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2008 Summer Reliability Assessment to ensure reliability of the the bulk power system May 2008 116-390 Village Blvd., Princeton, NJ 08540 609.452.8060 | 609.452.9550 fax www.nerc.com This Page Left Intentionally Blank Page 2 NERC 2008 Summer Reliability Assessment Table of Contents Table of Contents INTRODUCTION............................................................................................................. 5 PROGRESS SINCE SUMMER 2007 .............................................................................. 8 KEY FINDINGS............................................................................................................... 9 1. Capacity Margins Adequate ..................................................................................................................................9 2. Coal Inventories Below Average, Natural Gas Supply is Healthy ......................................................................11 3. Demand Response Reduces Demand, Provides Ancillary Service .....................................................................13 4. Wind Resources Contribute to Capacity .............................................................................................................16 RESOURCES, DEMAND AND CAPACITY MARGINS ................................................ 17 Projected Margins Adequate for 2008 Summer ......................................................................................................18 Extreme Weather Impact on Reliability ..................................................................................................................20 Notes for Table 1a through 1d.................................................................................................................................25 REGIONAL RELIABILITY ASSESSMENT HIGHLIGHTS............................................ 26 ERCOT....................................................................................................................................................................26 FRCC ......................................................................................................................................................................26 MRO........................................................................................................................................................................27 NPCC ......................................................................................................................................................................27 RFC .........................................................................................................................................................................29 SERC.......................................................................................................................................................................30 SPP ..........................................................................................................................................................................31 WECC .....................................................................................................................................................................31 REGIONAL RELIABILITY SELF-ASSESSMENTS ...................................................... 32 ERCOT.......................................................................................................................................................................33 FRCC..........................................................................................................................................................................40 MRO ...........................................................................................................................................................................46 NPCC..........................................................................................................................................................................58 Maritime Area .........................................................................................................................................................59 New England...........................................................................................................................................................62 New York ................................................................................................................................................................68 Ontario ....................................................................................................................................................................73 Québec ....................................................................................................................................................................78 RFC.............................................................................................................................................................................85 SERC ..........................................................................................................................................................................96 Central...................................................................................................................................................................100 Delta ......................................................................................................................................................................102 Page 3 NERC 2008 Summer Reliability Assessment Table of Contents Gateway ................................................................................................................................................................105 Southeastern ..........................................................................................................................................................106 VACAR.................................................................................................................................................................108 SPP............................................................................................................................................................................112 WECC.......................................................................................................................................................................117 Northwest Power Pool (NWPP) Area ...................................................................................................................120 California–Mexico Power Area.............................................................................................................................122 Rocky Mountain Power Area ................................................................................................................................123 Arizona-New Mexico-Southern Nevada Power Area ...........................................................................................124 ABBREVIATIONS USED IN THIS REPORT .............................................................. 129 CAPACITY & DEMAND DEFINITIONS IN THIS REPORT ........................................ 131 RELIABILITY ASSESSMENT SUBCOMMITTEE ...................................................... 134 Page 4 NERC 2008 Summer Reliability Assessment Introduction Introduction The North American Electric Reliability Corporation’s (NERC) mission is to ensure the bulk power system in North America is reliable. To achieve this objective, NERC develops and enforces reliability standards; monitors the bulk power system; assesses and reports on future adequacy; evaluates owners, operators, and users for reliability preparedness; and offers education and certification programs to industry personnel. NERC is a non-profit, self- regulatory organization that relies on the diverse and collective expertise of industry participants that comprise its various committees and sub-groups. It is subject to oversight by governmental authorities in Canada and the United States (U.S.).1 NERC assesses and reports on the reliability and adequacy of the North American bulk power system divided into the eight regional areas as shown on the map below2. The users, owners, and operators of the bulk power system within these areas account for virtually all the electricity supplied in the U.S., Canada, and a portion of Baja California Norte, Mexico. ERCOT RFC Electric Reliability ReliabilityFirst Council of Texas Corporation FRCC SERC Florida Reliability SERC Reliability Coordinating Council Corporation MRO SPP Midwest Reliability Southwest Power Pool, Organization Incorporated NPCC WECC Northeast Power Western Electricity Note: The highlighted area between SPP and SERC Coordinating Council, Coordinating Council denotes overlapping regional boundaries Inc. The 2008 Summer Reliability Assessment provides key findings, a high-level reliability assessment, projected electricity demand/resource growth, regional assessment highlights, and regional self-assessments. The report represents NERC’s independent judgment of the reliability and adequacy of the bulk power system in North America for the 2008 summer season. NERC’s primary role is to identify areas of concern regarding the reliability of the North American bulk power system and to make recommendations for their remedy. 1 As of June 18, 2007, the U.S. Federal Energy Regulatory Commission (FERC) granted NERC the legal authority to enforce reliability standards with all U.S. users, owners, and operators of the bulk power system, and made compliance with those standards mandatory and enforceable. Reliability standards are also mandatory and enforceable in Ontario and New Brunswick, and NERC is seeking to achieve comparable results in the other Canadian provinces. NERC will seek recognition in Mexico once the necessary legislation is adopted. 2 Note ERCOT and SPP are tasked with reliability assessments as they are regional electrical areas. SPP-RE (SPP – Regional Entity) and TRE (Texas Regional Entity) are functional entities to whom NERC delegates certain authorities. Page 5 NERC 2008 Summer Reliability Assessment Introduction This assessment is prepared by NERC in its capacity as the U.S. Electric Reliability Organization.3 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. Energy Policy Act of 20054. In addition, NERC does not make any projections or draw any conclusions regarding expected electricity prices or the efficiency of electricity markets. Assessment Preparation NERC prepared the 2008 Summer Reliability Assessment with support from the Reliability Assessment Subcommittee (RAS) under the direction of NERC’s Planning Committee (PC). The report enables bulk power system users, owners and operators to systematically document their operational preparations for the coming season and exchange vital system reliability information. Data and regional self-assessments are submitted by each of the eight regional entities in March 2008 and updated, as required. Other data sources consulted by NERC staff are also identified. NERC uses an active peer review process in developing its reliability assessments, which takes full advantage of industry subject matter expertise from all sectors of the industry. This process also provides an essential check and balance for ensuring the validity of the data and information provided by the regional entities. Each regional self-assessment is individually assigned to two or three NERC’s Annual Assessments subcommittee members from other Assessment Outlook Published regions for an in-depth and Summer comprehensive review. Reviewer Assessment Upcoming season May comments are discussed with the Region Entity’s representative and refinements Long-Term 10 year October and adjustments are made as necessary. Assessment Each regional self-assessment is then subjected to scrutiny and review by the Winter Assessment Upcoming season November entire subcommittee. This review ensures that each member of the subcommittee is fully convinced that each regional self-assessment is accurate, thorough, and complete. The entire document, including the regional self-assessments, is reviewed by the PC and the Member Representatives Committee (MRC). At the conclusion of this process, NERC management reviews the assessment results in detail before the report is submitted to the NERC Board of Trustees for final approval. 3 Section 39.11(b) of the U.S. FERC’s regulations provide that: “The Electric Reliability Organization shall conduct assessments of the adequacy of the Bulk-Power System in North America and report its findings to the Commission, the Secretary of Energy, each Regional Entity, and each Regional Advisory Body annually or more frequently if so ordered by the Commission.” 4 http://frwebgate.access.gpo.gov/cgi-bin/getdoc.cgi?dbname=109_cong_bills&docid=f:h6enr.txt.pdf Page 6 NERC 2008 Summer Reliability Assessment Introduction In this assessment, the baseline calculations of electricity supply and internal demand projections are based on several assumptions, outlined below. • NERC’s projections are based on the forecasts provided to the Regional Entities and submitted by them to NERC in March 2008. Any subsequent resource plan changes may not be fully represented. • Baseline calculations of peak demand and capacity margins are established on average weather conditions as well as assumptions for economic activity. The impact of the variability of weather is discussed in each of the regional self assessment narratives. • Generating and transmission equipment will perform at historical availability levels. • Planned outages and additions/upgrades of generation and transmission will be completed as scheduled. • Demand reductions expected from demand response contracts will be effective, if and when they are needed. • Other peak demand-side management programs are reflected in the forecasts of net internal demand. • Firm transfers between regions are contractually arranged and occur as projected. See http://www.nerc.com/~members/reliability_concepts/documents.htm for more background on reliability concepts used in this report. Page 7 NERC 2008 Summer Reliability Assessment Progress Since Summer 2007 Progress Since Summer 2007 Several of the reliability issues and concerns highlighted in NERC’s 2007 Summer Reliability Assessment are being addressed, including: • Reliability in the Boston, Southwest Connecticut and Greater Connecticut areas have improved with the addition of transmission and both supply and demand-side resources. • Texas has increased existing generation resources resulting in higher capacity margins. • Transmission investments in the Southeast totaling more than $1.1 billion in 2007 and nearly $1.5 billion projected for 2008 are improving reliability in the region. • Agreements are now in place to operate the installed phase angle regulators between Canada (Ontario) and the U.S. (Michigan). They are expected to help manage system congestion and control circulating or “loop” flows. Due to equipment failure, only three of the four phase angle regulators are expected to operate for the summer months. • Over 240 miles of bulk transmission have been added in WECC since last summer. Page 8 NERC 2008 Summer Reliability Assessment Key Findings Key Findings 1. Capacity Margins Adequate Net capacity margins for the U.S. increased by 1.9 percent over last summer’s assessment; net capacity margins in Canada show a slight decrease of 1 percent. These incremental changes are small and may be influenced by the changes in NERC’s capacity categories.5 Capacity margins, reflecting existing resources reasonably anticipated to operate and deliver power to or into the region along with firm capacity purchases, appear adequate6 for the 2008 summer months. Figure 1a: Change in U.S. Projected Figure 1b: Change in Canadian Net Capacity Margins from Projected Net Capacity Margins from Summer 2007 to Summer 2008 Summer 2007 to Summer 2008 50.0 50.0 45.0 45.0 40.0 40.0 Net Capacity Resources Margin Net Capacity Resources Margin 35.0 35.0 1% Decrease 30.0 30.0 1.9% Increase 2007 25.0 2007 25.0 2008 2008 20.0 20.0 15.0 15.0 10.0 10.0 5.0 5.0 0.0 0.0 A key factor in forecasting summer demands and, thereby, capacity margins are summer temperatures. During the 2006 and 2007 summers, temperatures for cooling (air conditioning) degree days was higher by 12 percent and 10 percent, respectively compared to normal conditions. For the 2008 summer, the U.S. National Oceanic and Atmospheric Administration (NOAA) has predicted temperatures will be near normal (i.e., 0.2 percent below normal) Reliability in Southern California Remains a Concern Though capacity resources were increased and system reinforcements completed in the southern California area, capacity margins still remain tight. Significant amounts of imported power are required to fortify capacity margins and preserve reliability, resulting in heavily loaded transmission lines into this area during peak conditions. As a result, unplanned major transmission or generation outages, or extreme temperatures/demand may lead to resource 5 The definitions of capacity categories were modified in 2008 (See Resources, Demand and Capacity Section); as a result, capacity margins may not be directly comparable to those cited in previous reports. 6 NERC defines the reliability of the interconnected bulk power system in terms of two basic and functional aspects: • Adequacy — The ability of the bulk power system to supply the aggregate electrical demand and energy requirements of the customers at all times, taking into account scheduled and reasonably expected unscheduled outages of system elements. • Operating Reliability — The ability of the bulk power system to withstand sudden disturbances such as electric short circuits or unanticipated loss of system elements. Page 9 NERC 2008 Summer Reliability Assessment Key Findings 7 constraints. The California ISO’s April 28, 2008 summer assessment presents deterministic and probabilistic analyses for its portion of southern California. The assessment states that “…voluntary conservation and on-call interruptible loads could be needed more frequently than normal.” The assessment also references a 10 percent probability that its portion of southern California may experience reserves declining to 3 percent. Drought Conditions in SERC Improving; Reliability Concerns Relieved Parts of the Southeast experienced severe drought conditions during 2007, leading to concerns over plant operability as water levels threatened to drop below plant cooling water intakes. A special reliability assessment conducted in March by SERC members studied hydrological scenarios (including some more severe than the projected 2008 summer conditions) and showed that there should be no reliability concerns for the upcoming summer, though some resource redispatch, increased imports and operating procedures may be required if drought conditions were to worsen. Current projections forecast normal rainfall in the Southeast during the 2008 summer.8 Reservoir levels are expected to be sufficient to support the generation needed to meet forecasted peak and daily energy demands for the summer period. At the present time, conditions in 2008 are improving in many (but not all) affected areas. If drought conditions were to worsen from this point forward in 2008, conditions in 2009 could be more severe than 2007. Figure 2: 2008 Summer Seasonal Drought Outlook in the U.S. Drought conditions persisting in southern California, Nevada, eastern New Mexico and western Texas currently appear to have no impact on reliability, though potential for wildfires as a result of dry conditions can threaten infrastructure and will be monitored throughout the summer months. 7 http://www.caiso.com/docs/2003/04/25/200304251132276595.html 8 http://www.cpc.ncep.noaa.gov/products/expert_assessment/drought_assessment.shtml Page 10 NERC 2008 Summer Reliability Assessment Key Findings 2. Coal Inventories Below Average, Natural Gas Supply is Healthy Coal9 Eastern U.S. coal markets have been 70 Days of Burn 5-Yr Rolling Ave disrupted by events in the world coal market, which began in late 2007. A shortage of coal 60 in the world market has driven world prices Days of Burn 50 for both thermal and coking coals to record levels. Exports of eastern U.S. coal are 40 projected to jump in 2008 by 20 to 30 million tons over 2007 volumes. 30 These events have created a possibility of 20 tight coal supplies for east electric power 1/1/2003 4/1/2003 7/1/2003 10/1/2003 1/1/2004 4/1/2004 7/1/2004 10/1/2004 1/1/2005 4/1/2005 7/1/2005 10/1/2005 1/1/2006 4/1/2006 7/1/2006 10/1/2006 1/1/2007 4/1/2007 7/1/2007 10/1/2007 1/1/2008 generators for the summer of 2008. Many power generators did not purchase all of their coal needs for 2008 in advance of the change Figure 3a: Northern Appalachia Coal StocksMarch-2008 in the market, and the remaining coal that is 70 available is in limited supply at very high Days of Burn 5-Yr Rolling Ave prices. Power generators, therefore are 60 relying on coal inventory at the power plants. Coal inventories were at healthy levels at the 50 D ays o f B u rn beginning of 2008, with the average for all eastern U.S. generators at 51.6 days of 40 average burn, which is near the 5-year high. However, the inventory levels differ for 30 different coal types. Inventories of western coal from the Powder River Basin have fully 20 recovered from the disruption of 2005, and 1/1 /2003 4/1 /2003 7/1 /2003 10/1 /2003 1/1 /2004 4/1 /2004 7/1 /2004 10/1 /2004 1/1 /2005 4/1 /2005 7/1 /2005 10/1 /2005 1/1 /2006 4/1 /2006 7/1 /2006 10/1 /2006 1/1 /2007 4/1 /2007 7/1 /2007 10/1 /2007 1/1 /2008 were unusually high entering 2008 at 64 days of average burn. Inventories of northern Appalachia coal had already fallen to relatively Figure 3b: Central Appalachia Coal Stocks March-2008 low levels (36.8 days) by the beginning of 2008 (Figure 3a), as this coal entered the export market earlier than any other thermal coal. Inventories of central Appalachia coal, the largest eastern coal region, were at a healthy 52 days of average burn entering 2008, but fell quickly in the first two months of 2008, dropping to 48 days of burn (Figure 3b). If the world coal market continues at its recent highs, it is possible that eastern power generators will see coal inventories drop during the summer of 2008. Reliability concerns are not expected as a result of this shift, but NERC will closely monitor these levels over the summer months to ensure adequate inventories exist to meet peak demands. 9 This material was prepared by Energy Ventures Analysis, Inc. providing an independent view of the coal and natural gas conditions for the 2008 Summer Page 11 NERC 2008 Summer Reliability Assessment Key Findings Natural Gas The outlook for U.S. natural gas supply is healthy heading into the 2008 summer season on all fronts. U.S. dry production of natural gas experienced a net increase of 2.2 BCFD in 2007 averaging 52.8 BCFD on the heels of record drilling levels and the industry’s focus on unconventional resources, such as the Barnett shale and Rockies region that offset decline in the more mature Gulf of Mexico. The upward trend has continued in early 2008 following production increases in the deepwater Gulf of Mexico in late 200710 and despite a very slight decline in the U.S. drilling rig count. Natural gas pipeline infrastructure has also experienced favorable expansion over the past two years adding a record high level of new capacity to the U.S. pipeline grid with additions of 12.7 BCFD in 2006 and 14.9 BCFD in 2007. U.S. working gas in storage ended the 2007/2008 winter season on March 31st at 1.242 trillion cubic feet (TCF), on par with the five-year average of 2003-2007 but below the record high levels of the prior two years. Minimum average injections of 9.7 BCFD will be required through the summer season to reach the five year average of 3.321 TCF by the start of the 2008/2009 winter season on November 1st, and with 10.1 BCFD required to reach 3.400 TCF. These rates of injection compare favorably to the five year range of 8.2-11.5 BCFD. U.S. natural gas storage capacity increased about 150 BCF during the past two years, with another 45 BCF of new capacity expected in 2008. North America will also benefit from the addition of six new LNG regasification terminals coming online through 2008, with additions of global LNG liquefaction plants lagging somewhat. While the U.S.’s ability to attract LNG imports will partially depend on relative global prices, U.S. imports of LNG are likely to rise moderately in 2008, possibly by as much as 0.5 to 1.0 BCFD compared to last year, potentially reaching the 3.0 BCFD mark with peak deliveries likely occurring in the summer months. Despite the rosy U.S. natural gas supply outlook, U.S. Gulf production remains vulnerable to disruption by summer hurricanes especially during the peak months of August and September when the frequency of historical occurrences rise. Veteran weather forecaster, Dr. William Gray of Colorado State University, has predicted a busy 2008 hurricane season with 8 hurricanes predicted (compared to an average of 5.9), including 4 severe hurricanes, and 15 named storms predicted (compared to an average of 9.6).11 While the likelihood is for potential hurricanes to disrupt pipeline operations only temporarily, if at all, the initial production losses from Hurricanes Katrina and Rita in 2005 of 8 to 9 BCFD (with a sustained loss of about 1.0 BCFD) stand as a sober reminder of potential supply displacement by severe hurricanes. 10 The spring 2008 gasket problems for the 1 BCFD Independence platform are expected to shut down the facility for one to four weeks, and is considered only a temporary interruption in the upward trend for domestic production. 11 In simplified terms the 2008 hurricane forecast is 160% above normal. In comparison 2005 which included Hurricanes Katrina and Rita was about 250% above normal. Page 12 NERC 2008 Summer Reliability Assessment Key Findings 3. Demand Response Reduces Demand, Provides Ancillary Service Demand response is increasing as a resource to meet electricity demands. NERC completed studies in 2007 on demand-side management12 and load forecasting13 resulting in more detailed data on forecasted demand-side management resources (See Capacity and Demand Definitions Section for definitions). Dispatchable, controllable capacity used to reduced peak demand is shown in Figure 4. Figure 4: Forecast Dispatchable, Controllable Capacity Demand Response for 2008 Summer Peak 7.0% 7.0% 6.0% 6.0% 5.0% 5.0% % of Total Internal Demand 4.0% 4.0% 3.0% 3.0% 2.0% 2.0% 1.0% 1.0% 0.0% 0.0% ERCOT FRCC MRO NPCC RFC SERC SPP WECC Total Capacity Demand Response Direct Control Load Management Contractually Interruptible (Curtailable) Critical Peak-Pricing with Control Load as a Capacity Resource Comparison of the growth in dispatchable, controllable demand response normalized to total internal demand (Figure 5) shows a significant increase in the MRO and NPCC regions. As this figure is normalized to projected summer peak, year-on-year decreases in some regions may be due to load growth, as opposed to reduced demand response, during the 2008 summer months. 12 ftp://ftp.nerc.com/pub/sys/all_updl/docs/pubs/NERC_DSMTF_Report_040308.pdf 13 ftp://ftp.nerc.com/pub/sys/all_updl/docs/pubs/NERC_Load_Forecasting_Survey_LFWG_Report_111907.pdf Page 13 NERC 2008 Summer Reliability Assessment Key Findings Figure 5: Comparison of Dispatchable Demand Response between 2007 and 2008 Summer Peak normalized to Total Internal Demand 7.0% 6.0% % of Total Internal Demand 5.0% 4.0% 3.0% 2.0% 1.0% 0.0% ERCOT FRCC MRO NPCC RFC SERC SPP WECC 2007 2008 For the first time, NERC also collected projected demand response used for ancillary services14 defined as demand-side resource displacing generation deployed as operating reserves and/or regulation; penalties are assessed for nonperformance. In portions of the U.S., demand response used to support ancillary services may increase, in part due to FERC’s Order 890 pro-forma tariff15 being revised in 2007. Demand response used for ancillary services is used to reduce demand during system operations to increase flexibility for bulk power system reliability. Figure 6 shows forecast dispatchable demand response deployed for ancillary services during the 2008 summer months. 14 See Glossary of ftp://ftp.nerc.com/pub/sys/all_updl/docs/pubs/NERC_DSMTF_Report_040308.pdf for detailed definitions 15 http://ferc.gov/industries/electric/indus-act/oatt-reform.asp Page 14 NERC 2008 Summer Reliability Assessment Key Findings Figure 6: Forecast Dispatchable, Controllable Demand Response for Ancillary Services % of Total Demand Response Used for Ancillary Services 3.0% 3.0% 2.5% 2.5% 2.0% 2.0% 1.5% 1.5% 1.0% 1.0% 0.5% 0.5% 0.0% 0.0% ERCOT FRCC MRO NPCC RFC SERC SPP WECC Ancillary Services Demand Response Spinning Reserves Non-Spinning Reserves Regulation Page 15 NERC 2008 Summer Reliability Assessment Key Findings 4. Wind Resources Contribute to Capacity Wind resources are growing in importance as many areas of North America see new facilities come online. This growth is supported by state and provincial Renewable Portfolio Standards (RPS), which generally require utilities to increase the proportion of energy generated by renewable resources to up to 30 percent of their resource mix over the next five to 15 years. Further, U.S. Federal renewable tax credits concentrated on encouraging wind plant construction has fortified interest in development of renewable energy. As noted in previous NERC assessments, certain operational considerations are critical to reliably integrating wind and other “variable” renewable generation into the bulk power system – notably including an analysis of how much capacity can be counted upon to serve peak demand. Figure 7 shows the proportion of output available at the time of peak plotted against “nameplate” or total installed capacity at 100 percent output. On-peak wind capacity figures vary significantly between regions (from 8.7 percent to 27.8 percent), though wind contributes significantly as an off-peak energy-only resource. Anticipating the continued growth of variable generation resources in North America, NERC’s Integration of Variable Generation Task Force16 is preparing a report to include 1) philosophical and technical considerations for integrating variable resources into the Interconnection, and 2) specific recommendations for practices and requirements, including reliability standards that cover the planning, operations planning, and real-time operating timeframes. The final report is expected in the first quarter of 2009. Figure 7: Wind Plant Nameplate and 2008 Summer Peak Capacity 8000 30.0% 27.8% 7000 25.0% 6000 Wind Capacity on 20.0% Summer Peak 21.1% 5000 20.0% Wind Nameplate MW 4000 17.1% 15.0% Capacity 3000 12.6% Wind Capacity as 10.0% % of Total Wind 8.7% 2000 5.0% 1000 0.0% 0.0% 0 0.0% ERCOT FRCC MRO NPCC RFC SERC SPP WECC 16 http://www.nerc.com/~filez/ivgtf.html Page 16 NERC 2008 Summer Reliability Assessment Resources, Demand and Capacity Margins Resources, Demand and Capacity Margins To improve consistency and increase the assessment. Table 1a through 1d provides a granularity/transparency of how regional month-by-month summary of 2008 summer resource projections are represented in NERC resources, demand and capacity margins. assessment reports, NERC’s Planning Committee approved new categories for Net Internal Demand (MW) —Total Internal capacity resources and capacity purchases and Demand reduced by dispatchable controllable sales. The categories of “committed” and (capacity) demand response17. “uncommitted” resource designations used in Total Internal Capacity — The Sum of Existing the 2007 Summer Reliability Assessment are (both Certain and Uncertain) and Planned now replaced with the following: Capacity. 1. Existing Existing-Certain Capacity and Net Firm a) Certain — Existing capacity resources Transactions (MW) — Existing capacity reasonably anticipated to be available resources reasonably anticipated to be available and operate and that are deliverable to and operate and that are deliverable to or into the or into the region. region plus net Firm Purchases/Sales. b) Uncertain — Includes mothballed generation and portions of variable Net Capacity Resources (MW) — Total Internal generation not included in “Certain” Capacity, less Transmission-Limited Resources, all Derates, Energy Only, and Inoperable resources; plus net Firm, Expected and 2. Planned — Capacity resources expected Provisional Purchases/Sales. Net Capacity to be available for the 2008 Summer that Resources do not include Non-Firm have achieved one or more of the Purchases/Sales. following milestones: a) Construction has started Total Potential Resources (MW) — Total b) Regulatory permits approved Internal Capacity, less Transmission-Limited c) Approved by corporate or Resources plus the net of all Purchases/Sales. appropriate senior management Existing Certain Capacity and Net Firm Transactions Margin (%) — Existing-Certain 3. Capacity Purchases and Sales – the Capacity and Net Firm Transactions less Net following categories may be applied to Internal Demand shown as a percent of Existing existing and future capacity calculations. Certain Capacity and Net Firm Transactions. a) Firm b) Non-Firm Net Capacity Resources Margin (%) — Net c) Expected Capacity Resources reduced by the Net Internal d) Provisional Demand; shown as a percent of Net Capacity Resources. See the section entitled “Capacity Definitions Used in this Report” for more detail on the Total Potential Resources Margin (%) — Total definition of these categories. Potential Resources reduced by the Net Internal Demand; shown as a percent of Total Potential Resources. Data gathered using the improved resource categories were used to develop capacity 17 margins for trending and comparative ftp://ftp.nerc.com/pub/sys/all_updl/docs/pubs/NERC_DSMTF _Report_040308.pdf Page 17 NERC 2008 Summer Reliability Assessment Resources, Demand and Capacity Margins Projected Margins Adequate for 2008 Summer Capacity margins, reflecting existing resources reasonably anticipated to be available to operate and deliver power to or into the region, along with firm capacity purchases, appear adequate for the 2008 summer months (Figures 1a-1c). Net capacity margins18 for the U.S. increased by 1.9 percent over last summer’s assessment; net capacity margins in Canada decreased by 1.0 percent. Potential reasons for the decrease in Canada include year-on-year load growth not fully offset by new resources or higher firm transactions to the U.S. in 2008 summer season. Figure 1a: Change in U.S. Projected Net Capacity Margins from Summer 2007 to Summer 2008 50.0 45.0 40.0 Net Capacity Resources Margin 35.0 30.0 1.9% Increase 25.0 2007 2008 20.0 15.0 10.0 5.0 0.0 18 The granularity of capacity was expanded in 2008 (See Resources, Demand and Capacity Section) and capacity margins may not be directly comparable. Page 18 NERC 2008 Summer Reliability Assessment Resources, Demand and Capacity Margins Figure 1b: Change in Canadian Projected Net Capacity Margins from Summer 2007 to Summer 2008 50.0 45.0 40.0 Net Capacity Resources Margin 35.0 1% Decrease 30.0 2007 25.0 2008 20.0 15.0 10.0 5.0 0.0 Figure 1c19: U.S. Subregional Projected Net Capacity Margins from Summer 2007 to Summer 2008 50.0 45.0 40.0 Net Capacity Resources Margin 35.0 30.0 25.0 2007 2008 20.0 15.0 10.0 5.0 0.0 19 This is the first year PJM and MISO have been reported as subgroups within RFC. Page 19 NERC 2008 Summer Reliability Assessment Resources, Demand and Capacity Margins Summer demand for 2008 (Figure 1d) is forecast to increase20 by 1.5 percent in 2008 compared to last year’s forecast, assuming normal weather conditions. The summer weather experienced across much of North America in 2007 drove actual peak demand 0.2 percent higher than forecast. Overall, the 2008 summer forecast demand assuming normal weather is 1.3 percent higher than the 2007 actual summer demand. Percent changes from 2007 actual to 2008 summer forecast are: ERCOT: 4.2 percent, FRCC: 1.5 percent, MRO: 7.4 percent, NPCC: 2.4 percent, RFC: 1.3 percent, SERC21: -2.8 percent, SPP: 0.9 percent and WECC: 2.9 percent. Figure 1d: Year-on-Year Comparison of Projected Total Internal & Actual Demand 7 900,000 1.3% Increase 1.5% Increase 850,000 Demand (MW) 800,000 750,000 700,000 2001 2002 2003 2004 2005 2006 2007 2008 Projected Actual Extreme Weather Impact on Reliability Extreme weather driven by higher temperatures can impact both the overall demand and can increase reactive power requirements. NERC regions or their stakeholders have studied and prepared for this possibility as described below: • High temperatures can substantially increase demand and reduce forecast capacity margins. System simulations were performed, and operational procedures were explored for increased demand and reduced capacity margins conditions. In some cases, regions reported the need for operational procedures to mitigate the impact of extreme weather. • The reactive supply resources were reviewed to ensure they are adequate to provide suitable voltage profiles and manage system stability. For example, low voltage excursions caused by bulk power and distribution system switching can result in single phase air conditioner stalling. System reactive supply requirements increase when air conditioners stall and can impact the bulk power system reliability. Studies indicate the 2008 summer should have sufficient supplies. Local conditions on the distribution system, with no impact on bulk power system reliability, are being managed by the respective distribution and transmission entities. 20 Comparing 2007 actual and 2008 forecast demand does not account for actual demand response reducing 2007 actual demand. 21 The 2008 summer load forecast for SERC is 2.8 percent lower than the actual summer 2007 peak demand as an all-time peak occurred during an unusually hot 2007 summer. Page 20 NERC 2008 Summer Reliability Assessment Resources, Demand and Capacity Margins Table 1a: Estimated June 2008 Resources and Demands (MW) and Margins (%) June 2008 Existing Existing Certain and Certain and Net Firm Net Total Net Firm Net Total Trans- Capacity Potential Net Internal Trans- Capacity Potential actions Resources Resources Demand actions Resources Resources Margin Margin Margin (MW) (MW) (MW) (MW) (%) (%) (%) United States ERCOT 56,477 72,058 73,070 82,389 21.6% 22.7% 31.5% FRCC 40,241 53,077 53,552 54,606 24.2% 24.9% 26.3% MRO 39,193 47,480 48,777 52,176 17.5% 19.6% 24.9% NPCC 55,161 69,666 72,311 74,177 20.8% 23.7% 25.6% New England 23,017 30,950 31,057 31,161 25.6% 25.9% 26.1% New York 32,144 38,716 41,254 43,016 17.0% 22.1% 25.3% RFC 165,500 213,400 213,400 216,300 22.4% 22.4% 23.5% RFC-MISO 56,400 70,000 70,000 71,300 19.4% 19.4% 20.9% RFC-PJM 109,000 141,200 141,200 142,800 22.8% 22.8% 23.7% SERC 183,105 235,006 235,684 237,013 22.1% 22.3% 22.7% Central 39,521 49,652 50,835 50,835 20.4% 22.3% 22.3% Delta 25,902 31,822 31,822 32,211 18.6% 18.6% 19.6% Gateway 16,387 22,966 22,966 23,841 28.6% 28.6% 31.3% Southeastern 44,811 56,548 56,548 56,548 20.8% 20.8% 20.8% VACAR 56,483 74,017 73,952 74,017 23.7% 23.6% 23.7% SPP 38,467 48,993 58,096 59,379 21.5% 33.8% 35.2% WECC 126,944 165,847 172,877 184,724 23.5% 26.6% 31.3% AZ-NM-SNV 28,559 35,531 36,274 37,134 19.6% 21.3% 23.1% CA-MX US 51,859 61,379 65,759 69,981 15.5% 21.1% 25.9% NWPP 35,303 55,974 57,418 63,117 36.9% 38.5% 44.1% RMPA 11,223 12,963 13,309 14,375 13.4% 15.7% 21.9% Total-United States 705,088 905,527 927,767 960,764 22.1% 24.0% 26.6% Canada MRO 5,762 7,501 7,514 7,596 23.2% 23.3% 24.1% NPCC 47,361 62,477 62,984 76,656 24.2% 24.8% 38.2% Maritimes 3,039 5,789 5,790 6,220 47.5% 47.5% 51.1% Ontario 23,351 27,139 27,382 31,540 14.0% 14.7% 26.0% Quebec 20,971 29,549 29,812 38,896 29.0% 29.7% 46.1% WECC 17,644 21,287 21,348 26,237 17.1% 17.4% 32.8% Total-Canada 70,767 91,265 91,846 110,489 22.5% 23.0% 36.0% Mexico WECC CA-MX Mex 2,071 2,356 2,356 2,357 12.1% 12.1% 12.1% Total-NERC 777,926 999,148 1,021,969 1,073,610 22.1% 23.9% 27.5% * MISO and PJM information does not sum to the RFC total due to the handling of OVEC data. RFC information is only for demand and capacity within its region. Page 21 NERC 2008 Summer Reliability Assessment Resources, Demand and Capacity Margins Table 1b: Estimated July 2008 Resources and Demands (MW) and Margins (%) July 2008 Existing Existing Certain and Certain and Net Firm Net Total Net Firm Net Total Trans- Capacity Potential Net Internal Trans- Capacity Potential actions Resources Resources Demand actions Resources Resources Margin Margin Margin (MW) (MW) (MW) (MW) (%) (%) (%) United States ERCOT 63,702 72,058 73,096 82,689 11.6% 12.9% 23.0% FRCC 42,523 53,077 53,552 54,606 19.9% 20.6% 22.1% MRO 42,198 47,614 48,900 52,312 11.4% 13.7% 19.3% NPCC 58,431 69,666 72,403 74,324 16.1% 19.3% 21.4% New England 26,287 30,950 31,131 31,308 15.1% 15.6% 16.0% New York 32,144 38,716 41,272 43,016 17.0% 22.1% 25.3% RFC 177,700 213,400 213,400 216,300 16.7% 16.7% 17.8% RFC-MISO 59,900 70,000 70,000 71,300 14.4% 14.4% 16.0% RFC-PJM 117,700 141,200 141,200 142,800 16.6% 16.6% 17.6% SERC 197,040 236,328 237,006 238,335 16.6% 16.9% 17.3% Central 42,177 49,639 50,822 50,822 15.0% 17.0% 17.0% Delta 26,888 31,623 31,623 32,012 15.0% 15.0% 16.0% Gateway 19,105 23,496 23,496 24,371 18.7% 18.7% 21.6% Southeastern 47,767 57,460 57,460 57,460 16.9% 16.9% 16.9% VACAR 61,103 74,110 74,045 74,110 17.6% 17.5% 17.6% SPP 41,735 48,993 58,096 59,379 14.8% 28.2% 29.7% WECC 137,925 164,754 171,791 184,300 16.3% 19.7% 25.2% AZ-NM-SNV 30,996 35,448 36,191 37,113 12.6% 14.4% 16.5% CA-MX US 57,108 61,472 65,852 69,584 7.1% 13.3% 17.9% NWPP 37,778 54,422 55,873 62,662 30.6% 32.4% 39.7% RMPA 12,043 13,412 13,758 14,824 10.2% 12.5% 18.8% Total-United States 761,254 905,890 928,244 962,245 16.0% 18.0% 20.9% Canada MRO 5,848 7,495 7,514 7,596 22.0% 22.2% 23.0% NPCC 48,443 63,559 63,928 76,525 23.8% 24.2% 36.7% Maritimes 3,014 5,772 5,772 6,221 47.8% 47.8% 51.6% Ontario 24,351 28,194 28,268 31,376 13.6% 13.9% 22.4% Quebec 21,078 29,593 29,888 38,928 28.8% 29.5% 45.9% WECC 17,797 22,287 22,433 26,421 20.1% 20.7% 32.6% Total-Canada 72,088 93,341 93,875 110,542 22.8% 23.2% 34.8% Mexico WECC CA-MX Mex 2,223 2,788 2,788 2,790 20.3% 20.3% 20.3% Total-NERC 835,565 1,002,019 1,024,907 1,075,577 16.6% 18.5% 22.3% * MISO and PJM information does not sum to the RFC total due to the handling of OVEC data. RFC information is only for demand and capacity within its region. Page 22 NERC 2008 Summer Reliability Assessment Resources, Demand and Capacity Margins Table 1c: Estimated August 2008 Resources and Demands (MW) and Margins (%) August 2008 Existing Existing Certain and Certain and Net Firm Net Total Net Firm Net Total Trans- Capacity Potential Net Internal Trans- Capacity Potential actions Resources Resources Demand actions Resources Resources Margin Margin Margin (MW) (MW) (MW) (MW) (%) (%) (%) United States ERCOT 62,749 72,058 73,147 83,272 12.9% 14.2% 24.6% FRCC 44,417 53,077 53,552 54,606 16.3% 17.1% 18.7% MRO 41,072 47,669 48,953 52,371 13.8% 16.1% 21.6% NPCC 58,431 69,666 72,400 74,324 16.1% 19.3% 21.4% New England 26,287 30,950 31,131 31,308 15.1% 15.6% 16.0% New York 32,144 38,716 41,269 43,016 17.0% 22.1% 25.3% RFC 172,100 213,400 213,400 216,300 19.4% 19.4% 20.4% RFC-MISO 59,800 70,000 70,000 71,300 14.6% 14.6% 16.1% RFC-PJM 112,200 141,200 141,200 142,800 20.5% 20.5% 21.4% SERC 195,258 236,290 236,968 238,297 17.4% 17.6% 18.1% Central 41,546 49,639 50,822 50,822 16.3% 18.3% 18.3% Delta 27,927 31,590 31,590 31,979 11.6% 11.6% 12.7% Gateway 18,174 23,516 23,516 24,391 22.7% 22.7% 25.5% Southeastern 48,215 57,451 57,451 57,451 16.1% 16.1% 16.1% VACAR 59,395 74,094 74,029 74,094 19.8% 19.8% 19.8% SPP 42,827 48,993 58,096 59,379 12.6% 26.3% 27.9% WECC 135,725 163,495 171,102 185,127 17.0% 20.7% 26.7% AZ-NM-SNV 30,099 35,370 36,209 37,209 14.9% 16.9% 19.1% CA-MX US 57,507 61,662 66,479 70,138 6.7% 13.5% 18.0% NWPP 36,500 53,519 55,007 63,304 31.8% 33.6% 42.3% RMPA 11,619 12,944 13,290 14,359 10.2% 12.6% 19.1% Total-United States 752,579 904,648 927,618 963,676 16.8% 18.9% 21.9% Canada MRO 5,849 7,508 7,527 7,609 22.1% 22.3% 23.1% NPCC 47,947 63,242 63,604 76,519 24.2% 24.6% 37.3% Maritimes 2,969 5,763 5,763 6,222 48.5% 48.5% 52.3% Ontario 23,634 27,920 27,987 31,369 15.4% 15.6% 24.7% Quebec 21,344 29,559 29,854 38,928 27.8% 28.5% 45.2% WECC 17,907 22,407 22,575 26,444 20.1% 20.7% 32.3% Total-Canada 71,703 93,157 93,706 110,572 23.0% 23.5% 35.2% Mexico WECC CA-MX Mex 2,217 2,655 2,655 2,657 16.5% 16.5% 16.6% Total-NERC 826,499 1,000,460 1,023,979 1,076,905 17.4% 19.3% 23.3% * MISO and PJM information does not sum to the RFC total due to the handling of OVEC data. RFC information is only for demand and capacity within its region. Page 23 NERC 2008 Summer Reliability Assessment Resources, Demand and Capacity Margins Table 1d: Estimated September 2008 Resources and Demands (MW) and Margins (%) September 2008 Existing Existing Certain and Certain and Net Firm Net Total Net Firm Net Total Trans- Capacity Potential Net Internal Trans- Capacity Potential actions Resources Resources Demand actions Resources Resources Margin Margin Margin (MW) (MW) (MW) (MW) (%) (%) (%) United States ERCOT 50,205 72,058 73,147 83,272 30.3% 31.4% 39.7% FRCC 41,909 53,077 53,552 54,606 21.0% 21.7% 23.3% MRO 37,328 47,723 49,023 52,437 21.8% 23.9% 28.8% NPCC 52,516 69,666 72,432 74,353 24.6% 27.5% 29.4% New England 20,372 30,950 31,160 31,337 34.2% 34.6% 35.0% New York 32,144 38,716 41,272 43,016 17.0% 22.1% 25.3% RFC 150,300 213,400 213,400 216,300 29.6% 29.6% 30.5% RFC-MISO 50,700 70,000 70,000 71,300 27.6% 27.6% 28.9% RFC-PJM 99,500 141,200 141,200 142,800 29.5% 29.5% 30.3% SERC 176,267 233,081 233,759 235,057 24.4% 24.6% 25.0% Central 39,455 48,847 50,030 50,030 19.2% 21.1% 21.1% Delta 24,371 31,570 31,570 31,959 22.8% 22.8% 23.7% Gateway 15,473 22,779 22,779 23,654 32.1% 32.1% 34.6% Southeastern 43,653 55,861 55,861 55,861 21.9% 21.9% 21.9% VACAR 53,315 74,024 73,990 74,024 28.0% 27.9% 28.0% SPP 37,964 48,993 58,096 59,379 22.5% 34.7% 36.1% WECC 126,574 161,954 170,154 186,183 21.8% 25.6% 32.0% AZ-NM-SNV 27,631 35,005 35,844 37,191 21.1% 22.9% 25.7% CA-MX US 54,861 61,563 66,925 70,834 10.9% 18.0% 22.5% NWPP 33,508 52,859 54,391 63,611 36.6% 38.4% 47.3% RMPA 10,574 12,527 12,877 14,430 15.6% 17.9% 26.7% Total-United States 673,063 899,952 923,563 961,587 25.2% 27.1% 30.0% Canada MRO 5,489 7,522 7,546 7,628 27.0% 27.3% 28.0% NPCC 45,839 60,447 60,565 76,278 24.2% 24.3% 39.9% Maritimes 3,055 5,854 5,854 6,223 47.8% 47.8% 50.9% Ontario 21,487 25,643 25,444 31,105 16.2% 15.6% 30.9% Quebec 21,297 28,950 29,267 38,950 26.4% 27.2% 45.3% WECC 17,617 21,986 22,253 26,534 19.9% 20.8% 33.6% Total-Canada 68,945 89,955 90,364 110,440 23.4% 23.7% 37.6% Mexico WECC CA-MX Mex 2,118 2,455 2,455 2,457 13.7% 13.7% 13.8% Total-NERC 744,126 992,362 1,016,382 1,074,484 25.0% 26.8% 30.7% * MISO and PJM information does not sum to the RFC total due to the handling of OVEC data. RFC information is only for demand and capacity within its region. Page 24 NERC 2008 Summer Reliability Assessment Resources, Demand and Capacity Margins Notes for Table 1a through 1d Note 1: Existing-Certain and Net Firm Transactions and Net Capacity Resources are assumed to be deliverable. Note 2: The Inoperable portion of Total Potential Resources may not be deliverable. Note 3: The WECC-U.S. area subregional net capacity resources numbers include use of seasonal demand diversity. Note 4: The WECC-U.S. systems demand side management resources are not necessarily sharable between all the WECC-US subregions Note 5: WECC CA-MX represents only the northern portion of the Baja California Norte, Mexico electric system interconnected with the U.S. Page 25 NERC 2008 Summer Reliability Assessment Regional Reliability Assessment Highlights Regional Reliability Assessment Highlights ERCOT Total Internal Demand in the ERCOT Region for summer 2008 is expected to be 64,827 MW, based on typical summer weather conditions. This expected demand is 4.7 percent higher than the actual peak demand for 2007, which occurred during milder than typical weather conditions. Net Capacity Resources in the ERCOT Region have increased by 1,926 MW since summer 2007. The resulting reserve margin for the ERCOT Region for 2008 summer is 12.9 percent, which meets its target margin level. The continued rapid installation of wind generation in West Texas is expected to result in congestion on multiple transmission paths within and out of West Texas, which will require increased operational attention. However, none of these expected constraints or unusual operating conditions is expected to cause reliability problems. FRCC The 2008 summer demand forecast is 1 percent higher than for 2007. This smaller growth in demand over years past is primarily due to a slowdown in the Florida economy and the higher cost of electricity. A net increase in generation capacity from 2007 of 476 MW is the result of the expected addition of one new unit for this summer. FRCC expects a 21 percent reserve margin for this upcoming summer, which meets its target margin level. The transmission capability within the FRCC region is expected to be adequate to supply firm customer demand and to provide planned firm transmission service. The most notable transmission improvements are in Central Florida where a new 230 kV line and the rebuild of an existing 230 kV line are expected to be in-service by the summer. No unusual operating conditions impacting reliability are expected. Operational issues in Central Florida can develop due to unplanned outages of generating units serving this area. However, it is anticipated that existing operational procedures, pre-planning, and training will adequately manage and mitigate the impacts to the bulk transmission system. Page 26 NERC 2008 Summer Reliability Assessment Regional Reliability Assessment Highlights MRO The MRO Net Internal Demand forecasted for the 2008 summer is 1.8 percent higher than forecasted for the 2007 summer. An additional 1,428 MW of planned resources will be in service this summer. MRO’s projected 2008 summer reserve margin is 17.5 percent not counting uncertain resources. Last summer’s margin was 20.8 percent not counting uncommitted resources (These two values cannot be directly compared because of the changes in capacity definitions described earlier in the report.) No significant transmission or operational reliability concerns are expected in the MRO region. The completion of the Arrowhead – Stone Lake – Gardner Park 345 kV line in January 2008 provides needed transmission reinforcement on the Minnesota - Wisconsin interface and improves the area’s transmission reliability and transfer capability. MRO’s transmission system is expected to perform reliably during the summer months. NPCC No significant reliability issues have been cited for the 2008 summer period22. The non-coincident aggregate 2008 summer total projected Internal Demand is 111,557 MW23 (Canadian systems 49,778 MW; U.S. systems 61,779 MW). This forecast peak demand is little changed (-0.2 percent) from last summer’s 111,830 MW24 forecast aggregate demand. The forecast is based on average weather conditions and is 2.4 percent higher than last summer’s non-coincident aggregate actual 108,958 MW peak demand. 2007 2007 2008 2007 Actual 2008 Forecast NPCC Subregion Actual Forecast Forecast w/r 07 w/r 07 Peak Peak Peak Forecast-% Forecast-% Maritimes 3,496 3,738 3,542 -6.92 -5.24 New England 26,145 27,360 27,970 -4.65 2.23 New York 32,169 33,447 33,809 -3.97 1.08 Ontario 25,737 25,516 24,892 0.86 -2.45 Québec 21,411 21,769 21,344 -1.67 -1.95 Canadian Total 50,644 51,023 49,778 -0.75 -2.44 US Total 58,314 60,807 61,779 -4.28 1.60 NPCC Total 108,958 111,830 111,557 -2.64 -0.2 22 These figures differ from NPCC's May 1, 2008 Summer Assessment (http://www.npcc.org/documents/reports/Seasonal.aspx) as NPCC includes the month of May as part of the summer period in their non-coincident demand. 23 This demand figure is the sum of sub-regional summer season forecast peaks, regardless of month. NERC’s Total Internal Demand is the greatest sum of sub-regional monthly forecast peaks. Therefore these figures may differ. 24 This demand figure is the sum of sub-regional summer season actual peaks, regardless of month. NERC’s Total Internal Demand is the greatest sum of sub-regional monthly actual peaks. Therefore these figures may differ. Page 27 NERC 2008 Summer Reliability Assessment Regional Reliability Assessment Highlights About 1,100 MW of new capacity additions are projected to be in service for the 2008 summer peak. All NPCC sub-regions — ISO New England (ISO-NE), the New York Independent System Operator (NYISO), Hydro-Québec TransÉnergie, the Ontario Independent Electricity System Operator (IESO) and the Maritimes — expect sufficient resources to be available to meet projected demands during 2008 Summer and have monthly projected net capacity margins ranging from 15.6 percent to 53.0 percent. Québec and the Maritimes are predominately winter peaking areas, and therefore adequate resources, including the supply for firm external sales, are expected to be available. A new 345 kV transmission line between Point Lepreau, New Brunswick, and Orrington, Maine, went into service during December of 2007. It has increased the New Brunswick – Maine Electric Power Company (MEPCO) Total Transfer Capability (TTC) from 700 to 1,000 MW and the MEPCO – NB TTC from 300 to 550 MW. Reliability has previously been a concern in the Boston area. However, transmission upgrades completed in the spring of 2007 increased the import capability into the Boston area by 1,000 MW, to a total of 4,600 MW. As a result of those improvements, the capacity margin was forecasted to be positive in 2007 and is expected to remain so in 2008. Just prior to the summer peak season, New England and New York expect to energize a replacement set of 138 kV submarine cables in the 1385 circuit (Norwalk Harbor-Northport 138 kV) connecting southwestern Connecticut to Long Island, NY. The original cables had become highly unreliable because they had been damaged by marine anchors. Phase angle regulators (PARs) are installed on three of the four Michigan to Ontario interconnections. One PAR, on the Keith to Waterman 230 kV circuit J5D has been in service and regulating since 1975. The other two available PARs, on circuits L51D and L4D, which had been bypassed pending completion of agreements between the IESO, the Midwest ISO, Hydro One and the International Transmission Company, were placed in service on April 14, 2008, and are expected to start regulating before the summer. All parties have committed to completing the necessary operating agreements to meet this schedule. The operation of the PARs will assist in the management of system congestion and control of circulating flows. The fourth PAR, located in Michigan at the Bunce Creek terminal of circuit B3N, responsible for controlling the tie flow on the 230 kV circuit B3N, remains unavailable and is undergoing replacement. Upgrades in the Rochester, New York vicinity were made to accommodate the Russell Station retirement this summer. A capacitor bank at is scheduled to be added to by June 1, 2008. Page 28 NERC 2008 Summer Reliability Assessment Regional Reliability Assessment Highlights RFC Approximately 85 percent of the PJM RTO demand and approximately 60 percent of the MISO market load is within the RFC region. Since the Ohio Valley Electric Corporation (OVEC) is not a member of either RTO, the 88 MW of OVEC demand was added to the demand of the PJM and MISO areas, a 2.0 percent diversity factor was applied, and the result rounded to the nearest 100 MW. The resulting coincident peak for the RFC region is 177,700 MW Net Internal Demand (NID) and 184,000 Total Internal Demand. The forecast NID peak is 3,200 MW (1.7 percent) lower than the forecast demand for 2007. The amount of “Certain” OVEC, PJM and MISO capacity in RFC is 212,900 MW. No additional capacity is expected to go in service during the summer. All of the “certain” capacity in each RTO is determined to be fully deliverable by PJM and MISO within their respective RTOs. There is also 2,900 MW of capacity in the RFC region that is “uncertain” capacity, which is not included in the reserve margin. This total of 215,800 MW of existing capacity this summer is less (3,265 MW) than the 219,065 MW reported as existing capacity in last summer’s assessment due to the new capacity definitions. The RFC 2008 summer assessment for the regional area is derived by RFC from the results of PJM and MISO assessments. It is not meaningful to calculate a specific reserve margin requirement for all of RFC since each RTO has slightly different demand characteristics, capacity resource availabilities and calculated reserve requirements. However, since PJM and MISO each operate as single entities, it follows that when each RTO has adequate resources based on satisfying their respective reserve requirements, then the RFC reserves can be considered to be adequate. The resulting reserve margin for RFC is 35,700 MW, which is 20.1 percent based on NID and Net Capacity Resources. Both MISO and PJM have sufficient resources to satisfy their reserve margin requirements. Therefore, the calculated reserve margin for this summer in the RFC region is adequate. This compares to a 20.7 percent reserve margin documented in 2007 Summer Assessment. PJM Reserve Margin The reserve margin for the PJM RTO is 29,200 MW, which is 21.8 percent of the NID and is greater than the reserve requirement of 15.0 percent, which is 20,100 MW. MISO Reserve Margin The applicable reserve margin requirements in the Midwest ISO for the 2008 planning year were combined by RFC to a reserve requirement for MISO of 15,900 MW or 14.1 percent. The projected reserve margin for MISO is 21.6 percent of the NID, which is 21,600 MW. Therefore, the reserves are expected to be adequate within MISO. Page 29 NERC 2008 Summer Reliability Assessment Regional Reliability Assessment Highlights Many new additions to the bulk-power system since last summer have been placed in service and include a total of 85 miles of transmission lines at 230 kV and above, plus ten transformers with a total capacity of about 6,000 MVA. An additional total of 30 miles of transmission lines at 230 kV and above is expected to be placed in service by this summer, plus six transformers with a total capacity of about 3,000 MVA. These system changes are expected to enhance reliability of the bulk power system. The output of one power plant in the Washington, DC area is still restricted due to environmental issues. However, the restriction may be lifted for emergency operating conditions. Recent transmission enhancements have relieved local deliverability issues related to this restriction. No other unusual operating conditions that could impact reliability are foreseen for this summer. SERC The 2008 summer load forecast is 2.8 percent lower than the actual summer 2007 peak demand. An all-time peak occurred during an unusually hot 2007 summer, though earlier weather forecasts predicted “normal” weather. SERC projects a 16.6 percent capacity margin on the basis of Existing-Certain and Net Firm Transactions for the region as a whole in this upcoming summer. A net 1,800 MW in generation capacity increase was reported. This change is not due to any significant increase in generation additions, but to the transfer of ownership of existing generation between a non- SERC member and a SERC member. Most of this incremental capacity owned by non-SERC members existed in 2007, although some of it was not reported for the 2007 Summer Reliability Assessment. Further, by adhering to the enhanced definitions used this year, some capacity was reallocated to different reporting categories. The transmission capability within the SERC region is expected to be adequate to supply customer demand and provide planned transmission service. Operational issues in the SERC Region can develop due to unplanned outages of generating units. However, it is anticipated that existing operational procedures, pre-planning, and training will adequately manage and mitigate the impacts to customers and the bulk power system. SERC members conducted a special drought assessment considering a hydrological scenario more severe than the forecast 2008 summer conditions. The study projects that there will be no major reliability issues under the severe case tested in the study. At the present time, (early spring 2008) conditions are improving in many (but not all) of the drought-affected areas. Page 30 NERC 2008 Summer Reliability Assessment Regional Reliability Assessment Highlights SPP The 2008 summer peak forecast is 1 percent higher than the forecast for the summer of 2007. SPP experienced a slight increase in demand from the normal forecast due to higher temperatures in the summer and the modest load growth throughout the SPP footprint. A net increase in generation capacity from 2007 of 1,607 MW is primarily due to the expected addition of several small units for this summer across the SPP footprint SPP expects to have a 14.1 percent reserve margin for summer 2008, which is higher than the required reserve margin per SPP criteria. AEP-West plans to add new 14-mile 345 kV line from Chamber Springs to Tontitown in northwest Arkansas. SPP does not anticipate any operational issues that will impact reliability of the system for the upcoming summer and no reliability concerns are expected in SPP. WECC The WECC 2008 summer total internal demand is forecast to be 162,052 MW. This is 3.2 percent greater than last summer’s forecast peak demand of 156,988 MW for the 2007 summer period. The 2008 summer period direct control load management and interruptible demand capability has increased by about 560 MW compared to 2007. It is important to note that the total WECC Demand-Side Management (DSM) capability value shown is the sum of each of the subregions, so it is not available for use across all subregions. The deliverable internal capacity for 2008 is projected to be 196,545 MW compared to previously projected 192,312 MW for 2007 (185,940 actual). The WECC Regional capacity margin is projected to be 19.8 percent for July of 2008 based on Existing resources (Certain), Planned Capacity Additions and Net Firm Transactions for the region. If only the Existing resources (Certain) and the Net Firm Transactions are considered, without the Planned Capacity Additions, the projected capacity margin would be 16.8 percent. The southern California area is dependent on the transmission system for imports of significant amounts of power, as in the past; unplanned major transmission and/or generation outages coupled with lower import levels, or extreme temperatures coupled with lower import levels, may cause resource constraints due to system limits. Page 31 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments Regional Reliability Self-Assessments Regional Resource and Demand Projections The figures in the regional self-assessment pages show the regional historical demand, projected demand growth, capacity margin projections, and generation expansion projections reported by the regions. Capacity Fuel Mix The regional capacity fuel mix charts show each region’s relative reliance on specific fuels25 for its reported generating capacity. The charts for each region in the regional self-assessments are based on the most recent data available in NERC’s Electricity Supply and Demand database. Sample — Relative Capacity by Fuel Mix Sample: Relative Capacity by Fuel Mix Coal Dual Fuel Pumped Storage Other Gas Nuclear Oil Hydro Geothermal 25 Note: The category “Other” may include capacity for which a fuel type has yet to be determined. Page 32 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments ERCOT 2008 Projected Peak Demand MW Relative Capacity by Fuel Mix Total Internal Demand 64,827 Direct Control Load Management 0 Contractually Interruptible (Curtailable) 0 Coal 16% Critical Peak-Pricing with Control 0 Dual Fuel Load as a Capacity Resource 1,125 Hydro 0.6% 27% Net Internal Demand 63,702 Nuclear 7% MW Change 2007 Actual Summer Peak Demand 62,188 2.4% All-Time Summer Peak Demand Wind 7% 62,339 2.2% Other 0.8% 2008 Projected Capacity MW Margin Un- Existing Certain and Net Firm Transactions 72,058 11.6% determined Net Capacity Resources 73,096 12.9% 0.3% Gas 41% Total Potential Resources 82,689 23.0% Introduction Market participants in the ERCOT Region have added 3,722 MW of resources since last summer, which results in an increase in net dependable resources of 1,926MW26. A projected slowdown in economic conditions in Texas is reflected in the decrease of the 2008 peak demand forecast from the 2007 projection of 65,135 MW to the current projection for 2008 of 64,827 MW. Together, these changes result in a projected reserve margin for 2008 of 12.9%. This level of reserves is above the 12.5% minimum reserve margin, indicating that the ERCOT region is expected to have sufficient resources to serve its peak demand in the region this summer. ERCOT has implemented a new Emergency Interruptible Load Service, implemented as Step 3 of Emergency Electric Curtailment Plan27 (EECP), as a new tool for operators in the event reserves are depleted and in order to avoid interruption of firm demand during system-wide emergencies. There are no known transmission constraints that could significantly impact reliability across the ERCOT region. The continuing increase of installed wind generation in west Texas is likely to require increased operational focus during this summer due to transmission congestion within and out of west Texas. ERCOT continues to have a Reliability Must Run agreement to maintain reliability in the Laredo area. Demand The 2007 summer actual peak demand for the ERCOT region was 62,188 MW. This peak demand was set with temperatures during the summer in 2007 that were unusually mild (below normal). In 2007, the summer peak demand forecast for 2008 was 65,135 MW. This year, the 26 The balance of the 3,722MW is the portion of the new wind generation that is considered derated on-peak. 27 http://www.ercot.com/mktrules/protocols/current.html Section 184.108.40.206 Page 33 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments 2008 summer peak demand is forecasted to be 64,827 MW. The 2008 forecast is lower than last year’s forecast for 2008 due to the forecasted slowdown in economic conditions. The forecasted peak demands are produced by ERCOT for the ERCOT Region (which is a single Balancing Authority area) based on the coincident actual demands. The weather assumptions on which the forecasts are based are considered to represent an average weather profile (50/50). An average weather profile is calculated for each of the eight weather zones in the ERCOT grid, which are used in developing the forecast. These average weather profiles are based on a Rank- Median method. This method ranks the yearly temperatures from highest to lowest for all years in the database and assigns the ranked temperatures to a calendar. The calendar is selected using a minimum squared error criterion. Median temperatures are preferred as they are not affected as much by outliers as the average. The economic variables used in the ERCOT weather zone models are employment, real personal per-capita income and population. Employment is a measure of the growth in the commercial and industrial areas. Population is a proxy for capturing customer formation, and income addresses overall standard of living which translates into increase in comfort and convenience and in many instances leads directly to an increase in electricity demand. The key factors driving the lower peak demands and energy consumption forecasts reflect the overall state of the economy as captured by economic indicators listed above, such as the real per capita personal income, population, and various employment measures including non-farm employment and total employment. These economic variables are used throughout the eight weather zones that comprise the ERCOT electric grid. These economic indicators used in the 2008 forecast show a minor slowdown of the economy in the short-run, which results in an impact of about 300 MW in the summer forecast in 2008. There is a deceleration in the TX employment, but employment continues to grow faster than the weak pace of the US. High energy prices continue to power the Houston economy. The actual demands used for forecasting purposes are coincident hourly values across the ERCOT Region. The data used in the forecast is by weather zones. ERCOT has the Load acting as a Resource (LaaR) program28, which amounts to approximately 1,125 MW, slightly more than last year, which was 1,112 MW. The LaaR capacity is available through ERCOT’s ancillary services market. ERCOT has added a new load reduction program called Emergency Interruptible Load Service (EILS)29, which is designed to be deployed as Step 3 of an Emergency Electric Curtailment Plan (EECP) event. EILS loads are deployed after the Loads acting as Resources (LaaRs) but before the involuntary firm load. EILS is not considered an offset to net demand. Currently, there are 262 MW of participation in the EILS program. To assess the impact of weather variability on the peak demand for ERCOT, alternative weather scenarios are used to develop extreme MW forecasts. A high demand scenario is produced using the 90th percentile of the temperatures in the database spanning the last fourteen years available. 28 http://www.ercot.com/mktrules/protocols/current/06-030108.doc 29 http://www.ercot.com/mktrules/protocols/current/06-030108.doc Section 6.1.13 Page 34 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments The lower temperatures that rank in the bottom 10th percentile of the database are also used to produce a lower range forecasts. The extreme temperatures are input into the load-shape and energy models to obtain the forecasts. The higher temperature assumptions consistently produce MW forecasts that are approximately 5.5% higher than the base forecasts (50/50). Together, the forecasts from these temperature scenarios are usually referred to as 90/10 MW forecasts. Generation Currently, ERCOT has 71,704 MW of Existing-Certain generation, approximately 9,056 MW Existing-Uncertain generation, and 1,575 MW Planned generation capacity either presently in service or expected to be in service during the 2008 summer period. Of the Existing Certain amount, 53 MW of biomass is included, however only 8.7% of existing and planned wind generation nameplate capacity is used, based on a 2006 study of the effective load carrying capacity of wind30. The remaining existing wind capacity amount is included in the Existing- Uncertain generation amount. ERCOT is not dependent on hydro generation to meet summer peak demand or the daily energy demand because less than 1% of the generation mix in the ERCOT region is comprised of hydro generation. ERCOT is not currently experiencing drought conditions. Reservoir levels are currently at or near full capacity31. ERCOT does not expect significant capacity reduction implications due to low water levels. Purchases and Sales ERCOT has only limited connection with other regions through five DC ties (two between ERCOT and SPP and three between ERCOT and Mexico) and therefore has few long term firm contracts for transfer between the ERCOT region and SPP included in sales and purchases. An import to ERCOT from SPP is tied to a long term contract for a purchase of 48 MW of firm power from specific generation. There are a total of 820 MW of DC tie transfer capability between ERCOT and SPP and 286 MW of capability between ERCOT and Mexico’s Comision Federal de Electricidad (CFE), of which 553 MW are included as purchases under emergency support agreements. There are no non-Firm contracts signed or pending. There are also no known contracts under negotiation or under study. SPP members’ ownership of 247 MW of a power plant located in ERCOT is tied to long term firm contracts, which result in transfers from ERCOT to SPP. There are no non-firm contracts signed or known to be in negotiation. Additionally, there are no other transactions currently under study. ERCOT does not share reserves on a regular basis with any other regions. The only reliance on outside resources is for emergency service by request only. 30 http://www.ercot.com/meetings/gatf/keydocs/2007/20070112-GATF/ERCOT_Reserve_Margin_Analysis_Report.pdf 31 http://wiid.twdb.state.tx.us/ims/resinfo/BushButton/lakeStatus.asp Page 35 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments Fuel No significant disruptions in gas supply were experienced in ERCOT in the summer of 2007 and are not anticipated in 2008. Natural gas fuel supply interruptions are a potential concern during the winter due to demand for gas for home heating, but these interruptions typically do not occur in summer. No problems with coal supply deliveries to ERCOT are expected this summer. Transmission Approximately 167 miles of new or rebuilt 138kV transmission lines were completed since the 2007 summer and an additional 120 miles of rebuilt 138kV transmission lines are expected to be completed before the 2008 summer period. Approximately 45 miles of rebuilt 69kV transmission lines were completed since the 2007 summer and an additional 38 miles of rebuilt 69kV is anticipated before the 2008 summer. The continued rapid installation of new wind generation in West Texas is expected to result in congestion on multiple constraints within and out of West Texas for the next several years until new bulk transmission lines are added between West Texas and the rest of the ERCOT system. The existing transmission system into the Laredo area cannot support the energy imports to south Texas necessary to satisfy the area and maintain N-1 security requirements during high load periods without generation in the area. Currently, ERCOT has three units under Reliability Must- Run (RMR) contract in Laredo for a total capacity of 169 MW. Transmission line upgrades that will allow releasing the RMR contract are planned to be completed in 2010. A 100-MW Variable Frequency Transformer tie with Mexico has been installed. This device will not allow releasing the RMR units but helps ensure that adequate capacity is available to restrict the Laredo energy imports to acceptable levels that satisfy the Laredo area security criteria. Two 140 MVAr dynamic reactive devices will be installed in the Houston area (Bellaire South and Crosby 138 kV stations) by June 2008. These devices will provide reactive support necessary to maintain voltages within the voltage ride-through requirements for generation in the area during Category D contingencies32. Operational Issues Currently, there are about 30 minor unit outages planned during the assessment period; the majority of these are scheduled for September, after the typical peak demand. One planned outage for June, July and August will likely result in local congestion in the far south region of Texas. Planned transmission upgrade projects in this area are expected to be completed before the assessment period and should help this congestion. There are no environmental or regulatory restrictions known at this time which are expected to impact reliability. The continued increase in installed wind generation has the potential to lead to operating challenges during the summer season. ERCOT has recently implemented a wind power forecasting system to allow system operators to identify and take appropriate action when wind resource schedules may not track expected changes in wind production, which was one contributing factor to the EECP event on 2/26/2008.33 In addition, congestion management 32 http://www.ercot.com/mktrules/guides/operating/2007/11/03/03-110107.doc 33 http://www.ercot.com/meetings/ros/keydocs/2008/0313 /07._ERCOT_OPERATIONS_REPORT_EECP022608_public.doc Page 36 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments associated with the increased wind generation is likely to require increased attention. Finally, ERCOT recently completed a study of the impact of increased wind generation on ancillary services requirements. At the level of wind generation that will be installed during this summer season, the study found that ERCOT’s current ancillary services procurement methodologies are appropriate; those methodologies will likely result in higher levels of some ancillary services. Reliability Assessment Analysis The reserve margin for the 2008 summer assessment period is currently projected to be 12.9% which is 0.4% higher than the minimum reserve margin level for ERCOT of 12.5%. This currently projected reserve margin for 2008 is 0.8% lower than the 13.7% reserve margin that was projected for 2007 in last year’s Summer Assessment. ERCOT has a minimum reserve margin target of 12.5%, based on Loss-of-Load Expectation (LOLE) analysis of no more than one day in ten years loss of load. The last loss of load probability (LOLP) study that was used to assess the adequacy of the 12.5% reserve margin criteria in meeting a one-day-in-ten-years LOLP was performed in 2007.34 ERCOT does not have a formal definition of generation deliverability. However, in the planning horizon, ERCOT performs a security-constrained unit commitment and economic dispatch analysis for the upcoming year. This analysis is performed on an hourly basis for a variety of conditions to ensure deliverability of sufficient resources to meet a load level that is approximately 10 percent higher than the expected coincident system peak demand plus operating reserves. Load data for this analysis is based on the non-coincident demands projected by the transmission owners. Operationally, transmission operating limits are adhered to through market-based generation redispatch directed by ERCOT as the balancing authority and reliability coordinator. Operational resource adequacy is also maintained by ERCOT through market-based procurement processes (See Sections six and seven of the ERCOT Protocols35). ERCOT does not anticipate extreme summer weather to have an impact on fuel supply or fuel delivery. If fuel supply issues become a potential problem they are reported to ERCOT by the affected entity as a resource de-rating or a forced outage. ERCOT does not coordinate directly with the fuel industry; 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 (QSE) that represent generation to better prepare operationally for potential curtailments (See Section 5.6.5 of the ERCOT Protocols36). Specific information that may be requested can be found in the ERCOT Operating Guides.37 ERCOT has interconnections through DC ties with the Eastern Interconnect and with Mexico. The maximum imports/export over these ties is 1,106 MW. These ties can be operated at a maximum import and export provided there are no area transmission elements out of service. In the event of a transmission outage in the area of these ties, studies will be run during the outage coordination period for the outages to see if any import/export limits are needed. 34 http://www.ercot.com/meetings/gatf/keydocs/2007/20070112-GATF/ERCOT_Reserve_Margin_Analysis_Report.pdf 35 http://www.ercot.com/mktrules/protocols/current.html 36 Ibid 37 http://www.ercot.com/mktrules/guides/operating/index.html Page 37 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments There are no known transmission constraints that are expected to significantly impact reliability across the ERCOT region. If transmission constraints are identified in the operations planning horizon, remedial action plans or mitigation plans are developed to provide for preemptive or planned response to maintain reliability of a localized area. ERCOT regularly performs transient dynamics and voltage studies. Small signal stability studies were performed as part of the West-North stability study. There are no anticipated stability issues that could affect reliability however ERCOT closely monitors a west-north stability limit and a Rio Grande valley voltage limit. In the operations planning horizon, ERCOT performs off-line transient stability studies for specific areas of the region as needed. The results of these studies are used in real-time and near real-time monitoring of the grid. Operating Procedure 2.4.3 VSAT (Voltage Stability Analysis Tool) describes the procedure to monitor the system and to prevent voltage collapse using the online voltage stability analysis tool. Different scenarios along with the MW safety margins are described and mitigation procedures are prescribed based on VSAT results. Once the prescribed action is communicated, taken and verified VSAT will be rerun with the new topology. No explicit minimum dynamic reactive criteria exist, however reactive margins are maintained in the major metropolitan areas. Areas of dynamic and static reactive power limitations are Corpus Christi, Houston, Dallas/Ft. Worth, Rio Grande Valley, South to Houston generation, South to Houston load, North to Houston Generation and North to Houston load. These areas and mitigation procedures are found in Operating Procedure 220.127.116.11 ERCOT plans for a 5% voltage stability margin for category A and category B contingencies and a 2.5% margin for category C contingencies39. The UVLS program performs in up to three stages and is based on voltage trip points, with time delays prior to trip and percentage of load at the specific bus. The ERCOT region is expected to have more than sufficient resources to meet the 2008 summer demand. ERCOT should have sufficient capacity even for a peak demand that is as high as the 90th percentile of the weather sensitivity in the load forecast, which could result in a peak demand 5.5% higher than the expected peak demand. An extremely hot summer that results in load levels significantly above forecast, higher than normal unit forced outage rates, or financial difficulties of some generation owners that may make it difficult for them to obtain fuel from suppliers are all risk factors that alone or in combination could result in inadequate supply. In the event that occurs, ERCOT will implement its Emergency Electric Curtailment Plan (EECP) (See Section 18.104.22.168 of the ERCOT Protocols)40. The EECP includes procedures for use of interruptible load, voltage reductions, procuring emergency energy over the DC ties, ISO- instructed demand response procedures and are in place and are described in the ERCOT Operating Guides Section 4.5 Emergency Electric Curtailment Plan (EECP) 41. 38 http://www.ercot.com/mktrules/guides/procedures/TransmissionSecurity_V3R89.doc 39 http://www.ercot.com/mktrules/guides/operating/2007/07/05/05-070107.doc 40 http://www.ercot.com/mktrules/protocols/current.html 41 http://www.ercot.com/mktrules/guides/operating/current.html. Page 38 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments Region Description ERCOT is a separate electric interconnection located entirely in the state of Texas and operated as a single balancing authority. ERCOT has 251 members that represent independent retail electric providers; generators, and power marketers; investor-owned, municipal, and cooperative utilities; and retail consumers. It is a summer-peaking region responsible for about 85 percent of the electric load in Texas with a 2006 peak demand of 62,339 megawatts. ERCOT serves a population of more than 20 million in a geographic area of about 200,000 square miles. Additional information is available on the ERCOT web site42. 42 http://www.ercot.com Page 39 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments FRCC 2008 Projected Peak Demand MW Relative Capacity by Fuel Mix Total Internal Demand 47,364 Direct Control Load Management 2,256 Contractually Interruptible (Curtailable) 691 Coal 17% Critical Peak-Pricing with Control 0 Load as a Capacity Resource 0 Hydro 0.1% Net Internal Demand 44,417 Nuclear 8% MW Change 2007 Actual Summer Peak Demand 46,676 -4.8% Other 2% Gas 52% All-Time Summer Peak Demand 46,676 -4.8% 2008 Projected Capacity MW Margin Oil 21% Existing Certain and Net Firm Transactions 53,077 16.3% Net Capacity Resources 53,552 17.1% Total Potential Resources 54,606 18.7% Introduction FRCC expects to have adequate generating capacity reserves with transmission system deliverability for the 2008 summer peak demand. In addition, existing uncertain merchant plant capability of 1,053 MW is available as potential future resources of FRCC members and others. The transmission capability within the FRCC region is expected to be adequate to supply firm customer demand and to provide planned firm transmission service. Operational issues in the Central Florida area can develop due to unplanned outages of generating units serving this area. However, it is anticipated that existing operational procedures, pre-planning, and training will adequately manage and mitigate the impacts to the bulk transmission system. Demand The Florida Reliability Coordinating Council (FRCC) is forecast to reach its 2008 summer peak demand of 47,364 MW in August, which represents a projected demand increase of 1.5 % over the actual 2007 summer demand of 46,676 MW. This projection is consistent with historical weather-normalized FRCC demand growth and is 1.0% higher than last year’s summer forecast of 46,878 MW. The increase in the 2008 summer peak demand is attributed to normal temperatures and a sluggish economy. 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 actual peak demand. The individual peak demand forecasts are then aggregated by summing these forecasts to develop the FRCC Region forecast. The 2008 net internal FRCC Page 40 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments peak demand forecast includes the effects of 2,947 MW of potential demand reductions from the use of direct control load management and interruptible load management programs composed of residential, commercial and industrial demand. Projections also incorporate MW impacts of new energy efficiency programs. 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. FRCC assesses the peak demand uncertainty and variability by developing regional bandwidths or 80% confidence intervals on the projected or most likely load (90/10). The 80% confidence intervals on peak demand can be interpreted to mean that there is a 10% probability that in any year of the forecast horizon that actual observed load could exceed the high band. Likewise, there is a 10% 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 include weather and non- weather load variability such as demographics, economics and price of fuel and electricity. Factors that dampened the growth outlook for this summer’s forecast include a weaker Florida economy and projected higher fuel prices. Generation The total existing generation in the FRCC region for this summer is 51,683 MW of which 50,629 MW (462 MW of biomass) are certain and 1,053 MW are uncertain. Since the beginning of the year, a net capacity of 476 MW (11 MW of biomass) are planned to be online by September 30, 2008. 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. Purchases and Sales Currently, there are 2,448 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. These purchases have firm transmission service to ensure deliverability into the FRCC region. The FRCC Region does not consider non-firm, expected or provisional sales to other regions as capacity resources. The FRCC Region does not rely on external resources for emergency imports and reserve sharing. Fuel For the 2008 summer period, we do not anticipate any load serving concerns 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 is 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. Page 41 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments 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 additions expected to be in-service for the summer of 2008 include a new 230kV transmission line and the rebuild of an existing 230kV in the Central Florida area. In addition a new 138kV transmission line is expected to be in-service for the summer of 2008 in the Southeast Florida area. Operational Issues No scheduled generating unit or transmission facility maintenance outages of any significance are planned for the summer period. Scheduled transmission outages are typically performed during seasonal off peak periods to minimize any impact on the bulk electric system. In addition, there are no foreseen environmental and/or regulatory restrictions or unusual operating conditions that can potentially impact reliability in the FRCC Region during the 2008 summer period. No unusual operating conditions are expected that could impact reliability for the upcoming 2008 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 analysis program to evaluate current system conditions. These programs are provided with new input data from operating members every ten seconds. These tools enable the FRCC Reliability Coordinator to implement operational procedures such as generation redispatch, sectionalizing, planned load shedding, reactive device control, and transformer tap adjustments to successfully mitigate line loading and voltage concerns that may occur in real time. Reliability Assessment Analysis The FRCC Region is required by the Florida Public Service Commission to maintain a 15% Reserve Margin. Presently, there are no requirements in the FRCC Region to plan for or maintain a specific capacity margin. However, based on the expected load and generation capacity, the calculated capacity margin for the summer of 2008 is 17.1% (Reserve Margin = 21%). This year’s calculated capacity margin is 0.5% lower than last year’s calculation for the summer of 2007. The expected Reserve Margin for this summer includes a total of 2,448 MW import from the Southeastern Subregion of SERC to the FRCC. The total import into the FRCC Region consists of 846 MW of generation that resides in the Southeastern Subregion of SERC owned by FRCC entities and the remaining 1602 MW are firm purchases. These imports account for 5.0 % of the total Reserve Margin, and have firm transmission service to ensure deliverability into the FRCC region. During last year’s summer a total of 2,398 MW (firm transmission service) of external resources were included in the Reserve Margin calculation for the Region. The increase in imports over last year’s summer assessment is primarily due to a firm purchase of 50 MW from the Southeastern Subregion of SERC. The 15% Reserve Margin was established based on a Loss Of Load Probability (LOLP) analysis 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 Page 42 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments this periodic study is to establish resource levels such that the specific resource adequacy criterion of a maximum LOLP of 0.1 day in a given year is not exceeded. The results of the most recent LOLP analysis conducted in 2006 indicated that for the “most likely” and extreme scenarios (e.g., extreme seasonal demands; no availability of firm and non-firm imports into the region; and the non-availability of load control programs), the peninsular Florida electric system maintains a LOLP well below the 0.1 day per year criterion. The FRCC is planning to conduct the next LOLP analysis by the end of 2008. Given the FRCC fuel diversity as listed within the FRCC Load and Resource Database, it is anticipated that fuel supply availability will be adequate during summer peak conditions. For potential generating capacity constraints due to fuel delivery problems, the FRCC State Capacity Emergency Coordinator (SCEC) along with the Reliability Coordinator (RC) have been provided with an enhanced ability to assess Regional fuel supply status by initiating Fuel Data Status reporting by Regional utilities. The recently revised FRCC Generating Capacity Shortage Plan includes specific actions to address capacity constraints due to generating fuel shortages. This process relies on utilities to report their actual and projected fuel availability along with alternate fuel capabilities to serve their projected system loads. This is typically provided by type of fuel and expressed in terms relative to forecast loads or generic terms of unit output depending on the event initiating the reporting process. Data is aggregated at the FRCC and is provided, from a Regional perspective, to the RC, SCEC and governing agencies as requested. Fuel Data Status reporting is typically performed when threats to Regional fuel availability have been identified and is quickly integrated into an enhanced Regional Daily Capacity Assessment Process along with various other coordination protocols to ensure accurate reliability assessments of the Region and also ensure optimal coordination to minimize impacts of Regional fuel supply issues and/or disruptions. The FRCC Region does not have an official definition for deliverability. However, the FRCC Transmission Working Group (composed of transmission planners from FRCC member utilities) conducts regional studies to ensure that all dedicated firm resources are deliverable to loads under forecast conditions and other various probable scenarios to ensure the robustness of the Bulk Electric System (BES). In addition, the FRCC Transmission Working Group evaluates planned generator additions to ensure the proposed interconnection and/or integration is acceptable to maintain the reliability for the BES within the FRCC Region. Availability and deliverability of internal and external resources are ensured by firm transmission service, purchase power contracts and transmission assessments. These internal and external resources were included in the “2008 Summer Transmission Assessment” demonstrating the deliverability of these resources and no deliverability concerns were identified. 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 suppliers and generators within the region. The recently revised FRCC Generating Capacity Shortage Plan includes specific actions to address capacity constraints due to natural gas availability constraints and includes close coordination with the pipeline operators serving the Region. The FRCC Operating Committee has also developed the procedure, FRCC Communications Protocols – Reliability Coordinator, Generator Operators and Natural Gas Transportation Service Page 43 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments Providers, to enhance the existing coordination between the FRCC Reliability Coordinator and the natural gas pipeline operators and in response to FERC Order 698. An interregional 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. Transmission constraints in the Central Florida area may require remedial actions depending on system conditions creating increased west-to-east flow levels across the Central Florida metropolitan load areas. Permanent solutions such as the addition of two new 230kV transmission lines and the rebuild of an existing 230kV transmission line have been identified and implementation of these solutions is underway. In the interim, remedial operating strategies have been developed to mitigate thermal loadings and will continue to be evaluated to ensure system reliability. Transmission constraints in the Northwest Florida area may occur under high imports into Florida from the SERC Region. The FRCC Region and Southeastern Subregion of SERC worked together to develop and approve a special operating procedure to address and mitigate these potential constraints. The FRCC Region is planned and operated such that NERC Reliability Standards are met without the need to identify any specific criteria for minimum dynamic reactive reserve requirements or transient voltage-dip criteria. Transient stability studies are performed by the FRCC and no issues have been identified that would impact the summer 2008 season. Small signal analysis is performed when damping issues are identified during transient stability studies. Voltage stability studies performed in the Region involve identifying the worst case conditions such as the unavailability of multiple units. These studies are normally load flow based using an algorithm that can identify voltage limitations. Under firm transactions, reactive power-limited areas can be identified during transmission assessments performed by the FRCC. These reactive power-limited areas are typically localized pockets that do not affect the bulk power system. The FRCC 2008 Summer Transmission Assessment did not identify any reactive power-limited areas that would impact the bulk electric system during the summer of 2008. The FRCC Region has not identified the need to develop specific criteria to establish a voltage stability margin. The FRCC Region has approximately 700 MW of load set for Under Voltage Load-Shedding (UVLS) in localized areas to prevent voltage collapse as a result of a contingency event. The UVLS system is designed with multiple steps and time delays to shed only the necessary load to allow for voltage recovery. 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 2008 Summer Transmission Assessment, which evaluated the steady-state summer peak load conditions under different operating scenarios, Page 44 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments indicates that any concerns about 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. The FRCC ensures resource adequacy by maintaining a minimum 15% Reserve Margin to account for higher than expected peak demand due to weather or other conditions. In addition, there are operational measures available to reduce the peak demand such as the use of Interruptible/Curtailable load, DSM (HVAC, Water Heater, Pool Pump), Voltage Reduction, customer stand-by generation, emergency contracts and unit emergency capability. The FRCC is not anticipating any other reliability concerns for the 2008 summer conditions. Unexpected potential reliability real-time issues identified by the Reliability Coordinator can be resolved with existing operational procedures. Region Description FRCC’s membership includes 26 members, which is composed of investor-owned utilities, cooperative systems, municipal utilities, power marketers, and independent power producers. Historically, the region has been divided into 11 control areas. As part of the transition to the ERO, FRCC has registered 79 entities (both members and non-members) performing the functions identified in the NERC Reliability Functional Model and defined in the NERC Reliability Standards glossary. The region contains a population of more than 16 million people, and has a geographic coverage of about 50,000 square miles over peninsular Florida. Additional details are available on the FRCC website (https://www.frcc.com/default.aspx). Page 45 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments MRO 2008 Projected Peak Demand MW Relative Capacity by Fuel Mix Total Internal Demand 51,166 Direct Control Load Management 1,587 Dual Fuel 9% Contractually Interruptible (Curtailable) 1,533 Critical Peak-Pricing with Control 0 Load as a Capacity Resource 0 Gas 12% Net Internal Demand 48,047 Oil 4% MW Change Undeter- Coal 51% mined 0.1% 2007 Actual Summer Peak Demand 47,629 0.9% Other 3% All-Time Summer Peak Demand 47,629 0.9% Wind 1.0% Nuclear 7% 2008 Projected Capacity MW Margin Existing Certain and Net Firm Transactions 55,109 12.8% Net Capacity Resources 56,414 14.8% Hydro 13% Total Potential Resources 57,758 16.8% Introduction The Midwest Reliability Organization (MRO) is expected to have sufficient generating capacity within the region to maintain an adequate reserve margin for the 2008 summer peak demand. The transmission system within the MRO region is expected to perform reliably to meet firm customer demand for the summer 2008. There are no significant operational issues that may cause reliability concerns expected in the MRO region during the upcoming summer. From the resource adequacy assessment viewpoint, the MRO membership consists of the members of the MAPP Generation Reserve Sharing Pool (GRSP), members from the former Mid-America Interconnected Network, Inc. (MAIN),43 and a Canadian member, Saskatchewan Power Corporation (SaskPower). The assessment of transmission adequacy and identification of operational issues are, however, conducted by areas in the MRO footprint: Iowa, Nebraska, Northern MRO, and Wisconsin-Upper Michigan Systems (WUMS). The Northern MRO region consists of the Dakotas, Minnesota, part of Montana, and the Canadian provinces of Manitoba and Saskatchewan. Demand The MRO forecasted 2008 summer non-coincident peak total internal demand in the combined MRO US and MRO Canada is 51,166 MW, assuming normal weather conditions. This forecast is 4.2 percent above last summer’s forecasted total demand of 49,102 MW. The MRO 2008 forecast Net Internal Demand is 48,047 MW, which is 1.8 percent higher than the 2007 forecasted Net Internal Demand of 47,177 MW. 43 The former MAIN members are Alliant Energy, Wisconsin Public Service Corp., Upper Peninsula Power Co., Wisconsin Public Power Inc., and Madison Gas and Electric. Page 46 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments Last summer’s actual peak demand was 47,629 MW. This actual peak value is not adjusted to exclude any additional peak-demand reduction demand-side management programs that were not implemented. Direct control load management DSM (1,587 MW, or 3.1 percent) and contractually interruptible demand (1,533 MW, or 3.0 percent), amounting to 6.1 percent of MRO’s projected Total Internal Peak Demand of 51,166 MW, are used by a number of MRO members. A wide variety of demand-side management programs may be used to reduce peak demand during the summer season. Each MRO member uses its own forecasting method. 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 significant changes in this year’s forecast assumptions in comparison to last year. Peak demand uncertainty and variability due to extreme weather and other conditions are accounted for within the determination of adequate generation reserve margin levels, although they are treated differently among the MRO groups, as follows. The MAPP GRSP members and the former MAIN members within MRO use a Load Forecast Uncertainty factor within the calculation for the Loss of Load Expectation (LOLE) and the percentage reserve margin necessary to obtain a LOLE of 0.1 day per year or 1 day in 10 years. The load forecast uncertainty considers uncertainties attributable to weather and economic conditions. For the Saskatchewan system, high and low demand forecasts were simulated using a Monte Carlo method to reflect economic and weather uncertainties. This model considers each uncertainty independently from other variables and assumes a probability distribution around the expected demand forecast. Results are based on an 80 percent confidence interval, meaning there is an 80% probability of the demand falling within the bounds created by the high and low forecasts. Generation The MRO existing internal certain resources for the 2008 summer are 54,752 MW. The MRO existing internal uncertain resources for the 2008 summer are 3,423 MW. Planned resources that will be in service this summer are 1,428 MW. These values do not include firm or non-firm purchases and sales. New generation added before this summer includes generating facilities in Iowa and the Northern MRO area. In Iowa, within the last year, • The net generation output of the Louisa plant was increased from 730 MW to 755 MW; • A 75 MW wind farm was added to the Charles City South 69 kV substation; • The Wall Lake wind farm was expanded by 15 MW to bring the total generation to 200 MW; and • A 200 MW wind farm was added at the new Pocahontas County substation. Page 47 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments A few wind farms have been installed in North Dakota this past year including 180 MW farm near Ellendale, ND and a 159 MW farm near Langdon, ND. A second natural gas peaking unit, rated at 120 MW, near Groton, South Dakota is scheduled to be online in June 2008 to help serve load in northeastern South Dakota. Significant generation additions at High Bridge (after decommissioning generation previously installed, new net output will be 630 MW) in the Twin Cities and Colville (350 MW) near Cannon Falls, MN are expected to be online before summer. Among the resources expected to be in-service for the 2008 summer, there is 3,997 MW nameplate capacity of wind generation. MISO allows a capacity credit of 20% for wind generation. Assuming this 20% capacity value, 799 MW of wind capacity is expected to be available to serve load at peak times. There is, however, a potential ambient temperature restriction (e.g., some wind turbines can be restricted to operating in ambient temperatures between -20 degrees F and 104 degrees F) with wind turbines. The biomass portion of resources for the MRO region expected to be available at peak times is 346 MW. The MRO region is not experiencing a drought that would limit thermal unit cooling. While reservoir water levels continue to remain low in Montana, North Dakota, and South Dakota, and will likely continue to reduce the magnitude and duration of power transfers out of Northern MRO, they are sufficient to meet projected peak demand and energy requirements for the 2008 summer season. The Manitoba water condition is normal and, therefore, normal Manitoba-US power exports are likely. Purchases and Sales For the 2008 summer season, MRO is projecting total firm purchases of 1,192 MW. These purchases are from sources external to the MRO region. MRO has approximately 835 MW of total projected firm sales to load outside of the MRO region. The net transfers in and out of the MRO region can vary at peak load, depending on system conditions and economic conditions. Transmission providers within the MRO region treat Liquidated Damage Contracts (LDC) according to their tariff policies, which may differ among transmission providers. Most MRO members are within non-retail access jurisdictions (except for Upper Michigan) and therefore liquidated damages products are not typically used. MRO members do not count on any emergency imports or reserve sharing from outside of the region to meet their target reserve margins. Fuel MRO considers known and anticipated fuel supply or delivery issues in its assessment and does not foresee any significant fuel supply and fuel delivery issues for the upcoming 2008 summer season. Because MRO has a large diversity in fuel supply, inventory management, and delivery methods throughout the region, it does not have a specific mitigation procedure in place should fuel delivery problems occur. If problems occur, they will be handled on a case-by-case basis. Page 48 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments Transmission Iowa A 200 MW wind farm was added at the new Pocahontas County substation located on the Sac County – Pomeroy 161 kV line. Network upgrades for the Pocahontas County wind farm were completed in 2007 and included reconductoring the Clipper - Little Sioux 161 kV line and the Pomeroy – Hayes 161 kV line. In response to increasing load in the Fort Dodge area, MidAmerican Energy Company constructed the new Tate & Lyle 161 kV substation and added a 125 MVA 161/69 kV auto- transformer to improve load serving capacity and reliability. The new Tate & Lyle 161 kV substation replaced the existing three-terminal Pomeroy – Webster – Sub T 161 kV line with three independent 161 kV lines from Hayes – Pomeroy , Hayes – Webster, and Hayes – Tate & Lyle - Sub T. Nebraska Phase I of Nebraska Public Power District’s Electric Transmission Reliability (ETR) Project for east-central Nebraska is scheduled to be complete prior to the summer of 2008. Phase I of the ETR Project entails conversion to 345 kV of an existing 230 kV transmission line from just north of Norfolk to a point just north of Columbus, expansion of the Hoskins Substation near Norfolk, and construction of the new Shell Creek substation north of Columbus. This phase of the project is expected to improve local area voltage support during the summer months. As a part of the Nebraska City Unit 2 power plant project, a 345 kV transmission line is being built from the site of the Nebraska City 2 plant approximately 50 miles to a new substation southeast of Lincoln. The new line is scheduled to be completed by mid-summer 2008 and is expected to reduce the need for temporary operating guides during critical prior outages in and around Lincoln. Northern MRO The Hensel - Langdon 115 kV line was added in 2007 in association with the 159 MW wind farm near Langdon, ND. The Arrowhead - Stone Lake - Gardner Park 345 kV line was energized January 23, 2008. The line has been included in the new Minnesota-Wisconsin interface defined as MWEX. Studies have shown the export limit for this interface to be 1,525 MW and that this line relieves congestion on the Eau Claire-Arpin 345 kV line and the Alma - Elk Mound 161 kV line. The new interface replaces the Minnesota-Wisconsin Stability Interface as the primary constraint for bulk transfers between Minnesota and Wisconsin. Significant transmission for wind generation has been completed in the Buffalo Ridge area in southwestern Minnesota. The following transmission system upgrades are now in place: • Nobles County - Lakefield Junction 345 kV Page 49 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments • Chanarambie - Fenton-Nobles County 115 kV • Buffalo Ridge - Yankee-Brookings County 115 kV • Brookings County - White 345 kV • Fieldon Series Compensation for Blue Lake - Wilmarth - LGS 345kV line The final upgrade for this area, the Split Rock - Nobles 345 kV line, is expected to be energized before the summer, which will then complete all the transmission improvements needed for the 825 MW of firm wind generation capacity in the Buffalo Ridge area. Other facility additions needed to accommodate growing load for this coming summer include minor projects such as capacitor additions and up-rating facilities. Wisconsin-Upper Michigan Systems The WUMS electric transmission system encompasses the service territories of five Balancing Authorities: Alliant Energy-Wisconsin Power & Light, We Energies, Wisconsin Public Service Corporation, Madison Gas & Electric Company, and Upper Peninsula Power Company. The WUMS system consists of 345, 230, 161, 138, 115, and 69 kV transmission facilities and is owned by American Transmission Company, LLC (ATCLLC). The operation of WUMS is coordinated between ATCLLC and Midwest ISO. Reliable operation of the WUMS transmission system is expected during the summer 2008 season.44 Major transmission projects with expected in-service dates between July 2007 and June 2008 are listed below. These additions and upgrades strengthen the reliability of the WUMS system for the summer 2008 season and subsequent years. • Construct an Arrowhead – Stone Lake 345 kV line. In service in January 2008. • Install an Arrowhead 345 kV substation including a 345/230 kV transformer and two 75 MVAr capacitor banks. Available for service in January 2008. • Install a 230 kV phase shifting transformer in series with the Arrowhead 345/230 kV transformer and the Arrowhead – Stone Lake 345 kV line at the Arrowhead 230 kV substation. In service in January 2008. • Complete the Stone Lake 345 kV substation including installation of a 75 MVAr capacitor bank and a 75 MVAr shunt inductor. Available for service in January 2008. • Install a Cypress 345 kV substation tapping into the Forest Junction – Arcadian 345 kV line. In service in December 2007. • Increase ratings of N. Appleton – Fox River 345 kV line. In-service in April 2008. • Construct an Eagle River – Conover 115 kV line. Expected to be in-service in June 2008. • Construct an Ellinwood – Sunset Point 138 kV line. In service in November 2007. 44 2007 – ATCLLC 10-Year Transmission System Assessment Update, http://www.atc10yearplan.com. Midwest ISO Summer 2008 Assessment Studies (on-going), http://extranet.midwestiso.org/operations/seasonal.php. ReliabilityFirst Corporation (RFC) Summer 2008 Transmission Assessment Studies (on-going), http://www.maininc.org/. Eastern Interconnection Reliability Assessment Group (ERAG) Summer 2008 Inter-regional Transmission Assessment, MRO-RFC-SERC West-SPP (MRSWS) sub-group study (on-going), http://www.midwestreliability.org/. Page 50 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments • Construct Rubicon – Hustisford - Hubbard 138 kV lines. Expected to be in-service in May 2008. • A number of other major projects. There is no anticipated delay of the expected in-service dates for those facilities planned for May and June 2008. Operational Issues There are no known environmental or regulatory restrictions that could impact reliability during the summer 2008 season. Iowa During the summer of 2008, East to West power transfers across Iowa are expected to be at more moderate levels in comparison with the period from 2000-2006, due to operation of the Walter Scott Energy Center Unit-4. This flow pattern is not expected to cause any significant operational issues. Additionally, two 161 kV line flowgates in Central Iowa that used to be the most affected facilities by the East to West flow pattern have been re-conductored.45 The addition of wind generation at Pocahontas and Charles City, as well as in southern Minnesota will contribute better voltage control and less congestion associated with power transfers. Single-event and double-event contingencies were simulated to evaluate steady-state impacts of the Pocahontas and Charles City projects on system loading and bus voltages. None of the simulated contingencies caused violation of emergency ratings. Operating studies indicated that 161 kV facilities in the area are well designed to withstand any credible contingency. However, prior outage conditions may cause limiting of the total wind farm output of Clipper, Pocahontas and Buena Vista wind farms in order to protect underlying 69 kV facilities. Operating guides will be implemented to protect the affected facilities. During congestion, total output of the Charles City wind farm (75 MW) and combustion turbines (35 MW) will be limited to reduce loading on the Adams-Rochester 161 kV flowgate. Summer operation of the Emery combined cycle gas generation near Mason City, Iowa and the MidAmerican Energy Greater Des Moines Energy Center will have positive impacts on reliability of the transmission system in the Waterloo area and in central Iowa, respectively. The central Iowa system will be operated, most of the summer, without the 345/161 kV transformer at the SE Polk substation that experienced an unrecoverable failure. The new transformer is expected to be in service in late August. The Sycamore combustion turbines can be run if necessary for transmission relief. A temporary operational guide is pending by MidAmerican and will be in place for the 2008 summer season. The Oak Grove-Galesburg Standing Operating Guide has been developed by MISO-Central to document the operating procedures necessary to deal with heavy real-time loading on both Galesburg 161/138 kV transformers and potential operating issues associated with a potential loss of either the TSS940-Nelson 345 kV line or the Quad Cities-N.W.S&Q 345 kV line with subsequent post-contingency overloading of the 161 kV line Oak Grove-Galesburg. The 45 MEC-1. “2007 N-2 Contingency Analysis Studies”, MidAmerican Energy, System Planning Department, February 2008. Page 51 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments Galesburg 161/138 kV transformers and the Oak Grove-Galesburg 161 kV line should be adequately protected by this operating guide. Standing operating guides for all Iowa flowgates have been reviewed and made available to the transmission operators. In addition to the standing operating guides, temporary operating guides will be issued in case of any unexpected change in system configuration due to forced outages or for scheduled outages in which high transfer levels create operating conditions with a likelihood of violating system operating limits. The Seams Operating Agreement between Midwest ISO and MAPP will continue to be used for facilitating coordination of congestion management procedures on Iowa flowgates. Nebraska Nebraska Public Power District (NPPD) and Omaha Public Power District (OPPD) currently post six constrained paths on the MAPP OASIS which are located within or adjacent to the NPPD and OPPD control areas. All of these interfaces have approved operating guides that have historically proven effective in dealing with system conditions throughout the year. During the summer peak and off-peak loading periods, two export interfaces are monitored closely including the Cooper South Interface (COOPER_S) and the Western Nebraska to Western Kansas Interface (WNE_WKS). Upgrades to the COOPER_S Interface are expected to be completed prior to the 2008 summer season which should result in less frequent TLR events. During peak loading periods with heavy exports to the south, NERC TLR is expected to be implemented to limit the flows on the GGS-Red Willow 345 kV line to address system operating limits associated with the WNE_WKS Interface. With increased loads in the western Nebraska area during the summer months, stability limitations associated with the Gerald Gentleman Station (GGS) Stability Interface are less severe. High power transfers out of the western Nebraska area are typically less in 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. Northern MRO No significant operational issues are expected this summer for the Northern MRO area. The existing approved operating guides that are in use today have maintained a reliable transmission system throughout the year. Page 52 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments A number of bulk transmission outages are scheduled for maintenance in the US portion of the Northern MRO area; however no operating problems are expected. Temporary operating guides will be developed as necessary. Wisconsin-Upper Michigan Systems The completion of the Arrowhead – Stone Lake – Gardner Park 345 kV line provides needed transmission reinforcement on the WUMS western interface with Minnesota and improves the WUMS transmission reliability and transfer capability. Studies have demonstrated that with high imports into WUMS from Minnesota, there is potential transient voltage recovery limit and voltage instability limit and therefore determined the need for a new interface flowgate comprised of Arrowhead-Stone Lake 345 kV line and King-Eau Claire 345 kV line, called the Minnesota Wisconsin Export (MWEX) Interface. This interface is managed as a reciprocal Interconnection Reliability Operating Limit (IROL) Flowgate of Midwest ISO and MAPP. The existing Minnesota Wisconsin Stability Interface (MWSI) will be retained for prior outage conditions and to gain operational experience with MWEX. The existing operating guides for King – Eau Claire – Arpin 345 kV line and Arpin – Rocky Run 345 kV line will be accordingly revised for summer 2008. With high imports into WUMS through southwest Wisconsin, the Paddock 345/138 kV transformer could be overloaded for loss of the Wempletown – Rockdale 345 kV tie-line. Also, with high imports or exports through southeast Wisconsin, the Lakeview – Zion 138 kV line could be overloaded for loss of either of the two 345 kV tie-lines, Pleasant Prairie – Zion or Arcadian – Zion. Together, these southeast and southwest tie-lines comprise the ATC South Ties Interface, which is thermally limited for critical N-1 contingencies and voltage stability limited for critical N-2 contingencies during periods of heavy transfers across the interface. Operating guides are used to monitor and manage the constraints during high imports into WUMS across this southern interface. The ATCLLC has filed an application with the Public Service Commission of Wisconsin to add a new 345 kV transmission line between the Rockdale and Paddock 345 kV substations that will help to alleviate the southern interface constraints. The eastern portion of the Upper Peninsula of Michigan (UP) is susceptible to changes from generating to pumping mode at Ludington pumped storage station (in lower Michigan). As a result, the eastern UP can experience flows in both directions — from east to west and west to east. Heavy flows in either direction across the McGulpin – Straits 138 kV tie-line can cause potential thermal violations in the eastern UP. Additionally, an east to west system bias can result in low voltages or voltage instability in the eastern UP. Additions of the second 138/69 kV transformers at Hiawatha (in-service January 2008) and at Straits (in-service December 2007) have helped reduce the constraint level. This constraint continues to be managed by opening the 69 kV lines between the eastern UP and the rest of the WUMS system, as per the operating guide. ATC has initiated an Eastern UP Strategic Assessment Team to review this situation. ATC is working with the Michigan Transmission Owners and the Midwest ISO to evaluate this operating challenge. The pressure of power import into UP from northeast Wisconsin continues. The 138 kV corridor consisting of the three 138 kV lines south of the Morgan and Stiles substations continues to be a potential constraint that could lead to thermal and voltage violations under contingencies during Page 53 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments periods of high flows towards UP. This constraint is monitored and managed by following an operating guide. Completion of the Werner West – Highway 22 – Morgan and Gardner Park – Highway 22 345 kV lines in late 2009 will help to alleviate this constraint. Operating studies have been or will be performed for all scheduled transmission or generation outages during the 2008 summer season. When necessary, temporary operating guides will be developed for managing the scheduled outages to ensure transmission reliability. Reliability Assessment Analysis In December 2007, the MRO Board of Directors approved a regional standard, RES-501-MRO- 01, requiring all LSEs or their designated entity to annually perform a Resource Adequacy study. This will be required by December 2008, one year after board approval. Reserve margins are typically used as criteria for a target level, as opposed to capacity margins. MRO’s projected 2008 summer Reserve Margin is 17.5% without uncertain resources. For the MAPP GRSP members, resource adequacy is measured through the accreditation rules and procedures. The MAPP GRSP requires a 15% reserve capacity obligation (RCO) for predominantly thermal systems, and 10% reserve margins for predominantly hydro systems.46 The RCO is established by the MAPP Restated Agreement and its governing authorities, i.e. MAPP Executive Committee and MAPP Pool Committee. This level of reserve requirements is subject to periodic review based on reserve requirements studies conducted regularly by MAPP.47 The RCO requires the MAPP GRSP members to maintain their respective minimum reserve based on after-the-fact peak demand; i.e., the members are responsible for maintaining adequate generation to account for load forecast uncertainty. When a new peak occurs, the member will be required to maintain the minimum reserve based on that peak for the next 11 months, or until a new, higher peak takes place. Approximately 8,850 MW of generation in the MAPP GRSP (15.7% of MRO net internal capacity) is associated with predominantly hydro systems and only requires a 10% RCO. The projected MRO reserve margin of 17.5% for the 2008 summer season is in excess of the MAPP Reserve Capacity Obligation. For the former MAIN members, generation resource adequacy is assessed based on LOLE studies previously conducted by the MAIN region.48 Although conducted on a yearly basis, MAIN’s LOLE studies consistently recommended a minimum short-term planning reserve margin of 14%. The projected MRO reserve margin of 17.5% for the 2008 summer season is in excess of the target Reserve Margin. 46 The MAPP GRSP Handbook, http://www.mappcor.org/assets/pdf/GRSP_Handbook_20070116.pdf. 47 The last MAPP reserve requirements study was conducted in 2003 by the MAPP Composite System Reliability Working Group. This study has not been posted on the MAPP website, but it is available upon request from Brian Glover, MAPPCOR (651-855-1715 or firstname.lastname@example.org). 48 In the former MAIN region, MAIN Guide 6 adopted a resource adequacy criterion of 0.1 days/year, http://www.maininc.org/bg/guide6.pdf. Studies concerning LOLE calculations for the former MAIN Region are available. The 2005 study is located at http://www.maininc.org/files/MG6GenerationReliabilityStudy2005_14.pdf. Other studies are found by navigating through http://www.maininc.org/files/files.htm. Page 54 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments Saskatchewan's reliability criterion is based on annual expected unserved energy (EUE) analysis and equates to an approximate 15% reserve margin requirement.49 The projected MRO reserve margin of 17.5% for the 2008 winter season is in excess of the target Reserve Margin. This summer’s projected capacity margin of 14.9%, which includes certain resources only and net interchange, can be compared with last summer’s projected capacity margin of 17.2% (considering committed resource and net interchange). With uncertain resources included, the 2008 projected capacity margin is 19.7%, as compared to 17.4% in 2007 with uncommitted resources included. There are several reasons for this difference. There are likely some differences in the way members submitted their generation data due to the significant changes in generation definitions implemented by NERC in 2008. Additionally, the difference between the nameplate value of variable generation (wind in particular) and that portion considered as capacity was submitted as Existing-Uncertain resources. Also, purchases and sales in 2007 included purchases from IPPs within the MRO footprint, since that is how data was previously collected. For 2008, MRO staff attempted to include all IPP MWs as an internal resource, not as a purchase. Most large IPPs that are registered as Generator Owners within the MRO region were properly captured. However, there are smaller IPPs within the MRO region 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. Throughout the MRO region, firm transmission service is required for all generation resources that are used to provide firm capacity; consequently, these firm generation resources are fully deliverable to the load. There are no known deliverability concerns with the various methods used within the MRO region for firm deliverability. Generation deliverability is performed by Transmission Providers within the MRO region. Links to deliverability criteria within the MRO region are: http://www.midwestiso.org/page/Generator+Interconnection http://www.mappcor.org/content/policies.shtml https://www.oatioasis.com/spc/ No specific analysis is performed to ensure external resources are available and deliverable. However, to be counted as firm capacity the MAPP GRSP, former MAIN utilities, and Saskatchewan require external purchases to have a firm contract and firm transmission service. Based on the MRO/RFC/SPP/SERC-W 2008 Summer Inter-regional Assessment, the non- simultaneous Total Import Capabilities into MRO from RFC-W, SERC-W, and SPP Regions are:50 49 Studies concerning EUE and Loss of Load calculations on the Saskatchewan Power system are presently considered internal documents and are not publicly posted. Information regarding these studies may be obtained by contacting Wayne Guttormson, Saskatchewan Power (306-566-2166 or email@example.com). 50 Eastern Interconnection Reliability Assessment Group (ERAG) Summer 2008 Inter-regional Transmission Assessment, MRO- RFC-SERC West-SPP (MRSWS) sub-group study (on-going), http://www.midwestreliability.org/. Page 55 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments TIC The Total Import Capability (TIC) is equal to the net import Transfer Direction (MW) into MRO (1,752 MW) in the base case plus the First Contingency Incremental Transfer Capability (FCITC) RFC West / MRO 2400 obtained in the transfer analysis. These studies recognize SPP / MRO 3300 constraints internal and external to the MRO. SERC West / MRO Transient, voltage and small signal stability studies are 0 performed as part of the near-term and long-term transmission 51 assessments. Voltage stability is also evaluated in the Midwest ISO’s seasonal assessment.52 The results of the Midwest ISO summer assessment were not available prior to the due date of this regional assessment. No transient, voltage, or small signal stability issues are expected that impact reliability during the summer 2008 season. Most subregional entities evaluate dynamic reactive reserve requirements on a case-by-case basis if issues are identified. For example, dynamic reactive margin is part of the ATCLLC Planning Criteria, which is determined using a reduction to the reported reactive capability of synchronous machines. A 10 percent dynamic reactive margin is required in the intact system and a 5 percent dynamic reactive margin is required for NERC Category B contingencies.53 Manitoba Hydro maintains a 150 MVAr reserve on the Dorsey Substation synchronous condensers at all times to cover for the loss of small and large synchronous condensers and prevent voltage collapse from occurring. In addition, no less than 20 MVAr reserve per in- service synchronous machine is permitted when the synchronous machines are taking in MVAr. This is required to reduce the risk of system overvoltage for loss of HVDC-connected generation or loss of a synchronous machine during light load periods. Iowa, Nebraska, Northern MRO, and WUMS all have transient voltage dip criteria or guidelines with varying requirements.54 As an example, the MAPP default criteria require voltage recovery to be within 70 percent to 120 percent of nominal following the clearing of a disturbance. The Operational Issues section above has identified potential voltage stability limitations. Subregional entities evaluate voltage stability limitations and margins on a case-by-case basis.55 For example, voltage stability margin is part of the ATCLLC Planning Criteria. Under NERC Category B contingencies, the steady state system operating point of selected areas for evaluation is required to be at least 10 percent away from the nose of the P-V curve. 51 2007 – ATCLLC 10-Year Transmission System Assessment Update, http://www.atc10yearplan.com. 2008 MAPP System Performance Assessment. MAPP Small Signal Stability Analysis Project Report, June 2007. Midwest ISO 2007 Expansion Planning, http://www.midwestiso.org/page/Expansion%20Planning. 52 Midwest ISO Summer 2008 Assessment Studies (on-going), http://extranet.midwestiso.org/operations/seasonal.php. 53 ATCLLC collects the generator maximum reactive capability information from the generator owners within ATCLLC footprint. For reactive reserve analysis, power flow cases would be created with a 5% or 10% simultaneous reduction in maximum reactive capability of all generators within ATCLLC footprint. Analysis of Category A and B contingencies would then be performed. Voltage violations are not acceptable in the case with a 10% reduction in generator maximum reactive capability under Category A contingencies. Voltage violations are not acceptable in the case with a 5% reduction in generator maximum reactive capability under Category B contingencies. 54 2007 – ATCLLC 10-Year Transmission System Assessment Update, http://www.atc10yearplan.com. MAPP Members Reliability Criteria and Study Procedures Manual, November, 2004. 55 2007 – ATCLLC 10-Year Transmission System Assessment Update, http://www.atc10yearplan.com. The MAPP Reliability Handbook, December 2004 Page 56 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments Several members within the MRO region have Undervoltage Load Shedding programs to prevent localized low voltage conditions. These programs are not required to protect the bulk electric system. Assessment Process The MRO Reliability Assessment Committee is responsible for this summer reliability assessment. The MRO Transmission Assessment Subcommittee, the MRO Resource Assessment Subcommittee, the MAPP Transmission Operations Subcommittee, the ATCLLC, and Saskatchewan Power Corporation all contribute to this MRO Summer Reliability Assessment. Region Description The Midwest Reliability Organization (MRO) has 48 members which include Cooperative, Canadian Utility, Federal Power Marketing Agency, Generator and/or Power Marketer, Small Investor Owned Utility, Large Investor Owned Utility, Municipal Utility, Regulatory Participant and Transmission System Operator. The MRO has 19 Balancing Authorities and 115 registered entities. The MRO Region as a whole is a summer peaking region. The MRO Region covers all or portions of Iowa, Illinois, Minnesota, Nebraska, North and South Dakota, Michigan, Montana, Wisconsin, and the provinces of Manitoba and Saskatchewan. The total geographic area is approximately 1,000,000 square miles with an approximate population of 20 million. Page 57 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments NPCC 2008 Projected Peak Demand MW Relative Capacity by Fuel Mix Total Internal Demand 111,226 Direct Control Load Management 378 Coal 10% Contractually Interruptible (Curtailable) 1,999 Dual Fuel Critical Peak-Pricing with Control 0 18% Load as a Capacity Resource 1,975 Net Internal Demand 106,874 MW Change Hydro 31% Gas 13% 2007 Actual Summer Peak Demand 108,794 -1.8% All-Time Summer Peak Demand 114,216 -6.4% 2008 Projected Capacity MW Margin Oil 8% Other 1.1% Existing Certain and Net Firm Transactions 133,225 19.8% Wind 0.2% Net Capacity Resources 136,331 21.6% Nuclear 16% Pumped Total Potential Resources 150,849 29.2% Storage 3% The non-coincident aggregate 2008 summer total projected internal demand56 is 111,55757 MW (Canadian demand is 49,778 MW; U.S. demand is 61,779 MW). This forecast peak demand is little changed (-0.2%) from last summer’s 111,83058 MW forecast aggregate demand. The forecast is based on average weather conditions and is 2.4% higher than last summer’s non-coincident aggregate actual 108,958 MW peak demand. All NPCC sub-regions (ISO New England (ISO-NE), the New York Independent System Operator (NYISO), Hydro-Québec TransÉnergie, the Ontario Independent Electricity System Operator (IESO) and the Maritimes) expect sufficient resources to be available to meet projected demands during 2008 summer and have monthly projected net capacity margins ranging from 15.6% to 53.0%. Québec and the Maritimes are predominately winter peaking Areas, and therefore adequate resources, including the supply for firm external sales, are expected to be available. Adequate transfer capability exists to transmit surplus resources from these sub-regions to the others; however, a certain amount of bottling of resources from Québec and the Maritimes to the rest of NPCC is normal and expected. In general, in the NPCC region load projections show little increase, and very little new generating capacity is coming on line for the summer 2008 period. Wind capacity in NPCC and associated peak derates are highlighted in the table below. 56 These figures differ from NPCC's May 1, 2008 Summer Assessment (http://www.npcc.org/documents/reports/Seasonal.aspx) as NPCC includes the month of May as part of the summer period in their non-coincident demand. 57 This demand figure is the sum of sub-regional summer season forecast peaks, regardless of month. NERC’s Total Internal Demand is the greatest sum of sub-regional monthly forecast peaks. Therefore these figures may differ. 58 This demand figure is the sum of sub-regional summer season actual peaks, regardless of month. NERC’s Total Internal Demand is the greatest sum of sub-regional monthly actual peaks. Therefore these figures may differ. Page 58 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments Very little new generating capacity is Nameplate Capacity after Sub-Region expected to go into service for the 2008 Capacity Applied De-rating summer period. Capacity additions in the Maritimes 159.7 MW 43.7 MW NPCC Areas include: Maritimes (0 New England 11.1 MW 4.3 MW MW), New England (210 MW), New York (65 MW), Ontario (371 MW), New York 424 MW 42.4 MW Quebec (489 MW). Ontario 471 MW 47 MW Québec 420 MW 0 MW With regard to transmission, a new 345 kV transmission line between Point Lepreau, New Brunswick and Orrington, Maine went into service during December of 2007. It has increased the New Brunswick - MEPCO Total Transfer Capability (TTC) from 700 to 1000 MW and the MEPCO – NB TTC from 300 to 550 MW. Just prior to the summer peak season, New England and New York expect to energize a replacement set of 138 kV submarine cables in the 1385 (Norwalk Harbor-Northport 138 kV) circuit connecting southwestern Connecticut to Long Island, NY. The original cables had become highly unreliable due to a number of incidents where they had been damaged by marine anchors. Phase angle regulators (PARs) are installed on three of the four Michigan to Ontario interconnections. One PAR, on the Keith to Waterman 230 kV circuit J5D has been in service and regulating since 1975. The other two available PARs, on circuits L51D and L4D, which had been bypassed pending completion of agreements between the IESO, the Midwest ISO, Hydro One and the International Transmission Company, were placed in service on April 14, 2008, and they are expected to start regulating before the summer. All parties have committed to completing the necessary operating agreements to meet this schedule. The operation of the phase angle regulators will assist in the management of system congestion and control of circulating flows. The fourth PAR, responsible for controlling the tie flow on the 230 kV circuit B3N, remains unavailable and is undergoing replacement. This PAR is located in Michigan at the Bunce Creek terminal of circuit B3N. Upgrades in the Rochester vicinity are continuing in preparation of the Russell Station retirement this summer. A capacitor bank is scheduled to be added to Millwood 345 by June 1, 2008. Detailed summaries of the expectations of each of the NPCC sub-regions follow: Maritime Area Demand The actual peak for summer 2007 was 3,496 MW on July 27, 2007, which was approximately 242 MW (6.9 %) lower than last year’s forecast of 3,738 MW. Based on the Maritime Area 2008 demand forecast, a peak of 3,542 MW is predicted to occur for the summer period, June through September. The 2008 demand forecast is lower by 196 MW (5.2 %) when compared to the 2007 demand forecast. This reduction in demand is expected to be due to a combination of Page 59 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments higher than normal temperatures forecast for 2008 summer and resulting in a lower electric heating load in September 2008, and loss of industrial load due to plant closures. The weekly Maritime Area load is the mathematical sum of the forecasted weekly peak loads of each of the sub-areas (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 effect of load coincidence within the week. If the total Maritime Area load included a coincidence factor, the forecast load would be approximately 1-3% lower. For the 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 for general service and industrial loads, correlating forecasted economic growth and historical loads. Each of these models is weather adjusted using a 30-year historical average. For Nova Scotia, the load forecast is based on a 30-year historical normal climate for the major load center, along with analyses of sales history, economic indicators, customer surveys, technological and demographic changes in the market, and the price and availability of other energy sources. 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 using the previous year’s data. The Northern Maine Independent System Administrator performs a trend analysis on historic data in order to develop an estimate of future loads. Load Management is not used to reduce the forecast in the resource adequacy assessment for the Maritime Area. In the Maritime Area there is between 445 and 487 MW of interruptible demand available during the assessment period; there is 487 MW forecasted to be available at the time of the Maritime Area seasonal peak. Generation The Maritimes Area resources will vary between 6,425 MW and 6,428 MW of existing capacity plus 2.4 MW of planned wind generation scheduled to come on line during the summer period. The uncertain portion of the existing capacity ranges from 367 MW to 457 MW. Of the existing capacity there is 159.7 MW of wind expected on peak and 154.1 MW of biomass. The Maritimes Area is forecasting normal hydro conditions for the summer 2008 assessment period, and it is not presently, nor does it anticipate, a drought. Purchases and Sales on Peak There are no purchases from other regions or sub-regions that would affect the capacity margins in the Maritimes Area. However, there is a firm sale of 205 MW to Hydro Quebec which is tied to specific generators. The firm transmission to provide the sale at the Quebec-New Brunswick border is also tied to this transaction. The Maritime Area does have agreements in place for the purchase of emergency energy with other sub-regions of NPCC as well as a reserve sharing agreement within NPCC. But the Maritime Area does not rely on this assistance when doing the summer assessment. Page 60 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments Fuel The Maritime Area does not consider potential fuel-supply interruptions in the regional assessment because the fuel supply in the Maritimes Area is very diverse and includes nuclear, natural gas, coal, oil (both light and residual), Orimulsion, hydro, tidal, municipal waste, and wood. Transmission A new 345 KV transmission line between Point Lepreau, New Brunswick and Orrington, Maine went into service in December 2007. It has increased the NB to MEPCO Total Transfer Capability from 700 to 1000 MW and the MEPCO to NB Total Transfer Capability from 300 to 550 MW. Operational Issues There are no major generating unit or transmission facility outages anticipated for the summer that will impact reliability in the Maritime Area. Furthermore, there are no environmental or regulatory restrictions that could impact reliability in the Maritime Area. The Point Lepreau generation station will be out of service for 18 months and this will include the entire summer assessment period. New Brunswick System Operator does not expect any unusual operating conditions for the summer that will impact reliability in the Maritime Area. Reliability Assessment Analysis When allowances for unplanned outages (based on a discreet MW value representing an historical assessment of the total forced outages typically experienced at the time of peak for the given operating season) are considered, the Maritime Area is projecting more than adequate surplus capacity margins above its operating reserve requirements for the summer 2008 assessment period. These surplus margins range from 35 to 53 % over the period from June 2008 through September 2008, meeting the NPCC once-in-10-year requirement for preventing the disconnection of firm load due to a capacity deficiency. The Maritimes Area is a winter peaking system and resource adequacy is generally not a concern during the summer operating period. No external resources were used by the Maritimes Area to meet capacity margins during 2007 summer and none are used for the 2008 summer period. To ensure seasonal resource adequacy, the Maritime Area conducts an 18-month load and resource balance assessment in accordance with NPCC Document C-13, “Operational Planning Coordination” (http://www.npcc.org/documents/regStandards/Procedure.aspx). The projected capacity margin for summer 2008 period is 35 to 53 percent as compared to the projected capacity margin for the summer 2007 of 29 to 52 percent. In the Maritime Area deliverability of generation to load is not a concern, operationally, as there are no transmission constraints or zonal issues within the area. The Maritime Area does not consider potential fuel- supply interruptions in the regional assessment because the fuel supply in the Maritimes Area is very diverse and it includes nuclear, natural gas, coal, oil (both light and residual), Orimulsion, hydro, tidal, municipal waste, and wood. As indicated in the Transmission section above, a new 345 KV transmission line between Point Lepreau, New Brunswick and Orrington, Maine went into service in December 2007. It has Page 61 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments increased the NB to MEPCO Total Transfer Capability from 700 to 1000 MW and the MEPCO to NB Total Transfer Capability from 300 to 550 MW. Because of the characteristics of the power system, the Maritimes Area does not have any transmission constraints that could impact reliability. Furthermore, this assessment did not use steady state or dynamic simulation analysis. The Maritimes Area does not use specific criteria for minimum dynamic reactive requirements or margins or voltage dip as reactive resources are based on local needs. The Maritimes Area system does not have stability or voltage-limited interfaces and has no need to apply voltage stability margins. Currently, no Under Voltage Load Shedding systems are installed in the Maritimes. In summary, no significant reliability concerns are expected for summer 2008. The Maritime Area participates in the NPCC Summer and Winter Reliability Assessment operations planning studies. The Maritimes Area is a winter peaking system. This area covers approximately 57,800 square miles serving a population of around 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). New England Demand The ISO New England’s Balancing Authority area actual 2007 summer peak load, which occurred on August 3, 2007, was 26,145 MW. The reference peak load forecast for the summer of 2007 was 27,360 MW. The 2008 summer peak load forecast is 27,970 MW which is 610 MW (2.2%) higher than the 2007 forecast. The key factors leading to this change in the forecast are underlying population and economic growth. The reference case forecast is the 50/50 forecast (50% chance of being exceeded), corresponding to a New England 3-day weighted temperature-humidity index (WTHI) of 80.1 which is equivalent to a dry bulb temperature of 90 degrees Fahrenheit and a dew point temperature of 70 degrees Fahrenheit. The 80.1 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 economic conditions that “most likely” would occur. ISO New England develops an independent load forecast for the Balancing Authority area as a whole, and does not use individual members’ forecasts of peak load in its load forecast. A total of 1,352 MW of demand resources that could be interrupted during times of capacity shortages is assumed available for the summer of 2008. These resources, which are in ISO New England’s Real-Time 30-minute, Real-Time 2-Hour, and Profiled Demand Response programs, are instructed to interrupt their consumption during specific actions of Operating Procedure No. 4 (OP 4) Action during a Capacity Deficiency59. Some of the assets in the Real-Time Demand Response programs are under direct load control. The direct load control involves the 59 http://www.iso-ne.com/rules_proceds/operating/isone/op4/index.html Page 62 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments interruption of central air conditioning systems in residential, commercial and industrial facilities. These direct load control resources are not reported separately from the other assets in the Real-Time Demand Response program. In addition to demand response resources, ISO New England considers energy efficiency to be a capacity-side resource. New energy efficiency programs are projected to amount to 331 MW in summer 2008. Not included in this assessment, is voluntary load that will interrupt based on the price of energy. As of February 29, 2008, there were approximately 97 MW enrolled in the price response program. The actual value of the load that responded is captured in collected demand response data; at the time of the peak in 2007, this figure was about 50 MW. ISO New England addresses peak demand uncertainty in two ways: • Weather — peak load distribution forecasts are made based on 37 years of historical weather which includes the reference forecast (50% chance of being exceeded), and extreme forecast (10%chance of being exceeded); • Economics — alternative forecasts are made using high and low economic scenarios. ISO New England reviews the 2008 summer conditions using the extreme, 90/10 peak demand based on the reference economic forecast. For summer 2008, that value is 29,895 MW. Generation The ISO New England Balancing Authority area Existing-Certain generating capacity amounts to approximately 30,900 MW based on summer ratings. None of the existing capacity is in the Existing-Uncertain category. Approximately 4 MW of the Existing-Certain capacity is wind generation, all of which is expected to be available on peak. The total nameplate capability of those wind facilities is 11 MW. An additional 24 MW (nameplate) of wind capacity is projected to begin commercial operation in September. The expected on-peak capacity of that facility has not yet been determined. A total of 210 MW of Planned capacity resources, not including the aforementioned wind plant, are expected to become commercial by the end of the summer. Also included in the Existing-Certain capacity is 765 MW of variable hydro resources. The full 765 MW is expected to be available on peak. A hydro uprate planned for completion by the beginning of the summer is expected to be able to produce an additional 16 MW on peak. Biomass capacity totals 888 MW, all of which is considered to be in the Existing Certain category. A Planned biomass facility with a capacity rating of 17 MW is expected to be in commercial operation by the summer, and another 5 MW project has a September projected commercial date. Hydro generation contributes to approximately 5% of the total New England generation, and hydro conditions are anticipated to be sufficient to meet the expected capability of these plants Page 63 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments this summer. The New England area is not experiencing a drought, and reservoir levels are expected to be normal for the upcoming summer. Purchases and Sales on Peak The forecast of summer firm external capacity purchases is 401 MW. This includes 310 MW from Hydro-Québec and 91 MW from New York. Only firm, Installed Capacity (ICAP) purchases that are known in advance are included as capacity. While the entire 401 MW of ICAP purchases are backed by firm contracts for generation, there is no requirement for those purchases to have firm transmission service. However, it is specified that deliverability of ICAP purchases must meet the New England delivery requirement and should be consistent with the deliverability requirements of internal generators. The market participant is free to choose the type of transmission service it wishes to use for the delivery of energy associated with ICAP, but the market participant bears the associated risk of ICAP market penalties if it chooses to use non-firm transmission. The 310 MW purchase from Hydro- Québec is a Liquidated Damage Contract (LDC) that is not a “make-whole” contract. The 91 MW purchase from New York is not an LDC. For the summer period, ISO-New England expects a firm sale to New York (Long Island) of 343 MW via the Cross Sound Cable. Although this sale is backed by a firm contract for generation, if past practice is indicative of future actions, the energy and capacity will be considered to be recallable by New England. This means that it can be cut earlier than non-recallable exports in the case of a transmission import constraint into Connecticut. The sale across the Cross Sound Cable is based on a make-whole contract. Based on experience, ISO New England assumes that it has 2,000 MW of emergency assistance, also referred to as tie-line benefits, available from other areas within the NPCC region. This is about 50% of New England’s total import capability. ISO New England also participates in a regional reserve sharing group with NPCC, and has a shared activation of reserves agreement with New York for up to 300 MW. Fuel ISO New England (ISO-NE) routinely gages the impacts that fuel supply disruptions will have upon system or sub-region reliability. Because natural gas is the predominant fuel used to produce electricity in New England, ISO-NE continuously monitors the regional natural gas pipeline system to ensure that emerging gas supply or delivery issues can be incorporated into the daily operating plans. Transmission During the upcoming Summer Operating Period, data provided by the New England Transmission Owners indicates that few new facilities are expected to be placed in service. A new autotransformer will be added at the Barbour Hill Substation in Connecticut. This autotransformer will provide a new supply from the 345 kV network into the existing radial 115 kV network which serves north central Connecticut. Addition of this transformer also removes load from the existing Manchester auto transformers which provide supply to the Middletown area and therefore eases operating constraints in this area. Page 64 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments A new 345/115 kV autotransformer will be added at the existing Scobie Substation in New Hampshire in order to provide additional supply into the southern New Hampshire 115 kV network. Projects that have already been placed in service include the Northeast Reliability Interconnection (NRI), which is a new 345 kV line between Orrington, Maine and Pt. Lepreau in New Brunswick. This area inter-tie improves the stability performance between New England and New Brunswick and also allows for increased transfers in both directions between the areas. The NRI became operational in December 2007. In addition, a new 115 kV line was built between the Scobie and Hudson substations to eliminate thermal overloads in the southern Manchester area of New Hampshire. Just prior to the summer peak season, New England and New York expect to energize a replacement set of 138 kV submarine cables connecting southwestern Connecticut to Long Island, NY. These cables replace an older set of cables that had become highly unreliable due to a number of incidents where they had been damaged through contact with marine anchors. The new cables will be buried, reducing the likelihood of future outages caused by external forces. Operational Issues There are no significant anticipated unit outages, variable resource, transmission additions or temporary operating measures that would adversely impact reliability during the summer. As stated in the Transmission section, new transmission upgrades have been placed in service or are expected to soon be placed in service which will improve the reliability of various portions of the New England transmission system. During extremely hot days and low river flow conditions, there may be environmental restrictions on generating units due to water discharge temperatures. Over the past four years, such conditions have occurred three times, resulting in reductions ranging from 150 MW to 200 MW. These reductions are reflected in our forced outage assumptions. The ISO monitors the situation and expects adequate resources to cover such forced outages or generator reductions. At this time, 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. Reliability Assessment Analysis ISO New England bases its capacity requirements on a probabilistic loss-of-load-expectation analysis that calculates the total amount of installed capacity needed to meet the NPCC once-in- 10-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 2008/2009 capability year. The ICR is approximately 32,160 MW during July and August, which results in reserves of 15.0%. The model used for conducting the 2008/2009 system-wide ICR calculations for New England accounts for all known external firm purchases and sales, which in 2008/2009 amount to a net value of 58 MW. This value is essentially the same as the 55 MW of net purchases and sales assumed in 2007/2008. In addition, 2,000 MW of tie-line benefits from neighboring systems were included in the ICR modeling for both summer 2007 and summer 2008. Page 65 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments ISO-New England’s latest resource adequacy studies are detailed in the report, “ISO New England Installed Capacity Requirements for the 2008-2009 Capability Year60.” For this summer reliability assessment, ISO-NE projects an installed capacity margin of approximately 4,844 MW (15.6 percent) under the reference economic forecast at the 50/50 peak load level forecast, and about 2,919 MW (9.4 percent) under the reference economic forecast at the 90/10 peak load level during the peak load period (July and August 2008). The net margin is based on known outages, anticipated generation additions and retirements, projected firm purchases and sales, and the impact of expected demand response programs. The margin does not include allowances for any unplanned outages or for operating reserve. The summer 2007 and 2008 projected 2007 Margin 2008 Margin capacity margins are summarized in the (MW) (MW) table. The projected margins are Reference sufficient to cover the New England (50/50 Forecast) 4250 4844 operating reserve requirement, which is Extreme approximately 1,800 MW; however, (90/10 Forecast) 2445 2919 higher than expected unit outages and/or higher than anticipated load could adversely affect the forecasted margin. During the 2007 summer peak load period, the projected capacity margin under the 50/50 peak load forecast was approximately 4,250 MW, and the capacity margin under the 90/10 forecast was about 2,445 MW. The 50/50 and 90/10 margins forecasted for the 2008 summer are about 594 MW and 474 MW higher, respectively, than the 50/50 and 90/10 margins forecasted for 2007. ISO New England currently addresses generation deliverability through a combination of transmission reliability and resource adequacy analyses. Detailed transmission reliability analyses of sub-areas of the New England bulk power system confirm that reliability requirements can be met with the existing combination of transmission and generation. Multi- area probabilistic analyses are conducted to verify that inter-sub-area constraints do not compromise resource adequacy. The ongoing transmission planning efforts associated with the New England Regional System Plan, support compliance with NERC Transmission Planning requirements and assure that the transmission system is planned to sufficiently integrate generation with load. No deliverability concerns for summer 2008 have been identified. In previous years, studies indicated that without additional resources or transmission improvements, Connecticut would experience a negative Net Margin if the 90/10 forecasted demand were to occur. However, analyses of the situation in 2008 have shown that the Net Margin in Connecticut is expected to be positive this year. No capacity shortage is expected in Connecticut this summer. The primary reasons for the improved situation are additional capacity as well as 130 MW of additional demand response resources in Connecticut. Reliability has also previously been a concern in the Boston area. However, transmission upgrades completed in the spring 2007 increased the import capability into the Boston area by 60 The draft report “ISO New England Installed Capacity Requirements for the 2008-2009 Capability Year” may be found on ISO-NE’s website at http://www.iso-ne.com/genrtion_resrcs/reports/nepool_oc_review/index.html. Page 66 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments 1,000 MW, to a total of 4,600 MW. As a result of those improvements, the Net Margin was forecasted to be positive in 2007 and is expected to remain so in 2008. Summer period fuel supply and delivery has not been an issue within New England. ISO-New England, through regular meetings with regional stakeholders and state and federal regulatory agencies, has established both formal and informal communications links with regional fuel suppliers. For example, membership on the ISO’s Electric/Gas Operations Committee (EGOC) routinely informs ISO-New England of the status of regional natural gas (and LNG) supply and delivery issues. In addition, ISO-New England has recently developed an Operating Procedure 21 (http://www.iso-ne.com/rules_proceds/operating/isone/op21/index.html) designed to help mitigate the impacts to the bulk power system reliability resulting from regional fuel supply deficiencies. The import capabilities to New England and the studies on which they are based are listed below. The studies are reviewed and updated as necessary on a regular basis. All of the studies are based on simultaneous transfer capability, and recognize transmission and generation constraints in systems external to New England. New England does not have any new transmission constraints that could significantly impact reliability for the summer of 2008. New England has identified existing transmission constraints within the regions and has developed extensive guides and procedures for operating within these limitations to ensure no System Operating Limit (SOL) or Interconnection Reliability Operating Limit (IROL) violations occur. Interface Transfer Capability (MW) Basis for Interface Limit New Brunswick-New 1,000 Second New Brunswick England Tie Study Hydro-Quebec-New 1,200-1,40061 PJM and NYISO Loss of England Phase II Source Studies Hydro-Quebec-Highgate 200 Various Transmission Studies New York — New England 1,350 NYISO Operating Study, Winter 2005-06 Cross Sound Cable 34662 Cross Sound Cable System Impact Study The impact of new generator interconnections or changes/additions to transmission system topology on transient performance and voltage or reactive performance of the bulk power system is analyzed. In the event that an adverse impact is discovered, either the project must be revised 61 The Hydro-Quebec 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. 62 The transfer capability of the Cross Sound Cable is 346 MW. However, losses reduce the amount of MWs that are actually delivered across the cable. When 346 MW is injected into the cable, 330 MW is received at the point of withdrawal. Page 67 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments in some manner to eliminate the concern or operational guides must be developed and implemented to mitigate the adverse impact. Operating studies to develop operating guides are generally performed under light load conditions to assess the impact on transient performance and under both peak and light load conditions to assess the impact on voltage/reactive performance. Therefore each and every change to the generation/transmission system is either implicitly or explicitly evaluated from a transient and voltage/reactive perspective. There is nothing particular about the summer of 2008 which would introduce any new concerns in these areas. New England has specific criteria to manage minimum dynamic reactive reserve requirements. ISO Operating Procedure (OP #17) defines acceptable Load Power Factor requirements for various subregions within New England. The procedure is designed to ensure adequate reactive resources are available in the subregion by managing the reactive demand. Furthermore, when transfer limits are developed for voltage or reactive constrained subregions, the ISO will develop detailed operating guides that cover all relevant system conditions to ensure reliable operation of the bulk power system. In determining the acceptable transfer limits, a 100 MW reserve margin is typically added to each limit to ensure that adequate reactive reserves are maintained. In some areas, such as Boston and Connecticut, where specific reactive compensation concerns exist, specific operating guides have been developed to ensure that the areas are operated reliably. New England has a specific guideline for voltage sag which states that the minimum post-fault voltage sag must remain above 70% of nominal voltage and must not exceed 250 milliseconds below 80% of nominal voltage within 10 seconds following the fault. This guideline is applied when developing transfer limits for the bulk power system in New England. There are no known reactive power-limited areas in the New England transmission system for the summer of 2008. Transmission planning studies have ensured that adequate reactive resources are provided throughout New England. In instances where dynamic reactive power supplies are needed, devices such as STATCOMs, Dynamic VAR Systems (D-VARs) and additional generation commitment have been employed to meet the required need. Additionally the system is reviewed in the near-tem via operating studies to develop operating guides to confirm adequate voltage and reactive performance. New England in creating transfer limits based on the dynamic performance of the system, does apply a 100 MW margin to the transfer limits. Northern New England has the potential to arm approximately 600 MW of load as part of Under Voltage Load Shedding. However, it is important to recognize that a significant portion of these relays are normally not armed and are only armed under severe loading conditions with a facility already out of service. As previously noted, ISO New England conducts operable capacity analyses for the current year using both the 50/50 and the 90/10 forecasts. Those analyses are updated on a monthly basis to reflect the latest information on new generation, purchases/sales and outages. Page 68 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments New York Demand The New York Balancing Area peak load forecast for this summer is 33,809 MW, which is 362 MW higher than the forecast of 33,447 MW reported in the 2007 Summer Assessment and 1,639 MW more than the 32,169 MW 2007 summer actual. The 2007 summer actual demand was lower than forecast because of moderate weather. This forecast load is 0.4 % lower than the all- time summer peak load of 33,939 MW that occurred on August 2, 2006. The daily peak demand observed by New York during the Summer Operating Period occurs in the mid to late afternoon. The forecast is developed by the NYISO using a Temperature-Humidity Index (THI) value of 84.2 degrees, which is representative of weather conditions during peak load conditions. At forecast load levels, a one-degree increase in the THI will result in approximately 610 MW of additional load. Under extreme conditions the peak load could reach 35,000 MW. The NYISO conducts a load forecast uncertainty analysis based on the combined effects of both weather and the economy. This analysis is conducted for annual energy, summer peak demand and winter peak demand. The results of this analysis are used to make projections of upper and lower bounds of each of these forecasts. The upper bounds are at the 90th percentile and the lower bounds at the 10th percentile. In addition to examining the load forecast uncertainty on a combined basis, the NYISO performs a separate analysis of the uncertainty for summer peak demand forecast due to weather alone. While the NYISO constructs upper and lower bounds for energy for both seasonal peaks, additional analysis is performed for summer peaks only. The NYISO develops error bounds at a total of 7 weather conditions, 3 below and 3 above the expected load. The NYISO introduced two load response programs for the New York Market in May 2001. The Special Case Resource (SCR) and Emergency Demand Response Program (EDRP) are programs in which Customers are paid to reduce their consumption by either interrupting load or switching to emergency standby generation when requested by the NYISO. The EDRP is continuing for summer 2008, and NYISO estimates that 301 MW of load relief during peak conditions is considered to be available. This load relief will be available to support the New York State power system during capacity emergency periods. This program is in addition to the relief obtained through the emergency procedures for Operating Reserve Peak Forecast Shortage (Section 4.4.1 NYISO Emergency Operations Manual) or in response to the major emergency state (Section 3.2 NYISO Emergency Operations Manual). Additionally, SCR is expected to provide 1,287 MW of load relief under peak conditions. Generation For 2008 the New York Balancing Area expects 39,770 MW of existing capacity. Of the existing capacity, 424 MW are from wind generation and 357 MW from biomass generation. Capacity classified by the NERC RAS as “Existing-Certain” total 38,716 MW; the breakdown of “Existing Certain” energy from various generation types is as follows: 42 MW from wind generation, 5,152 MW from hydro generation, and 333 MW from biomass generation. Capacity classified by the NERC RAS as “Existing Uncertain” totals 1,054 MW; the breakdown of “Existing Uncertain” energy from various generation types is as follows: 381 MW from wind generation, 652 MW from hydro generation, and 24 MW from biomass generation. Capacity classified by the NERC RAS as “Planned” total 130 MW; the breakdown of “Planned” energy Page 69 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments from various generation types is as follows: 100 MW from wind generation and 30 MW from hydro generation. Solar energy as capacity in the New York Balancing Area is negligible. Since the summer of 2007, 65 MW of additional resources have been added to the New York system. Planned capacity resources for the 2008 summer period include the Munnsville wind project (35 MW wind farm) and the Gilboa 2 up-rate (30 MW). For wind generation the NYISO derates all wind generators to 10% of rated capacity in the summer operating period. With 424 MW of wind generation capacity for this summer, the expected on-peak capacity counted is 42.4 MW from wind generators classified as “Existing Certain” capacity according to the NERC RAS. The 90% applied wind de-rate equates to 381 MW of wind capacity classified as “Existing Uncertain” capacity. For the summer 2008 water levels are normal and no drought exists. Hydro generation consists approximately 14% of the total capacity in the New York Balancing Area. NYISO applies a 45% de-rate factor for non-NYPA hydro generation for the expected peak months of July and August. The 45% de-rate factor is applied to the total available non-NYPA hydro generators totaling 1,040 MW. The large NYPA projects (St. Lawrence and Niagara) have specific de-rate factors based on the probability the unit will be at certain percentages of its rated capacity output. Adding all the hydro generation derates values in New York totals 652 MW classified as “Existing Uncertain” generation according to the NERC RAS. Hydro conditions are anticipated to be sufficient to meet the expected demand this summer. The New York area is not experiencing a drought, and reservoir levels are expected to be normal for the upcoming summer. Purchases and Sales on Peak The NYISO projects capacity backed energy net purchases into the New York Balancing Area backed by 2,802 MW of generating capacity. Due to NYISO market rules the specific projected sales and purchases are considered confidential non-public information and cannot be explicitly indicated in this report. Capacity purchases are not required to have accompanying firm transmission as the NYISO does not use firm transmission concept, however, adequate transmission rights must be available to assure delivery to NY when scheduled. External capacity is also subject to external availability rights. External availability on import interfaces 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. No portion of the purchases or sales to/from the New York Balancing Area is Liquidated Damage Contracts (LDCs). Thus, no portion of the purchases or sales to/from the New York Balancing Area is “make-whole” contracts as defined by FERC in order #890. Page 70 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments Fuel Fuel Type Percentage New York State 2008 capacity percentages by fuel type are listed in the table. Traditionally, the New York Area generation Gas & Oil 37 % mix has been dependent on fossil fuels for the largest portion Gas 17 % of the installed capacity. Recent capacity additions or enhancements now available use natural gas as the primary Hydro 14 % fuel. While some existing generators in southeastern New Nuclear 13 % York have “dual-fuel” capability, use of residual or distillate Oil 9% oil as an alternate may be limited by environmental regulations. Adequate supplies of all fuel types are expected to Coal 8% be available for the summer period. Wind63 1% Transmission Assessment Other64 1% Upgrades in the Rochester vicinity were made to accommodate the Russell Station retirement this summer. A capacitor bank is scheduled to be added to Millwood 345 by August 2008, for added voltage support in the lower Hudson Valley; the Athens Special Protection System (SPS) will also be added. Also planned for this summer (June or July) is the re-conductor of the Northport – Norwalk Harbor 138 kV cable. The new cable will have three circuits and operate at the same ratings as the current cable. Operational Issues There are no significant anticipated unit outages, variable resource, transmission additions or temporary operating measures that would adversely impact reliability in New York during 2008 Summer. All generating units in New York are required to operate with limits established in various permits. Limits apply to many operating parameters including water discharge temperatures, reservoir drawdown rates, and rates of exhaust gas emissions. In addition, on an annual basis and seasonal basis, fossil fueled generators are required to surrender emission allowances equivalent to their respective emissions of SO2 and NOx. The NYISO monitors the supply and use of NOx allowances during the Ozone Season for selected units to detect impending shortages and take action to guard against generation shortfalls. At this time, there are no unusual operating issues or concerns that are anticipated to impact the reliable operation of the New York transmission system for the coming summer. Reliability Assessment Analysis NYISO conducts semi-annual and monthly Installed Capacity (ICAP) auctions. Based on the forecast load for 2008, the ICAP requirement is 38,879 MW based on a 15% Installed Reserve Margin (IRM) requirement. Last year the IRM requirement was 16.5%. On February 29, 2008, the Federal Electric Regulatory Commission issued an order accepting the New York State Reliability Council's (NYSRC’s) filing of a 15% IRM for the State of New York. In addition to the generation resources within the New York Area, generation resources external to the New York Area can also participate in the NYISO ICAP market. An external ICAP supplier must 63 Wind is listed at full nameplate capacity 64 Includes methane, refuse, solar, and wood Page 71 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments declare that the amount of generation that is accepted as ICAP in NY will not be sold elsewhere. The external Area in which the supplier is located has to agree that the supplier will not be recalled or curtailed to support its own loads; or will treat the supplier using the same pro rata curtailment priority for resources within its Balancing Area. The energy that has been accepted as ICAP in NY must be demonstrated to be deliverable to the NY border. The NYISO sets a limit on the amount of ICAP that can be provided by suppliers external to NY. Resources within the New York Balancing Area that provide firm capacity to an external Area are not qualified to participate in the NYISO ICAP market. With net capacity resources of 41,272 MW, a capacity margin of 22.1% is projected for the summer peak. For 2008, the NYISO forecasts 3,075 MW of available transmission for import of external capacity into the New York Balancing Area. In last summer’s peak operating period, the NYISO purchased 3,085 MW of external capacity. The NYISO performs a resource adequacy study to help the New York State Reliability Council determine the required Installed Reserve Margin for the upcoming capability year. This study specifies the margin required for the New York Balancing Area. The NYISO conducts the Locational Capacity Requirements study which determines the amount of capacity that must be physically located within specific zones such as New York City and Long Island. This study also helps demonstrate the deliverability of internal and external ICAP capacity among the load zones within New York. The NYISO currently requires that a value of capacity equal to 80% of the New York City peak load be secured from within its zone and 94 % of Long Island peak load be secured from capacity within that zone, for the 2008-2009 capability years. The NYISO also performs an LOLE analysis that determines the maximum amount of ICAP contracts that can originate from Balancing Authorities external to the New York Balancing Authority. NPCC requires that New York perform a comprehensive resource adequacy assessment every three years. This assessment uses an LOLE analysis to determine resource needs five years into the future. A report is required showing how the NYISO would meet any projected shortfalls. In the two intervening years between studies, the NYISO is required to conduct additional analysis in order to update the findings of the comprehensive review. Presently, the New York State Reliability Council (NYSRC) Reliability Rules are implemented such that the electric system has the ability "to supply the aggregate electrical demand and energy requirements of their customers at all times, taking into account scheduled and reasonably expected unscheduled outages of system elements.” Compliance is evaluated probabilistically, such that the loss of load expectation (LOLE) of disconnecting firm load due to resource deficiencies shall be no more than an average of 0.1 days per year. This evaluation gives allowance for NYS Transmission System transfer capability documented in NYSRC Rules, Installed Reserve Margin (IRM), and Locational Capacity Requirements (LCR) reports. Currently all known deliverability concerns are captured in the evaluation and there are none identified needing mitigation. A multi area reliability simulation capturing the significant limitations of the NYS Transmission System is performed every year to demonstrate compliance. IRM Requirements are developed annually to satisfy resource adequacy requirements. The NYISO establishes installed capacity requirements (ICAP), including LCRs, recognizing internal and external transmission constraints. Page 72 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments New York Balancing Area import capability for this summer is summarized in the table below. These transfer capabilities are not Import Area Transfer Capability determined based on simultaneous transfers, how-ever they do take into PJM 3,000 MW account known limitations in adjacent Neptune Cable 660 MW systems. Quebec 1,825 MW New England 1,200 MW The Beck-Packard BP76 230kV line is out of service for this summer and scheduled Cross Sound Cable 330 MW to return August 29, 2008. Ontario 1,710 MW The NYISO performs transient dynamics and voltage studies. Small signal stability studies are not performed. There are no stability issues anticipated that could impact reliability during the 2008 summer. 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 Central-East interface is a reactive power-limited transfer interface. Mitigation plans include re-dispatch of generation and switching of reactive power equipment. There are a certain number of internal and external contingencies monitored by the EMS in real-time at regular intervals to check against post-contingency transfer limits on Central-East. Criteria for voltage stability margins are outlined in the NYISO Transmission Planning Guidelines. Post- contingency transfer levels have a 5% voltage stability margin. As required by NPCC Document A-03, “Emergency Operation Criteria,” New York maintains an automatic underfrequency load shedding program which trips demand at two frequency set points. Automatic load shedding of ten percent of load occurs at a nominal set point of 59.3 Hertz; automatic load shedding of an additional fifteen percent of load occurs at a nominal set point of 58.8 Hertz. With the underfrequency load shedding program in place in New York, there is no implementation of under voltage load shedding in New York. 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 Area. The studies are modeled under seasonal peak forecast load conditions. The operating studies also highlight and discuss operating conditions including topology changes to the system (generators, substations, transmission equipment or lines) and significant generator or transmission equipment outages. Load and capacity assessment are also discussed for forecasted peak conditions. Ontario Demand Ontario’s forecast summer peak demand is 24,892 MW based on Monthly Normal weather and taking into consideration the impacts of planned conservation and modest economic growth. The forecast peak for summer 2008 is 3.3% lower than the 25,737 MW actual peak demand which Page 73 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments occurred on June 26th, 2007. The 2008 forecast is 0.3% higher than last summer’s weather- corrected peak demand of 24,820 MW. 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 Ontario Power Authority to provide demand response under tight supply conditions. The combined amount of these demand measures has been steadily increasing and now amounts to approximately 818 MW in total of which 541 MW is included for seasonal capacity planning purposes, with 249 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 24,892 MW, the LFU is 1,288 MW. Generation The total capacity of existing installed resources connected to the IESO controlled grid is 31,297 MW, of which the amount of ‘certain’ capacity is 27,139 MW for June 2008. The remainder, 4,158 MW, is ‘uncertain’ capacity for June 2008 which includes the on-peak resource deratings, planned outages and transmission-limited resources. The certain capacities for July, August and September 2008 are 28,194 MW, 27,920 MW and 25,643 MW respectively. The variations in certain capacity arise primarily from monthly variations in hydroelectric capability and planned outages to large thermal units. In particular, the large variation for September 2008 results from generators beginning scheduled maintenance outages for their units after the peak summer period. More than 280 MW of dependable new supply (371 MW installed) is scheduled to come into service by June 1, 2008. All of this new supply is gas-fired generation, including 340 MW generation (250 MW under contract and considered dependable) in downtown Toronto from the first, simple cycle phase of a 550 MW combined cycle energy centre to be completed by summer 2009 and 31 MW of Combined Heat and Power projects in several locations around the province. A hydroelectric project with an installed capacity of 23 MW will come into service by July 1, 2008 MW. An additional 13 MW of hydroelectric is scheduled by September 1. Eighty percent of this new installed hydroelectric capacity is assumed to be available at the time of weekly peak. The existing installed capacity of wind generation connected to the IESO controlled grid is 471 MW. Ten percent of the installed wind capacity is assumed to be available at the time of weekday peak, thus, 47 MW of wind is considered certain for capacity planning purposes. Of the 75 MW of installed biomass generation in the province, 45 MW is assumed certain. The generation output of some biomass units has been reduced as a consequence of reductions in steam demand primarily from pulp and paper operations. IESO resource adequacy assessments include hydroelectric generation capacity contributions based on median historical values of hydroelectric production plus operating reserve provided Page 74 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments 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 used by the generation owner. In particular hydroelectric conditions are highly dependent on snow melt and spring rains occurring in April and May. 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. Most hydro storages are energy limited. An energy-limited hydroelectric facility has insufficient storage capability and stream flows to deliver full generator capacity for each and every hour of the day. Hydro operators identify weekly and daily limitations for near-term planning in advance of real-time operations. The province is not experiencing a drought at present. This is evident from the monthly water levels report published by Environment Canada. It is stated in the report that “Water supplies to each of the Great Lakes except Lake Superior were above average during February (2008). As a result, water levels increased on each of the lakes except Lake Superior during the month.”65 Purchases and Sales 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. The IESO is not aware of any firm purchase or sale contracts with other areas for the summer season. However, market participants may arrange limited external purchases of capacity to avoid deferral or cancellation of generator outages in the event that operating reserve deficiencies are forecast in the near-term. For use during daily operation, the IESO has agreements in place with neighbouring jurisdictions in NPCC, RFC and MRO for emergency imports and reserve sharing. Fuel The Ontario fuel supply infrastructure is judged to be adequate during the summer peak demand period, and there is no fuel delivery problems anticipated for this summer. Gas pipeline capacity, historically, has not limited the summer energy or capacity capability of Ontario generation fuelled solely by natural gas and is not expected to be a problem for this summer. Similarly, no fuel delivery concerns have been identified for coal-fired or nuclear generating stations. In its market manuals, the IESO requires generator market participants in Ontario to provide specific information regarding energy or capacity impacts if fuel-supply limitations are anticipated. No limitations have been reported for the summer months. Transmission The supply to central Toronto will be improved for the summer with the John TS to Esplanade TS link, built by Hydro One, which provides an additional 90 MW of load transfer capability within the city core. This project was completed in December 2007 ahead of schedule. 65 http://www.on.ec.gc.ca/water/level-news/ln200803_e.html?CFID=9615995&CFTOKEN=96650156 Page 75 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments Since last summer, Hydro One has installed a new 230/115kV autotransformer at Cambridge and a 245 MVAR shunt capacitor at Orangeville, both in southwestern Ontario. These transmission projects are among a number under various stages of development to improve local area deliverability over the next few years. Phase angle regulators (PARs) are installed on three of the four Michigan to Ontario interconnections. One PAR, on the Keith to Waterman 230 kV circuit J5D has been in service and regulating since 1975. The other two available PARs, on circuits L51D and L4D, which had been bypassed pending completion of agreements between the IESO, the Midwest ISO, Hydro One and the International Transmission Company, were placed in service on April 14, 2008, and they are expected to start regulating before the summer. All parties have committed to completing the necessary operating agreements to meet this schedule. The operation of the phase angle regulators will assist in the management of system congestion and control of circulating flows. The fourth PAR, responsible for controlling the tie flow on the 230 kV circuit B3N, remains unavailable and is undergoing replacement. This PAR is located in Michigan at the Bunce Creek terminal of circuit B3N. Operational Issues There are no unusual operating condition, environmental, or regulatory restrictions that are expected to affect capacity availability for this summer. All known planned generator outages and forecast energy limitations have been included in the IESO’s adequacy assessment. Reliability Assessment Analysis The IESO uses a multi-area resource adequacy model, in conjunction with power flow analyses, to determine the deliverability of resources to load. This process is described in the document, “Methodology to Perform Long-Term Assessments.”66 The IESO assumes that the planned resource additions meet their stated in service dates and the forecast amount of conservation is achieved. The generator planned outages submitted by Market Participants are inputs to the studies, as well. Reserve requirements are established in conformance with NPCC regional criteria. The IESO doesn’t consider external resources in the calculation of resource adequacy. The resource adequacy studies are done during the last month of every quarter for the subsequent 18 months. The latest study results are published in the March 12, 2008 18-Month Outlook.67 Planning reserves, determined on the basis of the IESO’s requirements for Ontario self- sufficiency, are above target levels for all weeks in this period. On average, the projected capacity margins for the upcoming summer are 1.5% higher than for the summer of 2007. The IESO reviews its system operating limits on an ongoing basis, as warranted by system configuration changes on the grid. In advance of each summer peak season, the IESO analyzes the forecast demand for Ontario, and forecast transmission and generation availability, and assesses the ability of the planned generation to supply the forecast load (in essence its deliverability). Where transfer limits are expected to restrict available generation, these restrictions, in addition to zone-to-zone system operating limits, are factored into the reliability 66 http://www.ieso.ca/imoweb/monthsYears/monthsAhead.asp 67 http://www.ieso.ca/imoweb/pubs/marketReports/18MonthOutlook_2008mar.pdf Page 76 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments analysis for the season, to determine IESO’s resource adequacy. IESO, as the Reliability Coordinator, and via its authority to direct the operation of the IESO-administered market and the IESO-controlled grid, can ensure that generation dispatch does not violate system operating limits. Where resources are expected to be insufficient to satisfy established criteria68, the IESO can deny final approval for planned outages, and can rely on emergency procedures in the operational time frame to address shortfall conditions. Fuel supply is forecast to be adequate to meet the summer peak demands, with no delivery problems anticipated. IESO obtains fuel supply information directly from market participants as required. At times, extreme weather conditions may affect hydroelectric and wind supply since hot, dry calm conditions often elicit peak demands. Allowance for these factors is developed through IESO review of historic performance every three months. Specifically related to the convergence of the natural gas and electricity sectors, the IESO is jointly working with the Ontario gas transportation industry to identify and address issues. With partial phase angle (PAR) control of the Ontario – Michigan interconnection, the coincident import/export capability is unlikely to equal the arithmetic sum of the individual flow limits. At best, the total transfer capability is the sum of the interconnection flow limits. At worst, the total transfer capability will equal the minimum of the New York (St. Lawrence plus Niagara) or Michigan interconnection flow limit, plus all other interconnection flow limits. In the summer, the interconnections can carry coincident exports from 2,765 MW up to 4,915 MW, and coincident imports from 3,734 MW up to 5,284 MW. In the winter, the interconnections can carry coincident exports from 3,512 MW up to 5,912 MW, and coincident imports from 4,115 MW up to 5,915 MW. The IESO regularly conducts transmission studies that include results of stability, voltage, thermal and short-circuit analyses in conformance with NPCC criteria. Since the implementation of the NERC TPL standards in June 2007, the IESO’s comprehensive 2007 transmission studies have been conducted to comply with these standards, in addition to NPCC criteria. There are no transmission constraints, stability based limits or reactive power deliverability constraints that are expected to significantly impact reliability based on the forecast availability of generation and transmission facilities for the upcoming season, although there are many transmission limits on the IESO-controlled grid that the IESO manages on a day-to-day basis (e.g. through constrained-dispatch, and occasional use of Transmission Loading Relief procedures). The IESO has market rules and connection requirements that establish minimum dynamic reactive requirements, and the requirement to operate in voltage control mode for all resources connected to the IESO-controlled grid. In addition, the IESO’s transmission assessment criteria includes requirements for absolute voltage ranges, and permissible voltage changes, transient voltage-dip criteria, steady-state voltage stability and requirements for adequate margin demonstrated via pre and post-contingency P-V curve analysis. These requirements are applied in facility planning studies. Seasonal operating limit studies review and confirm the limiting phenomenon identified in planning studies. 68 NPCC Criteria A-02, ”Basic Criteria for Design and Operation of Interconnected Power Systems” and IMO_REQ_0041, “Ontario Resource and Transmission Assessment Criteria” Page 77 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments There are currently no Under-Voltage Load Shedding systems installed in Ontario for the purpose of controlling the voltage on the bulk power system portion of the IESO-controlled grid in response to bulk power system events. There are several systems used for localized voltage control in the event of an outage to local supply facilities. Although energy supplies available within Ontario are expected to be adequate overall, energy deficiencies could arise as a result of higher than forecast forced outage situations, prolonged extreme weather conditions and other influencing factors. Interconnection capability and available market and operational measures have been evaluated as sufficient to ensure summer energy demands can be met for a wide variety of conditions. The IESO uses a measure of forecast uncertainty in a probabilistic analysis to account for variations in demand due to weather volatility. This uncertainty is used in conjunction with the normal weather demand forecast to determine resource adequacy. As well, the IESO creates a demand forecast based on extreme weather and uses it in further assessing system adequacy. Québec Demand Québec’s forecasted internal peak demand for the 2008 summer NERC RAS reporting period ─ June to September ─ is 21,344 MW. The actual peak demand for the 2007 summer NERC RAS report period was 21,411 MW. This occurred on August 2, 2007 at 17h00 EDT. The all-time summer peak for the NERC RAS report period was 21,614 MW on June 28, 2005. Hydro-Québec Distribution is the only Load Serving Entity in Québec, and its load forecast is conducted for the entire Area. HQD’s load forecast is based on the average climatic conditions observed from 1971 to 2006 adjusted for a global warming of 0.30 °C per decade starting in 1971. The latest forecast – based on economic, demographic and energy-use assumptions – was presented in the Hydro-Québec Distribution Procurement Plan submitted to the Québec Energy Board in October 2007 (available on the Québec Energy Board web site). HQD has developed a method to estimate the impact of climatic uncertainty on peak demand based on 252 simulations of the hourly load forecast under the 36 years of the climatic period 1971-2006. Each year of climatic data is shifted up to ± three days to gain information on the effect of the climatic conditions on each days of the week. Since Québec has a winter peaking load profile, the uncertainty – measured by a standard deviation analysis – is lower during the summer than during the winter. As an example, at the summer peak, weather conditions uncertainty is about 300 MW, equivalent to one standard deviation. During winter, this uncertainty is approximately 1,500 MW. Extreme weather deviations can be quantified at about 900 MW for the summer peak and at about 4,700 MW for the winter peak. The following table summarizes and compares actual and forecasted demands in Québec for 2007 and 2008. Page 78 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments Demand in MW June July August September A) Observed 2007 21,272 20,919 21,411 21,255 B) Forecasted 2007 21,487 21,606 21,769 21,750 Difference (A-B) 2007 -215 -687 -358 -495 C) Forecasted 2008 20,971 21,078 21,344 21,297 Difference (C-B) -516 -528 -425 -453 The shutting down of certain industrial loads, such as sawmills and paper mills, has reduced the forecasted demand by 400 to 500 MW for the next summer months. Since Québec is a winter peaking system, no interruptible load programs are available for the summer period. Generation For the 2008 Summer Operating Period, total installed capacity in Québec is projected to be 42,111 MW, up 605 MW from last summer’s installed capacity of 41,506 MW. This includes firm capacity purchases from Churchill Falls Labrador Co., from Québec private producers, from Alcan in Québec, and from wind farm generation. Hydro-Québec Production’s (HQP) main hydro project ─ the Péribonka generating station ─ will be completely in service for the Summer Operating Period. Commissioning has begun in fall 2007 and will be through in early spring 2008. The total capacity is 340 MW. Two more hydro generating stations ─ Chute-Allard and Rapide-des-Coeurs ─ are being partially commissioned during the Summer Operating Period and will add 64 MW of capacity to the system. A number of small capacity adjustments, derates, etc. in many hydro generating stations account for the rest of the 2007-2008 capacity differences. The following table summarizes the anticipated ‘existing certain’, ‘existing uncertain’ and planned resources in Québec during the 2008 summer season. Capacity (MW) in 2008 June July August September Existing Certain 32,732 32,776 32,742 32,133 Existing Uncertain 9,110 9,066 9,100 9,709 Planned 237 269 269 291 Total Internal 42,079 42,111 42,111 42,133 The present Québec wind power installed capacity is 420 MW. Wind power is completely derated for reliability assessments, so it is reported as capacity that is treated as “Existing Uncertain” in the submission of data for the 2008 summer analysis. The present Québec biomass installed capacity is 298 MW (derived from forest biomass), and this capacity is reported as capacity that is treated as “Existing-Certain” in the submission of data for the 2008 summer analysis. Presently, there are no drought conditions in Québec. Reservoir levels are expected to be more than sufficient to meet both peak demand and energy demand throughout the summer. To Page 79 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments demonstrate its energy reliability, HQP ─ Québec’s reservoirs’ manager ─ presents an energy reliability assessment to the Québec Energy Board three times a year. Its energy criterion states that Hydro-Québec Production must maintain a sufficient energy reserve to protect against a possible hydraulic deficit of 64 TWh for two consecutive years and 98 TWh for four consecutive years. The last assessment (November 2007) shows that Hydro-Québec Production complies with this energy reliability criterion. The next assessment will be presented to the Québec Energy Board in May 2008. Purchases and Sales on Peak HQP does not require any external purchases for the 2008 summer peak period in terms of resource adequacy. Also, no firm sales affect the Québec sub-regional capacity margins. During summer periods, Québec does not need external purchases due to its winter peaking characteristic. Fuel Fuel supply vulnerability does not apply to Québec since about 95 % of resources are hydro- electric. The only natural gas generating station in Québec (507 MW) will be out of service (mothballed) for the entire year 2008. This capacity is considered to be “Existing Uncertain – Inoperable”. Transmission Since summer 2007, no new Bulk Power System transmission projects have been commissioned in Québec. Operational Issues There are no anticipated unit outages, variable resource, transmission addition or temporary operating measure issues that may impact reliability during the summer. Internal generating unit and transmission outage plans are assessed to meet internal demand, firm sales, expected additional sales and additional uncertainty margins. They should not impact internal reliability and inter-area capabilities with neighboring systems. In addition, there are no environmental or regulatory restrictions that could impact Quebec reliability. There are no unusual operating conditions anticipated on the system that could impact reliability for summer 2008. All scheduled interconnection installation maintenance is to be done outside the summer operating period. Reliability Assessment Analysis In the “Québec Control Area 2007 Interim Review of Resource Adequacy” report approved in March 2008 by the NPCC, the projected capacity margins for the next three winter periods are between 14 and 16 % of the peak demand forecasts. These percentages are higher than those required to respect the NPCC and Québec Energy Board reliability criteria. In the 2007 Interim Review of Resource Adequacy, the required reserve expressed as a percentage of winter peak demand is about 11 %. A description of the various assumptions used to assess the resource adequacy of Québec is available in the 2005 and 2007 Québec Area Review of Resource Adequacy. The major assumptions of the 2007 Interim Québec Review are consistent with Hydro-Québec Page 80 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments Distribution’s Procurement Plan 2008-2017 filed with the Québec Energy Board in November 2007. No external resources were considered, as Québec is generally a resource exporter. Moreover, each year, Québec produces resource adequacy assessments for NPCC and the Québec Energy Board. These assessments are conducted during fall for the next winter peak period and the years thereafter. The conclusions show that Québec is more reliable than the NPCC resource adequacy criterion. As shown in the next table, for August the capacity margin is 1,500 MW lower than last year’s. The main factor explaining this difference is the firm sales in August 2008, which are 2,000 MW higher than last year. Projected Capacity Margin Comparison for Summer Assessments in August 2008 Versus 2007 (MW) 2007 2008 Difference Existing Capacity 41,474 41,842 368 Planned Additions 32 269 237 Total Internal Capacity 41,506 42,111 605 Maintenance/Hydro Derates -8,338 -8,654 -316 Wind Derates -322 -420 -98 Internal Capacity 32,846 33,037 191 Purchases 200 200 0 Sales -1,335 -3,383 -2,048 Net Capacity Resources 31,711 29,854 -1,857 Net Internal Demand 21,770 21, 344 -426 Margin (MW) 9,941 8,510 -1,431 Margin (%) 45.7 39.9 TransÉnergie conducts a yearly peak-demand period assessment for the Québec system to assess generation deliverability. However, this is done for the winter peak period. For the summer period, when the greater part of system maintenance is done, weekly generation deliverability studies are conducted to assure not only deliverability to internal load but also to interconnections so as to fill in neighboring Area requirements. When deliverability concerns to interconnections are identified in summer, maintenance is usually rescheduled so as to maintain scheduled deliveries. Hydro-Québec Production plans its summer generating unit maintenance so that enough resources are available for internal load and any scheduled exports to neighboring Areas with a sufficient capacity margin to allow for demand forecast uncertainty and unscheduled short term Page 81 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments exports. Summer capacity margins in Québec are usually between 4,000 and 9,000 MW. TransÉnergie, through the weekly generation deliverability studies mentioned above, assures maximum access to internal and external markets. Fuel supply is not a concern in Québec since about 95 % of the resources are hydroelectric. Thermal generation is used for peaking purposes in winter. Transmission capabilities from and to the Eastern Interconnection are revised periodically with Québec’s neighboring systems to assess interconnection limits. Transfer capabilities vary from peak to non peak periods. These are the Québec import capabilities in summer: From Maritimes: 685 to 735 MW From New England: 1,600 MW From New York: 1,100 MW From Ontario: 712 to 880 MW The summer demand in Québec is historically lower than the winter demand. Summer peak is approximately 60% of the winter peak. During summer, the Québec Area does not expect to need external assistance. These are the Québec export capabilities in summer: To Maritimes: 921 to 991 MW To New England: 1,460 MW To New York: 1,825 to 1,980 MW To Ontario: 1,465 to 1,540 MW The capacity margin available in Québec during summer period ranges from 4,000 to 9,000 MW approximately so that a certain amount of bottling of resources from Québec to the rest of NPCC is expected due to the rated transfer capabilities of Québec interconnections compared to the available resources. Also, due to system configuration, capacity may not be available simultaneously to New York and Ontario. However, maximum capacity is made available in July and August for Ontario, New York and New England, with due regard to system constraints concerning exports. There are no transmission constraints that could impact reliability in Québec for summer 2008. Transient and voltage stability studies are performed continuously by TransÉnergie to establish the system transfer limits on all possible system configurations. No particular issue has been found to impact the summer 2008 season. TransÉnergie has a criterion for minimum dynamic reactive requirements. Due to system geography and configuration (Generation centers are remote from load centers and system is made up of long 735-kV lines) this is not applied to generators but to synchronous condensers and Static Var Compensators distributed along the system. There are 20 SVCs and synchronous condensers on the system, each with a nominal reactive power range of -100 to +300 MVAR. Page 82 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments The steady state operating range is -50 to +50 MVAR per compensator, so that a 250 MVAR margin per compensator is available as dynamic reactive reserve. (Up to 5,000 MVAR total). Moreover, a significant amount of 735-kV 330 MVAR reactors may be switched on and off to continually keep the compensators within their operating range. The SVC and synchronous condenser operating range is strictly monitored. The following table shows the voltage-dip criteria applicable to the Bulk Power System and guidelines after a system contingency. Voltage Limits on the Transmission System Normal Limits Emergency Limits Nominal Voltage Low limit High limit Low Limit High Limit kV p. u. kV p. u. kV p. u. kV p. u. 735 kV 725 0.985 760 1.034 698 0.95 765 1.04 315 kV 299 0.95 331 1.05 284 0.90 347 1.10 230 kV 219 0.95 242 1.05 207 0.90 253 1.10 Interconnections 0.95 1.05 0.90 1.05 The emergency limits must be respected five minutes after a contingency. This is done automatically by voltage regulation on the system, with the adequate amount of reactive capacity built into the system. However, the 735-kV Emergency Low Limit is quite stringent and the use of MAIS (Automatic Shunt Reactor Switching System) is permitted after the contingency to re- establish 735-kV voltages. On the 735-kV system, the transient limit is 0.80 p. u. voltage for two seconds after fault clearing and the mid-term limit is 0.90 p. u., from two seconds up to five minutes after fault clearing. All transient and long term voltage stability analyses must respect these criteria. There are no dynamic and static reactive power-limited areas on the Québec Bulk Power System. TransÉnergie is a winter peaking area, and as such, does not expect to encounter voltage collapse problems (or any kind of low voltage problem) during the summer. On the contrary, controlling over voltages on the 735-kV network during off-peak hours is the concern. This is accomplished mainly with the use of shunt reactors. Typically, about 15,000 MVAR of 735 kV shunt reactors may be connected at any given time during the summer, with seven to ten 735-kV lines out of service for maintenance. Most shunt capacitors, at all voltage levels, are disconnected during the summer. Under Voltage Load Shedding is installed in Québec. It has been designed to operate following extreme contingencies involving the loss of two or more 735-kV lines tripped out in the load area of the system. UVLS operates on a pre-defined pool of load located in the Montréal area. The amount of load shed is proportional to the length and severity of the measured under voltage. A total load shedding of 2,500 MW can be ordered. UVLS is used as an effective countermeasure against voltage instability. Operational planning studies are being continuously conducted by TransÉnergie, the Québec Area controller. These studies lead to the implementation of procedures to safely operate the Page 83 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments system. For example, the Québec system being asynchronous with the rest of NPCC ─ and being an Interconnection in its own right ─ has procedures for maintaining spinning reserve to guard against post-contingency frequency drops. Also, TransÉnergie conducts a yearly peak demand period study to assess system conditions during the winter peak period. Extreme weather conditions in Québec translate into very low temperatures during the Winter Operating Period. Through a transmission planning criterion, transmission planning and operational planning studies must take into account a 4,000 MW load increase on the system during such extreme weather conditions. This is equivalent to 110 % of system winter peak load. The Load Serving Entity relies on both internal and external resources to serve this additional load and transmission capacity is available. Québec System Information Peak season: winter. Winter to summer peak ratio: 1.7 Population served: Around 7 million Area: approximately 1,668,000 km2 Regional Description The Northeast Power Coordinating Council, Inc. (NPCC) is the cross-border regional entity and criteria services corporation for Northeastern North America. It is the NPCC mission to promote and enhance the reliable and efficient operation of the international, interconnected bulk power system in Northeastern North America pursuant to its agreement with the Electric Reliability Organization, which designates NPCC as a regional entity and delegates authority from the U.S. Federal Energy Regulatory Commission, and by Memoranda of Understanding with applicable Canadian Provincial regulatory and/or governmental authorities. The geographic area covered includes New York, the six New England states, and Ontario, Québec, and Maritimes provinces in Canada. The total population served is approximately 56 million, and the total geographic area is 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. Additional information can be found on the NPCC Web site (http://www.npcc.org/). Page 84 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments RFC 2008 Projected Peak Demand MW Relative Capacity by Fuel Mix Total Internal Demand 184,000 Direct Control Load Management 900 Contractually Interruptible (Curtailable) 5,400 Critical Peak-Pricing with Control 0 Gas 25% Load as a Capacity Resource 0 Net Internal Demand 177,700 MW Change Coal 47% 2007 Actual Summer Peak Demand 181,700 -2.2% Oil 8% All-Time Summer Peak Demand 190,213 -6.6% Other 0.4% 2008 Projected Capacity MW Margin Wind 0.8% Existing Certain and Net Firm Transactions 213,400 16.7% Pumped Net Capacity Resources 213,400 16.7% Nuclear 15% Storage 2% Hydro 1.1% Total Potential Resources 216,300 17.8% Introduction All ReliabilityFirst Corporation (RFC) members are affiliated with either the Midwest ISO (MISO) or PJM RTO (PJM) for operations and reliability coordination. Ohio Valley Electric Corporation (OVEC), a generation and transmission cooperative located in Indiana, Kentucky and Ohio, is not affiliated with either RTO market; however OVEC’s Reliability Coordinator services are performed by PJM. Duquesne Light Co. has recently announced its intention to withdraw from PJM and join MISO later this year. For this assessment, Duquesne Light continues to be included within the PJM RTO. ReliabilityFirst does not have officially-designated subregions; however, about one-third of the RFC load is within MISO and nearly all remaining load is within PJM, except for about 100 MW of load within the OVEC Balancing Authority area. From the perspective of the RTOs, approximately 60% of the MISO load and 85% of the PJM load is within RFC. The PJM RTO spans into the SERC region, and the MISO RTO also spans into the MRO and SERC regions. The PJM RTO operates in total as one Balancing Authority area. MISO has recently received approval to begin operation as a single Balancing Authority area however operation as a BA is not expected to occur until after this summer. This assessment provides information on projected resource adequacy for the upcoming summer season across the ReliabilityFirst region. The RFC Resource Adequacy Standard BAL-502- RFC-01 requires Planned Reserve Sharing Groups (PRSGs) to identify the minimum acceptable reserves to maintain resource adequacy for their respective areas of RFC. PJM operates as the PRSG for its members. The Midwest PRSG consists of a consortium of MISO members that includes about 95% of the MISO load in the RFC regional area. Since nearly all ReliabilityFirst area demand is in either Midwest ISO or PJM, the reliability of these two RTOs will determine the reliability of the RFC region. This report assesses the resource adequacy of each RTO based on the reserve margin requirements applicable to each RTO. PJM determines the reserve margin Page 85 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments requirement for all demand within PJM. The Midwest PRSG and MAPP determine reserve requirements for most of the demand in MISO. MISO uses a 12% default reserve requirement for demand not included in the Midwest PRSG and MAPP. The combination of reserves from the Midwest PRSG, MAPP and the default reserve calculation was used by RFC as the MISO reserve margin target for assessing resource adequacy. Demand The analysis of the demand data for the summer assessment focuses on three factors, Total Internal Demand (TID), Net Internal Demand (NID) and Demand-Side Management (DSM). TID represents the entire forecast electric system demand. This demand forecast is based on “50/50” or average summer weather (a 50% chance of the weather being warmer and a 50% chance of the weather being cooler). The ReliabilityFirst Region identifies the various programs and contracts designed to reduce system demand during the peak periods as DSM. Individual companies may implement DSM through a demand response program, a direct-controlled load program, an interruptible load contract or other contractual load reduction arrangement. Since DSM is a contractual management of system demand, the reserve margin requirement for the RTO includes DSM. NID is total internal demand (TID) less DSM. Reserve margin requirements are based on NID. Demand-Side Management can be addressed in different ways, reflective of its operational impact on peak demand and reserve margins. DSM offers the companies that have these programs and contracts a way to mitigate adverse conditions that the individual companies may experience during the summer. The total demand reduction of each RTO is the maximum controlled demand mitigation that is expected to be available at the time of the peak system demand. For the summer of 2008, the ReliabilityFirst RTOs have identified the following types of DSM programs: DIRECT-CONTROLLED LOAD MANAGEMENT There are a number of load management programs under the direct control of the system operators that allow interruption of demand (typically residential) by controlling specific appliances or equipment at the time of the system peak. Radio controlled water heaters or air conditioners would be included in this category. Direct controlled load management is typically used for “peak shaving” by the system operators. INTERRUPTIBLE DEMAND Industrial and commercial customer demands that can be contractually interrupted at the time of the system peak, either by direct control of the system operator (remote tripping) or by the customer at the request of the system operator, are included in this category. PJM RTO DEMAND DATA The estimated Net Internal Demand (NID) peak of the entire PJM RTO for the 2008 summer season is 134,000 MW and is projected to occur during July. This value is based on the Total Internal Demand (TID) forecast prepared by PJM staff with the full utilization of the load management placed under PJM coordination. The forecast is dated January 2008, and is based on economic data from late 2007. Page 86 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments Emergency Load Management placed under PJM coordination is PJM’s program for Demand- Side Management (DSM). PJM identifies two types of DSM, Direct Control, and Interruptible. Direct control amounts to 400 MW during the summer for PJM with an additional 3,500 MW of Interruptible Demand. The estimated Total Internal Demand (TID) of PJM RTO for the 2008 summer season is 137,900 MW and is projected to occur during July. This value is based on an independent demand forecast prepared by PJM staff for each PJM zone, region and the total RTO. This compares to the 2007 metered peak demand of 139,568 MW, and a weather normalized peak demand of 136,095 MW. The 2008 forecast TID is 1,805 MW (1.3%) higher than the weather normalized 2007 peak TID, and 1,668 MW (1.2%) lower than the actual 2007 metered peak demand. MISO DEMAND DATA The estimated Net Internal Demand (NID) coincident peak of the entire Midwest ISO (MISO) Market Area for the 2008 summer season is 100,000 MW and is projected to occur during July. This value is based on the Total Internal Demand (TID) demand forecast prepared by the MISO market participants and the expected peak reduction from various DSM programs. The MISO market participants developed their demand forecasts at different times throughout the last half of 2007, so the economic basis for each company forecast reflects the specific economic data of that company’s planning area at the time of their forecast. The amount of MISO market participant demand response or load management expected at the time of the peak is 4,800 MW. This is categorized as 1,700 MW of Load Management with an additional 3,100 MW of Interruptible Demand. The estimated coincident Total Internal Demand (TID) of MISO for the 2008 summer season is 104,800 MW and is projected to occur during July. This value is based on information provided by the market participants. This compares to the 2007 peak demand of 103,891 MW. The 2008 forecast demand is 909 MW (0.9%) higher than the actual 2007 peak demand. RFC DEMAND DATA In this assessment, the data related to the RFC areas of PJM and MISO is combined with the data from the Ohio Valley Electric Corporation (OVEC) to develop the RFC regional data. The RFC demand forecast also accounts for expected demand diversity among these entities. RFC uses the minimum diversity from the past 5 years which is 2.0% in July. Approximately 85% of the PJM RTO demand and approximately 60% of the MISO market load is within the RFC region. Since OVEC is not a member of either RTO, the 88 MW of OVEC demand was added to the non-coincident demand of the PJM and MISO areas; a 2.0% diversity factor, the minimum diversity in July over the past five years of history, was applied; and the result rounded to the nearest 100 MW. The resulting coincident peak for the RFC region is 177,700 MW NID and 184,000 TID. The forecast NID peak is 3,000 MW (1.7%) lower than the forecast demand for 2007. This lower forecast is the result of lower expected economic growth at the time of the demand forecasts, and 2,800 MW of additional DSM. The forecast TID peak is 2,300 MW higher than the actual peak demand of 181,700 MW that occurred on August 8, 2007 for the ReliabilityFirst regional area. Page 87 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments DEMAND SENSITIVITY Although the demand forecasts used in this assessment were collected in recent months, these forecasts were prepared months earlier. Both weather and economic conditions have significant influence on the peak demands. Any deviation from the original forecast assumptions for those parameters could cause the aggregate 2008 summer peak to be significantly different. For the summer of 2008, a 90/10 TID forecast was prepared by PJM for its load zones as a sensitivity for extreme weather. A 90/10 demand forecast includes weather related demand for weather that has a 10% chance of being warmer and a 90% chance of being cooler. The PJM load zones that are in RFC have a non-coincident 90/10 demand of 129,600 MW, a 4.43% increase. The MISO performs a statistical analysis with the participants 50/50 TID forecast and historical demand data to calculate a 90/10 demand forecast. From this analysis there is a 4.97% increase in the demand of the RFC area of MISO to 66,800 MW for 90/10 weather. For the summer of 2008, the NID forecast based on 90/10 weather for the MISO and PJM areas, including OVEC and a 2% demand diversity, was used to calculate the sensitivity of the reserve margin to extreme weather in RFC. The results of this demand sensitivity are included in the Reliability Assessment Analysis section of this report. Generation The generating capacity in this assessment represents the rated capability of the generation in OVEC and in the PJM and MISO market areas. The category of Existing Capacity listed as “certain” represents existing resources in PJM’s Reliability Pricing Model (RPM) and Designated Network Resources (DNR) in the MISO market. The “uncertain” resources are the existing generation that represents wind/variable resource deratings, and other existing capacity resources within the region that are not included in the “certain” category or the reserve margin calculations. Also included in “uncertain” capacity would be generating capacity that has not been studied for delivery within the region, and capacity located within the region that is not part of PJM committed capacity or MISO DNR. “Planned” capacity additions are those additions expected to go in-service during the summer period and are included in the determination of the reserve margins. Any “proposed” capacity additions have an uncertain in-service status for this summer and are not included in the reserve margins. The recent emphasis on renewable resources is increasing the amount of wind power capacity being added to systems in the ReliabilityFirst Region. In this assessment, the amount of available wind power capability included in the reserve calculations is less than the nameplate rating of the wind resources. PJM uses a three year average of actual wind capability during the summer daily peak periods as the expected wind capability. Until three years of operating data is available for a specific wind project, that project is assigned a 13% capability of the name plate rating. In MISO, wind power providers may declare up to 20% of nameplate capability as DNR. The difference between the nameplate rating and the expected wind capability is accounted for in the existing “uncertain” category. Scheduled maintenance and any existing capacity that is inoperable for this summer is not included in this assessment of reserve margins. Generally, scheduled maintenance is minimized Page 88 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments during the peak demand periods. This inoperable capacity listed during the summer peak (July) is expected to be zero for PJM and about 1,000 MW for MISO. PJM GENERATION The whole PJM RTO has 164,700 MW of capacity for this summer that is identified as “certain” in this assessment. Under the Reliability Pricing Model (RPM), all capacity that has cleared in the capacity market has to be in service prior to June 1. Therefore, there is no “planned” capacity included for this summer. There is also 1,600 MW of generation related to capacity deratings of wind generators and generators that are energy-only participants in the PJM market. Since these resources are not in the RPM market, the deliverability and availability of this generation at the time of the peak is uncertain. Therefore, in this assessment none of this capacity is included in the PJM reserve margins. MISO GENERATION The whole MISO RTO has 115,300 MW of DNR capacity for this summer that is identified as “certain” in this assessment. This includes 4,400 MW of expected DNR capacity that does not have final contracts at the writing of this report. No additional capacity is expected to go in service during the summer. However, there are 6,600 MW of capacity in the MISO RTO that is “uncertain” capacity, consisting of uncommitted resources and the derated amount of wind energy capacity. None of this uncertain capacity is included in the reserve margin calculation. RFC GENERATION The RFC analysis includes only generation physically located within the ReliabilityFirst Region, although generating capacity outside the regional area owned by member companies may be included with the scheduled power imports. The amount of “certain” OVEC, PJM and MISO capacity in RFC is 212,900 MW. No additional capacity is expected to go in service during the summer. All of the “certain” capacity in each RTO is determined to be fully deliverable by PJM and MISO within their respective RTOs. There is also 2,900 MW of capacity in the RFC region that is “uncertain” capacity, which is not included in the reserve margin. Deliverability of capacity between the RTOs is not addressed in this report. However, each of the reserve requirement studies conducted has assumed limited or no transfer capability between these RTOs. Studies by the RFC Transmission Performance Subcommittee indicate there is additional inter-RTO transfer capability. The limited use of transfer capability in the reserve requirement studies provides a level of conservatism in this resource assessment. Included in the total of “certain” generation is 225 MW of wind power expected at the peak. An additional 1,565 MW of wind power is categorized as “uncertain” due to the variable nature of wind. Other renewable categories make up an addition 400 MW of generation within the RFC region. If there are any known adverse weather conditions or fuel supply concerns expected to affect available generating capacity this summer, those deratings have been applied to the existing capacity and included in the uncertain capacity category. If any specific adverse conditions are expected to exist this summer they will be addressed in the Fuel section. Page 89 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments Purchases and Sales PJM and MISO have reported expected firm purchases and sales across their RTO boundaries at the time of the peak. This net interchange is due to member ownership interest in generation outside the RTO boundary, and contracted transactions. Specific transactions identified by PJM and MISO as interchange that supports the reserve margins in RFC are firm transactions with firm transmission reservations. Some of the total interchange reported by PJM and MISO is due to jointly owned generation. These resources are located in one RTO but have owners in both RTOs with entitlements to the generation. Also, some of the interchange in PJM and MISO comes from OVEC entitlements. Since the jointly owned generation and the OVEC generation is all within RFC, the jointly owned and OVEC generation is included in RFC’s generation and not in the RFC net interchange. Other transfers between the RTOs may have been reported. Since these transfers originate and terminate within the RFC region, they will also not be included in the RFC interchange. Therefore, the total net interchange for the RFC region is not a simple summation of the PJM and MISO RTO interchange. Since both the MISO and PJM balancing authority areas span into neighboring regions, the values shown below for each RTO are for the total of the respective RTO footprint. The RFC net interchange below only includes that portion of the respective RTOs within the ReliabilityFirst regional area. PJM NET INTERCHANGE Firm power transfers into all of PJM are reported to be 2,700 MW. Firm power transfers out are reported to be 4,200 MW. Net interchange is a 1,500 MW power export flowing out of the PJM RTO. MISO NET INTERCHANGE MISO has reported net interchange (purchases) of 6,300 MW into the whole MISO market at the time of the peak demand. There are no projected firm power sales. RFC NET INTERCHANGE The combined net interchange transactions for OVEC, MISO and PJM at the time of the peak that cross the RFC regional boundary are projected to be a 500 MW import into ReliabilityFirst. These include only firm transactions. Other transactions may occur this summer, but they are not considered to be firm transactions and are not included in this analysis. For both MISO and PJM, any firm capacity from outside the region would be used as any other market resource and, therefore, could be used for emergency and reserve sharing purposes. Fuel Severe weather conditions or fuel supply and delivery problems can adversely affect available generating capacity. Droughts, like the current drought in the Southeastern U.S. can affect coal barge traffic on some rivers. Droughts can also impact the cooling water needed for steam generating plants, by lowering intake channel depths, or by thermal discharge limitations. Rail bottlenecks or other limitations on rail transportation would be expected to cause significant coal delivery problems. Generation that depends on a single natural gas pipeline can become Page 90 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments unavailable during a pipeline outage. Insufficient natural gas in storage during high use periods can create a regulatory prohibition of gas usage for electric generation. The RFC area is not currently experiencing a drought. Two thirds of the hydro resources in the ReliabilityFirst Region are pumped storage units and the remaining are conventional hydro units. These conventional impoundment or run-of-river units only account for about 1% of the capacity resources within the region, limiting the region’s exposure to adverse water conditions. RFC is dependent on natural gas as a fuel for the demand peaks, particularly in the summer time. Over 64,000 MW (29%) of the regional capacity is fueled by gas. Natural gas in storage at the middle of March is near the 5-year average of gas in storage at this time of year according to the Energy Information Administration. Although natural gas usage for electric generation in the summer has increased significantly in recent years, the peak gas usage is during the winter heating season. ReliabilityFirst does not expect any problem with gas availability this summer. Coal is a plentiful fuel within the region, and a potential concern is the dependence on rail transport for much of the coal supply. However, RFC is not aware of any major railroad reporting rail transportation limitations or concerns for this summer. ReliabilityFirst expects each member to be ready to mitigate any fuel supply disruption that may occur. Although ReliabilityFirst has not compiled a list of mitigation actions that could be taken, some members may resort to fuel switching for those units with dual-fuel capability, if it becomes necessary to maintain reliable fuel supplies. Data available to ReliabilityFirst indicates that at least 25% of the regional capacity has dual-fuel capability. ReliabilityFirst has not verified with individual members the ease or difficulty involved with switching to alternate fuels. PJM is investigating firm gas supply contracts. There are significant financial consequences within the PJM market structure for generators not supplying output when called upon. PJM does not have a policy for on-site coal or back-up fuel storage. Transmission Historically, ReliabilityFirst (including the heritage regions) has experienced widely varying power flows due to transactions and prevailing weather conditions across the region. As a result, the transmission system could become constrained during peak periods because of unit unavailability and unplanned transmission outages concurrent with large power transactions. Generation redispatch has the potential to mitigate these potential constraints. Notwithstanding the benefits of this redispatch, should transmission constraint conditions occur, local operating procedures as well as the NERC transmission loading relief (TLR) procedure may be required to maintain adequate transmission system reliability. Certain critical flowgates that have experienced TLRs in previous summers continue to be identified as heavily loaded in various reliability assessments and may require operator intervention to ensure reliability is maintained. No major changes have been identified that would adversely impact reliability this summer. Many new additions to the bulk-power system have been placed in-service since last summer and include a total of 85 miles of transmission line at 230 kV and above, plus ten transformers with a total capacity of about 6,000 MVA. An additional total of 30 miles of transmission line at 230 Page 91 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments kV and above is projected to be placed in-service by this summer, plus six transformers with a total capacity of about 3,000 MVA. These system changes are expected to enhance reliability of the bulk-power system. Phase Angle Regulators (PARs) are located on all major ties between northeastern PJM and southeastern New York to help control unscheduled power flows. The Ramapo PARs in NPCC control flow from RFC to NPCC. The Michigan-Ontario PARs have not yet achieved long-term operation of all four units. The B3N PAR that previously failed will still be out-of-service this summer. An operations agreement for controlling the interface is expected to be completed by the summer, after which the remaining three PARs are expected to control flows (i.e. will be regulating). Operational Issues During normal operations and for typical operations planning scenarios, there may be some transmission constraints within both the PJM and MISO areas of ReliabilityFirst. All of these constraints may be alleviated with generation redispatch or other operating plans/procedures with minimal impact on reliability. ReliabilityFirst does not anticipate any significant impact on reliability from scheduled generating unit or transmission facility outages. In addition to the NERC TLR procedure, other operating procedures are available to maintain reliability. These include a multiregional agreement involving balancing authorities around Lake Erie, to use generation redispatch and phase angle regulator adjustment to mitigate emergency TLR procedures and curtailments in situations where the affected system(s) is about to curtail firm demand. Both MISO and PJM will need to continue to use a transmission constrained economic dispatch. The output of one power plant in the Washington, DC area is still restricted due to environmental issues. However, the restriction may be lifted for emergency operating conditions. Recent transmission enhancements have relieved any local deliverability issues related to this restriction. No other unusual operating conditions that could impact reliability are foreseen for this summer. No unusual operating conditions that could impact reliability are foreseen for this summer. Reliability Assessment Analysis The ReliabilityFirst 2008 summer assessment relies on the reserve margin requirements determined for the PJM and MISO areas. Analyses were conducted by PJM and the Midwest PRSG at the end of 2007 or early in 2008 to satisfy the ReliabilityFirst Loss of Load Expectation (LOLE) criterion of not exceeding one occurrence in ten years on an annual basis. These analyses include demand forecast uncertainty, outage schedules, and other relevant factors when determining the probability of forced outages exceeding the available margin for contingencies. The assessment of PJM resource adequacy was based on reserve requirements determined from their analysis. To assess MISO resource adequacy, RFC calculated a combined reserve target based on the reserve requirement for demand in the Midwest PRSG, the remaining MRO area of MISO that uses the MAPP reserve requirement, and a small amount of other MISO demand that uses a MISO default reserve requirement. This RFC calculated reserve target may be different than the MISO calculated reserve requirement, based on provisions in the Energy Markets Tariff. Page 92 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments Therefore, the assessment for the entire ReliabilityFirst regional area is derived from the results of the PJM and MISO assessments. It is not meaningful to try and calculate a specific reserve margin requirement for all of RFC since each RTO has slightly different demand characteristics, capacity resource availabilities and calculated reserve requirements. However, since PJM and MISO each operate as single entities, it follows that when each RTO has adequate resources based on satisfying their respective reserve requirements, then the RFC reserves can be considered to be adequate. It is important to note that the capacity resources identified as “certain” in this assessment have been pre-certified by either PJM or MISO as able to be used within their RTO market area. This means that these resources are considered to be fully deliverable within and recallable by their respective markets. Both PJM and MISO only include in the certain category those generator resources determined to satisfy their respective deliverability requirements. In both RTOs, there are additional resources identified as uncertain that may be available to serve load. PJM RESERVE MARGINS The reserve margin requirement for all of PJM is 15.0%. This was determined from a study performed by the PJM planning department, and approved by the PJM Board of Managers. Study criteria used in the evaluation can be found in the PJM Planning Manual M-20, “PJM Resource Adequacy Analysis”. The 15.0% reserve margin requirement in this assessment is based on NID and Net Capacity Resources. The reserve margin for the PJM RTO is 21.8% of the NID, which is 29,200 MW and is greater than the reserve requirement of 15.0%, which is 20,100 MW. MISO RESERVE MARGINS Under the current Resource Adequacy section of the MISO’s Energy Markets Tariff (Module E), reserve margins are established by the States and NERC Regional Entities. There are two groups within the MISO that have established reserve requirements consistent with the Regional Entity standards. The Midwest PRSG (MPRSG) has approved planning reserve requirements for three zones (East, Central, West) within the MISO Market Footprint.69 MAPP also has an approved planning reserve requirement for MRO regional demand within the MISO market. A 12% default requirement is applicable to the small amount of demand not included in MAPP or the MPRSG. RFC used these applicable reserve margins in the Midwest ISO for the 2008 planning year to calculate a reserve target for MISO in this assessment of 15,900 MW or a 14.1% reserve margin. The reserve margin target in this assessment is based on NID and Net Capacity Resources. The projected reserve margin for MISO is 21.6% of the NID (21,600 MW). Therefore, the reserves are adequate within the Midwest ISO since the available reserves are greater than the target of 15,900 MW. 69 www.midwestmarket.org/page/Regulatory+and+Economic+Standards Page 93 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments RFC RESERVE MARGINS The reserve margin for ReliabilityFirst is 35,700 MW, which is 20.1% based on NID and Net Capacity Resources. PJM and MISO each have sufficient resources to satisfy their respective reserve margin requirements. Therefore, the 20.1% calculated reserve margin this summer in the ReliabilityFirst region is adequate. This compares to a 20.7% reserve margin in last year’s assessment. While it is not essential for either PJM or MISO to have access to external resources to satisfy this summer’s reserve requirements, both RTOs use resources that are not within the ReliabilityFirst boundary. RESERVE MARGIN SENSITIVITY For the summer of 2008, a higher demand forecast was used to prepare a reserve margin sensitivity for extreme weather across the ReliabilityFirst region. This high demand forecast was developed by combining the 90/10 demand forecasts of PJM and MISO with the OVEC demand and applying a coincidence factor. This is not a true 90/10 demand forecast for the ReliabilityFirst regional area. However, it is being used to evaluate sensitivity to extreme weather. This forecast amounts to a potential demand increase of about 8,700 MW in July under this weather scenario. On an NID basis, the reserve margin would be 27,000 MW or 14.5%. This illustrates that high demand due to extreme weather can significantly reduce the reserve margin available (from 20.1% to 14.5%) to cover potential generator outages. As load increases due to the weather conditions, system operators closely monitor the available generator status and attempt to maintain reserves above the minimum by purchasing additional power from the Interconnection. Curtailment of the interruptible and other DSM program loads would precede a public appeal for conservation and any alerts and warnings that would be issued as reserves become lower. Such procedures are designed to minimize the potential for curtailing firm load. However, a high level of generator outages coupled with high loads from extreme weather and a lack of additional power available from the Interconnection could result in the curtailment of firm demand. Such a curtailment is considered to be a low probability event for this summer. There are two automatic under voltage load shed (UVLS) schemes within RFC. One is located in the northern Ohio/western Pennsylvania area and the other is in the northern Illinois area. These schemes have the capability to automatically shed a combined total of about 2,300 MW and provide an effective method to prevent uncontrolled loss-of-load following extreme outages in those areas. ReliabilityFirst is not aware of any coordinated activities with the fuel supply or delivery industries by the RTOs or other groups within the region. Fuel supply and delivery is the responsibility of the generation owner/operator. Through regional and interregional transmission transfer capability analyses, ReliabilityFirst has not identified any dynamic or static reactive power-limited areas. ReliabilityFirst also does not currently have regional criteria for dynamic reactive reserves or margins, voltage dip, or stability margin; as each individual transmission owner or RTO would develop their own. Voltage stability margin is not a foreseen concern for this summer. PJM performs voltage stability analysis (including voltage drop) as part of all planning studies and also as part of a periodic (every five minutes) analysis performed by the EMS. Results are Page 94 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments translated into thermal interface limits for operators to monitor. Transient stability studies are performed as needed and are part of the Regional Transmission Expansion Plan (RTEP) analysis (see http://www.pjm.com/planning/rtep-baseline-reports/baseline-report.html). Small signal analysis is performed as part of long-term studies, but not for seasonal assessments. ReliabilityFirst actively participated in all three of the Eastern Interconnection Reliability Assessment Group (ERAG) interregional seasonal transmission assessment efforts and also conducted its own transfer capability analyses and assessment (see http://www.rfirst.org/Reliability/ReliabilityHome.aspx). Transfer capability results are included in each of the regional and interregional seasonal reports. ReliabilityFirst regional analyses do recognize facility constraints external to its boundary. ReliabilityFirst members also conduct their own seasonal assessments. Simultaneous import capabilities are projected to be adequate for this summer. Region Description ReliabilityFirst currently consists of 44 Regular Members, 21 Associate Members, and 4 Adjunct Members operating within 12 NERC balancing authorities, which includes over 360 owners, users, and operators of the bulk-power system. They serve the electrical requirements of more than 72 million people in an area covering all of the states of Delaware, Indiana, Maryland, Ohio, Pennsylvania, New Jersey, and West Virginia, plus the District of Columbia; and portions of Illinois, Kentucky, Michigan, Tennessee, Virginia, and Wisconsin. The ReliabilityFirst area demand is primarily summer peaking. Additional details are available on the ReliabilityFirst website (http://www.rfirst.org). Page 95 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments SERC 2008 Projected Peak Demand MW Relative Capacity by Fuel Mix Total Internal Demand 203,320 Direct Control Load Management 958 Dual Fuel Contractually Interruptible (Curtailable) 4,977 15% Critical Peak-Pricing with Control 221 Load as a Capacity Resource 125 Net Internal Demand 197,040 Coal 39% MW Change Gas 18% 2007 Actual Summer Peak Demand 209,108 -5.8% All-Time Summer Peak Demand 209,108 -5.8% Oil 2% 2008 Projected Capacity MW Margin Other 0.3% Existing Certain and Net Firm Transactions 236,328 16.6% Pumped Net Capacity Resources 237,006 16.9% Hydro 6% Storage 4% Nuclear 16% Total Potential Resources 238,335 17.3% Introduction The SERC Reliability Corporation (SERC) is the Regional Reliability Organization for all or portions of 16 central and southeastern states. SERC is divided into five sub- regions: Central, Delta, Gateway, Southeastern, and VACAR, that together supply power to approximately 23% of the electric customers in the United States. Most electric utilities within SERC have traditional vertically integrated corporate structures with planning philosophies based on an obligation to serve ensuring that designated generation operates under optimal economic dispatch to serve local area customers. A few SERC members, however, have selected or been ordered to adopt a non-traditional operating structure whereby management of the transmission system operation is provided by a third party under an Independent Coordinator of Transmission or a Regional Transmission Organization that manages transmission flows to customers over a broader regional area through congestion-based locational marginal pricing. Companies within SERC are closely interconnected and the region has operated with high reliability for many years. It should be noted that the generation capacity figures provided here are based generally on the data submitted for the current EIA 411 report. SERC collects generation data for the upcoming season from its members in addition to the collection of data in accordance with NERC’s prescribed definitions. This data identifies on generation which is constructed, but not necessarily dedicated or committed to serving load. Such generation performs a merchant function, operating when it is economic to do so. Therefore, even though a significant amount of merchant generation has been developed within SERC in recent years, not all of that generation is reflected in the capacity margins calculated by NERC. It is estimated that there is over 28,000 MW of such generation in the SERC region in addition to what is reported in the EIA 411 report. Some companies wait to finalize some of their arrangements until close to the peak season, knowing that adequate capacity will be available. Another factor that should be recognized is an expansion of efforts in efficiency and demand side management (DSM) programs. Sub-regions Page 96 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments in SERC, for example Central, are committing to very aggressive programs that provide, in addition to consumer benefits, further means to reduce or curtail demand when needed to ensure reliability. Thus the region members anticipate no difficulties in meeting their respective goals for capacity margin during the 2008 summer peak. SERC members invested approximately $1.161 billion in transmission system upgrades 100 kV and above in 2007 and plan to invest approximately $1.478 billion in 2008 and $1.681 billion in 2009. Demand The SERC total internal demand for the 2008 summer is forecast to be 203,320 MW which is 5,788 MW (2.8%) lower than the all-time peak of 209,108 MW that occurred in August 2007, but is 2,666 MW (1.3%) higher than the forecast 2007 summer peak of 200,654 MW. This projection is based on average historical summer weather. There were no significant changes in weather and economic assumptions since last year except for considerations related to the southeast drought which have been incorporated into the operational planning for the upcoming season. However, small adjustments are made to better match current economic and weather outlooks. The SERC region has significant demand response programs. These programs allow demand to be reduced or curtailed when needed to maintain reliability. Traditional load management and interruptible programs such as air conditioning load control and large industrial interruptible services are common within the region. Interruptible demand and demand-side management capabilities for 2008 summer are 7,040 MW as compared with the 5,702 MW reported last summer. Traditional demand response programs include monetary incentives to reduce demand during peak periods. Some examples are real time pricing programs and voluntary curtailment riders. Temperatures that are higher or lower than normal and the degree to which interruptible demand and demand-side management is used, result in actual peak demands that vary from the forecast. Although SERC does not perform extreme weather or load sensitivity analyses at the region level, SERC members consider these issues. These member methodologies are documented and subject to audit by SERC. While member methodologies vary, many commonalities exist. Common considerations 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 SERC members use sophisticated, industry accepted methodologies to evaluate load sensitivities in the development of load forecasts Page 97 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments Regarding the influence of weather, the 90th percentile peak temperature relates to an extreme weather peak of about 6% higher than the regular forecast for the region. An extreme peak for 2008 summer equates to 215,520 MW of peak demand for the region. The capacity margin for this scenario is estimated to be over 9.5%, which, although reduced from the expected margin under normal forecast conditions remains at an adequate level for the extreme case condition. This analysis assumes the load response to temperatures in this extreme range is linear. However, historical evidence indicates that at some point saturation occurs as temperatures rise, so the capacity margin is likely to be better even under this extreme case. The SERC region as a whole is not expected to have any difficulty serving customers in a 90/10 outcome relative to the load forecast. Generation SERC members report 237,966 MW of Existing-Certain generating capability in the region for 2008 summer. This generation alone exceeds the forecast summer total peak demand by 33,686 MW and does not include the un-contracted merchant generation connected to the SERC member systems. SERC has had significant merchant generation development. SERC member responses to the annual SERC Reliability Review Subcommittee’s Generation Development Survey indicate in excess of 28,000 MW of un-contracted merchant generation is connected to the member systems. This merchant generation has not been contracted to serve load within SERC and its deliverability is not assured. For these reasons, only merchant generation expected to serve SERC load is included in the capacity margins reported for SERC. However, a significant amount of merchant capacity within the region has been participating in the short-term energy markets, indicating that a portion of these resources are deliverable during certain system conditions. Purchases and Sales Planned firm purchases across the SERC electrical borders total 1,548 MW and are comprised of 908 MW from RFC and 640 MW from SPP. These firm purchases have been included in the capacity margin calculations for the region. Planned firm sales across the SERC electrical borders total 3,186 MW and are comprised of 1,551 MW to FRCC, 1,247 MW to RFC, 13 MW to MRO, and 375 MW to SPP. These firm sales have been accounted for in the capacity margin calculations for the region. Fuel Sufficient inventories (including access to salt-dome natural gas storage), fuel-switching capabilities, alternate fuel delivery routes and suppliers, and emergency fuel delivery contracts are some of the important measures used by SERC members to reduce risks due to fuel supply problems. SERC entities with large amounts of gas-fired generation connected to their systems have conducted electric-gas interdependency studies. In-depth studies have simulated pipeline outages for near and long-term study periods as well as both summer and winter forecast peak conditions. Also included, for each of the major pipelines serving the service territory, is an analysis of the expected sequence of events for the pipeline contingency, replacing the lost generation capacity, and assessment of electrical transmission system adequacy under the resulting conditions. Other SERC entities with less dependence on gas generation have mapped generators to their respective pipelines from which they are served. Dual fuel units are tested Page 98 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments and back-up fuel supplies are maintained and positioned to ensure immediate availability. Some generating units have made provisions to switch between two separate natural gas pipeline systems, reducing the dependence on any single interstate pipeline. Current projections indicate that the fuel supply infrastructure and fuel inventories for the summer period are adequate even considering unexpected extreme conditions. New international gas supplies are continuing to enter the U.S. market. While fuel deliverability problems are possible for limited periods of time due to weather extremes, 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 increased deliveries from alternate fuel suppliers and impacts to emission levels. SERC members recognize that planning for variability in resource availability is necessary. Many SERC members typically provide for this variability through capacity margins, demand side management programs, fuel inventories, diversified fuel mix and sources, and transfer capabilities. Some SERC members participate in Reserve Sharing Groups (RSG). In addition, emergency energy contracts are used within the region and with neighboring systems to enhance recovery from unplanned outages. Emergency sales and purchases and activation of shared reserves have been used in the region during the past year. However, the frequency of their use has not increased relative to previous years. Transmission The SERC region has extensive transmission interconnections between its sub-regions. SERC also has extensive interconnections to the FRCC, MRO, RFC, and SPP 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 134 miles of 161 kV, 230 kV, 345 kV, and 500 kV transmission lines and several station reliability improvement projects were completed from Fall 2007 to Spring 2008 with approximately 228 more miles of 161 kV, 230 kV, 345 kV, and 500 kV additions scheduled for completion prior to or during the 2008 summer season. SERC members spent approximately $1.161 billion in new transmission lines and system upgrades (includes transmission lines 100 kV and above and transmission substations with a low-side voltage of 100 kV and above) in 2007 and plan to spend approximately $1.478 billion in 2008 and $1.681 billion in 2009. Coordinated interregional Eastern Interconnection Reliability Assessment Group (ERAG) transmission reliability and transfer capability studies for the 2008 summer season were conducted involving all the SERC sub-regions and neighboring regions. These studies indicate that the bulk transmission systems within SERC and between adjoining regions generally can be expected to provide adequate and reliable service over a range of system operating conditions. No significant limits to transfers were identified except for the Delta-SPP interface which is discussed later in the Delta subregional report. Operational Issues – Special Drought Assessment All sub-regions of SERC experienced drought effects during 2007. This provided a valuable basis for evaluation of 2008 conditions. SERC conducted a special assessment including an extreme hydrological scenario more severe in terms of water availability to forecast 2008 Page 99 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments summer conditions. Based on the assessment, if the drought continues through 2008, the hydrological conditions leading into 2009 could be more severe. However, at the present time hydrological conditions in 2008 are improving in many areas. No sub-region identified significant concerns that might threaten reliability for summer 2008. At most, some redispatch, modest increases in imports, or operating guidelines will be required. Individual Transmission Planners and Planning Coordinators are continuing drought preparedness initiatives already underway and operational representatives continue to provide opportunities for coordination and sharing of system conditions. Environmental restrictions are not expected to significantly impact operations. No major generator outages are planned for the summer that could impact reliability. With the exception of dams being repaired, hydro reservoirs are mostly at normal levels as the drought conditions have improved. Current projections are for normal rainfall this summer, although in some areas rainfall to date has been below normal. Reservoir levels are expected to be sufficient to meet forecast peak demands and daily energy demands for the summer period. Several hydro facilities in the region are continuing major rehabilitation such as rewinding of generators, turbine replacements, switchyard work, and dam repairs, but the outages are being coordinated so reliability and contractual commitments will not be impacted. Reliability Assessment Analysis Capacity resources in SERC are expected to be able to supply the projected firm summer demand with adequate margin. Although SERC does not specify a regional capacity margin requirement, members adhere to their respective state commission regulations, RTO requirements and/or internal business practices as applicable. The projected 2008 summer capacity margin for SERC is 16.9%, which is higher than last year’s projected capacity margin of 13.9% although on a significantly different definition basis for generation classification. While there are no common sub-region wide criteria to address transient dynamics, voltage and small signal stability issues, some members have noted that they adhere to voltage schedules and voltage stability margins. In addition to static reactive compensation, some members employ dynamic compensation devices to provide reactive power support and voltage stability. Under- voltage load-shedding (UVLS) programs are also used to maintain voltage stability and protect against bulk electric system cascading events. Sub-regional Details This section of the report describes highlights of reliability issues in each SERC sub-region. While details are not provided here, companies throughout the region work closely with each other, with NERC, inter-regionally through the ERAG, and other associations, to ensure continued reliability. In general the SERC sub-regions have negligible amounts of renewables (except for hydro resources) with many sub-regions reporting zero for the renewable categories. Central Demand - Projected total internal demand for the 2008 summer season is 43,866 MW based on normal weather conditions. This is 720 MW (1.7%) higher than the forecast 2007 summer peak demand of 43,146 MW. The projected total internal demand for 2008 is 921 MW (2.1%) lower than the actual 2007 summer peak of 44,787 MW, which was higher than expected due to higher Page 100 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments temperatures. The 2008 summer demand forecast is based on normal weather conditions and economic data from population, employment, energy sales, and gross regional product increases. To assess variability, some members within the sub-region use forecasts assuming normal weather, and then develop models for milder and more extreme weather to create optimistic and pessimistic scenarios. Others within the sub-region use historical peaks, and demand models to predict variance. The sub-region has a mix of various demand response programs including interruptible demand, new energy efficiency programs, customer curtailing programs, and direct load management including an air conditioner control program. Generation - Members in the Central sub-region reported approximately 49,582 MW of existing certain resources and zero MW of existing uncertain resources available during June 1 through September 30, 2008. Capacity expected on peak includes approximately 4,961 MW of hydro, 560 kW of solar and 15 MW of biomass. As noted below, additional firm capacity will be in place to ensure normal margins for the peak. The sub-region experienced a severe drought through 2007 which is expected to continue into 2008, and some members have seen a reduction in their power supply from Southeastern Power Administration due to repair work on the Wolf Creek Dam which is likely to continue for several more years. Hydro operations are constantly monitored and evaluated for potential changes and mitigation plans are formed to minimize any threats to reliability. While the continuing drought and dam repairs will affect hydro energy and capacity and cause some thermal de-rating no problems are foreseen in meeting normal margins and maintaining normal reliability. If unexpected capacity shortages occur, multi-step mitigation plans such as firm replacement contracts, alternative fuel generation, voluntary curtailment, and out of schedule dispatching are used as necessary. Purchases and Sales - Firm Sales of 66 MW are external to the Region and 143 MW are external to the sub-region. Firm Purchases of 266 MW are external to the Region. The majority of these sales/purchases are backed by firm contracts and very few are associated with liquidated damages contracts (LDC). The firm purchases and sales have been included in the capacity margin for the sub-region. Fuel - Fuel vulnerability is not considered to be a concern. Central sub-region members have a highly diverse mix of suppliers, transportation, supply contracts, on-site storage and fuel alternatives to supply generation. Coal is responsible for over 50% of generation in the sub- region and coal stocks and transportation systems are considered strong. While gas supplies have been disrupted in the past by hurricanes, this would affect only a small percentage of generation. Operational Issues - No major generating unit outages, generation additions, environmental/regulatory restrictions or temporary operating measures are expected to affect the reliability of the Central sub-region this summer. Page 101 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments Transmission - Members within the sub-region reported several 161 kV, 345 kV and 500 kV transmission line and substation projects including a new Davies County 345 kV interconnection between Big Rivers and E.ON U.S. and TVA’s 500 kV Cumberland-Montgomery line, are expected to be in-service for the upcoming season. Resource Assessment Analysis - Projected summer peak capacity margin in the sub-region as reported in January 2008 was 17.0% compared to 13.4% at the same time last year. However, as a consequence of the continuing drought effects, the schedule to finalize firm resource contracts for the summer has been extended to the end of April, but plans are in place to ensure firm resources with at least a 15% capacity margin for the summer peak. Resource adequacy analyses are performed on a regular basis, and no significant changes have been reported from last year. Some members use reserve margins, resource and supplier contracts as criteria to ensure resources are adequate to meet demand. Members also use planning studies to ensure generation deliverability. Studies are coordinated with neighboring systems to incorporate imports and unit outages. Members within the sub-region rely on quarterly OASIS studies. For example the SERC Near Term Study Group assesses transfer capability issues. Studies show that Western Kentucky and Southern Indiana continue to experience transmission constraints that limit regional power transactions; and. north-to-south power transfers through the state of Kentucky introduce loading concerns due to parallel flows in several transmission facilities within the northern Central sub-region and neighboring control areas. Transmission Loading Relief procedures are expected to be used this summer. No other constraints to the bulk electric system for the 2008 summer season has been identified that could impact reliability. Companies within the sub-region maintain individual criteria to address any problems with stability issues. UVLS systems have been installed to prevent voltage collapse at Philadelphia, Miss., and Knoxville, Tenn. All other systems are expected to be secure with no anticipated stability issues. Delta Demand - Total internal demand for the 2008 summer season is forecast to be 28,440 MW based on normal weather conditions. This forecast is 710 MW (2.6%) higher than the forecast 2007 summer peak demand of 27,730 MW and is 666 MW (2.3%) lower than the actual 2007 summer peak demand of 29,106 MW. Uncertainty and variability is assessed through load scenario development, based on historical temperature probabilities. Peak load scenarios are also performed to assess conditions due to extreme weather found in historical records. While certain parts of the sub-region are expecting increases in demand due to load growth, the overall decrease between the actual 2007 summer peak demand and forecasted 2008 summer peak demand is primarily due to Entergy experiencing a 2007 summer peak that occurred when Entergy’s system above average temperature was 101°F. The 2008 forecast assumes a 10-year system average temperature of 96°F. Page 102 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments Members within the Delta sub-region reported that they have a mix of demand response programs which consists of interruptible load programs for larger customers and a range of conservation/load management programs for all customer segments. Generation - Companies within the sub-region expect to have approximately 31,569 MW of Existing-Certain resources and 389 MW of existing uncertain resources available during June 1 through September 30, 2008. Approximately 79 MW of this generation is hydro expected on peak during this time period. Hydro conditions for the summer 2008 are expected to be normal based on current reservoir levels and anticipated rainfall. The sub-region expects no significant changes or assumptions and expects to have adequate capacity to meet peak demand. Purchases and Sales - Sales of 600 MW are external to the region and 1,145 MW is external to the sub-region. Purchases of 541 MW are external to the region and a max of 1,404 MW is external to the sub-region. These firm purchases and sales have been accounted for in the capacity margin calculations for the sub-region. Overall, the sub-region is not dependent on outside purchases, transfers, or contracts to meet the demands of its load. Fuel - Delta sub-regional members reported that they purchase a significant amount of fuel in short-term markets. The entities ensure that they are in constant communication with pipelines, storage facilities and suppliers in the region resulting in continuous up-to-date knowledge of supply and transportation issues. Agreements have been set in place to purchase supply, transportation, balancing, flexibility and peaking services to serve anticipated generation needs. Delta sub-regional members reported that fuel supplies and infrastructure are more than adequate for summer peak demands. Members also rely on a portfolio of firm-fuel resources to ensure adequate fuel supplies to generating facilities during projected winter peak demand. Those resources include nuclear and coal-fired generation that are relatively unaffected by winter weather events, fuel oil inventory, natural gas at a company-owned natural gas storage facility, and short-term purchases of firm natural gas. This mix of resources provides diversity of fuel supply and minimizes the likelihood and impact of potentially problematic issues on system reliability. Other measures include aggressive maintenance of coal delivery infrastructure. Resources - Projected capacity margin in the sub-region is 11.6% as compared to 13.9% last year. This decrease is primarily due to some generation previously reported as certain now being reported as uncertain. Because of the large amount of non-firm generation available within Delta sub-region, primarily within the Entergy System, additional resources could be procured in the short-term to meet any expected shortfalls in generation capacity. New combined cycle and wind generation, totaling about 580 MW are expected online for 2008 summer to serve sub- region load. The Delta sub-region has over 4,000 MW of firm purchases scheduled for 2008 summer. However, the resources are primarily from merchant generation located within the sub- region with only about 2,000 MW of that coming from outside the sub-region. Capacity in the sub-region should be adequate to supply forecast demand. Operational Issues - No reliability concerns are anticipated for the upcoming peak season. There are no major generating unit outages or transmission facility outages planned which would impact bulk system reliability for the 2008 summer season. There are also no local Page 103 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments environmental, regulatory restrictions or unusual operating conditions expected that might impact reliability. Transmission - Several transmission projects to increase system reliability are scheduled for completion prior to or during summer 2008 in the Delta sub-region. New transmission lines Gobbler Knob-Cox Creek 161 kV, Brookline-Springfield 161 kV, and a new 345/161 kV transformer have all been reported to be available for the summer of 2008 on the Associated Energy Cooperative, Inc. system. Other recently completed transmission projects on the Entergy System include construction of the Sterlington-Perryville 500 kV transmission line (May 2007), the Yandell Road-Bozeman 230 kV transmission line (September 2007), and the Hammond-Amite 230 kV transmission line (December 2007). The preliminary results from the ERAG sponsored 2008 Summer MRO-RFC-SERC West-SPP inter-regional study indicate potential transmission transfer issues between the Delta sub-region and some neighboring regions involved in the study. The areas of interest from this preliminary study indicate that the First Contingency Incremental Transfer Capability (FCITC) from the Delta sub-region to some neighboring interfaces, including SPP and MRO, as “zero”. These transfers are primarily limited by 161 kV transmission facilities on the Entergy-SPP interface for the outage of the ANO-Ft. Smith 500 kV line, which is a tie line between Entergy and OG&E. Previous reliability studies indicate that power flows on these 161 kV transmission lines are extremely sensitive to Entergy and SPP generation dispatch in the local area, as well as transactions modeled across Entergy’s northern interface. While Entergy and other SPP members have committed to upgrading one of these interface constraints (i.e., Danville- Magazine 161 kV line), Entergy is also evaluating other long-term transmission solutions for this limit. However, Entergy does not expect any reliability concerns for the upcoming summer. Reliability Assessment Analysis - As noted above, Delta sub-regional members projected an 11.6% capacity margin in the sub-region as compared to 13.9% last year. Even though there is a slight decrease in margins predicted for the upcoming season as compared to last year’s margins, capacity should be adequate to meet demand for the upcoming summer season. While the sub- region’s generation capacity is adequate for supplying its load, it also has access to reserve sharing programs, fuel diversification, fuel policy contracts and other firm resource network contracts and power agreements to ensure supply in times of catastrophic events. Several analyses (Loss-of-Load Expectation, etc.), coordinated with neighboring regions and other SERC sub-regions, indicate that transmission transfer capability will be adequate on all interfaces this summer to support reliable operations. From the results of these analyses, no bulk electric system constraints are expected that would need to be addressed. Studies have been performed to assess transient dynamics, voltage and small signal stability issues for summer conditions in the near-term planning horizons as required by NERC Reliability Standards. For certain areas of the sub-region, the 2009 assessment from the study was chosen as a proxy for the near-term evaluation. No critical impacts to the bulk electric power system were identified. While there are no common sub-region wide criteria to address transient dynamics, voltage and small signal stability issues, some members have noted that it adheres to voltage schedules and voltage stability margins. In addition, some members employ static var compensation devices to provide reactive power support and voltage stability. Under-voltage load-shedding (UVLS) programs are Page 104 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments also used to maintain voltage stability and protect against bulk electric system cascading events. It was reported that the maximum load that can be shed by the UVLS program is approximately 300 MW. Gateway Demand - Total internal demand for the 2008 summer season is forecast to be 19,233 MW based on normal weather conditions. This is 349 MW (1.8%) lower than the actual 2007 summer peak demand of 19,582 MW, but is 249 MW (1.3%) higher than the forecast 2007 summer peak demand of 18,984 MW. The increase in forecast load compared to 2007 summer is due to normal load growth. The decrease in forecast load compared to the 2007 actual peak is because the forecast is based on normal load and temperature patterns. The 2007 summer peak load was caused by hotter than normal temperatures. In order to assess the uncertainty and variability in projected demand some members within the sub-region use regression models, multiple forecast scenario models, and econometric models. Economic assumptions and historical temperature and weather pattern information are considered individually by each sub-region member. The sub-region has only 128 MW of direct control load management or contractual interruptible load. Generation - Companies within the Gateway sub-region expect to have approximately 23,979 MW of existing certain and 875 MW of uncertain existing resources during June 1 through September 30, 2008. The sub-region has 368 MW of hydro expected to be on peak during this time period. The generation resources to serve these retail loads are predominantly located within the Gateway sub-region for this summer. Hydro conditions within the sub-region are expected to be normal for the upcoming season, but represent less than 2% of the total capacity in the sub-region. Cooling water reservoirs are expected to be adequate and return to their full pool levels due to heavy precipitation in 2008. Purchases and Sales - Firm Sales - 869 MW are external to the region. Firm Purchases - 136 MW are external to the region 250 MW is external to the sub-region. These firm purchases and sales have been accounted for in the capacity margin calculations for the sub-region. Overall, the sub-region is not dependent on outside purchases or transfers to meet the demands of its load. Fuel - Gateway sub-region members reported various fuel policies and some members have reevaluated fuel inventories as a result of fuel delivery issues. Some members have developed Integrated Resource Plans to help ensure fuel reliability within the sub-region. These policies take into account contracts with surrounding facilities, alternative transportation routes, and alternative fuels. These practices help to ensure balance and flexibility to serve anticipated generation needs. Resources - Projected capacity margin in the Gateway sub-region is 18.7% as compared to 24.3% last year. Operational Issues - No reliability problems are anticipated on the transmission systems of the Gateway sub-region members for this summer. The City of Springfield-CWLP reported that its Dallman generator unit 1, which experienced an explosion last year that compromised 86 MW, will not be available this upcoming summer season. Several members within this sub-region have noted that there are limitations with emissions stipulations, thermal discharge or lake temperature limitations that can have an impact on peak energy needs. Many of these issues Page 105 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments would be alleviated with the above normal precipitation received in late 2007 and early 2008. These limitations or any unusual operating conditions are not expected to have a major impact on reliability. The Taum Sauk pumped storage facility in the AmerenUE control area remains unavailable but this is not a reliability concern as adequate resources are available in the sub- region. The Taum Sauk plant is expected to return to service in late 2009. Transmission - An eleven-mile 345 kV line between the Loose Creek switching station and the Mariosa Delta 345/161 kV substation in central Missouri should be completed by AmerenUE for the summer 2008. All transmission owners reported that they are steadily making capacity improvements to upgrade and enhance the bulk electric power system in the sub-region. Reliability Assessment Analysis - The projected capacity margin in the Gateway sub-region is 18.7% as compared to 24.3% last year. The decline can be attributed to data reporting at a time when not all resources were identified to serve the Illinois load for 2008 summer. Based on past experience it is expected that by summer, adequate resources and reserves could be secured from the market to reliably supply the load in the Gateway sub-region. Fuel supply in the area is not expected 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. Deliverability testing studies are performed on an ongoing basis throughout the sub-region to ensure that transmission capacity is sufficient to make the generation deliverable. No concerns for deliverability have been reported for the upcoming year. No significant issues within the Gateway sub-region have been identified. Transmission constraints within the sub-region are minimal and are not expected to impact reliability. Sub-regional studies involving power flow, short-circuit, and stability analyses are not performed on a regular basis involving the entire sub- region, but joint studies are performed by the members as needed to address sub-regional needs. Southeastern Demand - Total internal demand for the 2008 summer season is forecast to be 50,122 MW based on normal weather conditions. This is 598 MW (1.2%) higher than the forecast 2007 summer peak demand of 49,524 MW and 772 MW (1.5%) lower than the actual 2007 summer peak demand of 50,894 MW. The 2007 summer was much hotter than normal and so demand was higher than anticipated. The 2008 summer demand forecast is based on normal weather conditions and uses normal/median weather, normal load growth and conservative economic scenarios. The sub-region has a mix of various demand response programs including interruptible demand, customer curtailing programs, direct load control (irrigation, A/C and water heater controls) and distributed generation to reduce the effects of summer peaks. To assess variability, some sub-region members develop forecasts using econometric analysis based on approximately 30 year (normal, extreme and mild) weather, economics and demographics. Others within the sub-region use the analysis of historical peaks, reserve margins and demand models to predict variance. Generation - Companies within the Southeastern sub-region expect to have approximately 59,517 MW of Existing-Certain resources and over 5600 MW of uncommitted resources available during June 1 through September 30, 2008. Approximately 4,058 MW of this is hydro generation. Various areas within the sub-region are experiencing drought conditions, but these conditions have improved considerably with January - March rainfall and are not predicted to Page 106 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments affect reliability. Reservoirs and reserve margins are expected to be sufficient in 2008. Mitigation plans such as firm replacement contracts, alternative fuel generation, and dispatching operations are available if necessary. Purchases and Sales - Firm Sales - 1,551 MW are external to the Region and max 986 MW is external to the sub-region. Firm Purchases - None are external to the Region and 408 MW are external to the sub-region. The majority of these sales/purchases are backed by firm contracts, but none are associated with Liquidated Damages Contracts (LDC). These firm purchases and sales have been included in the capacity margin calculations for the sub-region. Overall, the sub- region is not dependent on outside purchases or transfers to meet the demands of its load. Fuel - Southeastern sub-regional members reported that fuel vulnerability is not an expected reliability concern for the summer reporting period. The members have a highly diverse fuel mix to supply its demand, including nuclear, PRB coal, Eastern coal, natural gas and hydro. Some members have implemented fuel storage and coal conservation programs, and various fuel policies to address this concern. These tactics help to ensure balance and flexibility to serve anticipated generation needs. Resources - Projected capacity margin in the Southeastern sub-region is 16.1% compared to 13.5% last year. In addition to the resources included in the capacity margin calculation, demand side options are available during peak periods along with large amounts of merchant generation in the sub-region. Capacity in the sub-region should be adequate to supply forecast demand. Additionally, the preliminary results of the SERC Summer Reliability Study indicate assistance can be imported into the Southeastern sub-region during the upcoming summer peak, if needed. No local deliverability problems are anticipated. McIntosh unit 1 (110 MW Compressed Air Energy Storage) experienced a forced outage during summer 2006. It is expected to be unavailable until March 2008. Two 48 MW Combustion Turbine units at Sowega were made operational in January 2007. Operational Issues - No reliability problems due to unit outages, additional/temporary operating measures or environmental regulations are anticipated to negatively affect the transmission systems of the Southeastern sub-region members this summer. The sub-region routinely experiences significant loop flows due to transactions external to the sub-region itself. However, all transmission constraints identified in current operational planning studies for the 2008 summer can be mitigated through generation adjustments, system reconfiguration or system purchases. 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 Southeastern sub-region than on loading within. Significant changes in gas pricing dramatically impact dispatch patterns. Adjustments to total transfer capability will be made as needed based on actual flows. Local procedures will be used as needed, but no delivery problems are anticipated. Utilizing the TLR process is not anticipated, but available if necessary. Page 107 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments Various areas are currently experiencing drought conditions; however recent weather assessments show that the drought conditions have improved significantly and this trend is expected to continue throughout spring 2008. The sub-region members participated in the SERC regional drought assessment which did not identify significant reliability impacts from the drought. Although hydro generation is predicted to be lower than normal for the upcoming season, reliability will not be affected due to ready access to other generation sources. Transmission - Numerous 230 kV and 500 kV additions are scheduled for the Southeastern sub- region to serve load and address contingency loadings and voltages for the upcoming season. A new 161 kV interconnection between SMEPA and TVA entered service on July 3, 2007 to increase reliability in portions of both the Southeastern and Central sub-regions. An existing SMEPA – Entergy interconnection will be upgraded, doubling its capacity, for summer 2008 operation. Several 230 kV and 500 kV transmission lines additions, re-rates and station reliability improvement projects are expected to be completed by the 2008 summer season. Reliability Assessment Analysis - The projected capacity margin in the Southeastern sub-region is 19.9% compared to 13.5% last year. Resources are expected to come from within the region and through external resources as well. Capacity in the sub-region should be adequate to supply forecast demand. There are no significant changes to LOLP, EUE, generation resource models and other resources adequacy studies that will affect margins. Various tactics are being used to ensure these resource adequacy measurements are within an acceptable range. Annual Transmission Transfer Capability, System Impact and Facility studies are performed jointly with various members within the sub-region to determine external generation deliverability. Operating guides are developed as necessary to ensure acceptable transfer levels are reached. Some entities perform annual contingency analysis (studies typically covering up to ten future years) and biannual stability studies to ensure internal generation deliverability. Current studies have identified no deliverability concerns expected to impact reliability. The fuel supply infrastructure, fuel delivery system, and fuel reserves are all adequate to meet peak gas demand. Various companies within the sub-region have firm transportation, gas storage, firm pipeline capacity, and on-site fuel oil and coal supplies to meet the peak demand. Transfer capability studies are routinely performed with neighboring companies both within and outside the SERC region. No major transmission constraints have been identified for the upcoming season that would impact existing firm transmission service. The Southeastern sub-region does not have sub-regional criteria for dynamics, voltage and small signal stability; however, various companies within the sub-region perform individual studies and maintain individual criteria to address any stability issues. All systems are expected to be secure for the upcoming season. VACAR Demand - Total internal demand for the 2008 summer season is forecast to be 63,130 MW based on normal weather conditions. This is 799 MW (1. 3%) higher than the forecast 2007 summer peak demand of 62,331 MW and 1,610 MW (2.5%) lower than the actual 2007 summer peak demand of 64,740 MW The 2007 actual peak exceeded the forecast because of temperatures which exceeded the statistically normal values used in the forecast. The 2008 summer demand forecast is based on averages of the latest 20 to 35 years of historical weather, forecast economic growth, and regressing demographics against system load. These tools are used to develop weather variables for forecasting peak demands. Some members reported that the demand forecast is based on a 50-50 weather projection. The sub-region has a mix of various demand Page 108 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments response programs including interruptible demand, customer curtailing programs, Standby Generator Control, Residential Time-of-Use, General Service and Industrial Time-of-Use, and Hourly Pricing for Incremental Load Interruptible programs to reduce the affects of summer peaks. To assess variability, some members within the sub-region use forecasts that are developed using assumptions through economic models, historical weather conditions, energy consumption and demographics. Others assess variability of forecast demand by accounting for reserve margins instead. Generation - Companies within the VACAR sub-region expect to have approximately 72,656 of existing certain resources and 0 MW of existing uncertain resources available during June 1 through September 30, 2008. Approximately 3,740 MW of this generation is hydro expected on peak and 225 MW of this generation is biomass expected on peak during this time period. Members within the sub-region report that it has experienced a drought and is expecting conditions to continue for the upcoming season. These conditions have caused substantial constraints on hydro operations. However, coupled with other resources, projected hydro generation and reservoir levels are expected to be adequate to meet both normal and emergency energy demands for the 2008 summer. Members within the sub-region are also monitoring drought conditions through studies to assess the expected severity and its impact on the system. Purchases and Sales - VACAR sub-regional members reported 100 MW of firm sales external to the region and 200 MW external to the sub-region. Firm purchases from entities were 605 MW external to the region and 1,149 external to the sub-region. Of these sales/purchases, very few are associated with Liquidated Damage Contracts (LDC). Outside purchases or transfers of capacity from other regions or sub-regions are not expected to be relied on to meet emergency imports and reserve sharing requirements for the upcoming season. Fuel - Fuel vulnerability is not a concern within this sub-region. The members have a highly diverse mix of options which consist of on-site storage, transportation alternatives and fuel contracts to ensure supply to its resources. Other mitigation plans generally involve tiered strategies that are invoked depending on the severity of the situation. This guidance on managing fuel in short supply has been formalized in procedures as required by NERC Reliability Standards. These tactics help to ensure balance and flexibility to serve anticipated generation needs for the upcoming season. Resources - Projected capacity margin in the subregion is 17.5%, compared to 13.1% last summer. Capacity in the subregion should be adequate to supply forecast demand. Operational Issues - For the upcoming summer season, no major outages, additions, or measures are anticipated. It was noted that the output of Potomac River generating plant located within Pepco, a member of ReliabilityFirst Corporation (RFC), in Washington, DC is still restricted because of environmental concerns. However, Potomac River may be dispatched during emergency conditions. Other members reported that the minimum flow, fish passage, and 401 water quality requirements may restrict available pooling of water for generation. There are also concerns of the limitations on generation due to the installation of scrubbers. Even though there are environmental/regulatory concerns within the sub-region, the members anticipate no restrictions that could potentially impact reliability for this summer. Page 109 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments Transmission - Several improvements to transmission facilities within VACAR have been completed or planned to be completed by the summer of 2008. The Brambleton to Greenway 230 kV line will complete the Brambleton – Beaumade – Pleasant View 230 kV loop and will address several contingency loading concerns in the Northern Virginia area for the upcoming season. A number of Bennettsville 230 kV Transmission Lines (TL) and upgrades are expected to be completed by the summer of 2008 on the Progress Energy Carolinas system. A new 230 kV interconnection with SCPSA at the Bennettsville Substation will be a part of this construction to Bennettsville, SC. Other 230 kV lines (Cross-Aiken 230 kV TL, Cross-Carnes Crossroads 230 kV TL rating upgrade, and the Cross-Jefferies 230 kV TL rating upgrade) are expected to be completed by the upcoming season as well. Reliability Assessment Analysis - The projected capacity margin in the sub-region is 17.5%, compared to 13.1% last summer. Capacity in the sub-region should be adequate to supply forecast demand. Members within this sub-region do not have an established target margin level to benchmark margins. To assess resource adequacy, some members have conducted studies for the upcoming summer and have determined that LOLP, LOLE and EUE figures are comparable to those for the previous summer. These studies may include estimates of the impacts of forced and planned outages on the system operation. Other members use reserve margins to account for worse-case scenarios with unavailability. However, members have reported that there are no significant changes from last year’s assessment that will impact reliability. To ensure generation deliverability, some members use deliverability load test as a requirement for new generation that will serve load in their system. These tests ensure that all new generation is accessible for the supply of load. Other members within the sub-region rely on contracts for fuel and transportation, operating limits and security constraints to ensure their deliverability. Fuel supplies are expected to be adequate for the upcoming season. Members have a very diverse mix of suppliers, transportation contracts, fuel switching plants and on-site storage to ensure adequacy of fuel supply. No fuel supply or delivery issues are expected for this summer. Members within the VACAR sub-region are involved in studies performed by SERC Study Groups and interregional reliability assessments conducted under the direction of the ERAG Management Committee. These studies analyze transfer capability problems and constraints throughout the sub-region. No constraints to the bulk electric system for the 2008 summer season has been identified that could impact reliability. The VACAR sub-region does not have a sub-regional criterion for dynamics, voltage and small signal stability. Various companies within the sub-region perform individual studies in accordance with NERC Reliability Standards and maintain individual criterion to address any problems with these stability issues. The sub- region does not predict any stability issues that will impact 2008 summers season reliability. Region Description The SERC Region is a summer peaking region covering all or portions of 16 central and southeastern states. Owners, operators, and users of the bulk power system in these states cover an area of approximately 560,000 square miles. The SERC Reliability Corporation (SERC) is the regional entity for the region and is a nonprofit corporation responsible for promoting and improving the reliability, adequacy, and critical infrastructure of the bulk power supply system. SERC membership includes 63 member entities consisting of publicly owned (federal, municipal and cooperative), investor owned operations. In the SERC Region there are 31 balancing authorities and over 200 registered entities under the NERC functional model. Page 110 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments SERC serves as a regional entity with delegated authority from NERC for the purpose of proposing and enforcing reliability standards within the SERC Region. SERC is divided geographically into five sub-regions that are identified as Central, Delta, Gateway, Southeastern, and VACAR. Additional information can be found on the SERC Web site (www.serc1.org). Page 111 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments SPP 2008 Projected Peak Demand MW Relative Capacity by Fuel Mix Total Internal Demand 43,571 Direct Control Load Management 36 Dual Fuel 6% Contractually Interruptible (Curtailable) 487 Critical Peak-Pricing with Control 35 Load as a Capacity Resource 187 Net Internal Demand 42,827 Coal 39% MW Change 2007 Actual Summer Peak Demand 43,165 -0.8% Gas 40% All-Time Summer Peak Demand 43,165 -0.8% Hydro 4% 2008 Projected Capacity MW Margin Existing Certain and Net Firm Transactions 48,993 12.6% Nuclear 2% Oil 2% Net Capacity Resources 58,096 26.3% Pumped Storage 0.7% Undeter- Total Potential Resources 59,379 27.9% Wind 0.5% Other 1.9% mined 3% Introduction Based on the evaluated contingency events and taking into consideration transmission operating directives, Southwest Power Pool is not expecting any reliability issues for the upcoming summer. The resources available for the region are adequate to meet the expected peak demand. Demand The non-coincident total internal demand forecast for the upcoming summer peak is 43,571 MW, which is 1% higher than the 2007 actual summer peak monthly non-coincident total internal demand of 43,167 MW. The actual 2007 summer demand of 43,165 was 0.4% higher than the 43,007 summer forecasted projection for 2007. Last year, SPP experienced a slight increase in demand from the normal forecast due to higher temperatures in the summer and the modest load growth throughout the SPP footprint. Although actual demand is very dependent upon weather conditions and typically includes interruptible loads, forecasted net internal demands are based on 10 year average summer weather, or 50/50 weather. This means that the actual weather on the peak summer day is expected to have a 50% likelihood of being hotter and a 50% likelihood of being cooler than the weather assumed in deriving the load forecast. SPP does not anticipate 90/10 weather scenario this year but has a 12% capacity margin requirement to address this. Forecast data is collected from individual reporting members as monthly non-coincident values and then summed up to produce the total forecast for SPP. Each SPP member also provides their demand response programs and then subtracts those values from their load forecasts to report the net load forecast. Based on the SPP member inputs, currently 487 MW of interruptible demand, 36 MW of load management, 35 MW of critical peak pricing and 187 MW of load as a capacity resource are reported. Page 112 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments Generation SPP expects to have 58,141 MW of total internal capacity for the upcoming summer season. This consists of Existing Certain Capacity of 47,754 MW, Existing Uncertain Capacity of 9,271 MW, and Planned Capacity of 1,116 MW The expected on peak capacity from the variable generation plant (predominantly wind) is 169 MW. SPP do not have any biomass-fueled generation reported at this time. The hydro capacity within SPP region represents a small fraction of the total resources (Approximately 1%). 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. There are no anticipated issues concerning the reservoir levels being sufficient enough to meet the peak and daily energy demands during the summer season. The SPP region is experiencing normal rainfall and is not expected to experience drought like conditions during the summer season that would that would prevent the region from meeting their capacity needs. Purchases and Sales SPP has a total of 2,789 MW of projected purchases of which 2,684 MW is firm and 105 MW is firm delivery service from WECC administered under Xcel Energy’s OATT. None of the purchase contracts are Liquidated Damage Contracts. SPP has a total of 1,550 MW of firm sales, and 145 MW of non-firm sales for the 2008 summer by regions external to SPP. None of the sales contracts are Liquidated Damage Contracts. SPP 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. The SPP’s Operating Reliability Working Group will set the Minimum Daily Contingency Reserve Requirement for the SPP Reserve Sharing Group. The SPP Reserve Sharing Group will maintain a minimum first Contingency Reserve equal to the generating capacity of the largest unit scheduled to be on-line. Fuel All fuel supplies throughout the summer are expected to be adequate. 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. Predicting and managing the energy output from intermittent resources like run-of-river hydro and wind farms are more challenging. Wind resources are not expected to provide a significant portion of the region’s capacity during the upcoming peak load conditions. Although dispatched to serve during high peak periods, hydro capacity represents a small fraction of the total resources (Approximately 1% of total MW sources) in SPP. Regarding adequacy, the coal supply of the Powder River Basin (PRB) is not considered to be a high-risk issue by SPP members at this time. Natural gas sources are abundant in the SPP region and are not considered to be at high risk regarding supply adequacy or security. Transmission American Electric Power West (AEPW) is scheduled to complete the installation of the new 14- mile 345 kV line from Chamber Springs to Tontitown expected to be in service in June 2008. Page 113 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments This will improve reliability in the Northwest Arkansas are by providing an additional EHV source into the area. Operational Issues There are no scheduled maintenance outages of operational concern within the SPP region that will impact reliability during the summer months. The SPP operations staff does not anticipate any environmental and/or regulatory restrictions that could potentially impact reliability. As a result of Flowgate assessment analysis, there are no unusual operating conditions expected for the upcoming summer months. Reliability Assessment Analysis Currently, a SPP criterion requires that its members maintain a minimum capacity margin of 12%, unless their system is primarily hydro-based and then the required minimum capacity margin is 9%. This is adequate to cover a 90/10 weather scenario. The SPP capacity margin based on certain resources is expected to be 14.1% for 2008 summer, which is slightly lower than the 2007 margin of 15.7%. On a total potential resources basis, SPP has sustained around a 26.4% capacity margin The total amount of external resources that were used by SPP to meet its criteria for the 2007 and upcoming 2008 summer is 2,789 MW of firm purchases. SPP is currently performing Loss-of-Load Expectation and Expected Unserved Energy studies. The preliminary results of these studies are expected in early Summer 2008. Historically, SPP has adhered to a 12% regional capacity margin to ensure the minimum LOLE of 1 day in 10 years is met. Presently the 12% capacity margin requirement is checked annually in the EIA-411 reporting as well as through supply adequacy audits of regional members. The last supply adequacy audit was conducted in 2007. SPP defines firm deliverability as electric power intended to be continuously available to the buyer even under adverse conditions; i.e., power for which the seller assumes the obligation to provide capacity (including SPP defined capacity margin) and energy. Such power must meet standards of reliability and availability as that delivered to native load customers. Power purchased can be considered to be firm power only if firm transmission service is in place to the load serving member for delivery of such power. SPP does not include financial firm contracts towards this category There are no significant deliverability problems expected due to transmission limitation at this time, SPP will continue to closely monitor the issue of deliverability through the Flowgate assessment analysis in the Spring 2008 and address any reliability constraints. This analysis validates the list of flowgates that SPP monitors on a short term basis using various scenario models developed by the SPP Staff. These scenario models reflect all the potential transactions in various directions being requested on SPP system. The results of this study are reviewed and approved by SPP’s Transmission Working Group prior to summer. Although this study is not completed yet, SPP is not expecting significant constraints in the upcoming summer operating conditions. Page 114 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments Due to the diverse generation portfolio in SPP, there is no concern of the fuel supply being affected by the extremes of summer weather during peak conditions. If there is to be a fuel shortage, it is communicated to SPP operations staff, in advance, so that they can take the appropriate measures SPP would assess if capacity or reserves would become insufficient due to the unavailable generation. If so, we would declare either EEA (Energy Emergency Alert) or OEC (Other Extreme Contingency) and post as needed on the RCIS (Reliability Coordinator Information System). As a part of the interregional transmission transfer capability study, SPP participates in the ERAG seasonal study group (MRO-RFC-SERC West and SPP) which produces an upcoming summer, and winter operating condition transfer limitation forecast. Simultaneous transfers are also performed as part of this study. The preliminary results of this study will be available in late spring. SPP develops an annual SPP Transmission Expansion Plan (STEP) with regional group of projects to address system reliability needs for the next 10 years (2008 through 2017). The latest STEP that was approved by SPP Board Of Directors is available on SPP website70. During the STEP process, SPP also performs a dynamic stability analysis. The latest dynamic study that was completed for the 2008 operating conditions did not indicate any dynamic stability issues for the SPP region. In addition, SPP also performs an annual review of reactive reserve requirements for load pockets within the region. Currently, SPP does not have specific criteria for maintaining minimum dynamic reactive requirement or transient voltage dip criteria. However, according to reactive requirement study scope, which is completed as a STEP process each load pocket or constrained area was studied to verify sufficient reactive reserves are available to cover the loss of the largest unit. The annual STEP process conducted by SPP did not indicate dynamic and static reactive power limited areas on the bulk power system. . SPP has an under-voltage load shedding (UVLS) program in the western Arkansas area within AEP-West footprint. This program targets about 180 MW of load shed during the peak summer conditions to protect bulk power system against under-voltage events. SPP does not conduct operation planning study to evaluate the extreme hot weather condition. The current capacity margin criteria are intended to address the load forecast uncertainty. Other Region-Specific Issues SPP continues to see a surge in wind development in the western part (Oklahoma, Texas Panhandle, and Western Kansas) of its system. Because wind–generated capacity is currently such a small fraction, less than 1 percent, of the total SPP capacity, wind farm operational issues is not expected to affect reliability for the upcoming summer. Should the capacity grow to a significant amount, near the capacity reserve margin, additional criteria, such as that requiring voltage support, will be added to handle issues native to unstable wind farm operations. 70 http://www.spp.org/publications/2007%20SPP%20Transmission%20Expansion%20Plan%2020080131_BOD_Public.pdf Page 115 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments Region Description Southwest Power Pool (SPP) region covers a geographic area of 255,000 square miles and has members in eight states: Arkansas, Kansas, Louisiana, Mississippi, Missouri, New Mexico, Oklahoma, and Texas. SPP manages transmission in seven of those states. SPP’s footprint includes 17 balancing authorities and 52,301 miles of transmission lines. SPP has 49 members that serve over 4.5 million customers. SPP’s membership consists of 13 investor–owned utilities, 11 generation and transmission cooperatives, 11 power marketers, 7 municipal systems, 3 independent power producers, 2 state authorities, and 2 independent transmission companies. Additional information can be found on the SPP Web site (www.spp.org). Page 116 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments WECC 2008 Projected Peak Demand MW Relative Capacity by Fuel Mix Total Internal Demand 162,052 Direct Control Load Management 3,053 Contractually Interruptible (Curtailable) 1,054 Dual Fuel Coal 18% 14% Critical Peak-Pricing with Control 0 Load as a Capacity Resource 0 Net Internal Demand 157,945 MW Change 2007 Actual Summer Peak Demand 157,526 0.3% Gas 29% All-Time Summer Peak Demand 161,131 -2.0% Hydro 29% 2008 Projected Capacity MW Margin Oil 0.4% Existing Certain and Net Firm Transactions 189,829 16.8% Geothermal Net Capacity Resources 196,956 19.8% Nuclear 5% 1.3% Total Potential Resources Pumped 213,507 26.0% Other 1.3% Storage 2% Wind 0.5% Demand The aggregate WECC 2008 summer total internal demand is forecast to be 162,052 MW (U.S. systems 142,032 MW, Canadian systems 17,797 MW, and Mexican system 2,223 MW). The forecast is based on normal weather conditions and is 2.9 percent above last summer’s actual peak demand, which was established under normal to somewhat above normal temperatures in the region. The 2008 summer total internal demand forecast is 3.2 percent greater than last summer’s forecast peak demand of 156,988 MW for the 2007 summer period. The internal demand forecast includes 3,053 MW of direct control demand-side management capability and 1,054 MW of interruptible demand capability. The 2008 summer period direct control load management and interruptible demand capability has increased by about 560 MW compared to last year. The direct control demand-side management capability is located mostly in California. The interruptible demand capability includes industrial interruptible demand and water pumping demand. The peak demand forecasts are non-coincident sums of balancing authority forecasts and are consistent with the balancing authority actual-year hourly demand data. Comparisons with hourly demand data indicate that the WECC non-coincident peak demands generally exceed coincident peak demands by two to four percent. WECC has not established a quantitative analyses process for assessing the variability in projected demand due to the economy. However, balancing authority forecast processes generally include assumptions regarding economic conditions but those assumptions may not fully reflect current economic expectations due to the inherent lag between forecast preparation dates and the assessment publication date. WECC has not published a weather sensitivity analyses for the 2008 summer peak period. Page 117 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments Generation WECC has not established an interconnection-wide process to address the issue of planning for variability in resource availability due to fuel and other conditions. The gross hydroelectric resource capability used for this assessment is approximately 63,662 MW with an associated de- rate (existing uncertain) amount that is roughly 6,890 MW to reflect river flow limitations and other factors leaving approximately 56,772 MW available for peak periods (existing certain). There is 6,918 MW of installed wind capability, of which only 1,205 MW is considered existing certain capacity after it has been reduced by about 5,713 MW to reflect expected available capability during the peak summer period. WECC’s biomass capacity is 239 MW, of which 236 MW is considered existing certain. There could be an additional 133 MW of peak planned wind generation after a reduction of approximately 789 MW. Transmission limitations that restrict generator access to the power grid are largely associated with wind farm interconnections. These limitations, however, do not exceed the wind derates referenced above. Transmission limitations for other generation sources are reported at 4 MW. WECC is not experiencing a drought and does not expect significant adverse hydroelectric generation conditions during the 2008 summer period. Purchases and Sales on Peak Net firm imports at time of peak are 467 MW, composed of 614 MW of gross imports and 147 MW of gross exports. The gross imports are scheduled across three back-to-back DC ties with SPP and four of the five back-to-back DC ties with MRO. The gross exports are scheduled across the back-to-back DC ties with MRO. WECC’s summer assessment forecasted net capacity resources include only firm capacity commitments. Fuel WECC has not implemented a formal fuel supply interruption analysis method. Historically, coal-fired plants have been built at or near their fuel source and generally have long-term fuel contracts with the mine operators, or actually own the mines. Gas-fired plants were historically located near major load centers and relied on relatively abundant western gas supplies. Some of the older gas-fired generators in the region have backup fuel capability and normally carry an inventory of backup fuel, but WECC does not require verification of the operability of the backup fuel systems and does not track onsite backup fuel inventories. Most of the newer generators are strictly gas-fired plants, increasing the region’s exposure to interruptions to that fuel source. A survey of major power plant operators indicates that their natural gas supplies largely come from the San Juan and Permian Basins in western Texas, from gas fields in the Rocky Mountains, and from the Sedimentary Basin of western Canada. It is not expected that extremes of summer weather during peak load conditions would have any impact on the fuel supply infrastructure and Powder River coal deliveries are not expected to be an issue. Dual-fuel capability is not a significant issue within the Western Interconnection. Only a nominal amount of generation outside of the Southwest has dual fuel capability and almost all of the Southwest dual-fueled plants are subject to severe air emission limitations that make alternate fuel use prohibitive for anything other than very short term emergency conditions. Page 118 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments Transmission WECC and regional entities have several processes in place that relate to generation deliverability. For example, 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.71 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. Major power grid 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 to reflect deliverability constraints identified by transfer capability studies, interconnection agreement studies, etc. The southern California area imports significant amounts of power and it is expected that the transmission into that area of the Western Interconnection will be used much of the time. As in the past; any unplanned major transmission, generation outages or extreme temperatures may cause resource constraints in the southern California area. The transmission system is considered adequate for all projected firm transactions and significant amounts of economy energy transfers. Reactive reserve margins are expected to be adequate for all expected peak load conditions in all areas. Close attention to maintaining appropriate voltage levels is expected to prevent voltage problems. While WECC has eight back-to-back direct current ties to the Eastern Interconnection with a combined transfer capability of almost 1,500 MW, only about 470 MW of net capacity imports are planned for the 2008 summer period. The net non-simultaneous capacity imports for the 2007 summer period were about 690 MW. It has been reported that the capacity imports have firm resource and associated firm transmission commitments. 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 generation and transmission projects that may impact the interconnected system. These processes identify potential deliverability issues that may result in actions such as the implementation of system protection schemes designed to ensure deliverability and to mitigate possible adverse power system conditions. Transmission Facilities Transmission projects for all of WECC’s subregions that have been installed during the time from October 2007 – February 2008 or that are projected to come on line during the time period of March 2008 – September 2008 are indicated in the tables at the back of WECC’s section. Operational Issues The WECC region is spread over a wide geographic area with significant distances between load and generation areas. In addition, the northern portion of the region is winter peaking while the southern portion of the region is summer peaking. Consequently, systems within the Western Interconnection may seasonally exchange very significant amounts of electric power but 71 http://www.wecc.biz/modules.php?op=modload&name=Downloads&file=index&req=viewdownload&cid=8 Page 119 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments transmission constraints between the subregions are a significant factor affecting economic utilization of surplus power. Due to the inter-subregion transmission constraints, reliability in the Western Interconnection is best examined at a subregional level. WECC does not expect major generating unit outages, transmission facility outages, or unusual operating conditions that would adversely impact reliable operations this summer. No environmental or regulatory restrictions have been reported that are expected to adversely impact reliability. Other Items The Northwest Power Pool72 and California ISO73 have publicly available document on their websites that address 2008 summer conditions. Reliability Assessment Analysis WECC prepares an annual power supply assessment74 of generation resource capacity margins for the summer and winter peak hours over a 10-year planning horizon. The intent of the assessment is to identify subregions within the Western Interconnection that have the potential for electricity supply shortages based on reported demand, resource, and transmission data. For the peak summer month of July, WECC expects a capacity margin of 19.8 percent, which corresponds to a 24.7 percent reserve margin. WECC’s capacity margin last summer was 17.4 percent. The forecast margin of approximately 38,300 MW significantly exceeds WECC’s power supply assessment planning margin of about 23,900 MW. Subregions Northwest Power Pool (NWPP) Area The Northwest Power Pool (NWPP) is a winter peaking area. The 2008 summer peak total demand forecast of 55,922 MW is 0.3 percent greater than last summer’s actual peak demand of 55,737 MW and is 4.6 percent greater than last summer’s forecast peak demand of 53,479 MW. Last summer’s peak demand was higher than expected due to warmer temperatures. The forecast peak demand includes 347 MW of interruptible demand and load management capability. The subregion’s combined (Canadian and United States portion) projected capacity margin for their summer peak month (July) is 29.0 percent which equates to a 40.9 percent reserve margin. Resources — Over 60% of the Power Pool resource capability is from hydro generation. In addition, generation is produced from conventional thermal plants and miscellaneous resources, such as non-utility owned gas-fired cogeneration or wind. Under normal weather conditions, the Power Pool area does not anticipate dependence on imports from external areas during summer peak demand periods. Hydro Capability — Northwest power planning is done by sub-area. Idaho, Nevada, Wyoming, Utah, British Columbia and Alberta individually optimize their resources to their demand. The Coordinated System (Oregon, Washington and western Montana) coordinates the operation of its 72 http://www.nwpp.org/publications.html 73 http://www.caiso.com/docs/2003/04/25/200304251132276595.html 74 http://www.wecc.biz/modules.php?op=modload&name=Downloads&file=index&req=viewsdownload&sid=56 Page 120 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments 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. The 2008 March early bird forecast for the January through July Columbia River flows at The Dalles, Oregon is 103 million acre-feet, or 96 percent of the thirty-year average. Last year, the Coordinated System hydro reservoir refilled to approximately 94 percent by July 31. The water fueling 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, as well as special river operations for recreation, irrigation, navigation, and the refilling of the 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 2008 summer must be effective and efficient. The goal is to manage all the competing requirements while refilling the reservoirs to the highest extent possible. Sustainable Hydro Capability — Operators of the hydro facilities optimize the use of available water throughout the year while assuring all the competing purposes are evaluated. Although available capacity margin at time of peak can be calculated to be greater than 20%, this can be misleading. Since hydro can be limited due to conditions (either lack of water or imposed restrictions), the expected sustainable capacity must be determined before establishing a representative capacity 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 upon the availability of water for hydro-electric generation. The Power Pool has developed the expected 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 at least 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 relative to the Northwest in the winter: however, under summer extreme low water conditions, it impacts summer conditions. Thermal Generation — 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. Transmission — Constrained paths within the Power Pool area are known and operating studies modeling these constraints have been performed and operating procedures have been developed to assure safe and reliable operations. Page 121 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments The Northwest Operational Planning Study Group (NOPSG) coordinates seasonal inter-area and intra-area transmission transfer capability studies. Daily studies to determine transfer capabilities during planned outage conditions are coordinated by the operators of the individual operating paths. Operations — Balancing Authorities within the Power Pool use a fully automated system of sharing resources, when requested, to meet the NERC Disturbance Control Standard for loss of generation in the Pool area. The system has the ability to automatically move generation over a 2-Province, 7-State area while taking into consideration transmission constraints within the area. This system assures adequate resources are available over a broad area; an adequate response is delivered within the prescribed time; and the impact of the disturbance to internal as well as neighboring systems is mitigated. The Northwest 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 (ER) Response Process to address immediate power emergencies. The ER Team (ERT) remains in place and would be used in the event of an immediate emergency. The ERT 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 Power Pool. In view of the present overall power conditions, including the forecasted water condition, the area represented by the Power Pool is estimating that it will be able to meet firm loads including the required reserve. Should any resources be lost to the area beyond the required forced outage reserve margin and or loads are greater than expected as a result of extreme weather, the Power Pool area may have to look to alternatives which may include emergency measures to meet obligations. California–Mexico Power Area This is a summer-peaking area. The 2008 summer peak demand forecast of 62,691 MW75 is 0.3 percent greater than last summer’s actual peak demand of 62,508 MW and is 1.6 percent greater than last summer’s forecast peak demand of 61,687 MW. The areas’ 2007 summer peak demand occurred during a period of generally normal to slightly warmer than normal temperatures. The forecast peak demand includes 2,967 MW of interruptible demand and load management. The subregion’s combined (California and Mexico) projected capacity margin for their summer peak month (August) is 13.6 percent which equates to a 15.8 percent reserve margin. The California ISO has reported that its 49,071 MW forecast peak demand could increase by about 3,000 MW under a 1-in-10 hot weather condition which could reduce the capacity margin to 9.3% if no additional purchases were procured. As noted earlier, any unplanned major 75 Details regarding the California ISO portion of the subregion’s forecast may be found at: http://www.energy.ca.gov/2007publications/CEC-200-2007-015/CEC-200-2007-015-SF2.PDF Page 122 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments transmission and/or generation outages coupled with lower import levels, or extreme temperatures coupled with lower import levels, may cause resource constraints in the southern California area. The California ISO’s April 28, 2008 summer assessment76 presents deterministic and probabilistic analyses for its portion of southern California. The assessment states that “…voluntary conservation and on-call interruptible loads could be needed more frequently than normal.” The assessment also references a 10% probability that its portion of southern California may experience reserves declining to 3%. The California ISO performed an exhaustive generation deliverability study in 2006 of all existing generation. All new generation added since that time has been demonstrated to be deliverable along with the existing generation and imports. Although several major constrained transmission paths have been upgraded in recent years, path constraints still exist. Operating procedures are in place to manage any high loading conditions that may occur during the summer. Entities within the area report having no concerns with maintaining adequate reactive reserve margins. All power plants in California are required to operate in accordance with strict air quality environmental regulations. Some plant owners have upgraded emission control equipment to remain in compliance with increasing 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 expected that environmental issues will have additional adverse impacts on resource adequacy within the area. Rocky Mountain Power Area The Rocky Mountain Power Area’s peak demand may occur in either summer or winter. The 2008 summer peak demand forecast of 12,285 MW is 3.0 percent greater than last summer’s actual peak demand of 11,931 MW and is 6.4 percent greater than last summer’s forecast peak demand of 11,547 MW. Last summer’s peak demand was higher than expected due to warmer temperatures. The forecast peak demand includes 242 MW of interruptible demand and load management capability. The projected capacity margin for the peak month (July) is 12.5 percent which equates to a 14.2 percent reserve margin. Hydro conditions for the 2008 summer period are expected to be near normal, except for the Bighorn Basin drainage area, and reservoir releases will be similar to last year. The area has experienced several years of below normal runoff on the Colorado River, causing significant draw-down at Lake Powell (behind Glen Canyon dam). However, current run off forecasts are favorable and Lake Powell is expected to partially refill with a fifty-foot increase in reservoir elevation. The Glen Canyon power plant is operating under environmental impact restrictions that limit water releases. The release limitations reduce peaking capability by about 450 MW, but under normal hydro conditions the plant is able to respond to short-term emergency conditions. The transmission system is expected to be adequate for all firm transfers and most economy energy transfers. Although slightly different flow patterns from past years are expected on major bulk system transmission, no significant changes in flow patterns are expected. The transmission 76 http://www.caiso.com/docs/2003/04/25/200304251132276595.html Page 123 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments path between southeastern Wyoming and Colorado often becomes heavily loaded, as do the transmission interconnections to Utah and New Mexico. Consequently, the WECC Unscheduled Flow Mitigation Procedure may be invoked on occasion to provide line loading relief for these paths. Arizona-New Mexico-Southern Nevada Power Area This is a summer-peaking area. The 2008 summer peak demand forecast of 31,551 MW is 3.0 percent above last summer’s actual peak demand of 30,642 MW and is 4.0 percent greater than last summer’s forecast peak demand of 30,338 MW. Last summer’s peak demand was slightly higher than expected due to slightly higher temperatures. The forecast for the area includes 555 MW of load management and interruptible demand capability. The projected capacity margin for the peak month (July) is 14.4 percent which equates to a 16.8 percent reserve margin, excluding four megawatts of transmission limited resources. 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 system will be used to help control unscheduled flows. Reactive reserve margins have been studied and are expected to be adequate throughout the area. Fuel supplies are expected to be adequate to meet summer peak demand conditions. The physical gas commodity and pipelines that supply this area have proven very reliable. In addition, firm coal supply and transportation contracts are in place, and sufficient coal inventories are anticipated for the summer season. Page 124 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments WECC Scheduled Transmission Facility Additions, Retirements, and Re-ratings Additions and Upgrades (230 kV and Above) October 2007 through February 2008 Control Type of Expected Actual Length Capacity Voltage Area or Facility Change Operating Operating (Miles) (MVA) (kV) Company (Action) Date Date CA/MX Metcalf-Hicks Varona (previously as Monta In- PG&E Vista) #1 and #2 230 27 1714 230 12 2007 10 2007 Service kV Reconductoring (T-647A) Tracy-Westley 230 kV In- TID/MID 0.1 650 230 11 2007 02 2008 Line Service Westley 230 kV 2000 In- TID/MID N/A 230 11 2007 02 2008 Substation - Breakers AMPS Service NWPP John Day Substation 500/ In- BPA N/A 1300 10 2007 - Transformer 230 Service Rock Creek 500/ In- BPA Substation - N/A 1300 10 2007 230 Service Transformer Benewah ID to In- AVA 60 797 230 12 2006 11 2007 Shawnee WA Service A. A. Lambert - In- FBC N/A 90 230 12 2006 12 2007 Transformer Service Evander Andrews In- IPC 6 550 230 01 2008 Generation- Service Evander Andrews In- IPC Generation- Step-up N/A 230 230 01 2008 Service Station Evander Andrews 230/ In- IPC Generation – Auto- N/A 300 01 2008 138 Service Transformer RMPA Peetz Logan-Pawnee In- PSCo 70 800 230 3Q 2007 10 2007 230kV Line Service Denver Terminal – In- PSCo 7 495 230 05 2007 11 2007 Arapahoe Service Cedar Creek- In- PSCo Keenesburg 230kV 72 414 230 4Q 2007 12 2007 Service Line Page 125 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments Initial Service, Retirement, or Re-rating (230 kV and Above) March 2008 through September 2008 Projected Control Area Length Capacity Voltage Type of Facility Operating or Company (Miles) (MVA) (kV) Change Date AZ/NM/SNV KS 230 kV line Loop IID 5 150 230 05 2008 into Ave 42 Southeast Valley SRP 51 1405 500 06 2008 Project Pinal West TEP 1 925 345 06 2008 Interconnection Diamond – Mead 230 Can- VEA 44 640 230 06 2008 kV # 2 celled Capacitors (Navajo – 136 APS N/A 500 05 2008 Crystal 500 kV line) MVAr Palo Verde – Pinal SRP N/A 800 500 05 2008 West Project Palo Verde – Pinal SRP N/A 800 345 05 2008 West Project Palo Verde – Pinal SRP West Project – N/A 800 500 05 2008 Transformer Bank Southeast Valley SRP N/A 280 230 05 2008 Project Southeast Valley SRP Project – Transformer N/A 280 230 05 2008 Bank Reactor replacement APS N/A 83 MVAr 500 06 2008 (Reactor #4) CA/MX Westley – Rosemore MID 17 650 230 06 2008 230 kV Line Westley 2nd TID N/A 167 230/115 04 2008 Transformer Lone Tree Substation PG&E N/A 45 230 05 2008 Interconnection Silvergate-New 230kV SDGE N/A 230 06 2008 Substation Page 126 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments Control Area / Length Capacity Voltage Type of Projected Facility Company (Miles) (MVA) (kV) Change Op. Date NWPP Caribou Sub: 345kV 1 PAC 1396 345 06 2008 line loop-in Three Peaks Sub: 1 PAC 1163 345 06 2008 345kV line loop-in East Tracy – Emma 20 SPR 1076 345 08 2008 345 kV Line Rocky Ford 230/115 GCPUD kV auto-transformer N/A 230/115 05 2008 project Brownlee East 182 IPC N/A 230 05 2008 Capacity Increase MVAr IPC Mora Substation N/A 300 230/138 05 2008 Copperfield – IPC N/A 1200 A 230 06 2008 Capacitors Brownlee East IPC N/A 75 MVAr 230 06 2008 Capacity Increase Mill Creek Phase NWMT N/A 350 230 06 2008 Shifter TOT 4AVoltage PAC Support Project - N/A 30 MVAr 230 06 2008 Riverton TOT 4AVoltage PAC Support Project - N/A 25 MVAr 230 06 2008 Latham Edmonton Area 110 AESO N/A 240 DC 06 2008 Capacitor Banks MVAr Edmonton Area 110 AESO N/A 240 DC 06 2008 Capacitor Banks MVAr Edmonton Area AESO N/A 30 MVAr 240 DC 06 2008 Capacitor Banks Edmonton Area AESO N/A 36 MVAr 240 DC 06 2008 Capacitor Banks Edmonton Area AESO N/A 54 MVAr 240 DC 06 2008 Capacitor Banks TOT 4A Voltage PAC Support Project - N/A 15 MVAr 230 06 2008 Atlantic City RMPA Chambers 230/115 kV Interconnection Project N/A 280 230 05 2008 – Substation & Autotrans. Page 127 NERC 2008 Summer Reliability Assessment Regional Reliability Self-Assessments Regional Description WECC’s 209 members, including 35 balancing authorities, represent the entire spectrum of organizations with an interest in the bulk power system. Serving an area of nearly 1.8 million square miles and 71 million people, it is the largest and most diverse of the eight NERC regional reliability organizations. Additional information regarding WECC can be found on its Web site (www.wecc.biz). Page 128 NERC 2008 Summer Reliability Assessment Abbreviations Used in This Report Abbreviations Used in This Report AZ-NM-SNV Arizona-New Mexico-Southern Nevada (Subregion of WECC) CA-MX-US California-Mexico (Subregion of WECC) dc Direct Current DOE U.S. Department of Energy EECP Emergency Electric Curtailment Plan ERO Electric Reliability Organization ERCOT Electric Reliability Council of Texas FERC U.S. Federal Energy Regulatory Commission FRCC Florida Reliability Coordinating Council GHG Greenhouse Gas GRSP Generation Reserve Sharing Pool GTA Greater Toronto Area GWh Gigawatthours ICAP Installed Capacity IESO Independent Electric System Operator (in Ontario) IROL Interconnection Reliability Operating Limit ISO Independent System Operator ISO-NE New England Independent System Operator kV Kilovolts (one thousand volts) LFU Load Forecast Uncertainty LNG Liquefied Natural Gas LOLE Loss of Load Expectation LSE Load-serving Entities LTRA Long-Term Reliability Assessment MAPP Mid-Continent Area Power Pool MISO Midwest Independent Transmission System Operator MRO Midwest Reliability Organization MVA Megavoltamperes Mvar Megavars MW Megawatts (millions of watts) NERC North American Electric Reliability Corporation NIETC National Interest Electric Transmission Corridor NPCC Northeast Power Coordinating Council NWPP Northwest Power Pool Area (subregion of WECC) NYISO New York Independent System Operator OVEC Ohio Valley Electric Corporation PAR Phase Angle Regulators PC NERC Planning Committee PJM PJM Interconnection PRB Powder River Basin PRSG Planned Reserve Sharing Group Page 129 NERC 2008 Summer Reliability Assessment Abbreviations Used in This Report RAS Reliability Assessment Subcommittee of NERC Planning Committee RCC Reliability Coordinating Committee RFC ReliabilityFirst Corporation RFP Request For Proposal RMPA Rocky Mountain Power Area (subregion of WECC) RMR Reliability Must Run RRS Reliability Review Subcommittee RTO Regional Transmission Organization SCR Special Case Resources SERC SERC Reliability Corporation SOL System Operating Limit SPP Southwest Power Pool SPS Special Protection System TRE Texas Regional Entity THI Temperature Humidity Index TLR Transmission Loading Relief TVA Tennessee Valley Authority VACAR Virginia and Carolinas (subregion of SERC) WECC Western Electricity Coordinating Council Page 130 NERC 2008 Summer Reliability Assessment Capacity & Demand Definitions in this Report Capacity & Demand Definitions in this Report Capacity Categories Existing a. Certain — Existing resources reasonably anticipated to be available to operate and deliver power to or into the region. b. Uncertain — Includes mothballed generation and portions of intermittent generation not included in “Certain” Planned — This category includes generation that has achieved one or more of these milestones: a. Construction has started b. Regulatory permits approved • Site permit • Construction permit • Environmental permit c. Approved by corporate or appropriate senior management i. Included in a capital budget ii. BOD approved Announced/Proposed — This category includes generation that is not in a prior listed category, but has been identified through one or more of the following sources: a. Corporate or appropriate senior management announcement b. Included in integrated resource plan c. Generator Interconnection Queues Bulk Power System Transactions Capacity Purchases and Sales – the following categories may be applied to existing and future capacity calculations. Purchases are negative values, sales are positive values. Each interregional purchase/sale should be reported. a) Firm – contract signed b) Non-Firm – contract signed c) Expected – no contract executed, but in negotiation, projected, or other. d) Provisional – transactions under study, but negotiations have not begun. Demand Internal Demand: Is the sum of the metered (net) outputs of all generators within the system and the metered line flows into the system, less the metered line flows out of the system. The demands for station service or auxiliary needs (such as fan motors, pump motors, and other equipment essential to the operation of the generating units) are not included. Internal Demand includes adjustments for all non-dispatchable demand response programs (such as Time-of-Use, Critical Peak Pricing, Real Time Pricing and System Peak Response Transmission Tariffs) and some dispatchable demand response (such as Demand Bidding and Buy-Back). Page 131 NERC 2008 Summer Reliability Assessment Capacity & Demand Definitions in this Report 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. Demand Response The figure below provides an overview of NERC’s Demand-side management categories. Demand-Side Management and NERC’s Data Collection Information about demand response categories in Phase 1 were collected for the 2008 Summer Reliability Assessment. Each of these is defined below: Demand Response: changes in electric use by demand-side resources from their normal consumption patterns in response to changes in the price of electricity, or to incentive payments designed to induce lower electricity use at times of high wholesale market prices or when system reliability is jeopardized Dispatchable: demand-side resource curtails according to instruction from a control center Controllable: dispatchable demand response, demand-side resources used to supplement generation resources resolving system and/or local capacity constraints Capacity: demand-side resource displaces or augments generation for planning and/or operating resource adequacy; penalties are assessed for nonperformance Direct Control Load Management: demand-side management that is under direct remote control of a control center. It is the magnitude of customer Page 132 NERC 2008 Summer Reliability Assessment Capacity & Demand Definitions in this Report demand that can be interrupted at the time of the Regional Council seasonal peak by direct control of the System Operator by interrupting power supply to individual appliances or equipment on customer premises. Contractually Interruptible (Curtailable): curtailment options integrated into retail tariffs that provide a rate discount or bill credit for agreeing to reduce load during system contingencies. It is the magnitude of customer demand that, in accordance with contractual arrangements, can be interrupted at the time of the Regional Council’s seasonal peak. In some instances, the demand reduction may be effected by action of the System Operator (remote tripping) after notice to the customer in accordance with contractual provisions. Critical Peak Pricing (CPP) with Control: demand-side management that combines direct remote control with a pre-specified high price for use during designated critical peak periods, triggered by system contingencies or high wholesale market prices. Load as a Capacity Resource: demand-side resources that commit to pre- specified load reductions when system contingencies arise Energy-Voluntary: demand-side resource curtails voluntarily when offered the opportunity to do so for compensation, but nonperformance is not penalized Emergency: demand-side resource curtails during system and/or local capacity constraints Ancillary: demand-side resource displaces generation deployed as operating reserves and/or regulation; penalties are assessed for nonperformance Non-Spin Reserves: demand-side resource not connected to the system but capable of serving demand within a specified time Spinning/Responsive Reserves: demand-side resources that is synchronized and ready to provide solutions for energy supply and demand imbalance within the first few minutes of an electric grid event. Regulation: demand-side resources responsive to Automatic Generation Control (AGC) to provide normal regulating margin Page 133 NERC 2008 Summer Reliability Assessment Reliability Assessment Subcommittee Reliability Assessment Subcommittee Chairman William O. Bojorquez Electric Reliability Council of Texas, Inc. (512) 248-3036 Vice President of System 2705 West Lake Drive (512) 248-6560 Fx Planning Taylor, Texas 76574 bbojorquez@ ercot.com Vice Mark J. Kuras PJM Interconnection, L.L.C. (610) 666-8924 Chairman Senior Engineer, NERC and 955 Jefferson Avenue (610) 666-4779 Fx Regional Coordination Valley Forge Corporate Center firstname.lastname@example.org Norristown, Pennsylvania 19403-2497 ERCOT Dan Woodfin Electric Reliability Council of Texas, Inc. (512) 248-3115 Director, System Planning 2705 West Lake Drive (512) 248-4235 Fx Taylor, Texas 76574 dwoodfin@ ercot.com FRCC Vince Ordax Florida Reliability Coordinating Council (813) 207-7988 Transmission Planning 1408 N. Westshore Boulevard (813) 289-5646 Fx Engineer Suite 1002 email@example.com Tampa, Florida 33607-4512 MRO Hoa Nguyen Montana-Dakota Utilities Co. (701) 222-7656 Resource Planning 400 North Fourth Street (701) 222-7970 Fx Coordinator Bismarck, North Dakota 58501 hoa.nguyen@ mdu.com NPCC John G. Mosier, Jr. Northeast Power Coordinating Council, Inc. (212) 840-1070 AVP-System Operations 1515 Broadway (212) 302-2782 Fx 43rd Floor firstname.lastname@example.org New York, New York 10036-8901 RFC Jeffrey L. Mitchell ReliabilityFirst Corporation (330) 247-3043 Director - Engineering 320 Springside Drive (330) 456-3648 Fx Suite 300 jeff.mitchell@ Akron, Ohio 44333 rfirst.org RFC Bernard M. Pasternack, P.E. American Electric Power (614) 552-1600 Managing Director - 700 Morrison Road (614) 552-2602 Fx Transmission Asset Gahanna, Ohio 43230-8250 bmpasternack@ Management aep.com SERC Hubert C. Young South Carolina Electric & Gas Co. (803) 217-9129 Manager of Transmission 1426 Main Street (803) 933-7264 Fx Planning MC 034 Columbia, South Carolina 29201 SPP Mak Nagle Southwest Power Pool (501) 614-3564 Manager of Technical 415 North McKinley (501) 666-0376 Fx Studies & Modeling Suite 140 email@example.com Little Rock, Arkansas 72205-3020 Page 134 NERC 2008 Summer Reliability Assessment Reliability Assessment Subcommittee WECC James Leigh-Kendall Sacramento Municipal Utility District (916) 732-5357 Regulatory Compliance Mail Stop D113 (916) 732-7527 Fx Officer P.O. Box 15830 firstname.lastname@example.org Sacramento, California 95852-1830 WECC Christopher S Smart Western Electricity Coordinating Council (801) 883-6865 Staff Engineer 615 Arapeen Drive (801) 824-0129 Fx Suite 210 email@example.com Salt Lake City, Utah 84108-1262 IOU & K. R. Chakravarthi Southern Company Services, Inc. (205) 257-6125 DCWG Chair Manager, Interconnection 13N-8183 (205) 257-1040 Fx and Special Studies P.O. Box 2641 krchakra@ Birmingham, Alabama 35291 southernco.com ISO/RTO John Lawhorn, P.E. Midwest ISO, Inc. (651) 632-8479 Director, Regulatory and 1125 Energy Park Drive (651) 632-8417 Fx Economic Standards St. Paul, Minnesota 55108 jlawhorn@ Transmission Asset midwestiso.org Management ISO/RTO Peter Wong ISO New England, Inc. (413) 535-4172 Manager, Resource One Sullivan Road (413) 540-4203 Fx Adequacy Holyoke, Massachusetts 01040-2841 pwong@iso- ne.com Canadian-At- Daniel Rochester, P. Eng. Independent Electricity System Operator (905) 855-6363 Large Manager, Reliability 2635 Lakeshore Road, West (905) 403-6932 Fx Standards and Assessments Mississauga, Ontario L5J 4R9 dan.rochester@ ieso.ca FERC Sedina Eric Federal Energy Regulatory Commission (202) 502-6441 Electrical Engineer 888 First Street, NE, 91-11 (202) 219-1274 Fx Washington, D.C. 20426 sedina.eric@ ferc.gov FERC Dean Wight Federal Energy Regulatory Commission (202) 219-2675 Energy Industry Analyst , Dean.Wight@ ferc.gov DOE Patricia Hoffman Department of Energy (202) 586-1411 Acting Director Research 1000 Independence Avenue patricia.hoffman@ and Development SW 6e-069 hq.doe.gov Washington, D.C. 20045 LFWG Chair Yves Nadeau Hydro-Quebec (514) 879-6228 Manager, Load and Complexe Desjardins, Tour Est nadeau.yves@ Revenue Forecasting 25 etage -- Case postale 10000 hydro.qc.ca Montreal, Quebec H5B 1H7 Alternate Herbert Schrayshuen SERC Reliability Corporation (704) 940-8223 SERC Director Reliability 2815 Coliseum Centre Drive (315) 428 5114 Fx Assessment Charlotte, North Carolina 28217 hschrayshuen@ serc1.org Page 135 NERC 2008 Summer Reliability Assessment Reliability Assessment Subcommittee Alternate John E. Odom, Jr. Florida Reliability Coordinating Council (813) 207-7985 FRCC Manager of System 1408 N. Westshore Blvd. (813) 289-5646 Fx Planning Suite 1002 firstname.lastname@example.org Tampa, Florida 33607 Alternate Christopher Plante Wisconsin Public Service Corp. (920) 433-1290 MRO Director, Transmission 700 N. Adams Street (920) 433-1176 Fx Analysis Green Bay, Wisconsin 54307 CTPlante@ wisconsinpublicser vice.com Alternate Jeffrey L. Mitchell ReliabilityFirst Corporation (330) 247-3043 RFC Director - Engineering 320 Springside Drive (330) 456-3648 Fx Suite 300 jeff.mitchell@ Akron, Ohio 44333 rfirst.org Alternate Paul D. Kure ReliabilityFirst Corporation (330) 247-3057 RFC Senior Consultant, 320 Springside Drive (330) 456-3648 Fx Resources Suite 300 paul.kure@ Akron, Ohio 44333 rfirst.org Alternate Jay Caspary Southwest Power Pool (501) 614-3220 SPP Director, Engineering 415 North McKinley (501) 666-0376 Fx Suite 140 email@example.com Little Rock, Arkansas 72205 NERC Dave Nevius North American Electric Reliability (609) 452-8060 Senior Vice President and Corporation (609) 452-9550 Fx Director of Reliability 116-390 Village Boulevard dave.nevius@ Assessment and Princeton, New Jersey 08540-5721 nerc.net Performance Analysis NERC Kelly Ziegler North American Electric Reliability (609) 452-8060 Communications Specialist Corporation (609) 452-9550 Fx 116-390 Village Boulevard kelly.ziegler@ Princeton, New Jersey 08540-5721 nerc.net NERC Christopher Lada North American Electric Reliability (609) 452-8060 Analyst Technical Analyst Corporation (609) 452-9550 Fx 116-390 Village Boulevard chris.lada@ Princeton, New Jersey 08540-5721 nerc.net NERC Mark G. Lauby North American Electric Reliability (609) 452-8060 Coordinator Manager of Reliability Corporation (609) 452-9550 Fx Assessments 116-390 Village Boulevard mark.lauby@ Princeton, New Jersey 08540-5721 nerc.net Page 136 NERC 2008 Summer Reliability Assessment
"2008 Summer Reliability Assessment the reliability of the bulk power "