a total of 5.8 percent reduction of total peak load. As of August 2009, there are 392 EDRP participants representing 323 MW. There are 3,675 SCR participants representing 2,061 MW. There are 50 DADRP participants representing 331 MW. All SCR and EDRP program participants submit hourly interval data to the NYISO so actual performance indexes may be calculated. The NYISO files reports to the FERC on a periodic basis regarding the performance of these programs. The conservation programs are specific to each transmission district. The Public Service Commission of New York has instituted an Energy Efficiency Portfolio Standard (EEPS), which provides goals and timetables for each investor-owned utility, together with recommended goals for the state’s two power agencies, the New York State Energy Research and Development Agency, and some smaller state agencies. The state is currently establishing measurement and verification protocols to determine the impact of these energy efficiency programs. The NYISO is a member of the Evaluation Advisory Group, which provides input to the Public Service Commission on methods and standards used to verify the level of savings the EEPS achieves in practice. The New York State Energy Research and Development Agency (NYSERDA) also implements state-funded energy efficiency programs as authorized by the Public Service Commission. NYSERDA publishes annual reports on the measurement and verification of the programs it implements. The NYISO and transmission owners conduct a load forecast uncertainty assessment each year as part of the determination of the NYCA-installed reserve margin. The details of this assessment may be found in the following report: New York Control Area Installed Capacity Requirements for the Period May 2009 through April 2010, located at the New York State Reliability Council website,89 page 33. The basic procedure is to develop weather response functions at peak load conditions for the several regions of the control area. A statistical assessment of the temperature and humidity at peak conditions provides the basis for estimating the variability due to weather. Additional multiplicative factors due to high or low economic growth scenarios may also be included. Generation For 2010 summer, the New York Balancing Area expects 38,371 MW of existing capacity. Of the existing capacity, 1,275 MW are from wind generation and 357 MW from biomass generation. Capacity classified as Existing-Certain total 36,668 MW. The breakdown of certain energy from various generation types are as follows: 127.5 MW from wind generation, 5,050.5

89 http://www.nysrc.org/pdf/Reports/2009%20IRM%20Report%20-20Final%2012%2005%2008%20V1.pdf



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MW from hydro generation, and 333 MW from biomass generation. Capacity classified as Existing-Other totals 1,651 MW. The breakdown of uncertain energy from various generation type are as follows: 1,147.5 MW from wind generation, 479.5 MW from hydro generation, and 24 MW from biomass generation. Solar energy as capacity is negligible. NYISO applies a 45 percent derate factor for non-NYPA hydro generation for the projected peak months of July and August. The 45 percent derate factor is applied to the total available non-NYPA hydro generators totaling 1,060 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. Adding all the hydro generation derates values in New York totals 479.5 MW. For wind generation the NYISO derates all wind generators to 10 percent of rated capacity in the summer operating period. With 1,275 MW of wind generation capacity for this summer, the projected on-peak capacity counted is 127.5 MW from wind generators. Since the summer of 2009, 1,163 MW of additional resources have been added to the New York system. There is approximately 471 MW of new wind generation since last summer. The Gilboa 4 up-rate is 30 MW. The Empire Project (natural gas-fired, combined cycle), which consists of 635 MW of additional generation is projected in-service this summer. There is also an additional 27.2 MW of generation from the River Bay (natural gas-fired combined cycle) and Fulton Co (methane gas-fired) projects. Hydro conditions are anticipated to be sufficient to meet the projected demand this summer. The New York area is not experiencing continued effects of a drought or any conditions that would create capacity reductions. Reservoir levels are projected to be normal for the upcoming winter. NYISO is not experiencing or expecting conditions that would reduce capacity. No fuel supply vulnerability issues are projected for this winter. There were three retirements in New York during the Winter of 2009–2010 that will impact summer of 2010 generation: Poletti 1 with 890 MW of generation (Retired January 31,2010), Greenridge 3 with 55 MW of generation, and Westover 7 with 40.1 MW (both retired December 31, 2009) of generation for a total of 985.1 MW of retirements. However, these retirements are not projected to cause any reliability issues due to sufficient capacity in the local area and additional generation, which is scheduled to be on line during the summer peak season. Capacity Transactions on Peak The NYISO projects capacity backed energy resulting in net purchases into the New York Balancing Area backed by 1,580 MW of generating capacity. Capacity purchases are not required to have accompanying firm transmission but adequate transmission rights must be available to assure delivery to N.Y. when scheduled. External capacity is also subject to external availability rights. Availability on the import interface is available on a first-come first-serve basis. The total capacity purchased for this summer operating period may increase since there remains both time and external rights availability.




Due to NYISO market rules, information on specific import and export transactions is considered confidential. Information on the aggregated or net projected capacity imports and exports during peak summer conditions is not yet known. Capacity is traded in the NYISO market as a monthly product, and total imports and exports are not finalized until shortly before the month begins. NYISO does not rely on external resources for emergency assistance. Transmission In the North Country, Duley and Ryan 230 kV stations were added during the summer of 2009 to the Willis-Plattsburgh WP1 and WP2 lines, respectively. Ryan and Duley 230 kV stations serve to connect the following wind plants: Clinton, Ellenburg, Altona, and Chateauguay. High Sheldon, Wethersfield, and Canandaigua 230 kV stations were added during the summer of 2009 to the Stolle-Meyer-Hillside 230 kV path on the Southern Tier to connect the following wind plants: High Sheldon, Wethersfield, and Canandaigua. The Millwood 345 kV 240 Mvar capacitor bank was added during the summer of 2009 for added voltage support in the lower Hudson Valley. The Watercure 345/230 kV transformer bank remains out of service with a possible in-service date of fall 2011. The BP76 Beck2-Packard 230 kV tie with Ontario will remain out of service this summer. The Ithaca Transmission Project has an in-service date of 6/15/2010. This project includes a new substation, Clarks Corners, which will consist of two 345/115 kV LTC transformers, 14.8-mile existing 115 kV Line #947 rebuild, new 15-mile 115 kV line from Etna substation to the New Clarks Corners substation, and installation of new 50 Mvar capacitor banks at State Street substation, Wright Avenue substation, and the new Clarks Corners substation. There are currently no anticipated target in-service delays for this project. The re-conductor of the Northport-Norwalk Harbor 138 kV cable was completed during the summer of 2008. One cable is currently on maintenance and scheduled to return to service at the end of June of 2010. Once cables are in service, scheduling limits will increase. The NYISO performs seasonal operating planning studies to calculate 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 (see Table NPCC 10, below). 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. The NYISO does not have any transmission constraints that could significantly impact reliability. New York Balancing Authority area import capability is summarized in the Table below. These values are derived by joint studies with adjoining regions and recognize transmission and generation constraints.

Table NPCC-10: 2010 Summer Transfer Capability

Import Area Transfer Capability

(MW) PJM 3,000 Québec 1,500 New England 1,250 Ontario 2,050



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No significant substation SVC, FACTS controllers, or HVdc devices were added since the summer of 2009. Operational Issues There were no special operating studies done for 2010 since unique operational problems were not encountered. In addition, there were no special operating procedures implemented for the 2010 summer operating season resulting from integration of variable resources. In June 2008, the NYISO implemented a centralized program to forecast energy output for interconnected wind generating plants. The wind forecasts are integrated with the Real-time Security Constrained Dispatch (SCD) and the Real-time and Day-Ahead commitment processes. In anticipation of even greater amounts of wind interconnecting to the system, the NYISO is seeking tariff changes to become effective in May 2009 to improve the integration of wind resources into its SCD. These changes, if accepted, will require wind plants to receive and follow dispatch-down instructions when it is determined that a wind resource’s energy output is subject to limitations as identified by SCD. Reliability concerns resulting from high levels of Demand Response resources are not projected. The Regional Greenhouse Gas Initiative (RGGI) became effective January 1, 2009. The program is an agreement among ten northeast states designed to reduce the emissions of carbon dioxide from power plants greater than 25 MW. The RGGI system is administered through the use of permits known as allowances. One allowance is required for each ton of CO2 that has been emitted by an affected facility. RGGI established an annual emissions cap for each of the member states that approximates recent emission patterns. The allowances are mostly distributed through a series of auctions. Program compliance is measured over a three-year period with the first compliance period running from 2009 through 2011. If the market price of allowances increases above threshold prices then the compliance period is extended one more year. If the new RGGI Allowance market operates as set forth by the modeling conducted by the state, bulk power system reliability is not projected to be negatively impacted in the near term. If a gas pipeline failure were to cause dual fueled plants to convert to oil resulting in increased emissions of carbon dioxide and allowances were not available to cover the increased emissions, then some states have provided for the suspension of the RGGI program. New York State Department of Environmental Conservation administers the program in New York. The NYSDEC Commissioner has stated in the rule-making process that, in such a situation, he would act to maintain electric system reliability. There were no new smart grid programs fully implemented in 2009. No unusual operating conditions impacting reliability are anticipated. Reliability Assessment The NYISO assesses resource adequacy through a series of studies that determine an Installed Reserve Margin (IRM), Locational Installed Capacity Requirements (LCRs), and the maximum amount of Installed Capacity (ICAP) that may come from Areas outside of the NYISO Balancing




Authority Area. These studies are conducted on an annual basis in anticipation of an upcoming Capability Year that begins on May 1 and ends on April 30. For the upcoming Capability Year beginning on May 1, 2009, the NYISO will have 39,951 MW of internal ICAP available after considering firm sales and firm long term purchases, not including the 2,251 MW of Special Case Resources (SCRs) included in NYISO’s projected margin and peak load forecast of 33,025 MW. The 2010 summer Installed Reserve Margin is 18 percent. Last summer’s established Installed Reserve Margin requirement was 16.5 percent. NYISO complies with NPCC and NYSRC resource adequacy criteria of no more than one occurrence of loss of load per ten years due to a resource deficiency, as measured by 0.10 days/year LOLE. The assumptions take into account demand uncertainty, scheduled outages and de-ratings, forced outages and de-ratings, assistance over interconnections with neighboring control areas, NYS Transmission System emergency transfer capability, and capacity and/or load relief from available operating procedures. The NYSRC establishes the IRM90 based on a technical study conducted by the NYISO and the Installed Capacity Subcommittee (of the NYSRC). This study finds the required amount of installed capacity needed to meet the 0.1 days/year LOLE criterion. Following this study, the NYISO conducts the Locational installed Capacity Requirements (LCR) study 91. This study finds the amount of ICAP needed to exist in New York’s high load Areas. Restricting the Capacity imports allows the interface ties to be used for emergency support. During the Installed Reserve Margin study, the isolated and interconnected IRMs are calculated. The difference between these numbers gives an indication of the amount of emergency assistance that NYISO relies on from its neighbors. As stated above, the reserve margin for the upcoming year is projected to be 18 percent based on capacity of 39,951 MW and a peak load of 33,025 MW. Last year, the capacity totaled 40,959 MW with a peak load forecast of 33,930 MW. This resulted in a reserve margin projection of 16.5 percent before the addition of 2,100 MW of SCRs. The calculated reserve margin based on the 2010 forecasts for demand, resources, and net transactions is 22.3 percent for July. There are two types of demand resources that are considered in our resource adequacy studies. The first is emergency Demand Response. This is a program in which participation is voluntary at the time of being called and suppliers are only paid for what they provide. They are handled as any load reduction option available to operators on an emergency basis. The second type of resource is a Special Case Resource. This supplier gets paid like any other capacity resource, which usually means monthly ICAP payments. In addition, they are paid for the load that’s reduced or the generation that’s produced with their participation. Since these are like a regular resource in that regard, they are treated like the other capacity in resource adequacy studies.

1 NYSRC Report titled, “New York Control Area Installed Capacity Requirements for the Period May 2009 Through April 2010”

(December 5, 2008). 2 NYISO Report titled “LOCATIONAL MINIMUM INSTALLED CAPACITY REQUIREMENTS STUDY COVERING THE

NEW YORK CONTROL AREA For the 2008–2009 Capability, February 28, 2009.



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They have an associated forced outage rate (effectiveness factor) and are included when calculating the Installed Reserve Margin. NYISO has the New York State Gas-Electric Coordination Protocol as Appendix BB92 in the Open Access Transmission Tariff (OATT). This Coordination Protocol applies to circumstances in which the NYISO has determined (for the bulk power system) or a Transmission Owner has determined (for the local power system) that the loss of a generator due to a Gas System Event would likely lead to the loss of firm electric load. This Coordination Protocol also applies to communications following the declaration of an Operational Flow Order or an Emergency Energy Alert. There are no anticipated fuel delivery problems for this winter operating period. The NYISO performs transient dynamics and voltage studies. There are no stability issues anticipated that could impact reliability during the 2010 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). Other Region-Specific Issues There is no anticipated impact on reliability resulting from economic conditions. Sub-Region Description NYISO is the only Balancing Authority in the New York Control Area. The NYCA is more than 48,000 square miles serving a total population of about 18.5 million people and peaks annually in the summer.

3 New York State Gas-Electric Coordination Protocol, Attachment BB of the NYISO Open Access Tariff (OATT), September 30,

2008.




Ontario Demand Ontario’s 2010 forecast summer peak demand is 23,556 MW based on Monthly Normal weather. This forecast incorporates the impacts of planned conservation, growth in embedded generation, time of use rates, and some economic recovery. The forecast peak for 2010 summer is 3.4 percent lower than the 24,380 MW actual peak demand for 2009 summer, which occurred on August 17, 2009. Also, the 2010 summer forecast is 1.3 percent lower than last summer’s weather-corrected peak demand of 23,867 MW. The current forecast’s declining peak is the result of reductions due to conservation initiatives, time-of-use rates and the growth of embedded generation, which more than offsets the demand growth from an increasing building stock. The OPA provides the IESO with projected conservation savings arising from the OPAs and local distribution companies’ (LDC) initiatives. Validation and verification of these savings are the purview of the OPA and LDCs. A sizeable number of loads within the province bid their load into the market and are responsive to price and to dispatch instructions. Other loads have been contracted by the OPA to provide Demand Response under tight supply conditions. The forecast amount of these demand measures has been steadily increasing and now amounts to approximately 1,426 MW in total (about four percent of forecast demand) of which 951 MW is included for seasonal capacity planning purposes, with 545 MW of the included amount categorized as interruptible. 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. For the upcoming summer peak of 23,556 MW, the LFU is 1,283 MW. Economic factors do not have a significant impact in seasonal assessments. Since Ontario is a large geographic area, the IESO uses six weather stations to capture the weather variability across the province. Although the assessment is driven from the system’s perspective, the individual zones reflect their weather and economic diversity. The IESO addresses summer extreme weather conditions by using the most severe weather experienced since 1970 for each time period of the assessment. Generation The total capacity of existing installed generation resources (35,494 MW) and loads as a capacity resource (905 MW) connected to the IESO controlled grid is 36,399 MW, of which the amount of Existing-Certain capacity is 28,234 MW for June 2010. The remainder, 8,138 MW, is Existing-Other capacity for June 2010, which includes the on-peak resource de-ratings, planned outages, and transmission-limited resources. The Existing-Certain capacities for July, August, and September are 29,770 MW, 29,952 MW, and 28,561 MW respectively. There is 28 MW of inoperable capacity identified for the study period. Before June 2010, a new hydroelectric generator (16 MW) will be added to Healy Falls station. During the summer months, Thorold Cogeneration (236 MW) is planned to come into service,



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and an additional 46 MW of Demand Response will be added. Halton Hills Generating Station, a new 632 MW gas-fired facility, is projected to go into commercial operation later in 2010. To model wind resources in the seasonal assessments, the IESO uses an estimated wind capacity contribution during peak demand hours. This model captures wind output during the top five contiguous daily peak demand hours for the winter and summer seasons, as well as monthly shoulder periods. Two sets of wind data are considered: simulated wind data over a fixed ten-year history, and actual wind plant output data collected since March 2006. A conservative approach is employed, which selects the lesser value of the two data sets (simulated vs. actual) for each winter/summer season and shoulder period month. For the seasonal assessments, wind capacity contribution is represented deterministically, by selecting median values observed during the winter and summer seasons and shoulder period months. Wind capacity contribution for the summer season, June to September, is estimated at 11 percent of the installed capacity. The Existing-Certain capacity for wind is 119 MW and Existing-Other capacity is 965 MW. No other variable resources (solar, etc.) are connected to the IESO controlled grid or are projected to be connected in the study period. For biomass, the Existing-Certain capacity is 94 MW, and Existing-Other capacity is less than one MW. IESO resource adequacy assessments include hydroelectric generation capacity contributions based on median historical values of hydroelectric production plus operating reserve provided during weekday peak demand hours. The capacity assumptions are updated annually, in the second quarter of each year. Energy capability is provided by market participants’ forecasts. The amount of available hydroelectric generation is greatly influenced both by water-flow conditions on the respective river systems and by the way in which water is utilized by the generation owner. Material deviations from median conditions are not anticipated at this time. In the operating timeframe, water resources are managed by market participants through market offers to meet the hourly demands of the day. Since most hydro storages are energy limited, hydroelectric operators identify weekly and daily limitations for near-term planning in advance of real-time operations. The IESO does not anticipate any weather- or fuel-related constraints for the province that would reduce generating capacity. No generators are projected to be retired during the upcoming summer season. Generation outages planned over the summer months have been accounted in the Ontario reserve calculations. Reserves are adequate to cover forced extensions should they occur. Capacity Transactions on Peak No capacity imports or exports are forecast over the summer period. In its determination of resource adequacy, the IESO plans for Ontario to meet NPCC criteria without reliance on external resources to satisfy normal weather peak demands under planned supply conditions. Day to day, external resources are normally procured on an economic basis through the IESO-administered markets. To avoid deferral or cancellation of generator outages in the event that




operating reserve deficiencies are forecast in the near term, market participants may arrange limited external purchases of capacity. For use during daily operation, the IESO has agreements in place with neighbouring jurisdictions in NPCC, RFC, and MRO for emergency imports and with NPCC for reserve sharing. Transmission Since last summer, a new HVdc interconnection between Hawthorne transformer station (TS) in Ontario and Outaouais station in Québec entered commercial operation. A 200 Mvar shunt capacitor is anticipated to be placed in service at Buchanan TS and a new Hurontario switching station to be completed before the 2010 summer. There are no system related reliability concerns if the in-service dates for the above two projects are not met. The forced outage in 2008 to the 230 kV circuit BP76 on the Ontario-New York interconnection at Niagara reduces the total Ontario-New York import and export capability until its scheduled return to service in the last quarter of 2012. Phase angle regulators (PARs) are installed on the four Ontario-Michigan interconnections. One PAR, on Keith to Waterman 230 kV circuit J5D, has been in service and regulating since 1975. The next two available PARs are located on Lambton to St. Clair 230 kV circuits L4D and L51D. These are currently bypassed, however, but PARs can be placed in service and operated to control flows during emergency conditions. The last PAR, on Scott to Bunce Creek 230 kV circuit B3N, is being replaced and is projected to be available by the end of Quarter 2 in 2010. An agreement between the IESO, the Midwest ISO, Hydro One, and International Transmission Company is being negotiated for the operation of the PARs. 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 is scheduled for replacement by the beginning of Q3 in 2010. Regardless of these outages, Ontario meets all reliability criteria without dependence on any external resources. Ontario has many operating limits and instructions that could limit transfers under specific conditions, but for the forecast conditions, including design-criteria contingencies, sufficient resources and bulk system transfer capability are projected to be available to manage potential congestion and supply forecast demand. In the summer, Ontario’s theoretical maximum capability for coincident exports could be up to 6,000 MW and coincident imports up to 5,850 MW. These values represent theoretical levels that could be achieved only with a substantial reduction in generation dispatch in the West and Niagara transmission zones. In practice, the generation dispatch required for transfer levels this high would rarely, if ever, materialize. Therefore, at best, due to internal constraints in the Ontario transmission network in conjunction with external scheduling limitations, Ontario has an projected coincident import capability of approximately 4,600 MW.



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Below is the list of significant substation equipment that was added since the last summer. Four 230 Mvar shunt capacitor banks at Middleport TS Two 250 Mvar shunt capacitor banks at Nanticoke TS

Operational Issues IESO addresses summer extreme weather conditions by performing planning studies using the most severe weather experienced since 1970. Studies show that Ontario will have sufficient reserves over the summer period, except for four weeks, and then only under extreme weather conditions. Available operational and market measures and interconnection capability have been evaluated and are sufficient to meet summer energy demands. Ontario is expecting to experience surplus base load generation (SBG) under minimum demand conditions. Such SBG conditions are prevalent over the spring, summer, and fall months. Intermittent variable generators can be curtailed for reliability reasons. The IESO expects that any SBG conditions would be addressed through current processes. IESO is expecting to start a centralized wind forecasting pilot in 2010, ultimately leading to a wind forecasting service to improve the accuracy of wind generation forecasts. This will assist with the management of wind variability and its influence on load-generation balance. Demand measures currently comprise less than three percent of total resources. At these levels, any failure to respond does not pose any significant concern to reliability. Demand measures are grouped into two categories: price sensitive and voluntary. IESO considers only price sensitive demand for adequacy assessment purposes, and to be dispatched, they have to bid into the market, like other resources. By the end of 2010, households and small businesses in Ontario, totalling 4.5 million consumers, will have smart meters installed on their premises. As of December 2009, 3.4 million smart meters had been installed, with 350,000 customers paying time-of-use (TOU) rates. The implementation of TOU rates will ramp up significantly over the coming year. Early indications suggest that as consumers become more familiar with the new rate structure, load shifting away from peak and mid-peak hours starts to take place. The Green Energy and Green Economy Act passed by the Ontario legislature in May 2009 enables the implementation of a smart grid and imposes a regulatory obligation on distributors and transmitters to provide smart grid plans to the regulator. The feed-in tariff (FIT) program for renewable generation has attracted more than 8,000 MW in new project applications, but most approved projects will not be commissioned until at least 2011. There are no unusual operating conditions or environmental or regulatory restrictions that are projected to impact reliability for this summer. The Ontario program to reduce emissions from coal-fired generation is achievable and progressing without impacting reliability.




Reliability Assessment The IESO uses a multi-area resource adequacy model, in conjunction with power flow assessments, to determine the deliverability of resources to load. This process is described in the document “Methodology to Perform Long-Term Assessments.”93 The reserve margin target used for Ontario is 18.2 percent based on the NPCC criteria. The calculated reserve margin based on the 2010 forecasts for demand, resources, and net transactions is 31.3 percent for July. Planning reserves, determined on the basis of the IESO’s requirements for Ontario self-sufficiency, are above target levels for all weeks over this period for normal weather conditions. On average, the projected reserve margins for the upcoming summer are ten percent higher than the projected margin for the summer of 2009. These temporary levels are projected as Ontario positions itself for coal shutdowns in later years. The IESO requires demonstrated reliable performance from replacement resources prior to approving the removal of the coal facilities. Reserve requirements are established in conformance with the NPCC Regional criteria. The latest study results are published in the 18-Month Outlook.94 Due to the convergence of the natural gas and electricity sectors, the IESO continues to work with the Ontario gas transportation industry to identify and address issues. There are communication protocols in effect between the IESO and the gas pipe lines to manage and share information under tight supply conditions in either sector (gas or electricity). Summer gas demands are much reduced when compared with winter consumption and should not present any restrictions to generation. The IESO regularly conducts transmission studies that include results of stability, voltage, and thermal and short-circuit analyses in conformance with NPCC criteria. The IESO’s interim transmission studies in 2009 were conducted to comply with the NERC TPL standards in addition to NPCC criteria. Limits derived from the 2009 studies form the basis for 2010 summer operation. 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 assessment. These requirements are applied in facility planning studies. Seasonal operating limit studies review and confirm the limiting phenomenon identified in planning studies. Other Region-Specific Issues There are no other issues to report.

93 http://www.ieso.ca/imoweb/monthsYears/monthsAhead.asp. 94 http://www.ieso.ca/imoweb/pubs/marketReports/18MonthOutlook_2010feb.pdf.



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Subregion Description The province of Ontario covers an area of 1,000,000 square kilometres (415,000 square miles) with a population of 12 million. The Independent Electricity System Operator (IESO) directs the operations of the IESO-controlled grid (ICG) and administers the electricity market in Ontario. The ICG experiences its peak demand during the summer, although winter peaks still remain strong.



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QQuuéébbeecc IInntteerrccoonnnneeccttiioonn QQuuéébbeecc Demand Québec’s forecasted Internal Peak Demand for the 2010 NERC summer period is 20,677 MW, forecast to occur during September. Summer peak load is typically about 55 percent of winter peak load. The Load Serving Entity in Québec is Hydro-Québec Distribution (HQD). HQD is regulated by the Régie de l’énergie du Québec (Québec Energy Board) and as such, it must file a Procurement Plan and annual updates of this plan with the Régie. All the assumptions (economic, demographic, and energy-use) on which the HQD demand forecast is based are presented in the document “État D’avancement 2009 du Plan D’approvisionnement 2008–2017.”95 This document discusses, among other subjects, the following:

Demand and energy forecast Energy efficiency programs Resource procurement (demand and energy) Light and heavy forecast scenarios

Table NPCC-11 summarizes and compares Hydro-Québec’s actual and forecasted internal demands for 2009 and 2010.

Table NPCC-11: Québec 2010 Summer Internal Demand (MW)

June July August September Actual 2009 (A) 19,941 19,287 20,395 21,141Forecasted 2009 (B) 20,875 20,700 20,988 20,710Difference (A-B) -934 -1,413 -593 431Forecasted 2010 (C) 20,427 20,475 20,655 20,677Difference (B-C) 448 225 333 33

The table shows that the 2010 summer demand forecast is slightly lower than that of 2009 summer. The load forecast decrease is caused by the ongoing general economic slowdown. Hydro-Québec Distribution conducts its load forecast for the Québec Balancing Authority area represented as a single entity—there is no demand aggregation. The Area’s peak forecast information is coincident. Since Québec is a winter-peaking area, resource evaluations are based on coincident winter peak forecasts, with low, medium, and high scenarios.

95 http://www.regie-energie.qc.ca/audiences/EtatApproHQD/État%20d'avancement_2009.pdf.



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Since Québec is a winter-peaking Area, no interruptible load programs are required (nor are they available) for the Summer Operating Period. The demand forecast also takes into account the impact of energy efficiency programs and energy saving trends. Hydro-Québec Distribution promotes the wise use of electricity as a way to reduce demand. The programs and tools for promoting energy saving include the following:

For residential customers o Energy Wise home diagnostic o Recyc-Frigo (old refrigerator recycling) o Electronic thermostats o Energy Star-qualified appliances o Lighting o Pool-filter timers o Energy Star windows and patio doors o Rénoclimat and Novoclimat renovating grants managed by the Government of

Québec o Geothermal energy

For business customers — small and medium power users o Empower program for buildings optimization o Empower program for industrial systems o Efficient products program o Traffic light optimization program o Energy Wise diagnostic o Visilec electricity consumption analysis tool

For business customers — large power users o Building initiatives program o Industrial analysis and demonstration program o Plant retrofit program o Industrial initiatives program

Program characteristics (in English) can be found on the website “Programs and tools to be energy wise.”96 Climatic uncertainty is modeled by recreating each hour of the last 36-year period of climatic conditions (1971 through 2006) under the current load forecast conditions. Moreover, each year of historical data is shifted up to ± 3 days to gain information on conditions that occurred during a weekend, for example. Moreover, Hydro-Québec has developed hourly chronological load profiles based on a 36-year assessment of historical weather conditions (1971–2006). This methodology is useful to quantify weather uncertainty and its impacts on peak demand. Since Québec has a winter-peaking load profile, the uncertainty—measured by a standard deviation assessment—is lower during the summer than during the winter. For example, at the summer peak, weather conditions uncertainty, is about 300 MW—equivalent to one standard deviation. During winter, weather

96 http://www.hydroquebec.com/energywise/index.html



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uncertainty amounts to approximately 1,500 MW. Extreme weather deviations are quantified at about 800 MW for the summer peak and at about 4,700 MW for the winter peak. Generation The amount of Existing (-Certain, -Other, and -Inoperable) and Future (-Planned and -Other) capacity resources in service or projected to be in service from June 1, 2010, through September 30, 2010, is described in the following Table. Total Internal Capacity for 2010 summer is quite similar to what was posted last year for 2009 summer. The amount of Existing-Certain capacity in August is relatively lower than for the other months due to higher scheduled maintenance (Table NPCC-12).

Table NPCC-12: Anticipated Resources – Québec 2010 Summer (MW)

Capacity in 2010 June July August September Existing-Certain 32,158 33,864 30,756 32,195Existing-Other 8,739 7,032 10,138 8,698Existing-Inoperable 1,397 1,397 1,397 1,397Total Existing 42,294 42,293 42,291 42,290Future-Planned 0 0 0 0Future-Other 0 0 0 0Total Internal Capacity 42,294 42,293 42,291 42,290

Moreover, there are no planned capacity additions for the 2010 summer. In Québec, variable resources are constituted uniquely by wind capacity. The present wind power capacity installed in Québec is 642 MW. For summer assessments, this is entirely derated. The portion of Total Internal Capacity that is biomass is 224 MW. Normal hydro conditions are projected for the summer. Reservoir levels are sufficient to meet both peak demand and daily energy demand throughout the summer. To assess its energy reliability, Hydro-Québec Production has developed an energy criterion stating that sufficient resources should be available to go through sequences of two or four consecutive years of low water inflows totaling 64 TWh and 98 TWh respectively and having a two-percent probability of occurrence. These assessments are presented three times a year to the Québec Energy Board. Conditions that would create capacity reductions are not projected for the 2010 summer operating period. As a rule, Hydro-Québec Production’s generator maintenance during Summer Operating Periods is scheduled so as not to affect reliability in any way. As for 2010 summer particularly, TransCanada Energy’s (TCE) natural gas-fired generating station (507 MW) is still under a temporary shutdown agreement with HQD. This temporary shutdown does not affect reliability. Capacity Transactions on Peak The Québec Balancing Authority area does not require any external purchase for the 2010 Summer Operating Period in terms of resource adequacy due to its winter-peaking characteristic. There is, however, a firm purchase of 200 MW from the Maritimes Area, which is tied to



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specific generators. This purchase is backed by firm contracts for both generation and transmission. No part of this transaction is a Liquidated Damage Contract. On the other hand, Hydro-Québec Production has secured four firm sales backed by firm transmission contracts for the Summer Operating Period:

Ontario (Cornwall), 145 MW; New England, 310 MW; New York, 400 MW; New Brunswick (July, August, September), 175 MW.

Additional sales of 762 MW to the New York Balancing Authority Area are projected. With these sales, the Québec Balancing Authority area still projects higher than required reserve margins to meet its resource adequacy criterion. Firm transmission and resources back the entire portion of these sales. Finally, should an emergency situation occur, the Québec Balancing Authority Area can rely on imports from Ontario, New York, and the Maritimes. Import capabilities are shown in Table NPCC-13 in the Transmission section below. Capabilities may vary with system conditions. TransÉnergie has agreements with all neighboring Balancing Authority areas that detail conditions and procedures for exchanging emergency energy. A procedure specifying the Control Centre actions and communications for this energy exchange has been established Transmission During summer and autumn 2009, TransÉnergie commissioned the first and second 625 MW HVdc converters of the new Outaouais interconnection with the IESO. However, the full 1,250 MW interconnection capability was not available full-time due to Regional system limitations. In June 2010 a new double-circuit 315 kV line from Chénier (North of Montréal) to Outaouais will be placed in service along with a fourth 735/315 kV, 1,650 MVA transformer and a third 315 kV, 345 Mvar capacitor bank at Chénier. These new transmission additions are not required for the reliability of the Québec Balancing Authority area for the 2010 summer period. However, these additions will permit full use of the Outaouais interconnection capability and thus enhance import and export capacity to the IESO. Most transmission line, transformer, and generating unit maintenance is done during the summer period. Resource availability is therefore not a problem during the Summer Operating Period, even though exports to summer-peaking areas of NPCC are sustained during peak hours. As a matter of fact, available resources for exports often exceed actual interconnection summer transfer capabilities. Internal generating unit and transmission outage plans are assessed to meet internal demand, firm sales, projected additional sales, and uncertainty margins. Interconnection maintenance outages are scheduled outside peak periods. Therefore, no impact on internal reliability and inter-area capabilities with neighboring systems is expected. No internal transmission constraints that could significantly impact reliability are forecast in the Québec Balancing Authority area for the 2010 Summer Operating Period.



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The following table indicates the inter-Regional transfer capabilities out of and into Québec with its neighbor systems for the 2010 Summer Operating Period.97 These limits represent Normal Transfer Capability (NTC) values for the Summer Operating Period. Actual Feasible Transfer Capability (FTC) values during peak periods in Québec may be lower. Both NTC and FTC values are shown in the NPCC Seasonal Reliability Assessments.

Table NPCC-13: 2010 Summer Interconnection Normal Transfer Capability

Interconnection Limit out of

Québec (MW) Limit into

Québec (MW) Ontario North (D4Z, H4Z) 85 85Ontario Ottawa (X2Y, P33C, Q4C) 410 120Ontario Brookfield (D5A, H9A) 250 110Ontario Beauharnois (B5D, B31L) 800 470Ontario Ottawa (Outaouais Interconnection) 1,250 1,250 New York (CD11, CD22) 199 100New York (7040) 1,500 1,000 New England (Highgate) 225 170New England (Stanstead-Derby) 40 0New England (Sandy Pond) 2,000 1,900 Maritimes (Madawaska + Eel River) 877 400

These limits recognize transmission or generation constraints in both Québec and its neighbors for the 2010 Summer Operating Period. They are reviewed periodically with neighboring systems and are posted in the NPCC Seasonal Reliability Assessments. For example, for the 2010 summer period, Transformer T4 at Eel River, New Brunswick is out of service, thus limiting export and import capabilities. Moreover, these limits may not exactly correspond to other numbers posted in Hydro-Québec’s Annual Reports or on TransÉnergie’s website. Such numbers—usually corresponding to winter ratings—are maximum import/export capabilities available at any time of the year. The present NERC assessment focuses on summer conditions. Finally, no significant substation equipment such as SVCs, FACTS controllers, or HVdc systems has been added in the Québec Balancing Authority Area since the last summer season. Operational Issues TransÉnergie’s significant operating studies are performed for the winter season, where weather conditions will translate into higher demand levels. Readers may refer to the NPCC (Québec) section of the NERC 2009/2010 Winter Reliability Assessment for an overview of the latest winter studies.98

97 Limits obtained and updated from the NPCC Reliability Assessment for 2010 summer. 98 http://www.nerc.com/page.php?cid=4|61



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The Québec Area participates in NPCC’s seasonal CO-12 (Operations Planning) and CP-8 (Multi-Area Probabilistic Assessment) Working Group assessments of system reliability.99 All operational planning studies done in the Québec Balancing Authority area are done in compliance with NPCC and NERC planning standards. These include planning studies for the bulk power system, generation integration studies, NPCC reviews, transfer limit studies, etc. The last Comprehensive Review of the Québec transmission system for 2011–2012 was completed in May 2008. The last Interim Review of the Québec transmission system for 2014 was completed in November 2009. No particular operational problem is foreseen for the oncoming 2010 Summer Operating Period. Presently, the only variable resources integrated in the Québec Area are wind resources. The nameplate capacity is 642 MW but the maximum output to date has been 555 MW. Approximately 3,000 MW of additional wind resources are planned to come into service gradually until 2015. The Québec Balancing Authority area is a separate interconnection from the Eastern Interconnection into which other NPCC Areas (subregions) are interconnected. The system’s installed capacity is about 42,300 MW, but as little as 12,000 MW of capacity may be connected to the grid during summer low-load periods. System inertia may therefore be quite low. The Québec Interconnection’s frequency does not follow the Eastern Interconnection’s frequency. Frequency regulation is therefore a concern for the area. The normal frequency profile is 59.5 to 60.5 Hz and frequency excursions following a normal contingency may reach 58.5 to 61.5 Hz. Interconnections with other NPCC areas consist either of HVdc ties or radial generation to and from neighboring systems. Up to now, wind generation variability has not significantly impacted day-to-day operation of the system and the present level of wind generation does not necessitate particular operating procedures. However, data acquisition for different wind generation variables has been brought into the System Control Room and wind generation forecasting is used in the Balancing Area’s system forecasting software. For the longer term, a number of foreseeable impacts on system management may occur as follows and will be addressed:

Wind generation variability on system load and interconnection ramping Frequency and voltage regulation problems Increase of start-ups and shutdowns of hydroelectric units due to load-following coupled

with wind variability. Generally units must be operated within certain limits to ensure efficiency

Reduction of low load operation flexibility due to low inertial response of wind generation coupled to must-run hydroelectric generation

No reliability concerns resulting from high levels of Demand Response resources are forecasted in the Québec Balancing Authority area. Demand response resources consist only of interruptible load programs, which are not used during Summer Operating Periods.

99 http://www.npcc.org/documents/reports/Seasonal.aspxs



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Moreover, there are no environmental and, or regulatory restrictions that could impact reliability in Québec for the 2010 Summer Operating Period. No smart grid programs have been fully implemented at Hydro-Québec during the past year. Hydro-Québec TransÉnergie is pursuing a project called IMAGINE that uses automated maintenance and remote monitoring data management to improve system management efficiency. Through digital technologies such as remote monitoring, telemetry, and remote uploading and diagnostics, maintenance operations can be targeted more precisely and some of these can be remotely performed. In 2009, 32 substations were connected to a remote maintenance center near Montréal and a second remote maintenance center was opened in Québec City. No other unusual operating conditions that could significantly impact reliability for the upcoming summer are anticipated in Québec. Reliability Assessment Assessment The assessment process, be it for Resource Adequacy or for Transmission Adequacy, used for Québec assessments is documented in NPCC Regional Reliability Reference Directory #1—Design and Operation of the Bulk Power System. The process is summarized in the NPCC Regional Assessment Summary above. When performing these assessments, Hydro-Québec Distribution and Hydro-Québec TransÉnergie conform to the NPCC “Guidelines for Area Reviews” and all requirements therein. Table NPCC-14 shows projected reserve margins for the Summer Operating Period based on Existing, Certain Capacity and Net Firm Transactions. The target reserve margin for the Québec Balancing Authority area is 10 percent.

Table NPCC-14: Projected Québec Reserve Margins for 2010 Summer

Reserve Margin June July August SeptemberMW 11,020 12,492 9,204 10,621 % 54.0 61.1 44.6 51.4

Assumptions used to establish reserve margin criteria, target margin levels, and resource adequacy levels, and results thereof, are discussed in the last 2009 Québec Interim review of Resource Adequacy100 (filed with NPCC on December 2009 for approval). The latest resource adequacy study for 2010 summer is the 2009 Québec Interim Review of Resource Adequacy.101 The target margin level for the Québec Balancing Authority area is 10 percent. The 2010 summer projected reserve margins are in the same range as last summer’s projected reserve margins (between 45 percent and 60 percent) as can be seen in Table NPCC-14, above.

100 https://www.npcc.org/documents/reviews/Resource.aspx 101 https://www.npcc.org/documents/reviews/Resource.aspx



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Discussion of fuel supplies does not apply to the Québec Balancing Authority area since about 94 percent of resources are hydroelectric and the system is winter-peaking. Fossil fuel generation is used only for peaking purposes during the winter and fuel is stocked on-site at the beginning of each winter period. Transient and voltage stability studies are performed regularly by TransÉnergie (Transmission Planner) to establish transfer limits on all interfaces. No particular problems are anticipated for the light load Summer Operating Period. Voltage support in the southern part of the system (load area) is a concern only during the Winter Operating Period, especially during episodes of heavy load. Readers may refer to the NERC 2009/2010 Winter Reliability Assessment,102 NPCC (Québec) section, to overview the latest winter studies. Other Region-Specific Issues There are no other subregion-specific anticipated reliability concerns for the 2010 Summer Operating Period. Subregion Description The Québec Area is winter peaking. Summer peak load is typically about 55 percent of winter peak load. The all-time internal peak demand was 37,230 MW set on January 16, 2009. Summer peak demands are in the order of 21,000 MW. Installed capacity in 2010 is around 42,300 MW of which 39,700 MW (94 percent) is hydroelectric capacity (Renewable energy). Existing wind capacity totals 642 MW. Transmission voltages on the system are 735, 315, 230, 161 and 120 kV. Transmission line length totals about 33,244 km (20,658 miles). The Québec Balancing Authority area is a separate Interconnection from the Eastern Interconnection into which other NPCC Areas are interconnected. TransÉnergie ─ the Transmission Owner and Operator in Québec ─ has interconnections with Ontario, New York, New England and the Maritimes. Interconnections consist of either HVdc ties or radial generation or load to and from the neighboring systems. The population served is around 7 million and the Québec Area covers about 1,668,000 km (644,300 square miles). Most of the population lives in the St. Lawrence River basin, and the largest load area is in the southwest part of the province, mainly around the Greater Montréal area, extending down to the Québec City area.

102 http://www.nerc.com/page.php?cid=4|61



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Region Description The Northeast Power Coordinating Council, Inc. (NPCC Inc.) is the international Regional Reliability Organization (RRO) for Northeastern North America. Its purpose is to promote the reliable and efficient operation of the international, interconnected bulk power systems in Northeastern North America through the establishment of Regionally-specific criteria, coordination of system planning, design and operations, assessment of reliability and monitoring, and enforcement of compliance with such criteria and other applicable criteria. In the development of reliability criteria, NPCC Inc., to the extent possible, facilitates attainment of fair, effective, and efficient competitive electric markets. NPCC Inc. is a not-for-profit New York corporation. The geographic area covered includes New York, the six New England states, and Ontario, Québec, and Maritime Provinces in Canada. The total population served is approximately 56 million over approximately one million square miles. NPCC was originally formed shortly after the 1965 Northeast Blackout to promote the reliability and efficiency of the interconnected power systems within its geographic area. NPCC restructured in response to U.S. energy legislation signed into law in August 2005 in preparation for the certification of an Electric Reliability Organization (ERO) and subsequent execution of a Regional Delegation Agreement and Memorandums of Understanding with appropriate Canadian Provincial regulatory and governmental authorities. Membership interests were transferred to NPCC Inc., and a separate and independent, affiliated, not-for-profit corporation, NPCC: Cross-Border Regional Entity, Inc. (NPCC CBRE). NPCC CBRE (http://www.npcc-cbre.org/default.aspx) will perform functions delegated or contracted to it from the ERO, to be backstopped by the Federal Energy Regulatory Commission (FERC) and Canadian Provincial authorities. Additional information can be found on the NPCC website (http://www.npcc.org/). .

About This Report


2010 Su

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AAbboouutt TThhiiss RReeppoorrtt The 2010 Summer Reliability Assessment represents NERC’s independent judgment of the reliability of the bulk power system in North America for the 2010 summer season (Table B).103 The report specifically provides a high-level reliability assessment of 2010 summer resource adequacy and operating reliability, an overview of projected electricity demand growth, Regional highlights, and Regional self-assessments. NERC’s primary objective in providing 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 as needed. The assessment process enables bulk power system users, owners, and operators to systematically document their operational preparations for the coming season and exchange vital system reliability information. This assessment is prepared by NERC in its capacity as the Electric Reliability Organization.104 NERC cannot order construction of generation or transmission or adopt enforceable standards having that effect, as that authority is explicitly withheld by Section 215 of the U.S. Federal Power Act and similar restrictions in Canada.105 In addition, NERC does not make any projections or draw any conclusions regarding projected electricity prices or the efficiency of electricity markets. Report Preparation NERC prepared the 2010 Summer Reliability Assessment with support from the Reliability Assessment Subcommittee (RAS), which is under the direction of the NERC Planning Committee (PC). The report is based on data and information submitted by each of the eight Regional Entities in March 2010 and updated, as required, throughout the drafting process. Any other data sources consulted by NERC staff in the preparation of this document are identified in the report. NERC’s staff performed detailed data checking on the reference information received by the Regions, as well as review of all self-assessments to form its independent view and assessment of the reliability of the 2010 summer season. NERC also uses an active peer review process in developing reliability assessments. The peer review process takes full advantage of industry

103Bulk power system reliability, as defined in the How NERC Defines Bulk Power System Reliability section of this report, does

not include the reliability of the lower voltage distribution systems, which systems account for 80 percent of all electricity supply interruptions to end-use customers.

104Section 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.”

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

Table B: NERC’s Annual Assessments

Assessment Outlook Published

Summer Assessment

Upcoming season May

Long-Term Assessment

10 year October

Winter Assessment Upcoming season November

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2010 Summer Reliability Assessm

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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 a self-assessment, which is assigned to three or four RAS members, including NERC Operating Committee (OC) liaisons, from other Regions for an in-depth and comprehensive review. Reviewer comments are discussed with the Regional Entity’s representative and refinements and adjustments are made as necessary. The Regional self-assessments are then subjected to scrutiny and review by the entire subcommittee. This review ensures members of the subcommittee are fully convinced that each Regional self-assessment is accurate, thorough, and complete. The PC endorses the report for NERC’s Board of Trustee (BOT) approval, considering comments from the OC. The entire document, including the Regional self-assessments, is then reviewed in detail by the Member Representatives Committee (MRC) and NERC management before being submitted to NERC’s BOT for final approval. In the 2010 Summer Reliability Assessment, the baseline information on future electricity supply and demand is based on several assumptions:106

Supply and demand projections are based on industry forecasts submitted in March 2010. Any subsequent demand forecast or resource plan changes may not be fully represented.

Peak demand and Reserve Margins are based on average weather conditions and assumed forecast economic activity at the time of submittal. Weather variability is discussed in each Region’s self-assessment.

Generating and transmission equipment will perform at historical availability levels. Future generation and transmission facilities are commissioned and in-service as planned;

planned outages take place as scheduled. Demand reductions expected from Demand Response programs will yield the forecast

results, if they are called on. Other peak Demand-Side Management programs are reflected in the forecasts of Net

Internal Demand. Enhancements to the 2010 Summer 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 Long-Term Reliability Assessment processes required improvement. To achieve this goal, the PC formed a task force, the Reliability Assessment Improvement Task Force, and directed it to develop recommendations and a plan for improvement.

106 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 (50/50 forecast).

About This Report


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A number of the task force’s recommendations107 were incorporated into the 2010 Summer Reliability Assessment, including:

1. The Reliability Assessment Guidebook Task Force released its Reliability Assessment Guidebook (Version 1.2),108 to provide increased transparency on the reliability assessments process, resource reporting, load forecasting, and general assumptions made in NERC’s Assessments. Regions referenced the guidebook to enhance their contributions to this report.

2. In order to broaden stakeholder input, OC involvement was incorporated to support the assessment development and approval process.

3. To broaden NERC’s assessment beyond Regional Entity boundaries, assessments were performed on MidwestISO-RTO and PJM-RTO. These assessments are performed based on the RTO operating boundaries and reflect an enhanced assessment of resource adequacy and operational reliability within those boundaries.

Report Content Responsibility The following NERC industry groups have collaborated efforts to produce NERC’s 2010 Summer Reliability Assessment:

107 See http://www.nerc.com/files/Reliability%20Improvement%20Report%20RAITF%20100208.pdf 108 For the Reliability Assessment Guidebook, Version 1.2, see

http://www.nerc.com/docs/pc/ragtf/Reliability_Assessment_%20Guidebook%20v1.2%20031909.pdf

NERC Group Relationship Contribution

Board of Trustees NERC’s Independent Board

● Review Assessment Approve for publication

Planning Committee (PC) Reports to NERC’s Board of Trustees

Review Assessment and Endorse

Operating Committee (OC) Reports to NERC’s Board of Trustees

Review Assessment and provide comments to PC

Reliability Assessment Subcommittee (RAS)

Reports to the PC

Provide Regional Self-Assessments

Peer Reviews Review Report

Reliability Assessment Guidebook Task Force (RAGTF)

Reports to the PC Develop Reliability Assessment Guidebook

Data Coordination Working Group (DCWG)

Reports to the RAS Develop data and Regional reliability narrative requests

Reliability Concepts Used in This Report



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RReelliiaabbiilliittyy CCoonncceeppttss UUsseedd iinn TThhiiss RReeppoorrtt

How NERC Defines Bulk Power System Reliability NERC defines the reliability of the interconnected BPS in terms of two basic and functional aspects109:

Adequacy — is the ability of the electric system to supply the aggregate electric power and energy requirements of the electricity consumers at all times, taking into account scheduled and reasonably expected unscheduled outages of system components.

Operating Reliability — is the ability of the electric system to withstand sudden disturbances such as electric short circuits or unanticipated loss of system components.

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 — demand that the end-use customer makes available to its LSE

via contract or agreement for curtailment.110 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.

109See http://www.nerc.com/docs/pc/Definition-of-ALR-approved-at-Dec-07-OC-PC-mtgs.pdf more information about the

Adequate Level of Reliability (ALR). 110 Interruptible Demand (or Interruptible Load) is a term used in NERC Reliability Standards. See Glossary of Terms Used in

Reliability Standards, February 12, 2008, at http://www.nerc.com/files/Glossary_12Feb08.pdf.

Reliability Concepts Used in This Report


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Demand Response Concepts and Categorization As the industry’s use of Demand-Side Management (DSM) evolves, NERC’s data collection and reliability assessment need to change highlighting programs and demand-side service offerings that have an impact on bulk system reliability. NERC’s seasonal and long-term reliability assessments currently assume projected energy efficiency EE programs are included in the Total Internal Demand forecasts, including adjustments for utility indirect Demand Response programs such as conservation programs, improvements in efficiency of electric energy use, rate incentives, and rebates. DSM involves all activities or programs undertaken to influence the amount and timing of electricity use (See Figure Demand 1). Note the context of these activities and programs is DSM, rather than bulk power systems and, therefore, they are not meant to mirror those used in the system context. The Demand Response categories defined in Terms Used in this Report support Figure Demand 1

.

Figure Demand 1: Demand-Side Management and NERC’s Data Collection

Demand-Side Management (DSM)

Demand Response (DR) New Energy Efficiency

Dispatchable Non-Dispatchable

Controllable Economic

Energy-PriceCapacity Ancillary Energy-Voluntary

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

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NNEERRCC IInnaauugguurraatteedd PPrroojjeecctteedd DDRR DDaattaa CCoolllleeccttiioonn iinn 22000088

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DDaattaa CChheecckkiinngg MMeetthhooddss AApppplliieedd NERC's Reliability Assessment Data Validation and Error Checking Program ensures the Reliability Assessment Database operates with consistent data. It uses routines, often called “validation rules,” that check for correctness, meaningfulness, and security of data that are added into the system. Internal data checking and validation refers to the practice of validating and checking data through internal processes (e.g., Historical Comparison, Range and Limits, Data Entry Completeness, Correct Summations) to maintain high quality data (See Table Data Checking 1). The rules are implemented through automated processes — data dictionary for data checking and logic for validation. Incorrect data can lead to data corruption or a loss of data integrity. Data validation verifies it is valid, sensible, and secure before it is processed for analysis. The program uses scripts, developed on a composite Microsoft Excel and Microsoft Access platform, to provide a semi-automated solution.

Table Data Checking 1: NERC Data Quality Framework and Attributes Data Quality Attribute Responsible Entity Data Check Performed

Accuracy Ensure data are the correct values

Industry Validation rules Consistent with other

external sources Accessibility Data items should be easily obtainable and in a usable format

DCWG, NERC, and RE Data is submitted in the provided template

Comprehensiveness All required data items are submitted

DCWG, RE, and Stakeholders

Check for null values Compare to prior year’s

null values Inquiries to the RE

Currentness The data should be up-to-date

RE and Stakeholders Consistent with other external sources

Consistency Definitions of the data elements should be the same across different reporting entities

DCWG, NERC DCWG leads in this effort

Assumptions are verified with the RE

Definition Clear definitions should be provided so the current and future data users can understand the assumptions

DCWG, NERC Staff The DCWG leads in this effort

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In 2010, NERC implemented a two-phase approach to data checking and validation. Phase I is a data collection form-side validation procedure based on defined rules. It also specifies the error type or condition not met. This phase was applied to the data collection forms to prevent the incorrect entry of data and prompts the user with feedback explaining the error. Validation rules are used to ensure entered data meets defined thresholds, ranges, or both. An error halts the input of data until a valid entry is provided. For example, the reported deratings of existing generating units is a subset of the “Existing-Other” supply category; therefore, the sum of all deratings must be less than or equal to the value reported as “Existing-Other.” This example is shown below:

Incorrect Correct 6b Existing-Other (Note: The sum of 6b1 through 6b7 must be <= 6b) 5,000 5,0006b1 Wind Derate On-Peak 800 4006b2 Solar Derate On-Peak 445 2326b3 Hydro Derate On-Peak 789 06b4 Biomass Derate On-Peak 0 06b5 Load as a Capacity Resource Derate On-Peak 0 06b6 Energy Only 435 1,3456b7 Scheduled Outage - Maintenance 4,000 2,3986b8 Transmission-Limited Resources 0 0

Once data is submitted to NERC, reported values can be analyzed for validity. Phase II of NERC’s data checking and validation effort involves comparing submitted data to historical submissions. For this phase, a back-end database is used to compare key values, such as peak demand projections and installed capacity to what was reported in prior years. Only values with comparable definitions are considered. In addition, a preliminary analysis can identify potential errors. If a potential error is detected, it is flagged and categorized by one of the following error types:

Categorization — values may be incorrectly categorized Summation — values are incorrectly summed Double Count — identifies a possible double counting issue Missing Data — key values are null Confirmation — a notable discrepancy which must be confirmed

The Reliability Assessment Data Validation and Error Checking Program identifies potential errors and generates a report for further investigation. Thresholds are determined for each value and flagged when a major deviation is determined. For example, peak demand projections must be within a +/- 2 percent threshold to pass; all others are flagged. When errors are identified, NERC staff can send a request for data corrections to the Regional Entities. The Regional Entities then have the opportunity to update their data submittals or explain the flagged error. In addition, NERC’s Data Coordination Working Group (DCWG) monitors the quality of data reported. The DCWG serves as a point of contact responsible for supporting NERC staff, continuously maintaining high quality data and provide enhancements to current practices. Due to improved data checking processes in 2009 and 2010, and increased coordination between NERC staff and Regional representatives, data errors were minimal for the 2010 Summer Reliability Assessment.

Seasonal Climate Prediction Assumptions



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Dynamic Predictables Assumptions Dynamic Predictables LLC Columbia, MO 65205-1365 http://www.dynapred.com Dynamic Predictables specializes in predicting climate on site specific and regional basis at monthly time step for multiple years in advance. DynaPred predictions are distinguished by extensive area coverage with high spatial and temporal resolution while achieving accuracy at extrema with reliability. Prediction Title: Atlas First Level Prediction Type: dynamic climate Data vintage: through March 2010 Predictions of Monthly Mean Temperature and Monthly Total Precipitation are provided in three classifications (Above, Near, Below Average) for the 22 NERC subregions. Data unit basis is the US/DoC/NOAA/NCDC climate division system with 344 Climate Divisions for the continental US (ftp://ftp.ncdc.noaa.gov/pub/data/cirs/). The narrowly scored combined temperature and precipitation accuracy of Atlas First Level predictions since 2002 has been around 78% (81% temperature, 75% precipitation) above the three-classifier breakeven value of 1/3 with all climate divisions being predicted each month. The NERC SA prediction represents grouping that of the NCDC-cirs 344 into NERC subregions. Canada climate data is based on individual weather stations with no single-station to aggregation parallel to the US NCDC-cirs. Individual weather station data is available online through Environment Canada’s Climate Services office (http://www.climate.weatheroffice.gc.ca/Welcome_e.html ). NERC subregions and Regions cover large areas. Observations and DynaPred temperature and precipitation predictions with them often differ significantly within regions. Regional aggregate predictions and observed thereby may not reflect the DynaPred resolvable and resolved component predictions that would better reflect individual load areas.

Terms Used in This Report


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TTeerrmmss UUsseedd iinn TThhiiss RReeppoorrtt

Ancillary (Controllable Demand Response) — Demand-side resource displaces generation deployed as operating reserves and/or regulation; penalties are assessed for nonperformance.

Ancillary Services -- Those services that are necessary to support the transmission of capacity and energy from resources to loads while maintaining reliable operation of the Transmission Service Provider's transmission system in accordance with good utility practice. (From FERC order 888-A.)

Anticipated Capacity Resources – Existing-Certain and Net Firm Transactions plus Future-Planned capacity resources plus Expected Imports, minus Expected Exports. (MW)

Anticipated Reserve Margin (%) – Anticipated Capacity Resources minus Net Internal Demand shown as a percent of Net Internal Demand

Capacity (generator) — The output power, commonly expressed in megawatts (MW), that generating equipment can supply to system load.

Capacity (Controllable Demand Response) — Demand-side resource displaces or augments generation for planning and/or operating resource adequacy; penalties are assessed for nonperformance.

Capacity Categories — See Existing Generation Resources, Future Generation Resources, and Conceptual Generation Resources.

Conceptual Generation Resources — This category includes generation resources that are not included in Existing Generation Resources or Future Generation Resources, but have been identified and/or announced on a resource planning basis through one or more of the following sources:

1. Corporate announcement 2. Entered into or is in the early stages of an approval process 3. Is in a generator interconnection (or other) queue for study 4. “Place-holder” generation for use in modeling, such as generator modeling needed to

support NERC Standard TPL analysis, as well as, integrated resource planning resource studies.

Resources included in this category may be adjusted using a confidence factor (%) to reflect uncertainties associated with siting, project development or queue position.

Conservation – see Energy Conservation

Contractually Interruptible (Curtailable) (Controllable Capacity Demand Response) — Dispatchable, Controllable, Demand-side management achieved by a customer reducing its load upon notification from a control center. The interruption must be mandatory at times of system emergency. 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 accordance with contractual arrangements, can be interrupted at the time of the Regional Entity’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.




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Controllable (Demand Response) — Dispatchable Demand Response, demand-side resources used to supplement generation resources resolving system and/or local capacity constraints.

Critical Peak Pricing (CPP) (Non-dispatchable Time-Sensitive Pricing Demand Response) — 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.

Critical Peak Pricing (CPP) with Control (Controllable Capacity Demand Response) — Dispatchable, Controllable, 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.

Curtailable — See Contractually Interruptible

Demand – See Net Internal Demand, Total Internal Demand

Demand Bidding & Buyback (Controllable Energy-Price Demand Response) — Demand-side resource that enable large consumers to offer specific bid or posted prices for specified load reductions. Customers stay at fixed rates, but receive higher payments for load reductions when the wholesale prices are high.

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.

Derate (Capacity) — The amount of capacity that is expected to be unavailable on seasonal peak.

Direct Control Load Management (DCLM) or Direct Load Control (DLC) (Controllable Capacity Demand Response) — Demand-Side Management that is under the direct control of the system operator. DCLM may control the electric supply to individual appliances or equipment on customer premises. DCLM as defined here does not include Interruptible Demand.

111

Dispatchable (Demand Response) — Demand-side resource curtails according to instruction from a control center.

Economic (Controllable Demand Response) — Demand-side resource that is dispatched based on an economic decision.

Emergency (Controllable Energy-Voluntary Demand Response) — Demand-side resource curtails during system and/or local capacity constraints.

Energy Conservation — The practice of decreasing the quantity of energy used.

Energy Efficiency — Permanent changes to electricity use through replacement with more efficient end-use devices or more effective operation of existing devices. Generally, it results in reduced consumption across all hours rather than event-driven targeted load reductions.

Energy Emergency Alert Levels — The categories for capacity and emergency events based on Reliability Standard EOP—002-0:

Level 1 — All available resources in use.

111 DCLM is a term defined in NERC Reliability Standards. See Glossary of Terms Used in Reliability Standards, Updated April

20, 2009 www.nerc.com/files/Glossary_2009April20.pdf



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Balancing Authority, Reserve Sharing Group, or Load Serving Entity foresees or is experiencing conditions where all available resources are committed to meet firm load, firm transactions, and reserve commitments, and is concerned about sustaining its required Operating Reserves, and Non-firm wholesale energy sales (other than those that are recallable to meet reserve requirements) have been curtailed.

Level 2 — Load management procedures in effect. Balancing Authority, Reserve Sharing Group, or Load Serving Entity is no longer

able to provide its customers’ expected energy requirements, and is designated an Energy Deficient Entity.

Energy Deficient Entity foresees or has implemented procedures up to, but excluding, interruption of firm load commitments. When time permits, these procedures may include, but are not limited to: Public appeals to reduce demand, Voltage reduction, Interruption of non-firm end use loads in accordance with applicable contracts, Demand-side management, and Utility load conservation measures.

Level 3 — Firm load interruption imminent or in progress. Balancing Authority or Load Serving Entity foresees or has implemented firm

load obligation interruption. The available energy to the Energy Deficient Entity, as determined from Level (Alert) 2, is only accessible with actions taken to increase transmission transfer capabilities.

Energy Only (Capacity) — Energy Only Resources are generally generating resources that are designated as energy-only resources or have elected to be classified as energy-only resources and may include generating capacity that can be delivered within the area but may be recallable to another area.

Energy-Price (Controllable Economic Demand Response) — Demand-side resource that reduces energy for incentives.

Energy-Voluntary (Controllable Demand Response) — Demand-side resource curtails voluntarily when offered the opportunity to do so for compensation, but nonperformance is not penalized.

Existing-Certain (Existing Generation Resources) — Existing generation resources available to operate and deliver power within or into the Region during the period of analysis in the assessment. Resources included in this category may be reported as a portion of the full capability of the resource, plant, or unit. This category includes, but is not limited to the following:

1. Contracted (or firm) or other similar resource confirmed able to serve load during the period of analysis in the assessment.

2. Where organized markets exist, designated market resource112 that is eligible to bid into a market or has been designated as a firm network resource.

3. Network Resource113, as that term is used for FERC pro forma or other regulatory approved tariffs.

112 Curtailable demand or load that is designated as a network resource or bid into a market is not included in this category, but

rather must be subtracted from the appropriate category in the demand section. 113 Curtailable demand or load that is designated as a network resource or bid into a market is not included in this category, but

rather must be subtracted from the appropriate category in the demand section.




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4. Energy-only resources114 confirmed able to serve load during the period of analysis in the assessment and will not be curtailed.115

5. Capacity resources that can not be sold elsewhere. 6. Other resources not included in the above categories that have been confirmed able to

serve load and not to be curtailed116 during the period of analysis in the assessment.

Existing-Certain & Net Firm Transactions – Existing-Certain capacity resources plus Firm Imports, minus Firm Exports. (MW)

Existing-Certain and Net Firm Transactions (%) (Margin Category) – Existing-Certain & Net Firm Transactions minus Net Internal Demand shown as a percent of Net Internal Demand.

Existing Generation Resources — See Existing-Certain, Existing-Other, Existing, but Inoperable.

Existing, Inoperable (Existing Generation Resources) — This category contains the existing portion of generation resources that are out-of-service and cannot be brought back into service to serve load during the period of analysis in the assessment. However, this category can include inoperable resources that could return to service at some point in the future. This value may vary for future seasons and can be reported as zero. This includes all existing generation not included in categories Existing-Certain or Existing-Other, but is not limited to, the following:

1. Mothballed generation (that can not be returned to service for the period of the assessment).

2. Other existing but out-of-service generation (that can not be returned to service for the period of the assessment).

3. This category does not include behind-the-meter generation or non-connected emergency generators that normally do not run.

4. This category does not include partially dismantled units that are not forecasted to return to service.

Existing-Other (Existing Generation Resources) — Existing generation resources that may be available to operate and deliver power within or into the Region during the period of analysis in the assessment, but may be curtailed or interrupted at any time for various reasons. This category also includes portions of intermittent generation not included in Existing-Certain. This category includes, but is not limited to the following:

1. A resource with non-firm or other similar transmission arrangements. 2. Energy-only resources that have been confirmed able to serve load for any reason

during the period of analysis in the assessment, but may be curtailed for any reason. 3. Mothballed generation (that may be returned to service for the period of the

assessment). 4. Portions of variable generation not counted in the Existing-Certain category (e.g., wind,

solar, etc. that may not be available or derated during the assessment period). 5. Hydro generation not counted as Existing-Certain or derated. 6. Generation resources constrained for other reasons.

114 Energy Only Resources are generally generating resources that are designated as energy-only resources or have elected to be

classified as energy-only resources and may include generating capacity that can be delivered within the area but may be recallable to another area (Source: 2008 EIA 411 document OMB No. 1905-0129).” Note: Other than wind and solar energy, WECC does not have energy-only resources that are counted towards capacity.

115 Energy only resources with transmission service constraints are to be considered in category Existing, Other. 116 Energy only resources with transmission service constraints are to be considered in category Existing, Other.



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Expected (Transaction Category) — A category of Purchases/Imports and Sales/Exports contract including:

1. Expected implies that a contract has not been executed, but in negotiation, projected or other. These Purchases or Sales are expected to be firm.

2. Expected Purchases and Sales should be considered in the reliability assessments.

Firm (Transaction Category) — A category of Purchases/Imports and Sales/Exports contract including:

1. Firm implies a contract has been signed and may be recallable. 2. Firm Purchases and Sales should be reported in the reliability assessments. The

purchasing entity should count such capacity in margin calculations. Care should be taken by both entities to appropriate report the generating capacity that is subject to such Firm contract.

Future Generation Resources (See also Future-Planned and Future-Other) — This category includes generation resources the reporting entity has a reasonable expectation of coming online during the period of the assessment. As such, to qualify in either of the Future categories, the resource must have achieved one or more of these milestones:

1. Construction has started. 2. Regulatory permits being approved, any one of the following:

a. Site permit b. Construction permit c. Environmental permit

3. Regulatory approval has been received to be in the rate base. 4. Approved power purchase agreement. 5. Approved and/or designated as a resource by a market operator.

Future-Other (Future Generation Resources) — This category includes future generating resources that do not qualify in Future-Planned and are not included in the Conceptual category. This category includes, but is not limited to, generation resources during the period of analysis in the assessment that may:

1. Be curtailed or interrupted at any time for any reason. 2. Energy-only resources that may not be able to serve load during the period of analysis

in the assessment. 3. Variable generation not counted in the Future-Planned category or may not be

available or is derated during the assessment period. 4. Hydro generation not counted in category Future-Planned or derated. 5. Resources included in this category may be adjusted using a confidence factor to reflect

uncertainties associated with siting, project development or queue position.

Future-Planned (Future Generation Resources) — Generation resources anticipated to be available to operate and deliver power within or into the Region during the period of analysis in the assessment. This category includes, but is not limited to, the following:

1. Contracted (or firm) or other similar resource. 2. Where organized markets exist, designated market resource117 that is eligible to bid into

a market or has been designated as a firm network resource.


rather must be subtracted from the appropriate category in the demand section.




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3. Network Resource118, as that term is used for FERC pro forma or other regulatory approved tariffs.

4. Energy-only resources confirmed able to serve load during the period of analysis in the assessment and will not be curtailed.119

5. Where applicable, included in an integrated resource plan under a regulatory environment that mandates resource adequacy requirements and the obligation to serve.

Load as a Capacity Resource (Controllable Capacity Demand Response) — the magnitude of customer demand that, in accordance with contractual arrangements, is committed to pre-specified load reductions when called upon by a balancing authority. These resources are not limited to being dispatched during system contingencies and may be subject to economic dispatch from wholesale balancing authorities. Additionally, this capacity may be used to meet resource adequacy obligations when determining Planning Reserve Margins.

NERC Reference Reserve Margin Level (%) — Either the Target Reserve Margin provided by the Region/subregion or NERC assigned based on capacity mix (i.e., thermal/hydro). 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 Reserve Margin level is adopted as the NERC Reference Reserve Margin Level. If not, NERC assigned 15 percent Reserve Margin for predominately thermal systems and for predominately hydro systems, 10 percent.

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.

Non-dispatchable (Demand Response) — Demand-side resource curtails according to tariff structure, not instruction from a control center.

Non-Firm (Transaction Category) — A category of Purchases/Imports and Sales/Exports contract including:

1. Non-Firm implies a non-firm contract has been signed. 2. Non-Firm Purchases and Sales should not be considered in the reliability assessments.

Non-Spin Reserves (Controllable Ancillary Demand Response) — Demand-side resource not connected to the system but capable of serving demand within a specified time.

On-Peak (Capacity) — The amount of capacity that is expected to be available on seasonal peak.

Prospective Capacity Reserve Margin (%) – Prospective Capacity Resources minus Net Internal Demand shown as a percent of Net Internal Demand.

Prospective Capacity Resources – Anticipated Capacity Resources plus Existing-Other capacity resources, minus all Existing-Other deratings (Includes derates from variable resources, energy only resources, scheduled outages for maintenance, and transmission-limited resources), plus Future-Other capacity resources, minus all Future-Other deratings. (MW)


rather must be subtracted from the appropriate category in the demand section. 119 Energy only resources with transmission service constraints are to be considered in category Future-Other.



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Provisional (Transaction Category) — A category of Purchases/Imports and Sales/Exports contract including:

1. Provisional implies that the transactions are under study, but negotiations have not begun. These Purchases and Sales are expected to be provisionally firm.

2. Provisional Purchases and Sales should be considered in the reliability assessments.

Purchases/Imports Contracts – See Transaction Categories

Real Time Pricing (RTP) (Non-dispatchable Time-Sensitive Pricing Demand Response) — 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.

Reference Reserve Margin Level – See NERC Reference Reserve Margin Level

Regulation (Controllable Ancillary Demand Response) — Demand-side resources responsive to Automatic Generation Control (AGC) to provide normal regulating margin.

Renewable Energy — The United States Department of Energy, Energy Efficiency & Renewable Energy glossary defines “Renewable Energy” as “energy derived from resources that are regenerative or for all practical purposes can not be depleted. Types of renewable energy resources include moving water (hydro, tidal and wave power), thermal gradients in ocean water, biomass, geothermal energy, solar energy, and wind energy. Municipal solid waste (MSW) is also considered to be a renewable energy resource.”120 The government of Canada has a similar definition.121 Variable generation is a subset of Renewable Energy—See Variable Generation.

Renewables — See Renewable Energy

Reserve Margin (%) — See Anticipated Capacity Reserve Margin (%) and Prospective Capacity Reserve Margin (%). Roughly, Capacity minus Demand, divided by Demand or (Capacity-Demand)/Demand. Replaced Capacity Margin(s) (%) for NERC Assessments in 2009.

Sales/Exports Contracts – See Transaction Categories

Spinning/Responsive Reserves (Controllable Ancillary Demand Response) — 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.

System Peak Response Transmission Tariff (Non-dispatchable Time-Sensitive Pricing Demand Response) - Rate and/or price structure in which interval metered customers reduce load during coincident peaks as a way of reducing transmission charges.

Target Reserve Margin (%) — Established target for Reserve Margin by the Region or subregion. Not all Regions report a Target Reserve Margin. The NERC Reference Reserve Margin Level is used in those cases where a Target Reserve Margin is not provided.

Total Internal Demand: 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 indirect Demand-Side Management programs such as conservation programs, improvements in efficiency of electric energy use, all non-dispatchable Demand Response programs (such as Time-of-Use, Critical Peak Pricing, Real Time Pricing and System 120 http://www1.eere.energy.gov/site_administration/ glossary.html#R 121 http://www.cleanenergy.gc.ca/faq/ index_e.asp#whatiscleanenergy




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Peak Response Transmission Tariffs) and some dispatchable Demand Response (such as Demand Bidding and Buy-Back). Adjustments for controllable Demand Response should not be incorporated in this value.

Time-of-Use (TOU) (Non-dispatchable Time-Sensitive Pricing Demand Response) — Rate and/or price structures with different unit prices for use during different blocks of time.

Time-Sensitive Pricing (Non-dispatchable Demand Response) — Retail rates and/or price structures designed to reflect time-varying differences in wholesale electricity costs, and thus provide consumers with an incentive to modify consumption behavior during high-cost and/or peak periods.

Transaction Categories (See also Firm, Non-Firm, Expected and Provisional) — Contracts for Capacity are defined as an agreement between two or more parties for the Purchase and Sale of generating capacity. Purchase contracts refer to imported capacity that is transmitted from an outside Region or subregion to the reporting Region or subregion. Sales contracts refer to exported capacity that is transmitted from the reporting Region or subregion to an outside Region or subregion. For example, if a resource subject to a contract is located in one Region and sold to another Region, the Region in which the resource is located reports the capacity of the resource and reports the sale of such capacity that is being sold to the outside Region. The purchasing Region reports such capacity as a purchase, but does not report the capacity of such resource. Transmission must be available for all reported Purchases and Sales.

Transmission-Limited Resources — The amount of transmission-limited generation resources that have known physical deliverability limitations to serve load within the Region.

Example: If capacity is limited by both studied transmission limitations and generator derates, the generator derates take precedence. For example, a 100 MW wind farm with a wind capacity variation reduction of 50 MW and a transmission limitation of 60 MW would take the 50 MW wind variation reduction first and list 10 MW in the transmission limitation.

Transmission Status Categories — Transmission additions were categorized using the following criteria:

Under Construction Construction of the line has begun

Planned (any of the following) Permits have been approved to proceed Design is complete Needed in order to meet a regulatory requirement

Conceptual (any of the following) A line projected in the transmission plan A line that is required to meet a NERC TPL Standard or included in a powerflow

model and cannot be categorized as “Under Construction” or “Planned” Projected transmission lines that are not “Under Construction” or “Planned”

Variable Generation — Variable generation technologies generally refer to generating technologies whose primary energy source varies over time and cannot reasonably be stored to address such variation.122 Variable generation sources which include wind, solar, ocean and some hydro generation resources are all renewable based. Variable generation in this report 122 http://www.nerc.com/files/IVGTF_Report_041609.pdf



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refers only to wind and solar resources. There are two major attributes of a variable generator that distinguish it from conventional forms of generation and may impact the bulk power system planning and operations: variability and uncertainty.

Variability: The output of variable generation changes according to the availability of the primary fuel (wind, sunlight and moving water) resulting in fluctuations in the plant output on all time scales.

Uncertainty: The magnitude and timing of variable generation output is less predictable than for conventional generation.




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References: Glossary of Terms Used in Reliability Standards, Updated April 20, 2009 www.nerc.com/files/Glossary_2009April20.pdf Instructions for NERC Winter Reliability Assessment – Data Reporting Form ERO-2009W, May 15, 2009 Reliability Assessments Guidebook, Version 1.2, March 18, 2008 http://www.nerc.com/docs/pc/ragtf/Reliability_Assessment_%20Guidebook%20v1.2%20031909.pdf Reliability Standards for the Bulk Electric Systems in North America, Updated May 20, 2009 http://www.nerc.com/files/Reliability_Standards_Complete_Set_2009May20.pdf

Abbreviations Used in This Report


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AAbbbbrreevviiaattiioonnss UUsseedd iinn TThhiiss RReeppoorrtt A/C Air Conditioning AEP American Electric Power AFC Available Flowgate Capability ASM Ancillary Services Market ATCLLC American Transmission Company ATR AREA Transmission Review (of NYISO) AWEA American Wind Energy Association AZ-NM-SNV Arizona-New Mexico-Southern Nevada (Subregion of WECC) BA Balancing Authorities BCF Billion cubic feet BCFD Billion cubic feet per day CA-MX-US California-México (Subregion of WECC)CFE Commission Federal de Electricidad CFL Compact Fluorescent Light CMPA California-Mexico Power Area COI California-Oregon Intertie COS Coordinated Outage (transmission) System CPUC California Public Utilities Commission CRO Contingency Reserve Obligation CRPP Comprehensive Reliability Planning Process (of NYISO) DADRP Day-Ahead Demand Response Program dc Direct Current DCLM Direct Controlled Load Management DFW Dallas/Fort Worth DLC Direct Load Control DOE U.S. Department of Energy DSG Dynamics Study Group DSI Direct-served Industry DSM Demand-Side Management DVAR D-VAR® reactive power compensation system EDRP Emergency Demand Response Program EE Energy Efficiency EEA Energy Emergency Alert EECP Emergency Electric Curtailment Plan EIA Energy Information Agency (of DOE) EILS Emergency Interruptible Load Service (of ERCOT) EISA Energy Independence and Security Act of 2007 (USA) ELCC Effective Load-carrying Capability EMTP Electromagnetic Transient Program ENS Energy Not Served EOP Emergency Operating Procedure ERAG Eastern Interconnection Reliability Assessment Group ERCOT Electric Reliability Council of Texas ERO Electric Reliability Organization FCITC First Contingency Incremental Transfer Capability FCM Forward Capacity Market




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FERC U.S. Federal Energy Regulatory Commission FP Future-Planned FO Future-Other FRCC Florida Reliability Coordinating Council GADS Generating Availability Data System GDP Gross Domestic Product GGGS Gerald Gentleman Station Stability GHG Greenhouse Gas GRSP Generation Reserve Sharing Pool (of MAPP) GTA Greater Toronto Area GWh Gigawatt hours HDD Heating Degree Days HVac Heating, Ventilating, and Air Conditioning IA Interchange Authority ICAP Installed Capacity ICR Installed Capacity Requirement IESO Independent Electric System Operator (in Ontario) IOU Investor Owned Utility IPL/NRI International Power Line/Northeast Reliability Interconnect Project IPSI Integrated Power System Plan IRM Installed Reserve Margin IROL Interconnection Reliability Operating Limit IRP Integrated Resource Plan ISO Independent System Operator ISO-NE New England Independent System Operator kV Kilovolts (one thousand volts) LaaRs Loads acting as a Resource LCR Locational Installed Capacity Requirements LDC Load Duration Curve LFU Load Forecast Uncertainty LNG Liquefied Natural Gas LOLE Loss of Load Expectation LOLP Loss Of Load Probability LOOP Loss of off-site power LRP Long Range Plan LSE Load-serving Entities LTRA Long-Term Reliability Assessment LTSG Long-term Study Group MAAC Mid-Atlantic Area Council Maf Million acre-feet MAIN Mid-America Interconnected Network, Inc. MAPP Mid-Continent Area Power Pool MCRSG Midwest Contingency Reserve Sharing Group MISO Midwest Independent Transmission System Operator MPRP Maine Power Reliability Program MRO Midwest Reliability Organization MVA Megavolt amperes Mvar Mega-vars MW Megawatts (millions of watts) MWEX Minnesota Wisconsin Export



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NB New Brunswick NBSO New Brunswick System Operator NDEX North Dakota Export Stability Interface NEEWS New England East West Solution NERC North American Electric Reliability Corporation NIETC National Interest Electric Transmission Corridor NOPSG Northwest Operation and Planning Study Group NPCC Northeast Power Coordinating Council NPDES National Pollutant Discharge Elimination System NPPD Nebraska Public Power District NSPI Nova Scotia Power Inc. NTSG Near-term Study Group NWPP Northwest Power Pool Area (subregion of WECC) NYISO New York Independent System Operator NYPA New York Planning Authority NYRSC New York State Reliability Council, LLC NYSERDA New York State Energy and Research Development Agency OASIS Open Access Same Time Information Service OATT Open Access Transmission Tariff OP Operating Procedure OPA Ontario Power Authority OPPD Omaha Public Power District ORWG Operating Reliability Working Group OTC Operating Transfer Capability OVEC Ohio Valley Electric Corporation PA Planning Authority PACE PacifiCorp East PAR Phase Angle Regulators PC NERC Planning Committee PCAP Pre-Contingency Action Plans PCC Planning Coordination Committee (of WECC) PJM PJM Interconnection PRB Powder River Basin PRC Public Regulation Commission PRSG Planned Reserve Sharing Group PSA Power Supply Assessment PUCN Public Utilities Commission of Nevada QSE Qualified Scheduling Entities RA Resource Adequacy RAP Remedial Action Plan RAR Resource Adequacy Requirement RAS Reliability Assessment Subcommittee of NERC Planning Committee RC Reliability Coordinator RCC Reliability Coordinating Committee RFC ReliabilityFirst Corporation RFP Request For Proposal RGGI Regional Greenhouse Gas Initiative RIS Resource Issues Subcommittee of NERC Planning Committee RMPA Rocky Mountain Power Area (subregion of WECC) RMR Reliability Must Run




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RMRG Rocky Mountain Reserve Group RP Reliability Planner RPM Reliability Pricing Mode RRS Reliability Review Subcommittee RSG Reserve Sharing Group RTEP Regional Transmission Expansion Plan (for PJM) RTO Regional Transmission Organization RTP Real Time Pricing RTWG Renewable Technologies Working Group SA Security Analysis SasKPower Saskatchewan Power Corp. SCADA Supervisory Control and Data Acquisition SCC Seasonal Claimed Capability SCD Security Constrained Dispatch SCDWG Short Circuit Database Working Group SCEC State Capacity Emergency Coordinator (of FRCC) SCR Special Case Resources SEMA Southeastern Massachusetts SEPA State Environmental Protection Administration SERC SERC Reliability Corporation SMUD Sacramento Municipal Utility District SOL System Operating Limits SPP Southwest Power Pool SPS Special Protection System SPS/RAS Special Protection Schemes / Remedial Action Schemes SRIS System Reliability Impact Studies SRWG System Review Working Group STATCOM Static Synchronous Compensator STEP SPP Transmission Expansion Plan SVC Static Var Compensation TCF Trillion Cubic Feet TFCP Task Force on Coordination of Planning THI Temperature Humidity Index TIC Total Import Capability TID Total Internal Demand TLR Transmission Loading Relief TOP Transmission Operator TPL Transmission Planning TRE Texas Regional Entity TRM Transmission Reliability Margins TS Transformer Station TSP Transmission Service Provider TSS Technical Studies Subcommittee TVA Tennessee Valley Authority USBRLC United States Bureau of Reclamation Lower Colorado Region UFLS Under Frequency Load Shedding Schemes UVLS Under Voltage Load-Shedding var Voltampre reactive VACAR Virginia and Carolinas (subregion of SERC) VSAT Voltage Stability Assessment Tool



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WALC Western Area Lower Colorado WECC Western Electricity Coordinating Council WTHI Weighted Temperature-Humidity Index WUMS Wisconsin-Upper Michigan Systems

Reliability Assessment Subcommittee Roster



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RReelliiaabbiilliittyy AAsssseessssmmeenntt SSuubbccoommmmiitttteeee RRoosstteerr Chair Mark J Kuras

Senior Engineer PJM Interconnection, L.L.C. 955 Jefferson Ave Valley Forge Corporate Center Norristown, Pennsylvania 19403

(610)-666-8924 (610)-666-4779 Fx [email protected]

Regional Entity Representatives – Members of the Electric Reliability Organization: Reliability Assessment and Performance Analysis Group (ERO-RAPA Group)

Vice Chair, FRCC

Vince Ordax Manager of Planning

Florida Reliability Coordinating Council 1408 N. Westshore Blvd Tampa, Florida 33607

(813)-207-7988 (813) 289-5646 Fx [email protected]

MRO John Seidel

Principal Engineer Midwest Reliability Organization 1970 Oakcrest Avenue Roseville, Minnesota 55113

(651) 855-1716 (651) 855-1712 Fx [email protected]

NPCC John G. Mosier, Jr.

AVP-System Operations Northeast Power Coordinating Council, Inc. 1040 Avenue of the Americas-10th floor New York, New York 10018

(212) 840–4907 (212) 302 –2782 Fx [email protected]

RFC Jeffrey Mitchell, P.E.

Director, Engineering ReliabilityFirst Corporation 320 Springside Dr. Suite 300 Akron, Ohio 44333


SERC Herbert Schrayshuen

Director, Reliability Assessment

SERC Reliability Corporation 2815 Coliseum Centre Drive Charlotte, North Carolina 28217

(704) 940-8223 (315) 439 1390 Fx [email protected]

SPP Mak Nagle

Manager of Technical Studies & Modeling

Southwest Power Pool 415 N. McKinley Suite 140 Little Rock, Arkansas 72205


TRE William C Crews, P.E.

Regional Planning Assessment Engineer, Sr.

Texas Regional Entity 2700 Via Fortuna Suite 225 Austin, Texas 78746

(512) 275-7533 [email protected]

WECC David J. Godfrey

Director, Standards Development and Planning Services

Western Electricity Coordinating Council 155 North 400 West, Suite 200 Salt Lake City, Utah 84103




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ERCOT, ISO/RTO

Dan M Woodfin Director, System Planning

Electric Reliability Council of Texas, Inc. 2705 West Lake Dr. Taylor, Texas 76574


MRO

Hoa V Nguyen Resource Planning Coordinator

Montana-Dakota Utilities Co. 400 North 4th Street Bismarck, North Dakota 58501

701-222-7656 701-222-7872 Fx [email protected]

ISO/RTO Peter Wong

Manager, Resource Adequacy

ISO New England, Inc. One Sullivan Road Holyoke, Massachusetts 01040-2841


RFC

Bernie M. Pasternack, P.E. Managing Director - Transmission Asset Management

American Electric Power 700 Morrison Road Gahanna, Ohio 43230-8250


RFC, IOU

Esam A.F. Khadr Manager - Delivery Planning

Public Service Electric and Gas Co. 80 Park PlazaT-14A Newark, New Jersey 07102


SERC

Hubert C. Young Manager of Transmission Planning

South Carolina Electric & Gas Co. 220 Operations Way MC J37 Cayce, South Carolina 29033


SERC, IOU, DCWG Chair

K. R. Chakravarthi Manager, Interconnection and Special Studies

Southern Company Services, Inc. Southern Company Services, Birmingham, Alabama 35203


WECC, State/ Municipal Utility

James Leigh-Kendall Regulatory Compliance Officer

Sacramento Municipal Utility District 6002 S Street b303 Sacramento, California 95852

916-732-5357 (916) 732-7527 Fx [email protected]

ISO/RTO Jesse Moser

Manager, Regulatory Studies

Midwest ISO, Inc. P.O. Box 4202 Carmel, Indiana 46082-4202


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


Canada-At-Large, ISO/RTO

Dan Rochester, P. Eng. Manager, Reliability Standards and Assessments

Independent Electricity System Operator Station A, Box 4474 Toronto, Ontario M5W 4E5





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FERC Keith N. Collins Manager, Electric Analysis Group

Federal Energy Regulatory Commission 888 First Street, NE Washington, D.C. 20426


FERC Sedina Eric Electrical Engineer

Federal Energy Regulatory Commission 888 First Street, NE, 92-77 Washington, D.C. 20426


RFC, LFWG Chair

Bob Mariotti Supervisor – Short Term Forecasting

DTE Energy 2000 Second Avenue 787WCB Detroit, Michigan 48226-1279


FRCC Alternate

John Odom, Jr. Vice President of Planning and Operations

Florida Reliability Coordinating Council 1408 N. Westshore Blvd., Suite 1002 Tampa, Florida 33607-4512

813-207-7985 (813) 289-5646 Fx [email protected]

MRO Alternate

Salva R. Andiappan Manager – Reliability Assessment and Performance Analysis

Midwest Reliability Organization 2774 Cleveland Avenue N. Roseville, Minnesota 55113


RFC Alternate

Paul Kure Senior Consultant, Resources

ReliabilityFirst Corporation 320 Springside Drive Suite 300 Akron, Ohio 44333


SPP Alternate

Alan C Wahlstrom Lead Engineer, Compliance

16101 La Grande Dr. Suite 103 Littlerock, Arkansas 72223


WECC Alternate

Bradley M. Nickell Renewable Integration and Planning Director

Western Electricity Coordinating Council 155 North 400 West, Suite 200 Salt Lake City , Utah 84103

(801) 455-7946 (720) 635-3817 [email protected]

OC Liaison

Jerry Rust President

Northwest Power Pool Corporation 7505 NE Ambassador Place, St R Portland, Oregon 97035


OC Liaison

James Useldinger Manager, T&D System Operations

Kansas City Power & Light Co. PO Box 418679 Kansas City, Missouri 64141


Observer DOE

Patricia Hoffman Acting Director Research and Development

Department of Energy 1000 Independence Avenue SW 6e-069 Washington, D.C. 20045




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Observer DOE

Peter Balash Senior Economist

U.S. Department of Energy 626 Cochrans Mill Road P.O. Box 10940 Pittsburgh, Pennsylvania 15236


Observer DOE

Erik Paul Shuster Engineer

U.S. Department of Energy 626 Cochrans Mill Road P.O. Box 10940 Pittsburgh, Pennsylvania 15236


Observer DOE

Maria A. Hanley Program Analyst

Department of Energy 626 Cochrans Mill Road MS922-342C P.O. Box 10940 Pittsburgh, Pennsylvania 15236


Observer

C. Richard Bozek Director, Environmental Policy

Edison Electric Institute 701 Pennsylvania Avenue, NW Washington, D.C. 20004


Observer Erick Hasegawa

Engineer Midwest ISO, Inc. Carmel Office PO Box 4202 Carmel, Indiana 46082

317-910-8626 [email protected]

North American Electric Reliability Corporation Staff Roster


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NNoorrtthh AAmmeerriiccaann EElleeccttrriicc RReelliiaabbiilliittyy CCoorrppoorraattiioonn SSttaaffff RRoosstteerr North American Electric Reliability Corporation Telephone: (609) 452‐8060 116‐390 Village Boulevard Fax: (609) 452‐9550 Princeton, New Jersey 08540‐5721

Reliability Assessment and Performance Analysis

Mark G. Lauby Director of Reliability Assessment and Performance Analysis

[email protected]

Jessica Bian Manager of Benchmarking [email protected]

Aaron Bennett Engineer of Reliability Assessments

[email protected]

John Moura Technical Analyst, Reliability Assessment

[email protected]

Rhaiza Villafranca Technical Analyst, Benchmarking

[email protected]

Chrissy Vegso Administrative Assistant [email protected]

to ensure reliability bulk power system

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