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2009/2010 Winter Reliability Assessment to ensure reliability of the the bulk power system November 2009 116-390 Village Blvd., Princeton, NJ 08540 609.452.8060 | 609.452.9550 fax www.nerc.com NERC’s Mission The North American Electric Reliability Corporation (NERC) is an international regulatory authority for reliability of the bulk power system in North America. NERC develops and enforces Reliability Standards; assesses adequacy annually via a 10-year forecast and winter and summer forecasts; monitors the bulk power system; and educates, trains, and certifies industry personnel. NERC is a self-regulatory organization, subject to oversight by the U.S. Federal Energy Regulatory Commission (FERC) and governmental authorities in Canada.1 NERC assesses and reports2 on the reliability and adequacy of the North American bulk power system divided into the eight Regional Areas as shown on the map below (See Table A).3 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, México. Table A: NERC Regional Entities 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 Note: The highlighted area between SPP and SERC NPCC WECC denotes overlapping Regional area boundaries: For Northeast Power Western Electricity example, some load serving entities participate in Coordinating Council, Inc. Coordinating Council one Region and their associated transmission owner/operators in another. 1 As of June 18, 2007, the U.S. Federal Energy Regulatory Commission (FERC) granted NERC the legal authority to enforce Reliability Standards with all U.S. users, owners, and operators of the bulk power system, and made compliance with those standards mandatory and enforceable. In Canada, NERC presently has memorandums of understanding in place with provincial authorities in Ontario, New Brunswick, Nova Scotia, Québec and Saskatchewan, and with the Canadian National Energy Board. NERC standards are mandatory and enforceable in Ontario and New Brunswick as a matter of provincial law. NERC has an agreement with Manitoba Hydro, making reliability standards mandatory for that entity, and Manitoba has recently adopted legislation setting out a framework for standards to become mandatory for users, owners, and operators in the province. In addition, NERC has been designated as the “electric reliability organization” under Alberta’s Transportation Regulation, and certain reliability standards have been approved in that jurisdiction; others are pending. NERC and NPCC have been recognized as standards setting bodies by the Régie de l’énergie of Québec, and Québec has the framework in place for reliability standards to become mandatory. Nova Scotia and British Columbia also have a framework in place for reliability standards to become mandatory and enforceable. NERC is working with the other governmental authorities in Canada to achieve equivalent recognition. 2 Readers may refer to the Reliability Concepts Used in this Report Section for more information on NERC’s reporting definitions and methods. 3 Note ERCOT and SPP are tasked with performing reliability self-assessments as they are Regional planning and operating organizations. SPP-RE (SPP – Regional Entity) and TRE (Texas Regional Entity) are functional entities to whom NERC delegates certain compliance monitoring and enforcement authorities. Page i 2009/2010 Winter Reliability Assessment Table of Contents NERC’s Mission ...........................................................................................................................i Summary Reliability Assessment of North America ...............................................................1 Key Highlights ...................................................................................................................1 Reliability Assessment ......................................................................................................2 Demand.............................................................................................................................3 Generation ........................................................................................................................5 Transmission.....................................................................................................................7 Operational Issues ............................................................................................................7 Adequate-Level of Reliability (ALR) Winter Metrics ..............................................................12 Estimated Demand, Resources, and Reserve Margins .........................................................15 Regional Reliability Assessment Highlights ..........................................................................20 Regional Reliability Self-Assessments...................................................................................25 ERCOT............................................................................................................................26 FRCC ..............................................................................................................................33 MRO................................................................................................................................39 NPCC ..............................................................................................................................52 RFC.................................................................................................................................92 SERC ............................................................................................................................113 SPP ...............................................................................................................................154 WECC ...........................................................................................................................159 About This Report...................................................................................................................177 Reliability Concepts Used in This Report.............................................................................180 Data Checking Methods Applied ...........................................................................................182 Capacity Margin to Reserve Margin Changes ......................................................................184 Terms Used in This Report ....................................................................................................185 Abbreviations Used in This Report .......................................................................................194 Reliability Assessment Subcommittee Roster.....................................................................198 North American Electric Reliability Corporation Staff Roster ............................................201 2009/2010 Winter Reliability Assessment Page ii Summary Reliability Assessment of North America Summary Reliability Assessment of North America Winter Key Highlights Economic Recession Results in Increased Projected Reserve Margins Reduced economic activity and recession impacts have led to decreased peak demand projections and, as a result, higher Reserve Margins throughout North America are projected for the upcoming winter season. While some winter peaking subregions, including Québec and the Canadian portion of WECC, are projected to come close to NERC’s reference reserve levels, all Regions and subregions appear to have sufficient resources to maintain reliability this winter. Natural Gas and Wind Generation Resources Continue to Grow Natural gas-fired generation represents over half of the capacity added since last year, growing by approximately 11,000 MW. Regions with the highest growth include SERC, NPCC, and FRCC. Wind generation also continues to increase, with 8,000 MW of installed “nameplate” capacity added since last year (1,500 MW on-peak). Just under 30,000 MW of installed wind capacity is currently interconnected to bulk power system, providing approximately 5,000 MW of on-peak capacity. Operational Challenges Are Manageable Through the Winter Overall, no operational conditions are expected to significantly impact bulk power system reliability this winter. All Regions have operational procedures and strategies to mitigate expected reliability issues that may arise. As wind resources continue to increase, new operational challenges begin to emerge. Challenges in managing the variability of wind resources as well as the need to provide additional ancillary services, such as operating reserves, remain critical to maintaining reliability. Nevertheless, accommodating the increase of wind resources appears manageable this winter. Page 1 2009/2010 Winter Reliability Assessment Summary Reliability Assessment of North America Reliability Assessment Higher Reserve Margins are projected for this winter season, when compared to last year. The differences in the projected winter planning Reserve Margin from last winter to this winter are primarily the result of the economic recession, reducing peak demand projections in a majority of the Regions. In terms of resource adequacy, all Regions and subregions appear to have sufficient reserves for meeting winter peak demands and ensuring reliability. Overall, North America’s projected Deliverable Reserve Margin4 is expected to rise from 29.3 percent forecast last year, to 32.5 percent.5 For the majority of the summer-peaking Regions within the United States, higher Reserve Margins are expected this winter than the previous winter (Figure 1a). For winter-peaking Regions and subregions in Canada, Reserve Margins appear adequate and remain above the NERC Reference Margin Level (Figure 1b).6 Reserve Margins for the Québec subregion of NPCC and the WECC-Canada subregion are 12.6 and 15.7 percent respectively, due to flat or slight increases in projected peak demands. Resources in both subregions appear to be sufficient for meeting reliability and resource adequacy requirements. Figure 1a: U.S. Winter Peak Planning Figure 1b: Canada Winter Peak Reserve Margin Projections Planning Reserve Margin Projections 80% 60% 50% 60% 40% Margin Margin 40% 30% 20% 20% 10% 0% 0% S A S es S A T C C P io c FC U C U be O U C C R SP ar im C R FR SE C C C O O ue nt it ER C C PC R R ar O Q E E M M M N W W 2008/2009 Net Reserve Margin 2008/2009 Net Reserve Margin 2009/2010 Deliverable Reserve Margin 2009/2010 Deliverable Reserve Margin NERC Reference Margin Level NERC Reference Margin Level For subregions in the United States, Reserve Margins remain high for the winter season (Figure 1c). The New York subregion of NPCC and the Gateway subregion of SERC have decreased margins when compared to last winter, but remain well above NERC Reference Margin Levels.7 Figure 1c: U.S. Subregion Winter Peak Planning Reserve Margin Projections 120% 100% 80% Margin 60% 40% 20% 0% d rk SO JM al l ta y rn R V US PP PA lan Yo MI -P ntr De wa s te CA SN X NW RM Eng w C- FC Ce ate ea VA M- -M w Ne RF R G u th -N CA Ne So AZ 2008/2009 Net Reserve Margin 2009/2010 Deliverable Reserve Margin NERC Reference Margin Level 4 See Terms Used in this Report for the Deliverable Reserve Margin definition. “Deliverable” does not refer to deliverability. 5 For the U.S., the projected 2009/2010 Deliverable Reserve Margin is 52.6 percent; for Canada, 22.2 percent. 6 See Terms Used in this Report for the NERC Reference Margin Level definition. 7 Decreases in margins for these subregions are attributed to market functions and enhancements to NERC supply definitions. 2009/2010 Winter Reliability Assessment Page 2 Summary Reliability Assessment of North America Demand Winter forecast8 peak demands across NERC Figure 2a: 2009/2010 Winter Peak Demand Regions and subregions Comparisons for Winter Peaking Subregions appear manageable for the 50,000 upcoming winter season, 40,000 with a majority of the MW 30,000 Regions showing slight decreases when compared 20,000 to last year. For the 10,000 system as a whole, winter peak demand is projected 0 NWPP US MRO CA Maritimes Quebec WECC CA to reach 706,965 MW; assuming approximately 2008/2009 Forecast 2008/2009 Actual 2009/2010 Forecast 24,500 MW of Demand Response will be available on peak.9 A key driver for the overall improvement in Reserve Margins is the substantial reduction in projected peak Net Internal Demand, representing more than a 2.5 percent decrease from last year’s projected winter peak demand. However, when comparing the winter peaking subregions, winter peak demand is only slightly reduced, by less than one percent (Figure 2a).10 Additionally, despite economic conditions affecting electricity use compared to the past year, winter-peaking subregions, with the exception of the Maritimes subregion, experienced all-time record-high peak demands last winter. Decreases in peak demand are more prominent in the summer-peaking Regions and subregions—as much as 12 percent in FRCC when compared to last winter (Figure 2b). Other notable decreases are ERCOT (eight percent), CA-MX (seven percent), and RMPA (seven percent), while NPCC-US and SPP show slight increases. While these reductions are consistent with the continued effects of the economic recession, uncertainty still remains in the coming season in terms of magnitude and duration of these reductions. Figure 2b: 2009/2010 Winter Peak Demand Comparisons for Summer Peaking Regions/Subregions 200,000 150,000 MW 100,000 50,000 0 ERCOT FRCC MRO US NPCC US RFC SERC SPP AZ-NM- CA-MX RMPA Ontario SNV 2008/2009 Forecast 2008/2009 Actual 2009/2010 Forecast 8 A 50/50 forecast is defined as a forecast adjusted to reflect normal weather, and is expected on a 50 percent probability basis, i.e. a peak demand forecast level which has a 50 percent probably of being under or over achieved by the actual peak. 9 This is a non-coincident value for all eight NERC Regions, generally occurring in the month of January 2010. 10 Winter peaking subregions include NWPP-US, MRO-Canada, Maritimes, Quebec, and WECC-Canada. Page 3 2009/2010 Winter Reliability Assessment Summary Reliability Assessment of North America Weather and temperature are key drivers affecting peak electricity demand in North America. For most of the United States, winter temperatures are projected to be either normal or warmer than normal (see Figure 3a).11 Much of the Western Interconnection is projected to experience warmer than normal weather patterns. Although temperatures may average warmer than usual, periods of colder weather are still possible. In the southeast, temperatures are expected to be colder than normal this winter. However, increased demand, as a result of colder than normal temperatures, is not expected to affect reliability. While the FRCC Region has experienced annual peak demands during some winter seasons, primarily due to residential electric heating, current economic conditions has reduced the demand forecast in the region (12 percent lower than last winter). Temperatures are forecast to be colder than normal this winter in eastern Canada, specifically in the Ontario and Maritimes subregions, and southern British Columbia (see Figure 3b). Normal temperatures are forecast in the south-central provinces of Canada. 12 Figure 3a: U.S. Winter Mean Figure 3b: Canadian Winter Mean Temperature Probability Outlook, Temperature Anomaly Outlook, December 2009 to February 2010 December 2009 to February 2010 Source: Climate Prediction Center at NOAA, 10/15/09 Source: Environment Canada, 11/1/09 A (40) – 40% to 49% chance of temperatures Red – Warmer than normal temperatures being significantly warmer* forecast when compared to the 30 A (33) – 34% to 39% chance of temperatures seasons of the 1971-2000 period. being significantly warmer* White – Normal temperatures forecast when B (33) – 34% to 39% chance of temperatures compared to the 30 seasons of the being significantly colder * 1971-2000 period. B (40) – 40% to 49% chance of temperatures being significantly colder* Blue – Colder than normal temperatures forecast when compared to the 30 EC – No significant shift is expected compared seasons of the 1971-2000 period. to normal temperatures* Another variable affecting demand forecasts is the amount of Demand Response contributing to peak demand reduction. Economic factors and regional, state, or provincial Demand Response initiatives can greatly increase or decrease the amount (i.e., capacity) of demand resources available to system operators to manage peak demand. With declining peak demand forecasts and higher projected Reserve Margins, Demand Response is expected to contribute less to meeting peak demands this winter, a reduction of about 300 MW. Demand Response programs for this winter total approximately 27,500 MW for all NERC Regions. While some Regions 11 http://www.cpc.ncep.noaa.gov/products/predictions/long_range/seasonal.php?lead=2 and http://www.noaanews.noaa.gov/stories2009/20091015_winteroutlook.html 12 For more information on Canadian temperature forecasts, including the statistical significance of the areas in the figure above, see http://www.weatheroffice.gc.ca/saisons/index_e.html. * Above normal temperatures are defined as being in the warmest 1/3 of the temperatures in the same season within the years 1971—2000. Below normal temperatures are defined as being in the coldest 1/3 of the temperatures for the same time period. 2009/2010 Winter Reliability Assessment Page 4 Summary Reliability Assessment of North America show continued growth in Demand Response (NPCC and MRO), others show a reduction (RFC, SERC, and WECC) (Figure 4). The greatest rise in Demand Response resources is observed in NPCC, where market mechanisms have encouraged significant development in Demand Response programs within both ISO New England and the New York ISO. The Demand Response program showing the highest growth is Load as a Capacity Resource.13 The reductions in Demand Response are primarily due to current economic conditions resulting in a slow-down of commercial and manufacturing sectors, thereby eliminating their demand resources and, thus, no longer available to provide demand reductions. However, current economic conditions will not affect the performance of Demand Response expected to be available this winter. Figure 4: NERC Winter Peak Capacity Demand Response 2008/2009-2009/2010 Comparison 8,000 6,000 MW 4,000 2,000 0 2008 2009 2008 2009 2008 2009 2008 2009 2008 2009 2008 2009 2008 2009 2008 2009 ERCOT FRCC MRO NPCC RFC SERC SPP WECC Direct Control Load Management Contractually Interruptible (Curtailable) Critical Peak-Pricing with Control Load as a Capacity Resource Generation The total Existing-Certain capacity for NERC this winter peak is approximately 1,043,000 MW, an increase of about 19,000 MW when compared to last winter. While the 2009/2010 winter on- peak fuel-mix remains relatively unchanged from last year, natural gas-fired generation continues to be the primary fuel firing new on-peak capacity, with growth of approximately 11,000 MW since last year. Figure 5 shows the relative on-peak capacity by fuel for all of the interconnected North American bulk power system. Figure 5: 2009/2010 Winter On-Peak Capacity Fuel-Mix Coal 29.4% Pum ped Storage Gas 2.0% 27.8% 4.1% Other Geotherm al 0.7% 0.2% Oil Undeterm ined/ 3.8% Unknow n Biom ass Wind 0.3% Hydro 0.5% Nuclear 0.4% 12.8% Dual Fuel 10.9% 11.2% 13 See http://www.nerc.com/docs/pc/drdtf/NERC_DSMTF_Report_040308.pdf . Page 5 2009/2010 Winter Reliability Assessment Summary Reliability Assessment of North America Projected winter installed nameplate14 wind capacity increased by 8,000 MW since last winter to 29,416 MW. However, the total expected on-peak capacity from these resources is 5,000 MW (Figure 6). On-peak capacity from wind plants, as a percentage of total installed capacity, ranges from zero in two NERC Regions to over 30 percent in another NERC Region during the 2009/2010 winter. Consistent methods to determine Figure 6: Projected 2009/2010 Winter on-peak wind capacity are needed Expected On-Peak Wind Capacity to ensure uniform measurement of 2,500 40% its contribution to Reserve 31.2% 35% 2,000 Margins.16 On-peak capacity values 30% MW shown by Region in Figure 6 are a 1,500 19.9% 17.7% 25% 17.6% non-coincident consolidated sum of 15.4% 20% 1,000 subregional values, which may vary 8.7% 15% widely. For example, WECC and 500 10% 5% NPCC subregions use diverse 0.0% 0.0% 0 0% policies and methods to calculate ERCOT FRCC MRO NPCC RFC SERC SPP WECC expected on-peak capacity of wind generation (i.e., Effective Load Existing Additions % of Existing Capacity Expected On-Peak Carrying Capability), with results Table 1: Winter 2009/2010 Existing Wind Resources ranging from 12.4 to 37.3 percent % of in WECC and 20.9 to 39.4 percent Nameplate On-Peak Nameplate in NPCC (see Table 1).17 Capacity Capacity Capacity Region/Subregion (MW) (MW) On-Peak Additionally, some subregions ERCOT 8,335 725 8.7% FRCC 0 0 N/A have modified their own methods MRO 6,396 1,271 19.9% for determining expected on-peak NPCC 3,686 1,161 31.2% wind capacity this winter. For NPCC-Maritimes 350 138 39.4% example, in Québec, long-term NPCC-New England 103 91 * observations and overall increased NPCC-New York 1,507 452 30.0% installed wind capacity during the NPCC-Ontario 1,084 347 32.0% last year prompted the subregion to NPCC-Québec 642 134 20.9% review derating factors for wind RFC 1,700 300 17.6% SERC 0 0 N/A generation. Their simulations have SPP 455 70 15.4% determined 20—30 percent of the WECC15 8,844 1,568 17.7% installed nameplate capacity can be WECC-AZ-NM-SNV 410 153 37.3% relied upon for meeting peak WECC-CA-MX-US 3,089 499 16.2% demand. Similar reevaluations are WECC-NWPP US 3,714 680 18.3% underway in MRO, which WECC-RMPA 1,109 137 12.4% currently uses a 20 percent flat rule. WECC-CANADA 522 69 13.2% 14 From EIA: Installed nameplate capacity “The maximum rated output of a generator under specific conditions designated by the manufacturer. Generator nameplate capacity is usually indicated in units of kilovolt-amperes (kVA) and in kilowatts (kW) on a nameplate physically attached to the generator.” http://www.eia.doe.gov/glossary/glossary_i.htm 15 The WECC expected on-peak capacity value is a coincident value for all of WECC and is not the sum of the individual WECC subregions (which would be a non-coincident value). 16 Currently, different methods are being used by Regions and subregions to determine expected on-peak values of wind capacity. The Integration of Variable Generation Task Force is addressing this issue. http://www.nerc.com/files/IVGTF_Report_041609.pdf Currently, differences exist in how existing wind capacity is seasonally rated versus how new wind will be rated under ISO- NE’s Forward Capacity Market (FCM). Existing wind capacity was self-determined and, as such, reporting was not consistent. This discrepancy is minor in magnitude and, therefore, does not significantly effect resulting ISO-NE conclusions. 2009/2010 Winter Reliability Assessment Page 6 Summary Reliability Assessment of North America Transmission Based on the self-assessments provided by the Regions, transmission facilities across the NERC Regions appear adequate for the upcoming winter season. Delays in meeting target in-service dates for transmission additions are not expected. While some Regions have identified transmission constraints, operating procedures are in place and no significant reliability impacts are expected. Additionally, line outages during the winter season are expected to have minimal impacts to the transmission system. In some Regions, significant transmission enhancements have been made to meet reliability needs since the previous winter. In ERCOT, dynamic reactive devices were installed in the Dallas area to improve voltage stability margins. Further, a new 345 kV line will reduce congestion in the area. In MRO, a number of transmission additions and upgrades are expected to be in-service by the winter, significantly enhancing reliability throughout the Region. These enhancements address both local reliability (i.e., loading issues, voltage support, and increased load serving capabilities) and the integration of new wind generation. In NPCC, the Québec subregion has commissioned two 625 MW back-to-back HVdc converters on its interconnection with Ontario, increasing import and export capability by 1,250 MW. In RFC, a Variable Frequency Transformer (VFT) was placed in-service, connecting the PJM and NYISO systems. The 300 MW VFT enables system operators to control power flows across this new tie-line between the two systems, providing enhanced stability with a high degree of reliability and flexibility, and improved controllability.18 The VFT will be the first merchant transmission project with multiple parties holding the entitlements to the new transmission capacity. Operational Issues Overall, no operational conditions are expected to significantly impact bulk system reliability. All Regions have operational procedures and strategies to mitigate expected reliability issues that may arise during the winter season. However, some issues must be continually monitored and addressed, such as generator and transmission outage coordination, constrained flowgates, and, specifically for winter seasons, reservoir water levels for hydroelectric generation. One notable new ongoing operational challenge is the integration of variable generation. Operating Reserves for Variable Generation The continued increase in variable generation, predominately wind, can increase operational challenges. As wind resources are less predictable and follow the availability of their fuel (i.e., wind) rather than demand, non-typical transmission loading can emerge. Further, some Regions report specific challenges in managing the variability and magnitude of wind resources and the need to provide additional ancillary services (such as operating reserves). Nevertheless, operation of the increases in wind resources appears to be manageable for the 2009/2010 winter. 18 For more detailed explanation of this new technology, refer to the RFC Self-Assessment: Transmission section. Page 7 2009/2010 Winter Reliability Assessment Summary Reliability Assessment of North America On an operational basis, a rapid increase or decrease of wind generation, often referred to as “ramping,” can have a significant impact on the power flowing through the bulk power system. Wind generation ramps can have an inverse correlation, or out-of-phase ramping, to daily load profiles resulting in the need for additional operating reserves. Operators may need to closely monitor the system and introduce operational resources (i.e., operating reserves) that support the variability and ancillary services needed to maintain reliability. Additionally, enhanced operational measures, in particular, redispatch of conventional generation and dynamic curtailment/dispatch of wind resources can mitigate ramping impacts. Many Regions and industry groups are actively studying wind integration needs such as accurate wind forecasting, interconnection standards, new operator tools, and protection/control systems. Some examples include: SPP – Wind Integration Task Force (WITF)19 WECC – Variable Generation Subcommittee (VGS)20 Eastern Interconnection – Eastern Wind Integration & Transmission Study (EWITS)21 NREL – Wind Systems Integration22 Furthermore, tools are being implemented in ERCOT and IESO (the independent service operator for the Ontario subregion) to improve the accuracy of wind generation forecasts. NERC will continue to monitor the operational challenges of wind integration to ensure the reliability of the bulk power system is maintained. Minimum Demand/Minimum Generation Challenges In Ontario, variable generation may present a challenge in managing the output from their baseload23 generation fleet for the day-ahead unit commitment. For example, system demand may be near the aggregate minimum output of existing conventional baseload generation. Because existing contracts allow for all energy produced by wind generation to be injected into the grid, if operators cannot find export opportunities, they may be required to shut down a quantity of baseload generation to maintain bulk power system reliability. Variable generation, however, can be curtailed for reliability reasons. During the projected peak month of December, Ontario may be susceptible to this over- generation situation, where minimum baseload levels plus additional wind capacity can exceed minimum demands (see Figure 7).24 Ontario assumes 34 percent of the installed nameplate as baseload generation based, which is a historical median during minimum demand hours. Based on weekly minimum demand projections, if wind generation exceeds 50 percent of the installed 19 http://www.spp.org/committee_detail.asp?commID=78 20 http://www.wecc.biz/committees/StandingCommittees/JGC/VGS/default.aspx 21 http://wind.nrel.gov/public/EWITS/ 22 http://www.nrel.gov/wind/systemsintegration/ 23 All nuclear generation not scheduled to be on planned outage is considered to be baseload generation. Required minimum hydro output values provided by hydro generators are aggregated to represent baseload generation contribution from hydroelectric generation. Expected contribution from wind (34 percent of installed nameplate), cogeneration and other intermittent/self-scheduling generation is based on historical contributions during minimum demand hours and are included as baseload generation. The Baseload Other line also includes a 1,000 MW decrement to account for expected exports to occur during time of minimum demand. These exports are not Firm, but based on historical minimum exports during minimum demand. 24 Figure 7 assumes both a 50 and 70 percent effective wind capacity during minimum demand periods for sensitivity purposes. 2009/2010 Winter Reliability Assessment Page 8 Summary Reliability Assessment of North America nameplate capacity during the minimum demand period, an over-generation situation is possible. However, the risk of surplus baseload generation conditions is expected to be low. The NWPP subregion in WECC has also identified this concern, but to a lesser extent. In both cases, operating procedures have been developed to mitigate any reliability concerns that may occur in real-time, including the curtailment of wind generation if excess power cannot be reliably exported. Figure 7: Ontario Minimum Baseload Generation with 50% and 70% Wind Capacity Compared to Minimum Weekly Demands 16,000 15,000 14,000 13,000 MW 12,000 11,000 10,000 9,000 8,000 k1 k2 k3 k4 k1 k2 k3 k4 k1 k2 k3 k4 bW bW bW bW W W W W W W W W n n n n ec ec ec ec Fe Fe Fe Fe Ja Ja Ja Ja D D D D 70% of Installed Wind Capacity 50% of Installed Wind Capacity Minimum Demand Minimum Baseload Other Minimum Baseload Nuclear Low Ambient Temperature Limits for Wind Generation Operating wind generation in colder climates may also limit wind generation availability. The typical minimum operating temperature of a utility-scale wind turbine generator without any special cold-weather package is -20°C, with a standstill temperature of -30°C. These issues can largely be mitigated through the addition of cold-weather packages, which include heaters, ice detectors, and low-temperature lubricants. These measures can decrease ambient temperature operating limits to -30°C, with a standstill temperature of -40°C. Colder-climate subregions are considering these upgrades. Both MRO and the NWPP subregion of WECC have identified the potential need for additional operating reserves during these extreme weather conditions. Fuel Quality and Operational Challenges Most Regions and subregions have indicated there are no reliability concerns about fuel quality at this time. However, the increased reliance on natural gas as one of the leading fuels used for both intermediate and peaking capacity has prompted NERC to evaluate and monitor reliability issues associated with natural gas fuel quality and delivery. Because this issue is predominately Region-specific, the reliability assessment of the impacts of gas composition focuses on those areas with high reliance on gas-fired generation. With an increase in Liquefied Natural Gas (LNG) imports and production of unconventional natural gas, fuel quality is an important characteristic that must be monitored to ensure reliable operation of some electric generators. Specifically, combined-cycle gas-fired units with low NOx burners can be sensitive to unanticipated, transient changes in natural gas heat content25 (+/- 5 percent Btu/cu-ft) which could trigger automatic control-action to avoid unit shutdown and 25 See http://www.beg.utexas.edu/energyecon/lng/documents/NGC_Interchangeability_Paper.pdf and http://www.ferc.gov/industries/lng/indus-act/issues/gas-qual/lng-interchangeability-rpt.pdf for more background. Page 9 2009/2010 Winter Reliability Assessment Summary Reliability Assessment of North America 26 equipment damage. In cases where a number of these units obtain their fuel from the same pipelines, changes in natural gas heat content can result in multiple unit trips at nearly the same time, threatening bulk power system operating reliability.27 LNG presents the most notable challenges due to its diverse origins and compositions; however, unconventional natural gas production can also present similar fuel quality concerns. Furthermore, units are not only susceptible to full outages, but may also experience the inability to modulate power output as one mitigation strategy is to fix the output of units at constant power output until a fuel quality disruption subsides. This strategy may affect both operational flexibility and resource adequacy. While fuel quality and composition risks associated with the increased penetration of unconventional and liquefied natural gas remain relatively low, the potential reliability impacts should be studied further. With a NERC-wide view, the number of units vulnerable to fuel quality issues and their capacity is relatively low, 3.6 percent of all Existing capacity (see Table 2). However, for the New England subregion of NPCC, over 35.3 percent of Existing capacity resources are potentially vulnerable to fuel composition changes. Table 2: Gas-Fired Generation Identified as Vulnerable to Fuel Quality Issues # of Total Existing Winter % of # of Outages or Total Units Capability Existing Events Occurring Duration of Region/Subregion >100 MW (MW) Capacity Within Last Year Outages MRO 11 3,241 5.7% Unknown - NPCC-Maritimes 1 265 3.6% 1 Event 3 hours NPCC-New England 39 12,771 35.3% 14 Outages 27.8 hours NPCC-Ontario 12 1,992 6.5% 0 - SERC 61 16,199 6.4% 1 Event 3 hours SPP 3 3,014 6.2% 0 - 14 Outages, Total 127 37,482 3.6% 2 Other Events 33.8 hours ISO New England continually assesses the impacts on the availability of electric power generation due to constraints or contingencies within regional fuel supply chains. Due to the high levels of gas-fired generation within New England’s power generation fleet, ISO New England has been specifically studying the potential reliability impacts related to natural gas fuel supplies. Over 25 studies have been performed by ISO New England to date due to a wide range of events occurring on the regional natural gas supply and transmission systems. Furthermore, over the last three years, ISO New England has been monitoring the developments within the regional natural gas pipeline industry, as pipelines revise the gas quality sections of their tariffs in response to an upcoming influx of LNG that is re-gasified into the northeastern United States/Canadian natural gas pipelines. ISO New England has developed an operating procedure, which works to maintain bulk power system reliability that specifically addresses the seasonal impacts on regional gas-fired generation during periods of extreme winter weather.28 26 FERC Docket RP08-374-000, June 11, 2008, page 5, item 12: “Casco Bay states that in 2006 it experienced a unit trip due to a “lean blow out” condition… attributed to backhauling gas from alternate supply during a Sable outage.” 27 ISO-NE January 29, 2009 letter, “Summary of Events Related to the January 26, 2008 Sable Island Production Disturbance, 1,470 MW lost in New England – (No OP4 declared) but shows loss of Sable can be disruptive. 28 ISO-NE Market Rule 1 – Appendix H – Operation During Cold Weather Conditions. 2009/2010 Winter Reliability Assessment Page 10 Summary Reliability Assessment of North America ISO New England also has an operating procedure that deals with maintaining bulk power system reliability during events that constrain or temporarily interrupt regional fuel supplies.29 Although ISO New England has not specifically studied the impacts of variations within the natural gas stream on gas turbines equipped with low NOx burners, other studies were performed, which simulate the loss of regional gas-fired generation. This “end-effect” – the temporary loss of gas-fired generation, would be a similar by-product or result of any natural gas fuel quality issue affecting regional gas-fired power generators. Other Regions and subregions identified in Table 2 have a relatively low amount of vulnerable gas-fired generation when compared to all Existing generation within the Regions or subregion. Self-assessments to fuel quality issues are provided below. In FRCC, which has predominately gas-fired generation, the FERC Gas Tariff Gas Quality Provisions for natural gas in the Florida Market Area has strict specifications on gas composition, Wobbe Index, rate of change of the Wobbe Index, and the heat content.30 The FRCC has not experienced natural gas quality issues in the past year. This is attributed to compliance with the strict gas quality specifications outlined in the gas tariff and improved communication between Generator Operators and Natural Gas Transportation Service Providers (TSPs). The ERCOT Region is not generally reliant on any single natural gas supply paths that would impact significant amounts of generating capacity. In the Maritimes, within the last year, one event led to reduced output due to fuel quality issues. However, the Maritimes believes these events occur infrequently, and therefore, does not raise any major reliability concerns in their subregion. In SERC, any restrictions that may occur are continually managed in the daily operation of the systems while maintaining system reliability. Dual fuel units are tested to ensure their functionality and that back-up fuel supplies are adequately maintained and positioned for immediate availability and quality. Some generating units have made provisions to switch between two different natural gas pipeline systems, reducing the dependence on any single interstate or intrastate pipeline system. Moreover, the diversity of generating resources further reduces the Region’s risk. Generator operators within SPP continually monitor natural gas heat content and conduct regular communications with natural gas suppliers. Coordination with natural gas suppliers assures unannounced disruptions will not occur. For this winter season, any reliability impacts due to fuel quality issues appear manageable for all NERC Regions. However, NERC will continue to monitor fuel quality issues and other impacts associated with the increased use of unconventional natural gas. 29 ISO-NE Operating Procedure No. 21 – Action During an Energy Emergency. 30 FERC Docket No. RP04-249 This proceeding addressed potential changes in gas quality resulting from introduction of LNG into the gas pipeline system. FERC Commission orders in this proceeding resulted in changes to the FERC Gas Tariff Gas Quality Provisions for gas in the Florida Market Area. The Commission order was based upon (a) warranty specifications for the combustion turbines, (b) the testimony of expert witnesses, (c) the characteristics of the Florida gas system, and (d) the NGC+ Interim Guidelines. Page 11 2009/2010 Winter Reliability Assessment Adequate-Level of Reliability (ALR) Winter Metrics Adequate-Level of Reliability (ALR) Winter Metrics Introduction Carefully selected and vetted metrics have the potential for indicating impending reliability issues and performance. For the 2009/2010 Winter Reliability Assessment, two metrics were selected, which are supported by available monthly data (December, January, and February) They are: ALR 6-2 Energy Emergency Alert 3 (EEA 3) Firm load interruption imminent or in progress. Balancing Authority or Load Serving Entity foresees or has implemented firm load obligation interruption. The available energy to the Energy Deficient Entity, as determined from Level 2, is only accessible with actions taken to increase transmission transfer capabilities. ALR 6-3 Energy Emergency Alert 2 (EEA 2) Load management procedures in effect. Balancing Authority, Reserve Sharing Group, or Load Serving Entity is no longer able to provide its customers’ expected energy requirements, and is designated an Energy Deficient Entity. Energy Deficient Entity foresees or has implemented procedures up to, but excluding, interruption of firm load commitments. When time permits, these procedures may include, but are not limited to: Public appeals to reduce demand, voltage reduction, interruption of non-firm end use loads in accordance with applicable contracts, DSM, and load conservation measures. NERC is reviewing these and other metrics to monitor reliability performance trends. No conclusions as to the absolute value of these metrics can be drawn at this time. These metrics are only in their early stages. Identifying benchmarks for performance is a separate and future activity, which may aid the industry in quantifying its reliability performance. In some cases, the database for a given metric does not yet contain enough historical information to reveal useful information. While the metrics may show trends or variances from year-to-year, no determination has been made as to what indicates an “acceptable” level of performance. Rather, they show the annual performance and can be a basis for further root-cause analysis. Further, the metrics should not be compared between Regions or subregions as their bulk power system (BPS) characteristics and market structures differ significantly in terms of number of facilities, miles of line, system expansion design approaches, and simple physical, geographic, and climatic conditions. The metrics presented in this report have been vetted by the industry via the Reliability Metrics Working Group (RMWG),31 along with the Planning and Operating Committees. 31 Through the creation of the RMWG the Planning and Operating Committees have promoted the development of performance metrics for the North American Bulk-Power System (BPS). (BPS is a defined term under Federal Power Act Section 215.) The intent of this metrics program is to fulfill the obligations of the ERO relative to benchmarking by providing a slate of agreed upon metrics, which can yield an overall assessment of reliability of the BPS. The RMWG’s charge is to do so within the context of the “Adequate Level of Reliability” (ALR) framework as set out in a December 2007 report Definition of “Adequate Level of Reliability” (http://www.nerc.com/docs/pc/Definition-of-ALR-approved-at-Dec-07-OC-PC-mtgs.pdf) and filed with the FERC for “information” in response to a FERC directive. The RMWG has developed and implemented a decision-making process and has begun to apply it to the myriad field of possible metrics in order to provide a single source for the decisional process. 2009/2010 Winter Reliability Assessment Page 12 Adequate-Level of Reliability (ALR) Winter Metrics ALR 6-2. Energy Emergency Alert 3 (EEA 3) Background Energy Emergency Alert 3 (EEA 3) identifies the number of times EEA 3s are issued. EEA 3 events are firm-load interruptions due to capacity and energy deficiency. EEA 3 is currently reported to NERC and a database is maintained of these events. EEA 3 is defined in NERC Reliability Standard EOP-002-2.32 The frequency of EEA 3 over a timeframe provides an indication of performance measured at a balancing authority (BA) or interconnection level. As historical data is gathered, trends in future reports will provide an indication of either decreasing or increasing adequacy in the electric supply system. This metric will also provide value in developing a correlation between EEA events and Reserve Margins for future planning recommendation. Economic factors should not be included in use of EEAs. However, in certain Regions, and under certain reserve sharing agreements, the industry has adapted this metric in a way which requires EEA declarations in order to implement certain commercial or tariff processes. In those Regions where EEA 3 events are implemented under tariff or contract requirements for economic purposes, they have been eliminated from the tabulations. These events are not valid as a reliability indicator. This was not the intended purpose of the EEA process and unfortunately has the effect of making a reliability indicator into an economic tool for operation of the system. Limitations The metric counts the number of EEA 3 declarations. The severity (e.g. load shedding magnitude and duration) of the events is not presented at this time. The RMWG is presently examining additional data reporting requirements for gathering information on event severity. Assessment Figure Metrics 2 shows the number of EEA 3 events for the winter seasons 2006/2007, 2007/2008, and 2008/2009 at a Regional level. Only four EEA 3s were called during the past three winter seasons with zero occurring during the previous winter. SERC contains a number of relatively small Balancing Authorities, which in general makes this metric not comparable to other Regions. Figure Metrics 2 EEA 3 Events by Region and Winter Season 3 2 Count 1 0 2006/07 2007/08 2008/09 2006/07 2007/08 2008/09 2006/07 2007/08 2008/09 2006/07 2007/08 2008/09 2006/07 2007/08 2008/09 2006/07 2007/08 2008/09 2006/07 2007/08 2008/09 FRCC MRO NPCC SERC SPP ERCOT WECC 32 EEA 3 definition is available at http://www.nerc.com/files/BAL-002-0.pdf Page 13 2009/2010 Winter Reliability Assessment Adequate-Level of Reliability (ALR) Winter Metrics ALR 6-3. Energy Emergency Alert 2 (EEA 2) Background Energy Emergency Alert 2 (EEA 2) metric measures the number of events BAs declare for deficient capacity and/or energy during peak load periods, which may serve as a leading indicator of energy and/or capacity shortfall in the adequacy of the electric supply system. EEA 2 events precede the more severe EEA 3 events. The number of EEA 2 events, and any trends in their reporting, indicates how well the system is able to supply the aggregate load requirements. The historical record includes Demand-Side Management (DSM) activations and non-firm load interruptions per applicable contracts within the EEA alerts. These demand resources are called upon by BAs and are not of direct concern regarding reliability. As data is gathered on a going-forward basis, future reports will provide an indication of either decreasing or increasing adequacy in the electric supply system. EEA events calling solely for activation of DSM (controllable or contractually prearranged demand-side dispatch programs) or interruption of non-firm load per applicable contracts will be excluded from the metric, as Demand Response is a legitimate resource. This metric may also provide value in developing a correlation between EEA events and Reserve Margins for future planning recommendations. Limitations Future data reporting will be modified to add additional information on what actions are being taken in EEA 2 events to ensure DSM and non-firm load interruption are excluded from the metric. Through the RMWG, the Planning Committee is proposing that data reporting processes be modified to add additional information on what actions are being taken in EEA 2 events to ensure DSM and non-firm load interruption are excluded from the metric. Assessment Figure Metrics 3 shows the number of EEA 2 events for the winter seasons 2006/2007, 2007/2008, and 2008/2009 at a Regional level, unadjusted for DSM activations. SERC contains a number of relatively small Balancing Authorities, which in general makes this metric not comparable to other Regions. An increasing number of EEA 2s were called over the past three winter seasons. Figure Metrics 3 EEA 2 Events by Region and Winter Season 8 6 Count 4 2 0 2006/07 2007/08 2008/09 2006/07 2007/08 2008/09 2006/07 2007/08 2008/09 2006/07 2007/08 2008/09 2006/07 2007/08 2008/09 2006/07 2007/08 2008/09 2006/07 2007/08 2008/09 FRCC MRO NPCC SERC SPP ERCOT WECC 2009/2010 Winter Reliability Assessment Page 14 Estimated Demand, Resources, and Reserve Margins Estimated Demand, Resources, and Reserve Margins To improve consistency and increase granularity Table 3: Demand, Capacity, and Margins and transparency, the NERC Planning Committee approved new categories33 for capacity resources, Total Internal Demand (MW) — The sum of the metered (net) outputs of all generators within the purchases, and sales (see Table 3). The resource system and the metered line flows into the system, less designations of “Existing-Certain”, “Existing, the metered line flows out of the system. Total Uncertain” and “Planned” have been replaced with: Internal Demand includes adjustments for indirect Demand-Side Management programs such as 1. Existing: conservation programs, improvements in efficiency of electric energy use, and all non-dispatchable Demand a. Existing-Certain — Existing generation Response programs resources available to operate and deliver power within or into the Region during the Net Internal Demand (MW) — Total Internal Demand less Dispatchable, Controllable Capacity period of analysis in the assessment. Demand Response used to reduce load. b. Existing-Other — Existing generation resources that may be available to operate Existing-Certain and Net Firm Transactions (MW) — Existing-Certain capacity resources plus Firm and deliver power within or into the Region Imports, minus Firm Exports. during the period of analysis in the assessment, but may be curtailed or Deliverable Capacity Resources (MW) — Existing-Certain and Net Firm Transactions plus interrupted at any time for various reasons. Future, Planned capacity resources plus Expected c. Existing, but Inoperable — Existing Imports, minus Expected Exports portion of generation resources that are out- Prospective Capacity Resources (MW) — of-service and cannot be brought back into Deliverable Capacity Resources plus Existing, Other service to serve load during the period of capacity resources, minus all Existing, Other deratings analysis in the assessment. (includes derates from variable resources, energy only resources, scheduled outages for maintenance, and 2. Future: transmission-limited resources), plus Future-Other a. Future-Planned — Generation resources capacity resources, minus all Future-Other deratings. anticipated to be available to operate and Existing-Certain and Net Firm Transactions (%) deliver power within or into the Region — Existing-Certain, and Net Firm Transactions minus during the period of analysis in the Net Internal Demand shown as a percent of Net Internal Demand. assessment. b. Future-Other — Future generating Deliverable Reserve Margin (%) — resources that do not qualify in Future- Deliverable Capacity Resources minus Net Internal Demand shown as a percent of Net Internal Demand. Planned and are not included in the Conceptual category. Prospective Reserve Margin (%) — Prospective Capacity Resources minus Net Internal The monthly estimates of peak-demand, Demand shown as a percent of Net Internal Demand. resources and Reserve Margins for each Region NERC Reference Reserve Margin Level (%) – during the 2009/2010 winter season are in Table Either the Target Capacity Margin provided by the 3a-3c.34 Region/subregion or NERC assigned based on capacity mix (i.e. thermal/hydro). 33 See the section entitled “Reliability Concepts Used in this Report” for definitions that are more detailed. 34 For the Region of ERCOT, and the subregions of NPCC and RFC, coincident peaks are provided. Page 15 2009/2010 Winter Reliability Assessment Estimated Demand, Resources, and Reserve Margins Table 3a: Estimated December 2009 Demand, Resources, and Reserve Margins Existing Existing NERC Certain & Certain & Reference Total Net Firm Deliverable Prospective Net Firm Deliverable Prospective Reserve Internal Net Internal Trans- Capacity Capacity Trans- Reserve Reserve Margin Demand Demand actions Resources Resources actions Margin Margin Level (MW) (MW) (MW) (MW) (MW) (%) (%) (%) (%) United States ERCOT 39,754 38,639 70,088 70,524 70,524 81.4% 82.5% 82.5% 12.5% FRCC 35,980 32,807 54,572 55,907 55,907 66.3% 70.4% 70.4% 15.0% MRO 34,906 33,106 47,586 47,596 48,593 43.7% 43.8% 46.8% 15.0% NPCC 46,302 44,348 73,523 73,767 72,067 65.8% 66.3% 62.5% 15.0% New England 21,304 21,304 35,700 35,813 35,813 67.6% 68.1% 68.1% 15.0% New York 24,998 23,044 37,823 37,954 36,254 64.1% 64.7% 57.3% 16.5% RFC 143,500 138,600 215,800 215,800 217,200 55.7% 55.7% 56.7% 15.0% RFC-MISO 49,100 47,400 70,800 70,800 72,100 49.4% 49.4% 52.1% 15.0% RFC-PJM 94,300 91,100 142,800 142,800 142,900 56.8% 56.8% 56.9% 15.0% SERC 168,574 163,757 245,990 246,489 256,394 50.2% 50.5% 56.6% 15.0% Central 39,124 38,337 53,331 53,331 53,451 39.1% 39.1% 39.4% 12.7% Delta 22,040 21,406 39,352 39,455 39,623 83.8% 84.3% 85.1% 15.0% Gateway 14,738 14,738 20,934 20,934 21,404 42.0% 42.0% 45.2% 15.0% Southeastern 39,193 37,482 58,344 58,694 66,709 55.7% 56.6% 78.0% 15.0% VACAR 53,479 51,794 74,029 74,075 75,207 42.9% 43.0% 45.2% 15.0% SPP 32,636 31,988 49,549 49,972 58,822 54.9% 56.2% 83.9% 13.6% WECC 110,921 108,132 166,795 170,980 170,980 54.3% 58.1% 58.1% 16.7% AZ-NM-SNV 18,564 18,102 37,364 38,111 38,111 106.4% 110.5% 110.5% 15.5% CA-MX US 41,831 39,938 61,453 63,142 63,142 53.9% 58.1% 58.1% 15.9% NWPP 40,667 40,412 56,724 56,942 56,942 40.4% 40.9% 40.9% 18.4% RMPA 9,859 9,680 13,151 14,224 14,224 35.9% 46.9% 46.9% 15.4% Total-U.S. 612,573 591,377 923,902 931,034 950,486 56.2% 57.4% 60.7% 15.0% Canada MRO 7,390 7,102 8,839 8,947 8,947 24.5% 26.0% 26.0% 10.0% NPCC 60,323 58,434 75,171 74,205 73,583 28.6% 27.0% 25.9% 10.0% Maritimes 5,075 4,686 7,639 7,639 6,464 63.0% 63.0% 37.9% 15.0% Ontario 21,919 21,919 28,118 28,202 28,564 28.3% 28.7% 30.3% 17.5% Quebec 33,329 31,829 39,414 38,364 38,555 23.8% 20.5% 21.1% 10.0% WECC 21,548 21,548 24,751 24,929 24,929 14.9% 15.7% 15.7% 13.2% Total-Canada 89,262 87,085 108,761 108,081 107,460 24.9% 24.1% 23.4% 10.0% Mexico WECC CA-MX Mex 1,395 1,395 2,454 2,454 2,454 75.9% 75.9% 75.9% 10.1% Total-NERC 703,230 679,857 1,035,118 1,041,570 1,060,400 52.3% 53.2% 56.0% 15.0% 2009/2010 Winter Reliability Assessment Page 16 Estimated Demand, Resources, and Reserve Margins Table 3b: Estimated January 2010 Demand, Resources, and Reserve Margins Existing Existing NERC Certain & Certain & Reference Total Net Firm Deliverable Prospective Net Firm Deliverable Prospective Reserve Internal Net Internal Trans- Capacity Capacity Trans- Reserve Reserve Margin Demand Demand actions Resources Resources actions Margin Margin Level (MW) (MW) (MW) (MW) (MW) (%) (%) (%) (%) United States ERCOT 43,083 41,968 73,602 74,038 74,038 75.4% 76.4% 76.4% 12.5% FRCC 44,446 40,846 55,881 57,216 57,216 36.8% 40.1% 40.1% 15.0% MRO 34,977 33,075 47,661 47,765 48,936 44.1% 44.4% 48.0% 15.0% NPCC 47,098 45,144 74,021 74,273 72,560 64.0% 64.5% 60.7% 15.0% New England 22,100 22,100 36,198 36,319 36,319 63.8% 64.3% 64.3% 15.0% New York 24,998 23,044 37,823 37,954 36,241 64.1% 64.7% 57.3% 16.5% RFC 145,800 140,900 215,800 215,800 217,200 53.2% 53.2% 54.2% 15.0% RFC-MISO 49,100 47,400 70,800 70,800 72,100 49.4% 49.4% 52.1% 15.0% RFC-PJM 96,600 93,400 142,800 142,800 142,900 52.9% 52.9% 53.0% 15.0% SERC 179,659 174,649 248,181 248,680 259,037 42.1% 42.4% 48.3% 15.0% Central 43,230 42,410 54,303 54,303 54,649 28.0% 28.0% 28.9% 12.7% Delta 21,839 21,183 39,506 39,609 39,776 86.5% 87.0% 87.8% 15.0% Gateway 15,640 15,640 21,868 21,868 22,338 39.8% 39.8% 42.8% 15.0% Southeastern 41,740 39,940 58,273 58,623 66,639 45.9% 46.8% 66.8% 15.0% VACAR 57,210 55,476 74,231 74,277 75,635 33.8% 33.9% 36.3% 15.0% SPP 32,636 31,988 49,549 49,972 58,822 54.9% 56.2% 83.9% 13.6% WECC 109,194 105,981 165,371 170,190 170,190 56.0% 60.6% 60.6% 16.7% AZ-NM-SNV 18,880 18,188 37,178 38,368 38,368 104.4% 111.0% 111.0% 15.5% CA-MX US 40,185 38,179 60,033 61,829 61,829 57.2% 61.9% 61.9% 15.9% NWPP 40,867 40,577 56,555 56,841 56,841 39.4% 40.1% 40.1% 18.4% RMPA 9,262 9,037 13,442 14,534 14,534 48.7% 60.8% 60.8% 15.4% Total-U.S. 636,893 614,551 930,065 937,933 957,999 51.3% 52.6% 55.9% 15.0% Canada MRO 7,504 7,216 8,823 9,022 9,022 22.3% 25.0% 25.0% 10.0% NPCC 64,461 62,568 77,681 77,561 76,872 24.2% 24.0% 22.9% 10.0% Maritimes 5,497 5,104 7,697 7,697 6,458 50.8% 50.8% 26.5% 15.0% Ontario 22,848 22,848 30,659 30,889 31,398 34.2% 35.2% 37.4% 17.5% Quebec 36,116 34,616 39,325 38,975 39,016 13.6% 12.6% 12.7% 10.0% WECC 21,271 21,271 24,509 24,687 24,687 15.2% 16.1% 16.1% 13.2% Total-Canada 93,237 91,055 111,013 111,270 110,581 21.9% 22.2% 21.4% 10.0% Mexico WECC CA-MX Mex 1,359 1,359 2,265 2,265 2,265 66.7% 66.7% 66.7% 10.1% Total-NERC 731,488 706,965 1,043,343 1,051,468 1,070,845 47.6% 48.7% 51.5% 15.0% Page 17 2009/2010 Winter Reliability Assessment Estimated Demand, Resources, and Reserve Margins Table 3c: Estimated February 2010 Demand, Resources, and Reserve Margins Existing Existing NERC Certain & Certain & Reference Total Net Firm Deliverable Prospective Net Firm Deliverable Prospective Reserve Internal Net Internal Trans- Capacity Capacity Trans- Reserve Reserve Margin Demand Demand actions Resources Resources actions Margin Margin Level (MW) (MW) (MW) (MW) (MW) (%) (%) (%) (%) United States ERCOT 43,221 42,106 72,531 73,017 73,017 72.3% 73.4% 73.4% 12.5% FRCC 36,765 33,352 55,881 57,528 57,679 67.5% 72.5% 72.9% 15.0% MRO 33,969 32,027 47,496 47,600 48,774 48.3% 48.6% 52.3% 15.0% NPCC 46,612 44,658 73,099 73,351 71,786 63.7% 64.3% 60.7% 15.0% New England 21,614 21,614 36,098 36,219 36,219 67.0% 67.6% 67.6% 15.0% New York 24,998 23,044 37,001 37,132 35,567 60.6% 61.1% 54.3% 16.5% RFC 140,700 135,800 215,800 215,800 217,200 58.9% 58.9% 59.9% 15.0% RFC-MISO 47,500 45,800 70,800 70,800 72,100 54.6% 54.6% 57.4% 15.0% RFC-PJM 93,100 89,900 142,800 142,800 142,900 58.8% 58.8% 59.0% 15.0% SERC 172,901 167,807 247,467 247,966 256,558 47.5% 47.8% 52.9% 15.0% Central 40,964 40,161 53,946 53,946 54,112 34.3% 34.3% 34.7% 12.7% Delta 22,064 21,299 39,498 39,601 39,767 85.4% 85.9% 86.7% 15.0% Gateway 15,363 15,363 21,649 21,649 22,119 40.9% 40.9% 44.0% 15.0% Southeastern 40,075 38,273 58,198 58,548 66,563 52.1% 53.0% 73.9% 15.0% VACAR 54,435 52,711 74,176 74,222 73,997 40.7% 40.8% 40.4% 15.0% SPP 32,636 31,988 49,549 49,972 58,822 54.9% 56.2% 83.9% 13.6% WECC 104,703 101,599 162,855 168,605 168,605 60.3% 66.0% 66.0% 16.7% AZ-NM-SNV 17,762 17,078 35,788 36,978 36,978 109.6% 116.5% 116.5% 15.5% CA-MX US 39,032 37,028 59,066 61,826 61,826 59.5% 67.0% 67.0% 15.9% NWPP 38,866 38,675 56,079 56,369 56,369 45.0% 45.8% 45.8% 18.4% RMPA 9,043 8,818 13,516 14,608 14,608 53.3% 65.7% 65.7% 15.4% Total-U.S. 611,507 589,337 924,677 933,838 952,440 56.9% 58.5% 61.6% 15.0% Canada MRO 7,337 7,049 8,736 8,935 8,935 23.9% 26.8% 26.8% 10.0% NPCC 62,588 60,701 75,303 74,883 74,300 24.1% 23.4% 22.4% 10.0% Maritimes 5,468 5,081 7,697 7,697 6,412 51.5% 51.5% 26.2% 15.0% Ontario 22,601 22,601 28,446 28,676 29,187 25.9% 26.9% 29.1% 17.5% Quebec 34,519 33,019 39,160 38,510 38,701 18.6% 16.6% 17.2% 10.0% WECC 20,604 20,604 24,828 25,107 25,107 20.5% 21.9% 21.9% 13.2% Total-Canada 90,529 88,354 108,867 108,925 108,342 23.2% 23.3% 22.6% 10.0% Mexico WECC CA-MX Mex 1,357 1,357 2,264 2,264 2,264 66.8% 66.8% 66.8% 10.1% Total-NERC 703,393 679,048 1,035,808 1,045,027 1,063,047 52.5% 53.9% 56.5% 15.0% 2009/2010 Winter Reliability Assessment Page 18 Estimated Demand, Resources, and Reserve Margins Notes for Table 3a through 3c Note 1: Existing-Certain resources and Net Firm Transactions are reported to be deliverable by the Regions. Note 2: The inoperable portion of Total Potential Resources may not be deliverable. Note 3: The WECC-US peak demands or resources do not necessarily equal the sums of the non-coincident WECC- US subregional peak demands or resources because of subregional monthly peak demand diversity. Similarly, the Western Interconnection peak demands or resources do not necessarily equal the sums of the non-coincident WECC-U.S., Canada, and Mexico peak demands or resources. In addition, the subregional resource numbers include use of seasonal demand diversity between the winter-peaking northwest and the summer-peaking portions of the Western Interconnection. Note 4: The Demand-Side Management resources are not necessarily sharable between the WECC subregions and are not necessarily sharable within subregions. Note 5: WECC CA-MX represents only the northern portion of the Baja California Norte, Mexico electric system interconnected with the United States. Note 6: MISO and PJM information do not sum to the RFC total, as approximately 100 MW of Ohio Valley Electric Corporation (OVEC)35 peak demand is also included in RFC. OVEC is not affiliated with either PJM or MISO; however, OVEC’s Reliability Coordinator services are performed by PJM. RFC information is only for the demand and capacity within its Region. Additionally, the RFC Region and the MISO and PJM subregion demand values are coincident. Note 7: These demand and supply forecasts were reported on September 30, 2009. Note 8: Each Region/subregion may have their own specific Reserve Margin level based on load, generation, and transmission characteristics as well as regulatory requirements. If provided in the data submittals, the Regional/subregional Target Reserve Margin level is adopted as the NERC Reference Reserve Margin Level. If not, NERC assigned a 15 percent Reserve Margin for predominately thermal systems and a 10 percent Reserve Margin for predominately hydro systems. Note 9: Based on Midwest ISO tariff requirements, individual LSE reserve levels in the SERC Gateway subregion are 12.7 percent. Accordingly, the NERC Reference Margin Reserve Level for SERC Gateway subregion is 12.7 percent.36 35 OVEC is a generation and transmission utility located in Indiana, Kentucky and Ohio. 36 For more information, see the Midwest ISO 2009–2010 LOLE Study Report at: http://www.midwestmarket.org/publish/Document/62c6cd_120e7409639_-7f2a0a48324a Page 19 2009/2010 Winter Reliability Assessment Regional Reliability Assessment Highlights Regional Reliability Assessment Highlights ERCOT The 2009/2010 winter peak demand forecast of 43,463 MW is 9.08 percent lower than the 2008/2009 winter actual demand of 47,806 MW. This expected reduction is largely due to the impact of the economic recession. Market participants in the ERCOT Region have added a net of 2,715 MW of Existing-Certain generation capacity since last winter’s assessment. Of this amount, 214 MW was new wind generation (which is 2,460 MW nameplate capacity with an effective load carrying capability on-peak of 8.7 percent). With 72,531 MW of Net Capacity Resources, the ERCOT Region Reserve Margin is 68 percent, well over the target annual Reserve Margin of 12.5 percent. Several transmission improvements have been made throughout the ERCOT Region to meet reliability needs. Approximately 27 miles of new 345 kV lines have been completed since the 2008/2009 winter and 20.5 miles of upgraded 345 kV lines are expected to be completed during the 2009/2010 winter. Approximately 287 miles of new or upgraded 138 kV transmission lines were completed since the 2008/2009 winter and an additional 108 miles of new or upgraded 138 kV lines are expected to be completed by the end of the 2009/2010 winter period. There are no known transmission constraints expected to significantly impact reliability across the ERCOT Region during the winter period. Integration of additional wind generation continues to increasingly affect system operations. Several changes to requirements and processes have already been made, or are planned for implementation, to mitigate these impacts. FRCC FRCC expects to have adequate generating reserves with transmission system deliverability throughout the 2009/2010 winter peak demand. In addition, Existing-Other merchant plant capability of 1,340 MW is potentially available as future resources for FRCC members and others. The transmission capability within the FRCC Region is expected to be adequate to supply firm customer demand and planned firm transmission service. Operational issues can develop due to unplanned outages of generating units within the FRCC Region. However, it is anticipated that existing operational procedures, pre-planning, and training will adequately manage and mitigate these potential impacts to the bulk transmission system. 2009/2010 Winter Reliability Assessment Page 20 Regional Reliability Assessment Highlights MRO The Midwest Reliability Organization’s (MRO) forecasted 2009/2010 Non-Coincident Winter Peak Total Internal Demand is 42,480 MW. This forecast is 1.4 percent below last winter’s forecasted total demand of 43,080 MW. The recession and nationwide economic downturn are the main reasons for the slight decrease in forecast. The Existing-Certain resources for 2009/2010 winter are 56,623 MW. This is 1,036 MW higher than the Existing-Certain resources reported for the 2008/2009 winter. 303 MW of planned generation is expected to be placed in service prior to or during the 2009/2010 winter season. Approximately 700 MW of wind generation is expected to be placed in service prior to or during the 2009/2010 winter season (since June 1, 2009). The projected Reserve Margin is 41.3 percent, which is well above the various target Reserve Margins established by the RTOs and Planning Authorities within the MRO Region. Numerous transmission reinforcements will be completed by or during the upcoming winter season. These reinforcements include several rebuilt/reconductored transmission circuits; several new 115 kV, 138 kV and 161 kV circuits; two new 345 kV circuits in Nebraska and Wisconsin; three new bulk power transformers; two new substations; and various substation expansions and upgrades. The MRO footprint will have about 6,400 MW of nameplate wind generation as of December 1, 2009. Most of this wind generation is managed by the Midwest ISO Reliability Coordinator. At the present time ramp rates, output volatility, and the inverse nature of wind generation with respect to load levels have been manageable. However, the Midwest ISO closely watches the ramp-down rate of wind generation during the morning load pickup period. The simultaneous output of wind generation within the MRO Region has historically reached 75 percent or more of nameplate rating for extended periods of time which can occur during off-peak hours during minimum load periods. The Midwest ISO is actively exploring new and better ways to manage the wind generation within its footprint through stakeholder workshops. Extensive analysis is being performed by the Midwest ISO regarding wind generation in areas such as regulation, load following, ramp rates, managing minimum load periods, wind forecasting, equitable participation during curtailments, and redispatch. These ongoing quarterly workshops also address future aspects of wind such as establishing appropriate capacity credits, day-ahead participation in market processes, and energy storage. NPCC Due to the realization of milder weather than that which was forecast, the actual peak loads experienced during the winter of 2008/2009 were below forecasts in four of the five NPCC subregions; the subregion of Québec exceeded its forecast peak demand for the 2008/2009 winter period by almost 700 MW due to a period of extreme cold in January 2009. All NPCC subregions are currently experiencing the impact of the economic downturn in its projected system demand. Demand forecasts for the 2009/2010 Winter are lower than last winter’s forecasts for all five NPCC subregions mainly due to the slowdown of economic activity. Page 21 2009/2010 Winter Reliability Assessment Regional Reliability Assessment Highlights When compared with projections for the 2009/2010 winter, the New England, New York, Ontario, and Québec subregions are projecting Reserve Margins similar to or higher than the Reserve Margins projected for the 2008/2009 winter. The Maritimes subregion is projecting a lower Reserve Margin due to the continuing outage of the Point Lepreau nuclear unit, however, the Maritimes Reserve Margin is projected to be adequate with a forecast of 25 percent. The NPCC transmission system is expected to perform adequately, and several enhancements to the system have been made since the 2008/2009 Winter. RFC The projected Reserve Margin for the ReliabilityFirst (RFC) Region is 74,900 MW, which is 53.2 percent based on Net Internal Demand (NID) and Deliverable Resources. Both Midwest ISO and PJM RTO (PJM) have sufficient resources to satisfy their planning reserve requirements. Therefore, the resulting Reserve Margin for this winter in the ReliabilityFirst Region is adequate. This compares to a 49.8 percent Reserve Margin in last winter’s assessment. Approximately 85 percent of the PJM RTO demand and approximately 60 percent of the Midwest ISO market demand is within the RFC Region. Since Ohio Valley Electric Corporation (OVEC) is not a member of either RTO market, its demand of approximately 100 MW was added to that of the PJM and Midwest ISO areas within the RFC.37 The forecast winter 2009/2010 coincident peak demand for the RFC Region is 140,900 MW (Net Internal Demand). This is unchanged when compared to the previous winter’s forecast, primarily due to economic conditions. Both weather and economic conditions have significant influence on electrical peak demand forecasts. The amount of Existing-Certain OVEC, PJM and Midwest ISO capacity in RFC is 215,600 MW. This is 4,600 MW more Existing-Certain capacity than the 211,000 MW that was reported within the 2008/2009 winter assessment. Much of the increase in the Existing-Certain capacity for this winter comes from capacity in the Midwest ISO area of RFC that was not committed in the Midwest ISO market last winter. Capacity committed to the markets at the beginning of the winter period is assumed constant throughout the winter. New capacity in-service after the start of the planning year (June) is not included within the calculation of the winter Reserve Margins for either PJM or Midwest ISO. The projected reserves for the PJM RTO during the 2009/2010 winter peak are 58,000 MW, which is 53.0 percent of the Net Internal Demand. The PJM capacity requirement is based upon the summer peak demand and reflects a total capacity of 150,300 MW. The PJM net capacity resources are 167,500 MW, which is 17,200 MW greater than the requirement. The PJM RTO has adequate reserves to serve the 2009/2010 winter peak demand. 37 Ohio Valley Electric Corporation (OVEC), a generation and transmission company located in Indiana, Kentucky and Ohio, is not a member of either RTO and is not affiliated with their markets; however, PJM performs OVEC’s Reliability Coordinator services. 2009/2010 Winter Reliability Assessment Page 22 Regional Reliability Assessment Highlights The projected reserves for the Midwest ISO for the 2009/2010 winter peak are 42,200 MW, which is 53.1 percent, of the Net Internal Demand of its market area. The Midwest ISO reserve requirement is 15.4 percent for each month of the planning year. The Midwest ISO winter Reserve Margin is adequate for the Midwest ISO. New transmission additions to the bulk power system, since last winter, that have been placed in- service include a total of six miles of transmission line(s) at 230 kV and above, plus ten transformers with a total capacity rating of about 6,100 MVA. An additional total of 32 miles of transmission line(s) at 230 kV and above is expected to be placed in-service by this winter, plus three transformers with a total capacity rating of about 4,500 MVA. The transmission system within the RFC footprint is expected to perform well over a wide range of operating conditions, provided new facilities go into service as scheduled, and that transmission operators take appropriate action, as needed, to control power flows, reactive reserves, and voltages. SERC SERC Reliability Corporation (SERC) reports all utilities within the Region expect to meet all customer demand during the winter 2009/2010. The 2009/2010 winter demand forecast is 2.2 percent lower than the forecast for the 2008/2009 winter Total Internal Demand. This reduction in demand, as compared to last winter season is primarily due to the economic recession. The majority of the utilities in SERC are forecasting lower demand for the winter 2009/2010 period than was forecasted for the prior winter season. Utilities in the SERC Region expect to have adequate generating capacity and the reserves necessary to meet all customer demand during the 2009/2010 winter period. The transmission capability of the utilities within the SERC Region is expected to be adequate to deliver supply to firm customer demand. Operational issues can develop due to unplanned outages of generating units owned by the companies within the SERC Region; however, it is anticipated that existing operational procedures, pre-planning, and training will allow the utilities in the Region to adequately manage and mitigate the impacts of such events to the bulk transmission system in the Region. SPP The SPP RTO Region’s forecasted demand for the 2009/2010 winter operating season is 32,636 MW. Approximately 511 MW of Existing- Certain resources were added to the SPP Region since the last reporting year. Future resource growth is expected to total approximately 423 MW over the assessment timeframe. The SPP Page 23 2009/2010 Winter Reliability Assessment Regional Reliability Assessment Highlights RTO’s Reserve Margin, based on Existing-Certain and net firm transactions, is forecasted to be 54.9 percent. With the addition of Deliverable resources, the Reserve Margin is forecasted to be 56.2 percent. The projected Reserve Margins exceed SPP’s target Reserve Margin of 13.6 percent. On April 1, 2009, the SPP RTO acquired three new members for which SPP is performing reliability coordination and tariff administration services: Nebraska Public Power District, Omaha Public Power District, and Lincoln Electric System. However, Midwest Reliability Organization (MRO) will continue to perform Reliability Assessments for these entities until the NERC Regional Delegation Agreement is revised. Because the SPP RTO is a summer-peaking Region, no known transmission issues are expected during 2009/2010 winter. Because Level 3 Energy Emergency Alerts (EEA 3s) were issued in the Acadiana area during this past summer, the SPP RTO will continue to monitor this area closely as part of its reliability coordinator function. The continued surge in wind development in the western part of the SPP system (especially in Oklahoma, the Texas panhandle, and western Kansas) is the most challenging obstacle facing the operation of SPP’s bulk power system. In the coming years SPP will develop additional criteria, such as requiring voltage support, to handle issues native to variable wind farm operations. SPP staff is expected to complete a Wind Integration Task Force study this winter which will suggest implementing operational tools to manage wind penetration in the SPP footprint. WECC The WECC 2009/2010 winter Total Internal Demand is forecast to be 133,864 MW, with a Reserve Margin of 50.9 percent. Due to expected poor economic conditions, the forecast demand is 2.0 percent less than last winter’s actual peak demand of 136,592 MW. All of WECC’s four subregions project sufficient margins to meet their forecast peak demand and operating reserve obligations. Of the four subregions, the Northwest Power Pool is typically winter peaking, but the Rocky Mountain Power subregion could be either winter or summer peaking. The projected hydro levels for the 2009/2010 winter season are below normal, but the hydro generation and thermal generation are expected to be sufficient to meet the winter peak demands and energy loads. While it is not expected that extremes of winter weather during peak load conditions would have a significant impact on the fuel supply infrastructure, sudden and very severe winter storms may adversely affect transmission, generating plant availability, and fuel supplies in areas impacted by the storms. 2009/2010 Winter Reliability Assessment Page 24 Regional Reliability Self-Assessments Regional Reliability Self-Assessments Introduction Regional Resource and Demand Projections The figures in the Regional self-assessment pages show the Regional historical demand, projected demand growth, Reserve Margin projections, and generation expansion projections reported by the Regions. Capacity Fuel Mix The Regional capacity fuel mix charts shown in each Region’s self-assessment presents the relative reliance on specific fuels38 for its reported generating capacity. The charts for each Region in the Regional self-assessments are based on the most recent data available in NERC’s Electricity Supply and Demand (ES&D) database. Overall NERC fuel-mix is shown below. 2009/2010 Overall NERC Total Capacity Resources by Fuel-Type 350,000 300,000 250,000 200,000 MW 150,000 100,000 50,000 0 Coal Gas Hydro Nuclear Dual Fuel Oil Other Pumped Storage Existing-Certain Capacity Future-Planned Capacity (for the 2009/2010 Winter) NERC Interconnections NERC Subregions 38 Note: The category “Other” may include capacity for which the total capacity of a specific fuel type is less than 1% of the total capacity or the fuel type has yet to be determined Page 25 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments ERCOT Regional Assessment Summary 2009/2010 Winter Projected Peak Demand MW On-Peak Capacity by Fuel Type Total Internal Demand 43,221 Direct Control Load Management 0 Contractually Interruptible (Curtailable) 0 Dual Critical Peak-Pricing with Control 0 Gas Fuel Load as a Capacity Resource 1,115 52% 20% Net Internal Demand 42,106 Other 4% 2008/2009 Winter Comparison MW % Change Nuclear Coal 7% 2008/2009 Winter Projected Peak Demand 45,658 -7.8% 17% Hydro 2008/2009 Winter Actual Peak Demand 47,806 -11.9% 1% All-Time Winter Peak Demand 50,408 -16.5% 2009/2010 Winter Projected Peak Capacity MW Margin Existing Certain and Net Firm Transactions 72,531 72.3% Deliverable Capacity Resources 73,017 73.4% Prospective Capacity Resources 73,017 73.4% NERC Reference Margin Level - 12.5% Demand The 2009/2010 winter peak demand forecast of 43,463 MW, shown in Table ERCOT-1, is lower than the 2008/2009 winter actual demand of 47,806 MW by 4,343 MW. This represents a 9.08 percent decrease from the 2008/2009 actual winter peak, largely due to the current economic recession. The current forecast is also lower than last year’s forecast of 47,270 MW for the 2008/2009 winter peak demand. Table ERCOT-1: ERCOT Winter Peaks 2008/2009 ACTUAL 2009/2010 FORECAST December 2008 47,806 December 2009 39,996 January 2009 45,495 January 2010 43,325 February 2009 41,378 February 2010 43,463 The forecasted peak demands are produced by ERCOT ISO for the ERCOT Region, which is a single Balancing Authority area, based on the Region-wide actual demands. The weather assumptions on which the forecasts are based represent an average weather profile (50/50), calculated for each of the eight weather zones in the ERCOT Region. These average profiles are based on a Rank-Median method, because the calculation of the median temperatures is less affected by outliers than a simple average. 2009/2010 Winter Reliability Assessment Page 26 Regional Reliability Self-Assessments To assess the impact of weather variability on the peak demand for ERCOT, alternative weather scenarios are used to develop extreme weather load forecasts. One scenario is the one-in-ten-year occurrence of a weather event. This scenario is calculated using the 90th percentile of the temperatures in the database spanning the last fourteen years available. These extreme temperatures are input into the load-shape and energy models to obtain the forecasts. The extreme temperature assumptions consistently produce demand forecasts that are approximately 5.5 percent higher than the forecasts based on the average weather profile (50/50). Together, the forecasts from these temperature scenarios are usually referred to as 90/10 scenario forecasts. The economic factors that drive the 2009 ERCOT Long-Term Hourly Demand Forecast39 include per capita income, population, gross domestic product (GDP), and various employment measures that include non-farm employment and total employment. The forecasts of these economic indicators indicate the effects of the national recession on the Texas economy. Based on Transmission and/or Distribution Service Provider (TDSP) filings to the Public Utilities Commission of Texas, 242 MW of energy efficiency is assumed over the next winter. This energy efficiency estimate is not reflected in the 43,463 MW peak demand forecast. There are two categories of demand-response resources that can be dispatched by the ERCOT ISO in all hours, and therefore are capable of reducing winter peak demand: Loads Acting as a Resource40 (LaaR) providing Responsive Reserve Service (RRS) Emergency Interruptible Load Service41 (EILS) LaaRs are registered with ERCOT to provide ancillary services. ERCOT Staff measures and verifies Load acting as a Resource performance in the Ancillary Services markets using telemetry (updated every 2-10 seconds) that provides real-time visibility in the capability and performance of the Resources and is integrated into the Operators’ performance monitoring tools. The real-time data is stored using a Plant Information (PI) database that records key data parameters that allows for more detailed analysis after-the-fact. ERCOT’s analysis of this telemetry data is supported after-the-fact as necessary with 15-minute interval meter data. The total contribution of LaaRs to RRS cannot exceed 1,150 MW in any hour; this amount is one- half of the 2,300 MW of RRS procured for most winter hours. LaaRs providing RRS are required to deploy automatically with under-frequency relays or to deploy within ten minutes by a verbal dispatch instruction (VDI) from ERCOT. For the 2009/2010 winter season, 1115MW of LaaRs is the only Demand Response counted toward planning Reserve Margin requirements, which is 2.6 percent of the expected Net Internal Demand for the season. EILS resources are loads that provide capacity services and are subject to deployment by VDIs that can be executed prior to firm load shedding. EILS resources are procured for four-month contracts, and the capacity available to ERCOT is dependent on the details from accepted bids, which include time period, capacity, cost, location and performance. Measurement and verification of EILS is accomplished entirely after-the-fact with 15-minute interval data applied 39 See “2008 Long-Term Hourly Demand Energy Forecast” located on the following website: http://www.ercot.com/news/presentations/ 40 For additional information on LaaRs see: http://www.ercot.com/services/programs/load/laar/index 41 For additional information on EILS see: http://www.ercot.com/services/programs/load/eils/index Page 27 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments to multiple baseline types as assigned by ERCOT specific to the individual Load or aggregation. EILS capacity is not included in Reserve Margin calculations. Additionally, entities in the ERCOT Region may participate in market-based Demand Response activities through the competitive retail market, including direct load control, real-time price response, and critical peak price response. However, such resources are not dispatched by the ERCOT ISO, and as this competitive market information is not available, there are no reliable estimates of the aggregate capacity of these programs. Currently, this type of Demand Response is not a reliability concern in the ERCOT Region. However, as Demand Response activities continue to grow, ERCOT ISO is implementing efforts to improve Demand Response data submittals. Generation ERCOT has 72,419 MW of Deliverable Internal Capacity (the sum of Existing Summer and Future-Planned Generation) expected to be in service during the 2009/2010 winter period. The Table below shows this broken out into the different reporting categories. Table ERCOT-2: ERCOT Generation Category MW Existing-Certain 71,933 Existing-Other 11,852 Existing-Inoperable 4,782 Future-Planned 486 Future-Other 0 The amount of Existing-Other generation includes 6,154 MW of units undergoing maintenance or repair during the first week of the reporting period (which is reduced to 3,711 MW at the time of the expected Winter Peak Load in February) and 4,782 MW of units not readily available due to their mothball status throughout the planning period. This first week reflects the largest capacity outages that are planned for the period, and is not expected to adversely affect the ability to meet demand. Of the 8,335 MW of installed wind capacity, only 8.7 percent, or 725 MW, is used as Existing- Certain generation based on the ERCOT Reserve Margin Analysis Report42. The remaining 7,610 MW of the existing wind capacity is included in the Existing-Other generation amount. Similarly, the planned new wind generation expected to be online by the winter period totals 582 MW, however only 51 MW (8.7 percent) are considered to be available on-peak. In addition, 76 MW of biomass is included in the Existing-Certain generation amount. No solar generation is assumed to be added prior to the winter period. ERCOT has not performed a specific study of fuel supply vulnerability; generator owners and operators are responsible for assessing their fuel supply. The ERCOT Region is not generally 42 See “ERCOT Reserve Margin Analysis Report” located on the following website: http://www.ercot.com/calendar/2007/01/20070112-GATF 2009/2010 Winter Reliability Assessment Page 28 Regional Reliability Self-Assessments reliant on single gas pipelines or import paths such that the long-term outage of one of these types of lines or paths would lead to the loss of significant amounts of generating capacity. ERCOT does not expect significant capacity reduction implications due to water levels. While reservoir levels43 are currently below average, less than 1 percent of the ERCOT generation capacity is hydro. These facilities are typically operated as run-of-river or planned release due to downstream needs, and not operated specifically to produce electricity. Water necessary for cooling resources is not expected to be an issue during this period. If the drought-like weather continues over the longer period, then lack of water may become an issue. There are no other conditions expected within the ERCOT Region during the winter period that are expected to create capacity reductions. There are also no environmental or regulatory restrictions known at this time that would potentially impact capacity or reliability. Capacity Transactions on Peak ERCOT is a separate interconnection with only asynchronous ties to SPP and Mexico’s Comisión Federal de Electricidad (CFE) and does not share reserves with other Regions. There are two asynchronous (DC) ties between ERCOT and SPP with a total of 820 MW of transfer capability and three asynchronous ties between ERCOT and Mexico with a total of 280 MW of transfer capability. ERCOT does not rely on external resources to meet demand under normal operating conditions; however, under emergency support agreements with CFE and AEP, it may request external resources for emergency services over the asynchronous ties or by transferring block loads. One long-term contract for purchase of 48 MW of firm power from specific generation is an import from SPP. One-half of the asynchronous tie transfer capability is also included as an import (410 MW from SPP and 140 MW from CFE) due to emergency support arrangements. As a result, for the winter 2009/2010 season, ERCOT includes 458 MW as imports from SPP and 140 MW from CFE. Ownership by members of SPP of 247 MW of a power plant located in the ERCOT Region results in a firm export from ERCOT to SPP. There are no non-Firm contracts signed or pending. There are also no other known contracts under negotiation or under study. Transmission Several significant transmission improvements have been made throughout the ERCOT Region to meet reliability needs44. Dynamic reactive devices were installed in the Dallas area to improve voltage stability margins. A new 345/138 kV substation was constructed in the Tyler area. In the Dallas-Fort Worth area a new 345/138 kV autotransformer was installed and another one was replaced with a larger capacity autotransformer to meet load growth. North of Houston, a new 345 kV-switching station was constructed in order to allow for the reliable import of additional power into the Houston area. A 138 kV line was also upgraded to decrease Houston import congestion. A new 345 kV line, planned to be in-service in November, is being built through the city of Dallas in order to relieve congestion in the area. If this project 43 Reservoir levels can be found at: http://wiid.twdb.state.tx.us/ims/resinfo/bushbutton/lakestatus.asp 44 Additional details on transmission projects can be found in the “Transmission Constraints and Needs Report 2008” located on the following website: http://www.ercot.com/news/presentations/ Page 29 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments is delayed, reliability will continue to be ensured using existing congestion management techniques. Approximately 27 miles of new 345 kV lines have been completed since the 2008/2009 winter and 20.5 miles of upgraded 345 kV lines are expected to be completed during the 2009/2010 winter. Approximately 287 miles of new or upgraded 138 kV transmission lines were completed since the 2008/2009 winter and an additional 108 miles of new or upgraded 138 kV lines are expected to be completed by the end of the 2009/2010 winter period45. Table ERCOT-3: ERCOT Transmission Additions/Rebuilds Voltage New Upgraded 345kV 27.3 20.5 138kV 106.8 287.9 There are no known transmission constraints that are expected to significantly impact reliability across the ERCOT Region. The outage coordination process described in the Operational Issues section addresses many potential constraints. 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. Interregional transfers can provide support over the asynchronous ties or through block load transfers, but emergency support arrangements are not generally relied upon to resolve transmission reliability planning. Operational Issues ERCOT does not expect any unit or transmission outages, environmental or other unusual system conditions during this winter period that would impact reliability. Transmission outage plans are reviewed twice each year through discussions with the ERCOT transmission owners/operators, taking into account the known resource outages. Outage coordination begins approximately ninety days prior to real-time, when ERCOT Outage Coordination begins steady-state analysis of the ERCOT grid incorporating known stability limits. ERCOT continually studies outages, ensuring they are evaluated and coordinated; transmission outages are ultimately approved or rejected based on reliability until three days before the operating day. Several Special Protection Systems (SPS) have been implemented to resolve congestion more efficiently. The continued increase of installed wind generation has the potential to lead to operating challenges during the winter period. ERCOT has recently implemented a wind power forecasting system to allow ERCOT ISO system operators to identify and take appropriate action when wind resource schedules may not track expected changes in wind production. In addition, congestion management associated with the increased wind generation requires increased attention. As a result of transmission limitations, ERCOT does not expect issues this winter associated with base load unit commitment during minimum net load conditions. Finally, ERCOT evaluates the impact of increased wind generation on ancillary services requirements on an ongoing basis. 45 Details can be found on the following secure website: http://planning.ercot.com/reports/tpit/. Please note that registration is required to access this site. 2009/2010 Winter Reliability Assessment Page 30 Regional Reliability Self-Assessments Reliability Assessment Analysis The projected Reserve Margin for winter 2009/2010 is 67.8 percent, slightly higher than the 2008/2009 margin of 62 percent. This is well over the ERCOT Region minimum annual Reserve Margin of 12.5 percent. The ERCOT Reserve Margin is based on a loss-of-load expectation (LOLE) analysis of no more than one day in ten years loss of load. The LOLE study that was used to assess the adequacy of the 12.5 percent Reserve Margin criteria was completed in 200746. This Reserve Margin should be sufficient to cover, among other uncertainties, the potentially higher peak demand associated with the 10th percentile temperatures. 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 summer coincident system peak demand plus operating reserves. In the operations horizon, resource adequacy is maintained by ERCOT ISO through market-based procurement processes47. Transmission operating limits are adhered to through market-based generation redispatch directed by ERCOT ISO as the balancing authority and reliability coordinator. As the winter period approaches, ERCOT will perform 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. In addition, day-ahead studies are run to screen for possible resource deficiencies as well as potential delivery problems. Furthermore, ERCOT is increasingly using voltage and transient stability analysis to establish transfer limits and recommend transmission improvements. Generation capacity in ERCOT is fueled primarily by natural gas (69 percent) and coal (21 percent). ERCOT ISO does not coordinate directly with the fuel suppliers; ERCOT does perform a Regional survey to determine dual-fuel capabilities of generating units and reviews fuel studies completed by the Energy Information Administration48 (EIA) to determine if fuel availability issues are expected. As in past years, while ERCOT does not anticipate extreme winter weather to have an impact on fuel supply or fuel delivery, in extreme weather conditions, natural gas fuel supply becomes a primary concern due to heating demands. Fuel supply issues are typically reported to ERCOT by the affected generation entity as a resource de-rating or a forced outage. In the event of forecasted extreme weather and possible fuel curtailments, ERCOT may request fuel capability information from the scheduling entities that represent generation to better prepare operationally for potential curtailments49 46 See “ERCOT Reserve Margin Analysis Report” located on the following website: http://www.ercot.com/calendar/2007/01/20070112-GATF 47 See Sections 6 and 7 of the ERCOT Protocols found at http://www.ercot.com/mktrules/protocols/current 48 See the Short Term Energy Outlook from EIA at: http://www.eia.doe.gov/steo 49 See ERCOT Protocols Section 5.6.5 found at: http://www.ercot.com/mktrules/protocols/current. See also the ERCOT Operating Guides found at: http://www.ercot.com/mktrules/guides/operating/current Page 31 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments By maintaining appropriate voltage profiles50 at generating units and coordinating voltage- control equipment, it is possible to maintain transmission grid voltages at all points in ERCOT within acceptable operating voltage limits. Steady-state data sets are used to run a voltage profile study for the winter period. Specific dynamic reactive studies were not performed for the 2009/2010 winter network models. Region Description The ERCOT Region51 is a separate electric interconnection located entirely within the state of Texas. ERCOT is a summer-peaking Region covering 75 percent of the land area of Texas. ERCOT ISO serves over 21 million people, representing approximately 85 percent of the electric load in Texas, with an all-time peak demand of 63,400 MW52 set in July, 2009. The Texas Regional Entity (Texas RE)53, a functionally independent division of ERCOT, performs the Regional entity functions described in the Energy Policy Act of 2005 for the ERCOT Region. ERCOT ISO is the only Balancing Authority in the ERCOT Region. 50 Voltage profiles can be found at: http://www.ercot.com/gridinfo/generation/voltprof/ 51 For additional information, see “ERCOT Quick Facts May 2009” found in the key documents section of the following website: http://www.ercot.com/about/profile/ 52 This is a preliminary value; the value is not final until completion of the market’s financial settlement process six months after the operating day. 53 For additional information, see Texas RE website at: http://www.texasre.org 2009/2010 Winter Reliability Assessment Page 32 Regional Reliability Self-Assessments FRCC Regional Assessment Summary 2009/2010 Winter Projected Peak Demand MW On-Peak Capacity by Fuel Type Total Internal Demand 44,446 Direct Control Load Management 2,905 Dual Contractually Interruptible (Curtailable) 692 Gas Fuel Other Critical Peak-Pricing with Control 0 33% 3% 22% Load as a Capacity Resource 0 Net Internal Demand 40,846 Nuclear 8% 2008/2009 Winter Comparison MW % Change Oil Coal 2008/2009 Winter Projected Peak Demand 46,362 -11.9% 16% 18% 2008/2009 Winter Actual Peak Demand 45,604 -10.4% All-Time Winter Peak Demand 45,604 -10.4% 2009/2010 Winter Projected Peak Capacity MW Margin Existing Certain and Net Firm Transactions 55,881 67.5% Deliverable Capacity Resources 57,216 72.5% Prospective Capacity Resources 57,216 72.9% NERC Reference Margin Level - 15.0% Demand The Florida Reliability Coordinating Council (FRCC) is forecasted to reach its 2009/2010 winter peak demand of 44,446 MW in January, which represents a projected demand decrease of 2.6 percent over the actual 2008/2009 winter demand of 45,604 MW. This projection is consistent with historical weather-normalized FRCC demand growth and is 11.6 percent lower than last year’s winter forecast of 49,601 MW. The decrease in the 2009/2010 winter peak demand is attributed to a sluggish economy primarily driven by a declining housing market and higher energy prices as well as a modification to the winter demand forecast method aimed at reducing forecast errors.54 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 winter takes into consideration the overall economy in Florida with emphasis on the price of electricity. Each individual LSE within the FRCC Region develops a forecast that accounts for their actual peak demand. The individual peak demand forecasts are then aggregated by summing these forecasts to develop the FRCC Region forecast. These individual peak demand forecasts are coincident for each LSE but there is some diversity at the Region level. The entities within the FRCC Region plan their systems to meet the Reserve Margin criteria under both summer and winter peak demand conditions. There are a variety of energy efficiency programs implemented by entities throughout the FRCC Region. These programs can include commercial 54 https://www.frcc.com/Planning/Shared%20Documents/Load%20and%20Resource%20Plans/FRCC%202009%20Load%20and %20Resource%20Reliability%20Assessment.pdf Page 33 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments and residential audits (surveys) with incentives for duct testing and repair, high efficiency appliances (air conditioning, water heater, heat pumps, refrigeration, etc.) rebates and high efficiency lighting rebates.55 The 2009/2010 net internal FRCC peak demand forecast includes the effects of 3,600 MW (8 percent of Total Internal Demand) of potential demand reductions from the use of direct control load management and interruptible load management programs composed of residential, commercial and industrial demand. Entities within the FRCC use different methods to test and verify Direct Load programs such as actual load response to periodic testing, use of a time and temperature matrix and the number of customers participating. Projections also incorporate demand 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 percent confidence intervals on the projected or most likely load (90/10). The 80 percent confidence intervals on peak demand can be interpreted to mean that there is a 10 percent probability that in any year of the forecast horizon that actual observed load could exceed the high band. Likewise, there is a 10 percent probability that actual observed load in any year could be less than the low band in the confidence interval. The purpose of developing bandwidths on peak demand loads is to quantify uncertainties of demand at the Regional level. This would 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 winter’s forecast include a weaker Florida economy and projected higher fuel prices. Generation FRCC supply-side resources considered for the winter assessment are categorized as Existing- Certain, Existing-Other, and Existing Inoperable. The total Existing generation in the FRCC Region for this winter is 58,439 MW of which 53,343 MW (479 MW of biomass) are Existing- Certain, 908 MW are Existing Inoperable, and 4,188 MW (318 MW of biomass) are Existing- Other. The Region is expected to add 1,647 MW of Future-Planned generation for the winter season. The FRCC Region has a negligible amount of variable generation. The FRCC Region does not rely on hydro generation, therefore hydro conditions and reservoir levels will not impact the ability to meet the peak demand and the daily energy demand. For the 2009/2010 winter period, no load serving concerns are anticipated due to fuel supply vulnerabilities. For extreme weather conditions such as hurricanes affecting natural gas supply points, extreme temperatures or impacts to pipeline infrastructure, alternate short-term fuel supply availability continues to be adequate for the Region. There are no additional fuel availability or supply issues identified at this time and existing mitigation strategies continue to be refined. Based on recent studies, current fuel diversity, alternate fuel capability and fuel study results, the FRCC does not anticipate any fuel transportation issues affecting resource capability during peak periods and/or extreme weather conditions this winter. 55 Additional details can be found in the 10-Year Site Plan filing for each entity at the following link https://www.frcc.com/Planning/default.aspx?RootFolder=%2fPlanning%2fShared%20Documents%2fTen%20Year%20Site%2 0Plans%2f2009&FolderCTID=&View=%7bFBDE89E4%2dE66F%2d40EE%2d999D%2dCFF06CF2A726%7d 2009/2010 Winter Reliability Assessment Page 34 Regional Reliability Self-Assessments The FRCC Region has not identified any unit retirements that could have a significant impact on reliability. Progress Energy Florida’s 870 MW Crystal River Unit #3 (CR3) in Citrus County is presently in maintenance outage. Work is on schedule with the unit’s return to service expected before the winter peak season. While the unavailability of CR3 has minimal reliability impact to the Bulk Power System, in the unlikely event that the unit is not returned to service by the winter peak season, a mitigation plan has been developed as part of the FRCC Winter Assessment. Capacity Transactions on Peak Currently, there are 2,538 MW of generation under Firm contract that are available to be imported into the Region on a firm basis from the Southeastern Subregion of SERC. No portion of these contracts are from Liquidated Damages or “make whole” contracts. These purchases have firm transmission service to ensure deliverability into the FRCC Region. No Non-Firm or Expected transactions are included in the assessment. The FRCC Region does not rely on external resources for emergency imports and reserve sharing. However, there are emergency power contracts (as available) in place between SERC and FRCC members. Presently, the FRCC Region has no Firm winter contract exports into the Southeastern Subregion of SERC. The FRCC does not consider Non-Firm or Expected sales to other Regions as capacity resource reductions. Transmission Major additions to the FRCC bulk power system are mostly related to expansion in order to maintain the reliability of the transmission system. The most notable transmission additions placed in-service over the recent summer are the rebuild of two existing 230kV transmission lines in the Central Florida area. For the upcoming winter 2009/2010 there are no concerns in meeting targeted in-service dates for any new transmission line additions or upgrades. No significant substation equipment (i.e. SVC, FACTS controllers, HVdc, etc.) additions are expected. Presently there are no significant transmission lines expected to be out of service for the winter period. 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 new transmission lines and the rebuild of existing 230kV transmission lines are planned 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. 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 winter seasonal import capability of 3,800 MW into the Region, and an export capability of 1,900 MW. These joint studies account for constraints within the FRCC and/or the Southeastern Subregion of SERC. Page 35 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments Operational Issues FRCC expects the bulk transmission system to perform adequately over various system operating conditions with the ability to deliver the resources to meet the load requirements at the time of the winter peak demand. The results of the 2009/2010 Winter Transmission Assessment, which evaluated the steady-state winter peak load conditions under different operating scenarios, indicates that any concerns with thermal overloads or voltage conditions can be managed successfully by operator intervention. Such interventions may include generation redispatch, system sectionalizing, reactive device control, and transformer tap adjustments. The operating scenarios analyzed 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 amount of variable resources within the FRCC Region is negligible having no potential to cause over generation. Therefore, no operational changes are needed due to the integration of small amounts of variable resources. 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 2009/2010 winter period. Demand-Side Management load control programs within the FRCC are treated as “demand reduction” and not as a capacity resource. Therefore, high levels of demand reduction programs are considered to benefit reliability throughout the FRCC Region. No unusual operating conditions are expected that could impact reliability for the upcoming 2009/2010 winter season. 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 State of Florida to maintain a 15 percent Reserve Margin (20 percent for Investor Owned Utilities). Based on the expected load and generation capacity, the calculated Reserve Margin for the winter of 2009/2010 is 40 percent. This year’s calculated Reserve Margin is significantly higher than last year’s Reserve Margin calculation of 25 percent for the winter of 2008/2009 primarily related to a calibration of the winter forecast model.56 The expected Reserve Margin for this winter includes a total of 2,538 MW import from the Southeastern Subregion of SERC to the FRCC. The total import into the FRCC Region consists of 836 MW of generation residing in the Southeastern Subregion of SERC owned by FRCC 56 https://www.frcc.com/Planning/Shared%20Documents/Load%20and%20Resource%20Plans/FRCC%202009%20Load%20and %20Resource%20Reliability%20Assessment.pdf 2009/2010 Winter Reliability Assessment Page 36 Regional Reliability Self-Assessments entities and the remaining 1,702 MW are firm purchases. These imports account for 6.2 percent of the total Reserve Margin, and have firm transmission service to ensure deliverability into the FRCC Region. The FRCC has historically used the Loss Of Load Probability (LOLP) analysis to confirm the adequacy of reserve levels for peninsular Florida. The LOLP analysis incorporates system generating unit information (e.g., Availability Factors and Forced Outage Rates) to determine the probability that existing and planned resource additions will not be sufficient to serve forecasted loads. The objective of this study is to establish resource levels such that the specific resource adequacy criterion of a maximum LOLP of 0.1 day in a given year is not exceeded. The results of the most recent LOLP analysis conducted in 2009 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 below the 0.1 day per year criterion. Reactive power-limited areas are typically localized pockets that do not affect the bulk power system. The FRCC 2009/2010 Winter Transmission Assessment did not identify any reactive power-limited areas that would impact the bulk electric system during the upcoming winter season. The FRCC Operating Committee has developed the procedure, FRCC Communications Protocols – Reliability Coordinator, Generator Operators and Natural Gas Transportation Service Providers, to enhance the existing coordination between the FRCC Reliability Coordinator and the natural gas pipeline operators and in response to FERC Order 698. 57 For capacity constraints due to inadequate fuel supply, the FRCC State Capacity Emergency Coordinator (SCEC) along with the Reliability Coordinator (RC) have been provided with an enhanced ability to assess Regional fuel supply status by initiating Fuel Data Status reporting by Regional utilities. This process relies on utilities to report their actual and projected fuel availability along with alternate fuel capabilities, to serve their projected system loads. This is typically provided by type of fuel and expressed in terms relative to forecast loads or generic terms of unit output, depending on the event initiating the reporting process. Data is aggregated at the FRCC and is provided, from a Regional perspective, to the RC, SCEC and governing agencies as requested. Fuel Data Status reporting is typically performed when threats to Regional fuel availability have been identified and is quickly integrated into an enhanced Regional Daily Capacity Assessment Process along with various other coordination protocols to ensure accurate reliability assessments of the Region and also ensure optimal coordination to minimize impacts of Regional fuel supply issues and/or disruptions. Fuel supplies continue to be adequate for the Region and these supplies are not expected to be impacted by extreme weather during peak load conditions. There are no identified fuel availability or supply issues at this time. Based on current fuel diversity, alternate fuel capability and preliminary study results, the FRCC does not anticipate any fuel transportation issues affecting capability during peak periods and/or extreme weather conditions. 57 https://www.frcc.com/handbook/Shared%20Documents/EOP%20- %20Emergency%20Preparedness%20and%20Operations/FRCC%20Communications%20Protocols%20102207.pdf Page 37 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments Region Description FRCC’s membership includes 27 Regional Entity Division members and 25 Member Services Division members, which is composed of investor-owned utilities, cooperative systems, municipal utilities, power marketers, and independent power producers. The FRCC Region is divided into 11 Balancing Authorities. As part of the transition to the ERO, FRCC has registered 70 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). 2009/2010 Winter Reliability Assessment Page 38 Regional Reliability Self-Assessments MRO Regional Assessment Summary 2009/2010 Winter Projected Peak Demand MW On-Peak Capacity by Fuel Type Total Internal Demand 42,481 Nuclear Direct Control Load Management 810 8% Coal Contractually Interruptible (Curtailable) 1,380 46% Critical Peak-Pricing with Control 0 Load as a Capacity Resource* 0 Gas Net Internal Demand 40,291 15% Dual Hydro 2008/2009 Winter Comparison MW % Change Fuel 10% 2008/2009 Winter Projected Peak Demand 41,539 -3.0% Wind Other 7% 2008/2009 Winter Actual Peak Demand 43,317 -7.0% 2% Oil 2% All-Time Winter Peak Demand 43,317 -7.0% 4% 2009/2010 Winter Projected Peak Capacity MW Margin Existing Certain and Net Firm Transactions 56,643 40.6% Deliverable Capacity Resources 56,946 41.3% Prospective Capacity Resources 58,118 44.2% NERC Reference Margin Level - 15.0% *Note: MRO has classified an additional 44 MW of Demand Response as a supply resource which does not reduce Total Internal Demand. Demand The MRO’s forecasted 2009/2010 Winter Non-Coincident Peak Total Internal Demand in the combined MRO US and MRO Canada is 42,480 MW, assuming normal weather conditions. This forecast is 1.4 percent below last winter’s forecasted total demand of 43,080 MW and 1.9 percent lower than last year’s actual winter peak demand of 43,317 MW. Any interruptible demand or DSM implemented during last year’s peak load is unknown. The MRO 2009/2010 winter forecast Net Internal Demand is 40,291 MW, which is 3.0 percent lower than the 2008/2009 winter forecasted Net Internal Demand of 41,539 MW. The recession and nation- wide economic downturn are the main reasons for the slight decrease in forecast. Peak demand uncertainty and variability due to extreme weather and/or other conditions are accounted for within the determination of adequate generation Reserve Margin levels. Both the MAPP Generation Reserve Sharing Pool (GRSP) members and the former MAIN members within MRO use a Load Forecast Uncertainty (LFU) factor within the calculation for the Loss of Load Expectation (LOLE) and/or the percentage Reserve Margin necessary to obtain a LOLE of 0.1 day per year or 1 day in 10 years.58 The load forecast uncertainty considers uncertainties attributable to weather and economic conditions. Forecasts are developed for Saskatchewan to cover possible ranges in economic variations and other uncertainties such as weather using a Monte Carlo simulation model to reflect those uncertainties. 58 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 39 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments Each MRO member uses its own forecasting method, meaning some may use a 50/50 forecast and some may use a 90/10 forecast. In general, the peak demand forecast includes factors involving recent economic trends (industrial, commercial, agricultural, residential) and normal weather patterns. From a Regional perspective, there were no changes in this year’s forecast assumptions in comparison to last year. MRO staff distributed the NERC Winter 2009/2010 data request spreadsheet to each LSE member within the MRO in the format it was received from NERC. The members populated these spreadsheets based on NERC and MRO instructions and submitted them back to the MRO for processing by a predetermined due date. Internally, MRO staff compiled the individual spreadsheet submissions into a set of Regional spreadsheets representing the MRO Region as a whole as well as MRO U.S. and MRO Canada. When the spreadsheet was initially distributed, MRO instructions emphasized to the LSEs that each MW of demand must be counted once and only once and that LSEs should carefully coordinate with their neighboring LSEs to ensure that double-counting would not occur in the Regional compilations. Interruptible Demand (1,380 MW, 3.3 percent) and Direct Controlled Load Management (DCLM) (810 MW, 1.9 percent) programs, amounting to 5.2 percent of the MRO’s Projected Total Internal Peak Demand of 42,481 MW are used by a number of MRO members. A wide variety of programs, including direct load control (such as electric appliance cycling) and interruptible load may be used to reduce peak demand during the winter season. Reductions in demand due to energy efficiency are not known at this time. Saskatchewan Being an MRO member and one of the six Planning Authorities registered within the MRO footprint, Saskatchewan Power Corporation (SaskPower) develops annual energy and peak demand forecasts based on a provincial econometric model and forecasted industrial load data. Weather can have a significant impact on the amount of electricity consumed by non-industrial customers. Due to this weather sensitivity, average daily weather conditions for the last thirty years are assumed to develop the energy forecast. The winter peak load is forecasted on a heating season basis and represents the highest level of demand placed on the supply system. The winter forecast is normalized to account for cold weather based on a 30-year average weather pattern. The factors that contribute to the peak load include time of day, seasonal variations, industrial load and weather conditions. Seasonal variations include Christmas lighting, increased lighting load due to shorter daylight hours and increased shopping hours. The peak load forecast assumes that sustained cold weather will occur during the month of December. Forecasts are developed for Saskatchewan to cover possible ranges in economic variations and other uncertainties such as weather using a Monte Carlo simulation model to reflect those uncertainties. This model considers each variable to be independent from other variables and 2009/2010 Winter Reliability Assessment Page 40 Regional Reliability Self-Assessments assumes the distribution curve of a probability of occurrence of a given result to be normal. Results are based on an 80 percent confidence interval. This means that a probability of 80 percent is attached to the likelihood of the load falling within the bounds created by the high and low forecasts. Saskatchewan has energy efficiency programs designed to help customers save power, save money and help the environment. These programs include energy-efficiency, conservation, education, and load management programs. Residential programs focus on consumer education on energy efficiency and market transformation of lighting, appliances and furnace motors including retailer/ manufacturer partnerships and end-user incentives. Commercial and industrial programs include energy performance contracting, energy audits, and information services for facility operators. Saskatchewan is currently establishing an evaluation framework for this program, which includes measurement and verification for programs based on industry standard protocols. Generation The Existing-Certain resources for the MRO US and Canada 2009/2010 winter are 56,623 MW. The Existing-Other and Inoperable resources for the MRO US and Canada 2009/2010 winter are 6,719 MW. Planned resources expected to be in service this winter are 478 MW. These values do not include firm or non-firm purchases and sales. The month of January was used in all cases to be consistent. The nameplate capacity of the wind generation for the MRO is 6,396 MW. The wind resources for the MRO expected to be available at peak times is 1,271 MW, based on 20 percent of nameplate capacity. The Midwest ISO is using the 20 percent of nameplate capacity rule in determining capacity of wind generation. The biomass portion of resources for the MRO expected to be available at peak times is 242 MW. Reservoir water levels have improved over the past few years, but continue to remain below normal in Montana, North Dakota, and South Dakota, and will likely continue to reduce the magnitude and duration of power transfers (on an energy basis) out of northern MRO. This will continue to contribute to the imports of power into the MRO Region during peak load periods. The Manitoba water condition is normal and normal Manitoba-US transfers are expected. Manitoba Hydro manages its reservoir levels in preparation for the winter season such that there is adequate energy to meet daily energy demand throughout the winter. SaskPower reservoirs are at normal conditions and regular operating regimes are expected. Reservoir levels are sufficient to meet both peak demand and the daily energy demand throughout the upcoming system. SaskPower reservoirs are sufficiently large enough to meet daily requirements, and current hydrological conditions are expected to be normal during the upcoming season. Page 41 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments Environmental and regulatory requirements prevent continued operations of the Manitoba Hydro Brandon #5 generating unit (100 MW). This, however, will not impact the reliability of the interconnected system since there are two gas turbine generating units (140 MW each) at the station. Capacity Transactions on Peak For the 2009/2010 winter season, the MRO is projecting total firm purchases of 1,501 MW. These purchases are from sources external to the MRO Region. The MRO has approximately 1,481 MW of total projected sales to load outside of the MRO Region. The net import/export of the MRO Region can vary at peak load, depending on system conditions and market conditions. Transfer capability from MRO Canada (Saskatchewan and Manitoba) into the MRO US is limited to 2,415 MW due to the operating security limits of the two interfaces between these two provinces and the U.S. The forecasted firm transfers from Manitoba to the U.S. are 630 MW for the 2009/2010 winter. Saskatchewan has a firm import of 50 MW scheduled for the December 2009 to February 2010 reporting period. All of the energy contracts is firm and has firm transmission reserved. Throughout the MRO Region, firm transmission service is required for all generation resources that provide firm capacity; also meaning that these firm generation resources are fully deliverable to the load. The MRO is forecast to meet the various Reserve Margin targets without needing to include energy-only, uncertain, or transmission-limited resources. Different transmission providers within the MRO Region treat Liquidated Damage Contracts (LDC) according to their tariff policies. Most MRO members are within non-retail access jurisdictions (except for Upper Michigan) and therefore liquidated damages products are not typically used. Transmission Reliability Margins (TRM) are calculated and reserved by the Transmission Providers within the MRO Region to assure that operating reserves can adequately be delivered. TRM includes a contingency component and an uncertainty component on a flowgate such that operating reserves for the worst single contingency can be reliably delivered from the operating reserve sharing group. Most MRO members participate in the Midwest Contingency Reserve Sharing Group (CRSG) and will be able to call for resources as operating reserves from the members of the Midwest CRSG outside of the MRO Region in case of emergency. Transmission The following reinforcements include projects that have expected service dates from June 1, 2009 through December 2009. Several projects went in service prior to June 1, 2009, and are also listed in the 2009 summer assessment. 2009/2010 Winter Reliability Assessment Page 42 Regional Reliability Self-Assessments Iowa New wind farm generation, Whispering Willows and Crane Creek wind farms, is planned to be in service prior to (or during) this winter season. The Whispering Willows facility affects the Iowa transmission system. Several transmission enhancement projects are expected to be completed by the end of 2009: The Arnold-Vinton-Dysart-Washburn 161kV rebuild/reconductoring project The Fernald-Story County line rebuild, the Adams-Barton rebuild The Ground Mound 161 kV upgrades The Butler-Union Tap 161 kV line reconductoring The Crane Creek wind farm ties to the transmission system at Rice 161 kV in Northern Iowa and mainly affects the southern Minnesota areas. The transmission upgrades needed to accommodate the facility is described under the Northern MRO area discussions below. Nebraska Phase 2 of Nebraska Public Power District’s (NPPD) Electric Transmission Reliability (ETR) Project for East-Central Nebraska is expected to be energized in October of 2009. Phase 2 of the ETR Project includes the construction of 12 miles of new 345 kV transmission line from Shell Creek to Columbus East and expansion of the Columbus East 345/230/115 kV Substation. Completion of this phase of the project will improve local area voltage support. Phase 3 of the ETR Project includes the construction of 67 miles of new 345 kV transmission line from Columbus East to Lincoln Electric System’s (LES) NW 68th & Holdrege and the expansion of the NW 68th & Holdrege 345 kV Substation. This final project phase is currently expected to be completed in January 2010. The completion of this project will address peak load voltage issues and enhance the reliability of the eastern Nebraska Regional transmission system. A new third Grand Island 345/230 kV transformer was placed in-service in July 2009. This transformer was installed to address the contingency loading issues associated with the existing two 250 MVA 345/230 kV transformers at the Grand Island Substation. A 115 kV interconnection line between the LES 20th & Pioneers Substation and NPPD Sheldon Substation will be out of service from October 2009 to May 2010. This line is being rebuilt and will have a higher thermal capacity when completed. This is expected to reduce contingent overload issues in the local transmission area. The line outage during this time period is expected to have minimal impact on local power flows. Temporary operating guides will be issued for this outage if actions or limitations are required to protect system operating limits. Page 43 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments Northern MRO59 Dairyland Power Cooperative (DPC) has scheduled an outage to its Rochester-Adams and Beaver Creek-Harmony 161 kV lines for upgrades during the 2009/2010 winter season. The Rochester-Adams 161 kV outage is scheduled for this winter season. During this outage, final structure upgrades will be completed to accommodate reconductoring of this line with a 795 MCM ACSS conductor. Prior to this outage, phase raisers were installed under a live line permit to facilitate the new conductor. Likewise, the Beaver Creek-Harmony 161 kV line is schedule for a similar upgrade early in 2010. This line will also be reconductored with a 795 MCM ACSS conductor, and phase raisers will be used for the bulk of the structure improvements required to accommodate the new conductor. Note that Midwest ISO prior outage guides will be developed for these outages, and no operating problems are expected. The Integrated System of Basin Electric Power Cooperative-Western subregion Power Administration-Heartland Consumers Power District will energize a substation at Neset, North Dakota. This is a new 230/115 kV substation with a 125 MVA transformer that will sit in parallel to the nearby existing Tioga 230 kV substation. The Tioga 230 kV substation 100 MVA transformer will be replaced by a new 125 MVA 230/115 kV transformer. The additional transformer capacity in the area will be used to support load growth in the Region and imports/exports with Saskatchewan. The additions are anticipated to be in service October 2009. A new substation on the Little Missouri-Bowman 230 kV line called Rhame substation and 230kV transmission line from Rhame to Belfield substation are anticipated to be in service mid- January. This line will help with load and voltage support in the Region. In the Otter Tail Power Company system, the existing transmission can support 150 MW of new wind generation, which will be coming on line before the winter season at Rugby, North Dakota. No additional transmission facilities will be added. In the Minnkota Power Cooperative system, 358 MW of wind generation development near Fargo, ND will be installed at the Maple River 230 kV bus by December 2009. Constraints may occur on the 230 kV network lines in the Fargo area, for which upgrades are still pending. These constraints are addressed by a Special Protection System and operating guides which specify conditions requiring generation curtailment. Great River Energy (GRE) projects that have been added since 2008/2009 winter include: Elk River 14 Substation: A new 230 kV ring bus was installed in support of the new Elk River Generation Station, a 175 MW simple cycle gas turbine put in service in July 2009. There are now ring positions for the Bunker Lake and Monticello 230 kV lines, both 187 MVA 230/69 kV autotransformers, and the generation connection. Long Lake – Badoura 115 kV Line: A new 115 kV line connection between GRE’s Long Lake Substation and Minnesota Power’s (MP) Badoura Substation is expected to be completed by October 2009. 59 Northern MRO consists of the electric systems in eastern Montana, North Dakota, South Dakota, Minnesota, and Manitoba. 2009/2010 Winter Reliability Assessment Page 44 Regional Reliability Self-Assessments Tamarac Substation: 115 kV breakers were installed at Tamarac dividing the 115 kV line between Fergus Falls and Frazee. A 20 MVAr capacitor bank was installed on the 115 kV bus for voltage support. GRE has a scheduled outage on the 230 kV Line between Ramsey and Prairie scheduled for early 2010. There are no other anticipated outages or transmission additions that could impact reliability during the winter. Minnesota Power will commission the new Embarrass 115 kV substation in the fall of 2009. The new substation will have lines connecting to existing Virginia, Babbitt, and Laskin 115 kV substations. There will also be a new line built to connect to GRE's new Tower 115 kV sub. The new ring bus configuration will provide greater reliability for the area than the line tap that it replaces. Minnesota Power will also commission the new Pine River 115 kV substation in its Western Division this winter. The Pine River Substation will be connected to Badoura via a new line. Additionally, the Badoura bus will be changed to a ring bus configuration with a new line to GRE's Long Lake Substation. These upgrades will primarily provide more load serving capability in the area. Boswell unit 3 will be coming online at the end of October 2009 after an extended outage for environmental retrofits. Although the Bulk Electric System reliability will not be compromised, it will likely take most of the winter to adjust the new equipment at the unit for optimum performance. Wisconsin-Upper Michigan Systems (WUMS) Major transmission additions expected to be in-service between July and December 2009 are listed in the following. There are no concerns in meeting the targeted in-service dates of these projects. Construct an Iron Grove-Aspen 138 kV line. In-service in August 2009. Construct a Highway 22-Morgan 345 kV line. In-service in October 2009. Construct a Jefferson-Lake Mills-Stony Brook 138 kV line. In-service in October 2009. Inter-Regional Transfers The following information is based on the MRO/RFC/SPP/SERC-W 2008/2009 Winter Inter- regional Assessment, from which the total transfer capabilities listed below may be used for the purposes of this assessment. Non-simultaneous Total Import Capabilities into MRO from RFC-W, SERC-W, and SPP Regions: TIC Transfer Direction (MW) RFC_W TO MRO 3,064 SERC_W TO MRO 3,764 SPP TO MRO 3,164 Page 45 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments The Total Import Capability (TIC) is equal to the net import into MRO (1,964 MW) in the base case plus the First Contingency Incremental Transfer Capability (FCITC) obtained in the transfer analysis. The Inter-regional Assessment recognized constraints internal and external to the MRO. Operational Issues The Midwest ISO as a Reliability Coordinator and Balancing Authority does not expect any reliability concerns resulting from wind generation during minimum demand and over generation conditions for the 2009/2010 Winter Assessment period. At the present levels of nameplate wind generation, the Midwest ISO is able to manage ramp rates and volatility without any reliability concerns. The Midwest ISO’s Public Emergency Procedure RTO-EOP-003 Supply Surplus Procedure steps the Reliability Coordinator and Balancing Authority through necessary steps to continuously balance load and generation during minimum generation events, and this procedure includes variable resources as necessary. The maximum ramp down per hour in the MRO Region has been approximately 1,200 MW thus far and is managed though Region-wide forecasting that has proven to be routinely accurate to +/-10 percent out to 24 hrs. The MRO does not expect any reliability concerns resulting from high-levels of Demand Response resources. There are no known environmental or regulatory restrictions that could impact reliability during the 2009/2010 winter season. The MRO Region has approximately 6,400 MW of nameplate wind generation. There is 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 and there may be a potential increase in operating reserves that could be required for this wind generation during ambient temperature limitations. Accurate forecasting will help to identify any near-term concerns regarding ambient temperature limits. Iowa MidAmerican Energy Company has joined the Midwest ISO as a transmission-owning member. MidAmerican Energy turned over functional control of its transmission system to Midwest ISO on September 1, 2009. Two other Iowa utilities, Muscatine Power and Water and the Municipal Electric Utility of Cedar Falls, also joined the Midwest ISO. A strong south-to-north system bias across the transmission system in Iowa is again expected during winter 2009/2010. This bias may cause NERC TLR/LMP binding processes to be implemented to maintain the system operating parameters within system operating limits. However, reliable operation of the transmission system is expected in Iowa during winter 2009/2010. A significant number of generator and line outages have been scheduled to be completed during period from September 2009 to April 2010. These outages might cause congestion management mechanisms to be implemented and occasional limitations on wind generation outputs. 2009/2010 Winter Reliability Assessment Page 46 Regional Reliability Self-Assessments Temporary operating guides will be developed and issued whenever outage-scheduling studies or operational studies indicate a potential post-contingency overload or voltage limit violation. Nebraska No significant operational concerns are expected in Nebraska during winter 2009/2010. In the past, the eastern Nebraska transmission system has experienced heavy south-to-north transfers due to low water conditions and winter peak load conditions in northern MRO. These south-to-north transfers across the MRO system have a more profound impact on the eastern Nebraska system than on the western Nebraska system. All of the Nebraska area flowgates have approved operating guides that have proven effective in dealing with system conditions throughout the year. Winter season load distributions are considered worst case for western Nebraska area stability. Operating guides have been developed which adequately protect the western Nebraska Region for winter season load levels and maximum transfer conditions. Northern MRO No significant operational issues are expected this winter for the Northern MRO Region. Reservoir water levels have improved but continue to remain low throughout the northern U.S. MRO Region (Montana, North Dakota, and South Dakota). Hydro unit limitations continue in the winter due to requirements for endangered species and limitation due to flow of river restrictions. These issues coupled with maintenance outages will likely continue to reduce the magnitude and duration of exports out of northern MRO, and also continue to contribute to the recent significant imports of power into the MRO Region. The Manitoba water condition is normal. Therefore, normal Manitoba-US exports are likely. A number of bulk transmission outages are scheduled in the northern US MRO Region for construction and maintenance; however, no operating problems are expected. Temporary operating guides will be developed as necessary. Several large wind generation additions to the northern US MRO area are expected this winter. In conclusion, a typical winter flow pattern characterized by a south-to-north system bias is expected to re-occur this winter season. These heavy south-to-north power transfers will likely cause some TLR/Congestion Management activities. Overall, the northern MRO system is expected to operate under all load and firm exchange levels while meeting the Regional reliability criteria. Wisconsin-Upper Michigan Systems (WUMS) Significant increases in wind generation have occurred within the MRO-US Region. Approximately 5,000 MW of nameplate wind generation existed on December 1, 2008. This will increase to about 6,400 MW of nameplate by December 1, 2009. Page 47 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments It has been observed that the rapid increase or decrease of the overall high or low levels of wind generation in Iowa and Minnesota can have a significant impact on the flows through the WUMS western and southern interfaces, namely MWEX and SOUTH TIE interfaces, respectively. American Transmission Company LLC (ATCLLC) and the Midwest ISO are monitoring this operational issue closely. An operational study performed hourly by the Midwest ISO anticipates the impacts of the sudden change in wind generation in Iowa and Minnesota on a number of selected flowgates. Operators will be alerted when the study results show the loading of any monitored flowgate comes within 95 percent of its rating. ATCLLC also analyzes the data and trends related to this operational issue monthly to be better prepared for managing the potentially impacted flowgates, particularly the MWEX and SOUTH TIE interfaces, looking forward. The eastern portion of the Upper Peninsula of Michigan (UP) experiences flows in both west to east and east to west directions. Heavy flows in either direction can cause potential thermal and voltage violations in the eastern UP. These constraints are managed by opening the 69 kV lines between the eastern UP and the rest of the WUMS system, using procedures defined in an operating guide. Reliability Assessment Analysis The MRO Reliability Assessment Committee is responsible for the seasonal assessments. The MRO Transmission Assessment Subcommittee, MRO Resource Assessment Subcommittee, the MAPP Transmission Operations Subcommittee, the ATCLLC and Saskatchewan Power Corporation all contribute to this MRO seasonal Reliability Assessment. To prepare this MRO Regional self-assessment, MRO staff sent the NERC spreadsheets to the registered entities within the MRO and collected individual entity’s load forecast, generation, and Demand-Side Management data. The staff then combined the individual inputs from these spreadsheets to calculate the MRO Regional totals. The staff also sought responses to the questions included in the NERC seasonal request letter, from Planning Authorities within the MRO Region – MAPP, ATCLLC, and SaskPower. The MAPP Transmission Operations Subcommittee provided detail from the various MAPP operating groups. Using the information gathered from this process, the MRO Resource Assessment Subcommittee prepared the resource assessment portions, while the Transmission Assessment Subcommittee prepared the transmission assessment and operational issues portions. Finally, the MRO Reliability Assessment Committee, which is ultimately responsible for the long-term reliability assessments, reviewed and approved the final draft before it was submitted to NERC. The MRO’s projected 2009/2010 Winter Reserve Margin is 41.3 percent without existing uncertain resources. The projected MRO Reserve Margin of 41.3 percent for the upcoming winter season, compared with last winter’s projected Reserve Margin of 35.2 percent, is in excess of the target Reserve Margins. For the MAPP GRSP, resource adequacy is measured through its accreditation rules and procedures.60 The MAPP GRSP requires a 15 percent Reserve Capacity Obligation for predominantly thermal systems, and 10 percent Reserve Capacity Obligation for predominantly 60 MAPP Generation Reserve Sharing Pool Handbook; Revision May 27, 2009: http://www.mapp.org/ReturnBinary.aspx?Params=584e5b5f405b5072400a0d0a253b2c1518270c0754410e4413525c48421749 0e0b10002025053b0a0323 2009/2010 Winter Reliability Assessment Page 48 Regional Reliability Self-Assessments hydro systems, based on previously conducted LOLE studies. Approximately 8,850 MW of generation in the MAPP GRSP (15.7 percent of MRO net capacity) is associated with predominantly hydro systems and only requires a 10 percent Reserve Obligation. The projected MRO Reserve Margin of 41.3 percent for the 2009/2010 winter season is in excess of the target margin. The Midwest ISO has conducted a Loss of Load study establishing a 12.69 percent Reserve Margin requirement for all Midwest ISO load serving entities. Saskatchewan's reliability criterion is based on annual expected un-served energy (EUE) analysis and equates to an approximate 13 percent Reserve Margin. The projected MRO Reserve Margin of 41.3 percent for the 2009/2010 winter season is in excess of these target Reserve Margins. As in last year’s winter assessment, MRO staff attempted to include all IPP megawatts as an internal resource, not as a purchase. Most large IPPs that are registered as Generator Owners within the MRO were properly captured. However, there are smaller IPPs within the MRO that fall below registration criteria that have not been entirely captured. These additional IPPs would likely increase the projected capacity and Reserve Margins by a minimal amount. Throughout the MRO Region, firm transmission service is required for all generation resources that are used to provide firm capacity; also meaning that these firm generation resources are fully deliverable to the load. The MRO expects to meet the various Reserve Margin targets without needing to include energy-only, uncertain, or transmission-limited resources. 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. The MRO Region considers known and anticipated fuel supply or delivery issues in its assessment. Because the Region has a large diversity in fuel supply, inventory management, and delivery methods, the MRO does not have a specific mitigation procedure in place should fuel delivery problems occur. The MRO members do not foresee any significant fuel supply and/or fuel delivery issues for the upcoming 2009/2010 winter season. However, if problems occur, they will be addressed on a case by case basis. Therefore, there should be no apparent impacts to the reliability of meeting peak electrical demand. Fuel-supply coordination or interruption in Saskatchewan is generally not considered an issue due to system design and operating practices for the following reasons: Coal resources have firm contracts, are mine-to-mouth, and stockpiles are maintained at each facility in the event that mine operations are unable to meet the required demand of the generating facility. Typically there are 20 days of on-site stockpile for each of the coal facilities which in total represent approximately 47 percent of total provincial installed capacity. Strip coal reserves are also available and only need to be loaded and hauled from the mine. These reserves range from 30 to 65 days depending on the plant. Natural gas resources have firm on-peak transportation contracts with large natural gas storage facilities located within the province to back the contracts. Page 49 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments Hydro facilities/reservoirs are fully controlled by SaskPower. Typically, Saskatchewan does not rely on external generation resources. Transient, voltage and small signal stability studies are performed as part of the near-term/long- term transmission assessments. Voltage stability is also evaluated in the Midwest ISO’s seasonal assessment. The results of the Midwest ISO winter assessment were not available prior to the due date of this Regional assessment. Reactive power resources are considered in on-going operational planning studies. No transient, voltage, or small signal stability issues are expected that impact reliability during the 2009/2010 winter season. Dynamic reactive margin is part of the ATCLLC Planning Criteria, which is determined using a reduction to the reported reactive capability of synchronous machines. A 10 percent dynamic reactive margin is required in the intact system and a 5 percent dynamic reactive margin is required under NERC Category B contingencies. This criterion is applied in the ATCLLC planning 10-year assessment studies. Region Description The MRO has 116 registered entities. There are seven Balancing Authorities: NPPD, OPPD, LES, SPC, MH, WAPA and Midwest ISO, which assumes all tariff members under Midwest ISO operate as one Balancing Authority. The MRO Region as a whole is a summer peaking Region. The MRO Region covers all or portions of Iowa, Illinois, Minnesota, Nebraska, North and South Dakota, Michigan, Montana, Wisconsin, and the provinces of Manitoba and Saskatchewan. The total geographic area is approximately 1,000,000 square miles with an approximate population of 20 million. The MRO has six Planning Authorities registered within the footprint: the Midwest ISO, MAPP, American Transmission Company, Southwest Power Pool, Manitoba Hydro, and SaskPower. The Midwest ISO also spans into the RFC and SERC Regions. There are three Reliability Coordinators within the MRO footprint, the Midwest ISO, Southwest Power Pool, and SaskPower. The majority of Registered Entities within MRO are Midwest ISO tariff members and therefore participate in the Midwest ISO market operations. The Nebraska utilities fall under the Southwest Power Pool tariff and Reliability Coordinator. 2009/2010 Winter Reliability Assessment Page 50 Regional Reliability Self-Assessments Reference Documents 2008 – ATCLLC 10-Year Transmission System Assessment Update, http://www.atc10yearplan.com Midwest ISO Winter 2009/2010 Coordinated Seasonal Transmission Assessment (in progress), http://www.midwestiso.org/home Reliability First Corporation (RFC) Winter 2009/2010 Transmission Assessment Study (on- going), http://www.maininc.org/ Eastern Interconnection Reliability Assessment Group (ERAG) Winter 2008/2009 Inter-regional Transmission Assessment, MRO-RFC-SERC West-SPP (MRSWS) sub-group study (on-going) Fall, Winter and Spring Peak Operational Studies performed by NPPD Transmission Planning Department, 2009 MEC-Operational and Outage Studies conducted by System Operations Department, June- September 2009 2008 Baseline Reliability Study-Steady State Analysis, MidAmerican Energy Company, December 9, 2008 NMORWG Winter Peak sensitivity reviews and voltage stability analysis, pre-winter 2008/2009. 2009 MAPP System Performance Assessment MAPP Small Signal Stability Analysis Project Report, June 2007 MAPP Members Reliability Criteria and Study Procedures Manual, April, 2009. SaskPower 2009 Supply Development Plan SaskPower 2009 Load Forecast Report Manitoba Hydro - Saskatchewan Power Seasonal Operating Guideline on Manitoba- Saskatchewan Transfer Capability Page 51 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments NPCC Regional Assessment Summary 2009/2010 Winter Projected Peak Demand MW On-Peak Capacity by Fuel Type Total Internal Demand 111,559 Direct Control Load Management 250 Gas Dual Contractually Interruptible (Curtailable) 1,643 14% Fuel Other Critical Peak-Pricing with Control 0 Nuclear 14% 17% 6% Load as a Capacity Resource* 1,954 Coal Net Internal Demand 107,712 8% 2008/2009 Winter Comparison MW % Change Hydro 2008/2009 Winter Projected Peak Demand 106,874 0.8% 34% Oil 2008/2009 Winter Actual Peak Demand 110,764 -2.8% 8% All-Time Winter Peak Demand 116,284 -7.4% 2009/2010 Winter Projected Peak Capacity MW Margin Existing Certain and Net Firm Transactions 151,702 40.8% Deliverable Capacity Resources 151,834 41.0% Prospective Capacity Resources 149,432 38.7% NERC Reference Margin Level** - 15.0% *Note: NPCC has classified an additional 3,343 MW of Demand Response as a supply resource which does not reduce Total Internal Demand. **Refer to the NPCC LOLE criterion imposed on each subregion as presented in the NPCC Resource Adequacy Assessment Section The five NPCC subregions, or subregions, are defined by the following footprints: the Maritimes subregion (the New Brunswick System Operator, Nova Scotia Power Inc., the Maritime Electric Company Ltd. and the Northern Maine Independent System Administrator, Inc); New England (the ISO New England Inc.); New York (New York ISO); Ontario (Independent Electricity System Operator); and Québec (Hydro-Québec TransÉnergie). Demand The NPCC Region includes both summer peaking and winter peaking systems. The Maritimes subregion and the Québec subregion are winter peaking systems; Ontario, New York and New England are summer peaking systems. Due to milder than forecasted weather, the actual peak loads experienced during the winter of 2008/2009 were below forecasts in four of the five NPCC subregions; the subregion of Québec exceeded its forecast peak load for the 2008/2009 winter period by almost 700 MW due to a period of extreme cold in January. All NPCC subregions are currently experiencing the impact of the economic downturn in its projected system load. Demand forecasts for the 2009/2010 winter are lower than last winter’s forecasts for all five NPCC subregions, mainly due to the slowdown of economic activity. 2009/2010 Winter Reliability Assessment Page 52 Regional Reliability Self-Assessments When compared with projections for the 2009/2010 winter in the following table, the New England, New York, Ontario and Québec subregions are projecting Reserve Margins similar to or higher than the Reserve Margins projected for the 2008/2009 winter: The Maritimes subregion is projecting a lower Reserve Margin due to the continuing outage of the Point Lepreau nuclear unit, however, the Maritimes Reserve Margin is projected to be adequate with a forecast of 25 percent. Table NPCC-1: NPCC Demands and Reserve Margins NPCC 2008/2009 2008/2009 2009/2010 2009/2010 Balancing Forecasted Actual Peak Forecasted Forecasted Authority Peak (MW) (MW) Peak Reserve subregion (MW) Margin (%) Maritimes 5,547 5,504 5,514 25.0 New England 23,030 21,022 22,100 64.3 New York 25,293 24,673 24,998 54.3 Ontario 23,710 22,983 22,848 29.1 Québec 36,533 37,230 36,116 12.7 Transmission The NPCC transmission system is expected to perform adequately, and several enhancements to the NPCC transmission system have been made since the 2008/2009 Winter. The significant additions include: In New England, the Middletown–Norwalk phase of the Southwest Connecticut Reliability Project (SWCTRP) installed several new 345 kV overhead and underground circuits, approximately 70 miles in length, along with several 345/115 kV autotransformers within the area. The overhead portion extends from the Beseck substation in Middletown to the East Devon substation. Cables extend from East Devon to the Singer substation in Bridgeport and on to the Norwalk substation. In northern New York, two substations have been added on the Willis – Plattsburg 230kV circuits for connecting wind farms, and three substations around Stolle Rd – Meyer 230kV also for wind farm connections. The forced outage to the 230 kV circuit BP76 on the Ontario-New York interconnection at Niagara reduces the total Ontario-New York import and export capability until its scheduled return to service in the third quarter of 2010. The Millwood 345 kV 240 MVar capacitor bank was added in summer 2009 for added voltage support in the lower Hudson Valley. On July 2, 2009, TransÉnergie commissioned the first HVdc converter of the new Outaouais substation and its interconnection with IESO in the Ottawa-Gatineau area across the Ottawa River. The interconnection consists of two 625-MW back-to-back HVdc converters in Québec and a double-circuit 240 kV line to Hawthorne substation in Ottawa. On the Québec side of the converters, a 315 kV switchyard integrates the interconnection into the existing system. The Chénier 735/315 kV substation, north of Montréal is the source station feeding this interconnection. The second converter is Page 53 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments scheduled for commissioning in November 2009 and both converters will be available for the 2009/2010 Winter Operating Period. Resource Adequacy Assessment Through numerous studies and reviews, the NPCC Task Force on Coordination of Planning (TFCP) ensures that the proposed resources of each NPCC subregion will comply with NPCC Document A-02, “Basic Criteria for Design and Operation of Interconnected Power Systems.”61 Section 3.0 of Document A-02 defines the criterion for resource adequacy for each subregion as follows: Resource Adequacy - Design Criteria Each Area’s [subregion] probability (or risk) of disconnecting any firm load due to resource deficiencies shall be, on average, not more than once in ten years. Compliance with this criterion shall be evaluated probabilistically, such that the loss of load expectation [LOLE] of disconnecting firm load due to resource deficiencies shall be, on average, no more than 0.1 day per year. This evaluation shall make due allowance for demand uncertainty, scheduled outages and de-ratings, forced outages and de-ratings, assistance over interconnections with neighboring subregions and Regions, transmission transfer capabilities, and capacity and/or load relief from available operating procedures. The Northeast Power Coordinating Council has in place a comprehensive resource assessment program directed through NPCC Document B-08, “Guidelines for subregion Review of Resource Adequacy.”62 This document charges the TFCP to assess periodic reviews of resource adequacy for the five NPCC subregions. The primary objective of the NPCC subregion resource review is to ensure that plans are in place within the subregion for the timely acquisition of resources sufficient to meet this resource adequacy criterion and to identify those instances in which a failure to comply with the NPCC “Basic Criteria for Design and Operation of Interconnected Power Systems,” or other NPCC criteria, could result in adverse consequences to another NPCC subregion or subregions. If, in the course of the study, such problems of an inter-subregion nature are determined, NPCC informs the affected systems and subregions, works with the subregion to develop mechanisms to mitigate potential reliability impacts and monitors the resolution of the concern. Document B-08 requires each subregion resource assessment to include an evaluation and/or discussion of the: load model and critical assumptions on which the review is based; procedures used by the subregion for verifying generator ratings and identifying de- ratings and forced outages; ability of the subregion to reliably meet projected electricity demand, assuming the most likely load forecast for the subregion and the proposed resource scenario; 61 http://www.npcc.org/documents/regStandards/Criteria.aspx 62 http://www.npcc.org/documents/regStandards/Guide.aspx 2009/2010 Winter Reliability Assessment Page 54 Regional Reliability Self-Assessments ability of the subregion to reliably meet projected electricity demand, assuming a high growth load forecast for the subregion and the proposed resource scenario; impact of load and resource uncertainties on projected subregion reliability, discussing any available mechanisms to mitigate potential reliability impacts; proposed resource capacity mix and the potential for reliability impacts due to the transportation infrastructure to supply the fuel; internal transmission limitations; and the impact of any possible environmental restrictions. The resource adequacy review must describe the basic load model on which the review is based together with its inherent assumptions, and variations on the model must consider load forecast uncertainty. The anticipated impact on load and energy of Demand-Side Management programs must also be addressed. If the subregion load model includes pockets of demand for entities which are not members of NPCC, the subregion must discuss how it incorporates the electricity demand and energy projections of such entities. Each area’s resource adequacy review will be conducted for a window of five years and a detailed “Comprehensive Review” is conducted triennially. For those years when the Comprehensive Review is not required, the subregion is charged to continue to evaluate its resource projections on an annual or interim basis. The subregion will conduct an “Annual Interim Review” that will reassess the remaining years studied in its most recent Comprehensive Review. Based on the results of the Annual Interim Review, the subregion may be asked to advance its next regularly scheduled Comprehensive Review. These resource assessments are complemented by the efforts of the Working Group on the Review of Resource and Transmission Adequacy (Working Group CP-08), which assesses the interconnection benefits assumed by each NPCC subregion in demonstrating compliance with the NPCC resource reliability. The Working Group conducts such studies at least triennially for a window of five years, and the Working Group judges if the outside assistance assumed by each subregion is reasonable. Wind Energy Development Energy produced by wind will continue to increase in NPCC. For the winter of 2009/2010, the following contribution from wind generation is projected: Table 2: 2009/2010 Projected Wind Resources Sub-Region Nameplate Capacity Capacity After Applied De-Rating Maritimes 350 MW 138 MW New England 103 MW 91 MW New York 1,507 MW 452 MW Ontario 1,084 MW 347 MW Québec 642 MW 134 MW TOTAL 3,686 MW 1,162 MW Page 55 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments For the winter of 2008/2009, wind generation estimates were as follows: Table 3: 2008/2009 Projected Wind Resources Sub-Region Nameplate Capacity Capacity After Applied De-Rating Maritimes 335 MW 217 MW New England 5 MW 0 MW New York 706 MW 212 MW Ontario 494 MW 50 MW Québec 471 MW 0 MW TOTAL 2,011 MW 479 MW Transmission Assessment Process In parallel with the NPCC subregion resource review, the NPCC Task Force on System Studies (TFSS) is charged with conducting periodic reviews of the reliability of the planned bulk power transmission systems of each subregion of NPCC, the conduct of which is directed through NPCC Document B-04, “Guidelines for NPCC subregion Transmission Reviews.”63 Each subregion is required to present an annual transmission review to the TFSS, assessing its planned transmission network four to six years in the future. Depending on the extent of the expected changes to the system studied, the review presented each year by the subregion may be one of the following three types: Comprehensive Review A detailed analysis of the complete bulk power system of the subregion is presented every five years at a minimum. The TFSS will charge the subregion to conduct such a review more frequently as changes may dictate. Intermediate Review An Intermediate Review is conducted with the same level of detail as a Comprehensive Review, but, in those instances in which the significant transmission enhancements are confined to a segment of the subregion, the review will focus only on that portion of the system. Or, if the changes to the overall system are intermediate in nature, the analysis will focus only on the newly planned facilities. Interim Review If the changes in the planned transmission system are minimal, the subregion will summarize these changes, assess the impact of the changes on the bulk power system of the subregion and reference the most recently conducted Intermediate Review or Comprehensive Review. 63 http://www.npcc.org/documents/regStandards/Guide.aspx 2009/2010 Winter Reliability Assessment Page 56 Regional Reliability Self-Assessments In the years between Comprehensive Reviews, an subregion will annually conduct either an Interim Review, or an Intermediate Review, depending on the extent of the system changes projected for the subregion since its last Comprehensive Review. The TFSS will judge the significance of the proposed system changes planned by the subregion and direct an Intermediate Review or an Interim Review. If the TFSS agrees that revisions to the planned system are major, it will charge a Comprehensive Review in advance of the normal five-year schedule. Both the Comprehensive Review and the Intermediate Review analyze: the steady state performance of the system; the dynamic performance of the system; the response of the system to selected extreme contingencies; and the response of the system to extreme system conditions. Each review will also discuss special protection systems and/or dynamic control systems within the subregion, the failure or misoperation of which could impact neighboring subregions or Regions. The depth of the analysis required in the NPCC transmission review fully complies with, or exceeds, the obligations of NERC Reliability Standards TPL-001 through TPL-004: TPL-001-0, “System Performance Under Normal Conditions” TPL-002-0, “System Performance Following Loss of a Single BES Element” TPL-003-0, “System Performance Following Loss of Two or More BES Elements” TPL-004-0, “System Performance Following Extreme BES Events” NPCC-specific criteria requires system operation and system design to the following contingencies, which exceed what is required in the TPL standards. Simultaneous permanent phase to ground faults on different phases of each of two adjacent transmission circuits on a multiple circuit tower, with normal fault clearing. A permanent phase to ground fault on any transmission circuit, transformer, or bus section with delayed fault clearing. The following information is the specific discussions by each NPCC subregion. Page 57 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments Maritimes Demand The Maritimes subregion is a winter peaking system. The Maritimes subregion load is the mathematical sum of the forecasted weekly peak loads 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 into account. Economic assumptions are not made when determining load forecasts. Based on the Maritimes subregion 2009/2010 demand forecast, a peak of 5514 MW is predicted to occur for the winter period, December through February. The actual peak for Winter 2008/2009 was 5,504 MW on January 16, 2009, which was 43 MW (< 1 percent) lower than last year’s forecast of 5,547 MW. For the New Brunswick System Operator (NBSO), the load forecast is based on an End- use Model (sum of forecasted loads by use e.g. water heating, space heating, lighting etc.) for residential loads and an Econometric Model 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 10-year average measured at the major load center, along with analyses of sales history, economic indicators, customer surveys, technological, demographic changes in the market, and the price and availability of other energy sources. For Prince Edward Island, the load forecast uses average long-term weather for the peak period (typically December) and a time-based regression model to determine the forecasted annual peak. The remaining months are prorated on the previous year. 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 included in the resource adequacy assessment for the Maritimes subregion; it is assumed that all forecasted load is served in determining compliance with the NPCC Criterion of loss of load expectation [LOLE] of disconnecting firm load due to resource deficiencies shall be, on average, no more than 0.1 day per year. In the Maritimes subregion there is between 389 and 406 MW of interruptible demand available during the assessment period; there is 389 MW (7 percent of projected peak demand) forecasted to be available at the time of the seasonal peak. The Maritimes subregion is broken up into sub-areas and each area has its own energy efficiency programs. These programs are primarily aimed at the residential consumer to help reduce their heating costs. It is usually geared towards heat as the Maritimes subregion is a winter peaking system. For further information on the energy efficiency programs please review the following links: 2009/2010 Winter Reliability Assessment Page 58 Regional Reliability Self-Assessments www.maritimeelectric.com www.nbpower.com www.mainepublicservice.com www.emec.com www.nspower.ca/energy_efficiency/programs/ The Maritimes subregion does not address quantitative analyses to assessing the variability in projected demand due to weather, the economy, or other factors. In addition the Maritimes does not develop an extreme (e.g. 90/10) winter forecast in its seasonal assessment. Generation The Maritimes subregion resources will vary between 7,280 MW and 7,338 MW of existing capacity plus between 176.6 and 179.6 MW (nameplate rating) of planned wind generation scheduled to come on line. The Maritimes subregion does not consider conceptual, future or inoperable resources when doing its seasonal assessment. During this time period there is 138.1 MW of existing wind with a nameplate rating of 350.02 MW. Each sub-area in the Maritimes subregion use its own winter capacity factor. In New Brunswick it is 40 percent, Northern Maine 30 percent, Prince Edward Island 40 percent and Nova Scotia uses history for each individual wind farm giving an average for Nova Scotia of around 35 percent. Nova Scotia does not use any wind capacity towards their installed capacity. Wind project capacity is de-rated to its demonstrated or projected average output for each winter or winter capability period. This de-ration of wind capacity in the Maritimes subregion is based upon results from the Sept. 21, 2005 NBSO report Maritimes Wind Integration Study.64 This wind study showed that the effective capacity from wind projects, and their contribution to LOLE, was equal to or better than their seasonal capacity factors. Coincidence of high winter wind generation with the peak winter loads results in the Maritimes subregion receiving a higher capacity benefit from wind projects versus a summer peaking area. The effective wind capacity calculation also assumes a good geographic dispersion of the wind projects in order to mitigate the occurrences of having zero wind production. Wind is the only variable resource currently considered in the Maritimes subregion resource adequacy assessment. During this time period there is 130 MW of existing Biomass with a nameplate rating of 133 MW. The Maritimes subregion is forecasting normal hydro conditions for the Winter 2009/2010 assessment period. The Maritimes subregion hydro resources are run of the river facilities with limited reservoir storage facilities. These facilities are primarily used as peaking units or providing operating reserve. The Point Lepreau nuclear generating station (635 MW) will continue be out of service during the whole Winter Assessment period; the plant was removed from service in the spring of 2008 to begin a major refurbishment. With firm purchases from outside the Maritimes subregion in 64 http://www.nbso.ca/Public/_private/2005percent20Maritimepercent20Windpercent20Integrationpercent20Studypercent20_Fina l_.pdf Page 59 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments place, and all scheduled maintenance completed prior to the winter period, there are no anticipated shortfalls in capacity. Other than the continuing Pt. Lepreau outage, the Maritimes subregion does not expect to experience any conditions that would cause any further unanticipated capacity reductions during the winter period. Capacity Transactions on Peak There are firm capacity agreements in place between New Brunswick - H.Q and New Brunswick - Newfoundland and Labrador and are as follows: Table Maritimes 1: Firm Purchases Firm Purchases Dec-08 Jan-09 Feb-09 LD Energy 330 MW 330 MW 330 MW There is a firm sale of 207 MW to H.Q. which is tied to specific generators within New Brunswick. The Maritimes subregion does have agreements in place for the purchase of emergency energy with other sub Regions as well as a reserve sharing agreement within NPCC. But the Maritime subregion does not rely on this assistance when doing its winter assessment, and no portion of any transaction includes a provision for a Liquidated Damage Contract (LDC) Transmission There has been no significant new bulk power transmission addition since the last reporting winter period. Furthermore, there are no bulk transmission additions expected this winter. All existing significant transmission facilities are expected to be in service during the winter reporting period. The Maritimes inter-regional transfer capabilities are: NB – MEPCO: 1000 MW MEPCO – NB: 550 MW (presently a presidential order in the U.S.A. limiting the interface to 400 MW). HQ – NB: HVdc + Radial Load = Between 985 MW and 1017 MW. (The reason for the range is due to the varying radial load during the winter reporting period). NB – HQ: 770 MW The latest study would be the IPL/NRI studies on the NB / ISO-NE interface. The Regions import capabilities are based on real time values based on transmission and generation being in / out of service. NBSO has rules based on study results for simultaneous transfer capability with our interconnections. Transmission or generation constraints are recognized that are external to the Maritimes subregion. 2009/2010 Winter Reliability Assessment Page 60 Regional Reliability Self-Assessments No other significant substation equipment has recently been added. Operational Issues The Maritimes subregion assesses its seasonal resource adequacy in accordance with NPCC C- 13 Operational Planning Coordination procedure. As such, the assessment considers the Regional Operating Reserve criteria; 100-percent of the largest single contingency and 50- percent of the second largest contingency. The amount of wind presently operating does not require any operational changes. The Maritimes subregion is a winter is winter peaking system. Minimum demand and over generation will not be a concern. The only Demand Response considered in resource adequacy assessment for the Maritimes subregion is interruptible load. The Maritimes subregion uses a 20 percent reserve criterion for planning purposes, equal to 20 percent x (Forecast Peak Load MW – Interruptible Load MW). There are no environmental or regulatory restrictions which could impact reliability in the Maritimes subregion during the assessment period. Reliability Assessment Analysis When allowances for unplanned outages (based on a discreet MW value representing an historical assessment of the total forced outages in MW typically realized at the time of peak for the given operating season) are considered, the Maritimes subregion is projecting more than adequate surplus capacity margins above its operating reserve requirements for the Winter 2009/2010 assessment period. The projected capacity margin for winter 2009/2010 period is 8 percent to 30 percent as compared to the projected capacity margin for the winter 2008/2009 of 6 percent to 16 percent. The Maritime subregion does not consider potential fuel-supply interruptions in the Regional assessment. The fuel supply in the Maritimes subregion is very diverse and it includes natural gas, coal, oil (both light and residual), hydro, tidal, municipal waste, and wood. The NB transmission system is robust, comprised of a 345 kV transmission ring with additional supporting 230 kV transmissions. For those areas that may suffer low voltage post contingency, there are specific “must run” procedures that require generation online to meet necessary reactive reserves for contingencies. This requirement is applied for generation assessments as well as the day ahead review to ensure that there are sufficient reactive reserves. Page 61 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments New England Demand ISO New England Inc. (ISO-NE) serves as the NERC Balancing Authority (BA) for the six-state New England region. ISO-NE’s reference case winter peak demand forecast is the 50/50 forecast (50 percent chance of being exceeded), corresponding to a New England weighted dry- bulb temperature of 6.8º F. The 6.8º F dry-bulb temperature corresponds to the 50th percentile of the extreme weather distribution and is consistent with the average temperature at the hour of the ISO-NE winter peak demand for the previous 20 years. The reference case load forecast is for New England’s coincident peak demand and is based on the most recent reference economic forecast, which reflects the regional economic conditions that are most likely to occur. ISO-NE’s actual metered 2008/2009 winter peak demand was 21,022 MW, which occurred at hour ending 18:00 on Monday, December 8, 2008. The weather normalized 2008/2009 winter peak demand was 22,190 MW, which is 1,168 MW greater than the actual metered demand. The reconstituted65 2008/2009 winter peak demand was 21,581 MW, which is 559 MW greater than the actual metered demand. The 2009/2010 winter peak demand forecast is 22,100 MW, which is 930 MW (4.21 percent) lower than the 2008/2009 winter peak demand forecast of 23,030 MW. The current economic conditions have lowered this year’s forecast for peak demand (and also energy) when compared to last year’s forecast. The lower forecast for this winter is also due to modeling improvements within the energy and peak demand forecast methodologies, which resulted in a lower forecast for winter peaks. The change in the forecast methodology reflects the elimination of the growth trend on the weather sensitive portion of the winter peak demand. This methodology change subsequently results in even lower winter peak demand forecasts when compared with the 2008 long-term (10-year) forecast for both summer and winter peak demands. ISO-NE develops an independent demand forecast for the Balancing Authority area as a whole and each of the six states within it. ISO-NE uses historical hourly demand data from individual member utilities, which is based upon revenue quality metering, to develop historical demand data from which the regional peak demand and energy forecasts are based upon. From this, ISO- NE develops a forecast of monthly energies and peak demands, by state. Therefore, the peak demand forecast for the region and the states is a coincident66 peak demand forecast. A total of 2,520 MW of demand resources (DR) could be interrupted, during times of capacity shortages, during the winter of 2009/2010. As done in past seasonal reliability assessments, ISO- NE treats these demand-side resources like supply-side capacity. These resources, which are in ISO-NE’s Real-Time 30-Minute (1,767 MW), Real-Time 2-Hour (193 MW), and Profiled Demand Response (18 MW) programs, are instructed to interrupt their consumption67 during specific actions of ISO-NE Operating Procedure No. 4 - Action During a Capacity Deficiency 65 Reconstituted for the load reducing actions of demand resources. 66 The first two years of ISO-NE’s annual 10-year, long-range load forecast, for both peak demand and energy, is developed at the system or regional level with the remaining eight years of that same forecast being developed as the sum of the six-state’s forecasts. 67 May also include the starting of “on-site” generation. 2009/2010 Winter Reliability Assessment Page 62 Regional Reliability Self-Assessments (OP 4).68 Demand reductions from existing Demand-Side Management (DSM) programs are accounted for in the historical data that is used within ISO-NE’s load forecast model. In addition to demand response resources, ISO-NE also considers energy efficiency (EE) to be a supply-side capacity resource. New energy efficiency programs are projected to be 542 MW during the winter 2009/2010. Demand that will interrupt voluntarily based on the current price of energy is not included in this amount. As of July 31, 2009, there were approximately 77 MW enrolled within the Demand Resource price response program. Total demand response resources of 2,520 MW represent approximately 11.4 percent of the projected 2009/2010 winter peak demand, which is forecast to be 22,100 MW. ISO-NE Demand Response Measurement & Verification (M&V) Plans describe the methods, assumptions and measurements that will be used to determine actual demand reductions under ISO-NE’s Forward Capacity Market (FCM) Commitment Periods.69 All M&V Plans must comply with the requirements set forth within ISO-NE’s Manual for Measurement and Verification of Demand Reduction Value from Demand Resources (M-MVDR).70 As mentioned earlier, ISO-NE has always considered energy efficiency (EE) to be a supply-side capacity resource, and as such, new energy efficiency programs are projected to be 542 MW, during the winter 2009/2010. New England’s measurement and verification programs used for energy efficiency are also documented in ISO-NE’s M-MVDR. ISO New England addresses seasonal peak demand uncertainty in two ways: Weather — Peak demand distribution forecasts are made based on 35 years of historical weather, which includes the reference forecast (50 percent chance of being exceeded) and the extreme forecast (10 percent chance of being exceeded); Economics — Alternative forecasts are also made using high and low economic scenarios. The 2009/2010 winter peak demand forecasts for the various weather and economic scenarios are shown in Table New England-1. New England Table 1: Economic and Weather Assumptions Economic Assumptions Weather Assumptions Reference Extreme 50/50 (MW) 90/10 (MW) Reference Economic Forecast 22,100 22,850 Alternative High Economic Forecast 22,180 22,925 Alternative Low Economic Forecast 22,025 22,775 68 Operating Procedure No. 4 may be found on ISO-NE’s web site at: http://www.isone.com/rules_proceds/operating/isone/op4/index.html 69 A FCM Commitment Period runs from June 1 of one year to May 31 of the next year. 70 This ISO-NE Manual can be located at: http://www.iso-ne.com/rules_proceds/isone_mnls/index.html Page 63 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments Generation For the winter of 2009/2010, ISO-NE has 36,140 MW of Existing-Certain capacity, 141 MW of Existing-Other capacity and 525 MW of existing inoperable capacity. Included within the Existing-Certain capacity is 2,520 MW of demand resources, which are treated as capacity in New England. ISO-NE is also reporting 121 MW of Future-Planned capacity additions and 36 MW of Future-Other capacity. Approximately 91 MW of the Existing-Certain capacity is on-peak wind generation. The total nameplate capability of those wind facilities is 103 MW. Of the 121 MW of Future-Planned capacity projected to be in-service for the 2009/2010 winter, 55 MW (91 MW nameplate) is new wind capacity.71 Also included in the Existing-Certain capacity is 1,929 MW of hydro-electric capacity and 1 MW of solar capacity. Seasonal wind capacity ratings for existing resources is determined from either the sustained maximum net output averaged over a four (4) consecutive hour period (measured for the summer and winter capability periods each year); or the unit’s nameplate rating adjusted for engineering data that projects unit output at time of peak demand. The expected on-peak capacity values of new variable resources are determined based on engineering analyses performed by those resources in support of their qualified capacity within the Forward Capacity Market. For the 2009/2010 winter, biomass capacity within the Existing-Certain capacity category totals 986 MW. There are no biomass facilities planned for commercialization during the three-month winter period of 2009/2010. Hydrological conditions are anticipated to be sufficient during the winter of 2009/2010. Within New England, the seasonal variation of hydrological conditions traditionally peaks during the spring timeframe, are lowest during the summer, and range somewhat in between these seasonal variations (minimums and maximums) during the fall and winter. Small non-dispatchable and/or run-of-river hydro-electric facilities are seasonally rated against historical stream flow data, and as such, their monthly capacity ratings already reflect the dynamic variations of regional hydraulic conditions. Conventional weekly-cycle hydro-electric facilities, with significant pondage or storage capability, are seasonally de-rated based on demonstrated capacity, can also become energy limited. However, within New England, these conditions traditionally occur only during the dry, summer months. If and when these conditions do occur, these energy limitations are accounted for within the daily dispatch. However, the total hydro-electric capacity only contributes approximately 5 percent to New England’s overall installed generating capacity and that historical hydro-electric energy production has only accounted for approximately 6-8 percent of the annual (native generation) energy production within New England. New England is not currently experiencing or expecting any fuels supply constraints that would create temporary capacity reductions on regional power generators. 71 Currently, there is a significant difference between how existing wind capacity is seasonally rated versus how new wind capacity will be seasonally rated under ISO-NE’s Forward Capacity Market (FCM). These differences will no longer exist after June 1, 2010, when the FCM begins. 2009/2010 Winter Reliability Assessment Page 64 Regional Reliability Self-Assessments A large portion of generation in New England is fueled by natural gas (40.9 percent), followed by nuclear (28.5 percent), coal (14.9 percent), non-hydro renewables (6.0 percent), hydro (6.8 percent), oil (1.5 percent) and pumped storage (1.3 percent)72. Fuel supply vulnerability has historically not been a concern for any of the power plant fuels, other than natural gas. In the past, winter has traditionally brought concern over the availability and deliverability of natural gas to regional gas-fired generators. This situation was primarily due to two factors; 1) a seasonally (winter) constrained natural gas delivery system both into and within the region, and, 2) the overall characteristic of most regional gas-fired generators of having subordinate entitlements for contracting for both natural gas supply and transportation. However, the first factor has been eliminated due to the recent influx of new LNG projects73 within and around the region, in combination with several new pipeline expansion projects to deliver these new gas supplies to area markets. Several other recent regional pipeline projects have worked to eliminate seasonal bottlenecks and constraints as well as improve bidirectional flow capability. The second factor (#2 - lack of firm contracting) is still an ongoing issue, however, with the region now having access to more natural gas supplies (as a result of the initiatives from factor #1), the concern over the unavailability of regional gas-fired generating units during the winter peak season has now diminished. In addition, to minimize concerns over real-time reliability brought about by historical gas supply availability or short-term deliverability constraints, increased communication and coordination efforts have been implemented between ISO-NE and the regional natural gas industry, with help from the Northeast Gas Association (NGA).74 These communications improvements have increased the response-time for situational awareness of emerging gas supply constraints that could potentially impact regional gas-fired generators. ISO-NE and NGA co-chair the Electric/Gas Operations Committee (EGOC), which was formed in 2004 to address the operational issues that resulted from the Cold Snap75 of January 2004. The EGOC works on a variety of issues common to both industries and has recently been working on coordination of maintenance schedules, reviewing communications protocols and conducting cross-industry education and training sessions. ISO-NE recently held an EGOC Training Session on September 18, 2009. The only time when significant amounts of generating capacity are expected to be out of service is during the first two weeks in December 2009, when generators will be in the process of wrapping-up their late fall annual maintenance inspections.76 However, with the reduced projections for this winter’s peak demand and the natural surplus of generating capacity during the overall winter season, there are no major concerns with respect to serving potential winter peak loads that may occur in early December 2009 or for all winter for that matter. If, however, due to some unexpected situation where real-time capacity conditions deteriorate, to rebalance 72 Values represent 2008 actual energy generation. 73 These LNG projects include: 1) The Northeast Gateway Deepwater Port Project, 2) The Canaport LNG Facility, and the nearly complete Neptune LNG Deepwater Port Project. 74 The Northeast Gas Association (NGA) is a regional trade association that focuses on education and training, technology research and development, operations, planning, and increasing public awareness of natural gas in the Northeast U.S. The NGA web site is located at: http://www.northeastgas.org 75 Which occurred over a three-day period, January 14-16, 2004. 76 Includes 1,700 MW of planned maintenance during the first week in December and 1,300 MW of planned maintenance during the second week in December. Page 65 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments demand with supply, ISO-NE would invoke the load and capacity relief actions as available within ISO-NE Operating Procedure No. 4 – Action During a Capacity Deficiency (OP 4). Capacity Transactions on Peak For the 2009/2010 winter, ISO-NE expects firm external capacity imports of 401 MW. This includes 310 MW from Hydro-Québec and 91 MW from New York. Only firm, Installed Capacity (ICAP) imports that are known in advance are included as capacity transactions. While the entire 401 MW of ICAP imports 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 necessary for the delivery of energy associated with ICAP, but the market participant also bears the associated risk of ICAP market (non- delivery) penalties if it chooses to use non-firm transmission service. The 310 MW purchase from Hydro-Québec is a Liquidated Damage Contract (LDC), but the 91 MW purchase from New York is not. Based on studies and past experience, ISO-NE assumes approximately 2,000 MW of emergency assistance, also referred to as tie-line benefits, available from other areas within the NPCC Region. This tie benefit value represents about 50 percent of New England’s total import capability. ISO-NE 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. For the 2009/2010 winter, ISO-NE expects firm external capacity exports to New York (Long Island) of 343 MW via the Cross-Sound Cable. Although this export capacity transaction is backed by a firm contract for generation, the energy and capacity may be considered recallable by ISO-NE, depending on whether the transaction clears the New York market. In the event of a transmission import-constraint into Connecticut, if the capacity export transaction does not clear in the New York market, it is recallable and can be cut earlier than other non-recallable exports. The capacity export across the Cross-Sound Cable is based on a make-whole contract. Transmission Within the New England Balancing Authority area, the following new bulk power transmission facilities have either been placed in-service since the 2008/2009 winter period or are expected to be placed in-service during the 2009/20010 winter period: New Hampshire The northern and central New Hampshire voltage and thermal performance concerns were addressed by closing the Y-138 115 kV tie with Maine. This included the installation of a Phase Angle Regulator (PAR) at the Saco Valley Substation, located in New Hampshire. A new substation located in Fitzwilliam, NH consisting of one 345/115 kV autotransformer has also been energized. Vermont A set of transmission reinforcements, the Northwest Vermont Reliability Project (NWVTRP), which was designed to address thermal and voltage violation issues in the broad northwestern 2009/2010 Winter Reliability Assessment Page 66 Regional Reliability Self-Assessments portion of Vermont, has been completed. The remaining components, four +25/-12.5 MVAr synchronous condensers at the Granite Substation, were placed in-service in April 2009. The 28- mile 115 kV circuit from New Haven to Vergennes to Queen City was completed in December 2008. Massachusetts The final 345 kV cable from the Stoughton substation to the K Street substation in downtown Boston was placed in-service, along with an associated autotransformer and two reactors. Improvements have been made to provide additional line-out protection in lower Southeast Massachusetts (SEMA). The new facilities installed include a new 115 kV line between the Brook Street and Auburn Street substations, a new 115 kV line between the Carver and Tremont substations, and a 115 kV Static Var Compensator (SVC) at Barnstable. Additionally, the Bridgewater to Pilgrim 345 kV line has been looped into the Carver 345 kV substation. Connecticut The Middletown–Norwalk phase of the Southwest Connecticut Reliability Project (SWCTRP) installed several new 345 kV overhead and underground circuits, approximately 70 miles in length, along with several 345/115 kV autotransformers within the area. The overhead portion extends from the Beseck substation in Middletown to the East Devon substation. Cables extend from East Devon to the Singer substation in Bridgeport and on to the Norwalk substation. The planned Norwalk–Glenbrook 115 kV cable project has also been placed in-service. The project includes the installation of two 9-mile 115 kV underground circuits between the Norwalk and Glenbrook substations. There are no reliability concerns in meeting the in-service dates for the aforementioned facilities and there are no specific transmission additions deemed necessary to meet the demand forecast for the 2009/2010 winter period. ISO-NE does not expect any major transmission lines or facilities to be out-of-service (OOS) during the 2009/2010 winter period. However, if major transmission outages were to occur, system reliability would be maintained through adherence to ISO-NE Operating Procedure No. 19 - Transmission Operations (OP19)77 criteria, during real-time operations. No significant transmission constraints are anticipated for the upcoming winter. Table New England-2 summarizes the nominal interregional transmission transfer capabilities, which also reflects transmission and generation constraints in systems external to ISO-NE. In addition, these interregional transfer capabilities are also reviewed and (re)calculated78 on a day- to-day basis within real-time. 77 ISO-NE’s OP19 may be found on ISO New England’s web site at: http://www.isone.com/rules_proceds/operating/isone/op19/index.html 78 These “nominal” interregional transmission transfer capabilities are dynamic in nature and subject to a increase or decrease in value on a real-time basis, which is based upon ever changing system topology. Page 67 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments New England Table 2: Transfer Capability Transmission Interface Nominal Transfer Basis or Study for Capability (MW) Interface Limit New Brunswick – New England 1,000 Second New Brunswick Tie Study Phase II 1,400 PJM & NYISO Loss of Source Studies Highgate 200 Various Transmission Studies New York – New England 1,600 NYISO Operating Study, Winter 2005/2006 Cross-Sound Cable 330 Cross-Sound Cable System Impact Study As stated earlier, a new SVC has been installed at the Barnstable substation on Cape Cod and four +25/-12.5 MVAr synchronous condensers have been installed at the Granite substation in Vermont. Operational Issues ISO-NE is not projecting any major operational constraints or issues for the winter of 2009/2010, ISO-NE has not performed any special operating studies for the 2009/2010 winter period. As of October 2009, no special operating procedures have been developed as a result of the recent integration of approximately 100 MW of wind generation into New England’s bulk power system. ISO-NE is not projecting any reliability concerns resulting from minimum demand periods or over-generation. If this was to occur in real-time, ISO-NE can invoke System Operating Procedure(s) (SOPs)79 that work to mitigate such situations. ISO-NE is not projecting any reliability concerns resulting from high levels of demand response resources. If this was to occur in real-time, ISO-NE can invoke Operating Procedures (OPs)80 that work to mitigate such situations. No environmental or regulatory restrictions are anticipated to impact system or sub-area reliability during the 2009/2010 winter period. Furthermore, ISO-NE is not anticipating any unusual operating conditions during the winter of 2009/2010. 79 ISO-NE System Operating Procedure entitled SOP-RTMKTS.0120.0015 - Implement Minimum Generation Emergency Remedial Action, which can be located on the ISO-NE web site at: http://www.iso- ne.com/rules_proceds/operating/sysop/rt_mkts/sop_rtmkts_0120_0015.pdf. 80 ISO-NE Operating Procedure No. 4 – Action During a Capacity Deficiency, which can be located on the ISO-NE web site at: http://www.iso-ne.com/rules_proceds/operating/isone/op4/index.html. 2009/2010 Winter Reliability Assessment Page 68 Regional Reliability Self-Assessments Reliability Assessment Analysis ISO-NE does not have a Reserve Margin criterion. ISO-NE bases its capacity requirements on probabilistic loss-of-load expectation (LOLE) analysis that calculates the total amount of installed capacity needed to meet NPCC’s once-in-10-year resource adequacy requirement for preventing the disconnection of firm load due to a capacity deficiency. This value, known as the Installed Capacity Requirement (ICR),81 was calculated for the 2009/2010 capability year, which runs from June 1, 2009 to May 31, 2010. The annual ICR of 31,823 MW (in terms of summer ratings) for the 2009/2010 capability period translates to approximately 34,000 MW in terms of winter ratings. This results in a projected Reserve Margin of 54 percent. For this winter’s reliability assessment, ISO-NE projects deliverable capacity resources of 36,319 MW against a peak demand forecast of 22,100 MW, which results in a Reserve Margin of 14,219 MW or 64.3 percent under the 50/50 winter peak demand forecast. For the 90/10 winter peak demand forecast of 22,850 MW, the Reserve Margin is 13,469 MW, or 58.9 percent. The capacity margins are based on anticipated generation additions and retirements, planned generator outages, projected firm capacity imports and exports, and the expected impact of demand response programs. Table New England-3 shows New England’s projected winter Reserve Margins for winter 2008/2009 and 2009/2010 under both the 50/50 and 90/10 winter peak demand forecasts. The 2009/2010 winter Reserve Margins of 64 percent and 59 percent are higher than last year’s margins of 54 percent and 47 percent. Table 3: New England Reserve Margins Winter 2008/2009 Winter 2009/2010 Reserve Margin and Reserve Margin and Percent (%) Percent (%) Reference Winter Peak Demand (50/50 Forecast) 12,432 MW (54.0%) 14,219 MW (64.3%) Extreme Winter Peak Demand (90/10 Forecast) 11,287 MW (46.7%) 13,469 MW (58.9%) ISO-NE continuously monitors regional fuel supplies serving the power generation sector. In addition, ISO-NE attends regional fuels conferences82 which usually include seasonal assessments of all fuel supply chains serving the northeast U.S./CA corridor. However, because of the regional fuel mix, ISO-NE primarily focuses on both the liquid fuel and natural gas sectors. Early communications of potential supply-chain problems ensures timely development of remedial actions. Situational awareness in real-time is benefitted by increased communications with the gas control divisions of the regional pipelines. 81 The 2009/2010 ICR Report is located on the ISO New England web site at: http://www.iso- ne.com/genrtion_resrcs/reports/nepool_oc_review/index.html. 82 Includes market and regulatory based fuel supply and delivery assessments, seminars, conferences, briefings and meetings. Page 69 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments Communication is Key: During the winter season in New England, regional natural gas pipelines usually run full with LDC gas supplies targeted to serve the core space heating demands of the residential, commercial and industrial sectors. These LDC gas supplies typically have superior deliverability entitlements over those of the gas-fired electric generation sector. After contingency events within the natural gas sector (i.e. unplanned compressor station outages, regional production outages, etc.) or when other abnormal conditions exist, natural gas supplies to the electric power sector may be the first to be temporarily curtailed. It is under these types of situations that ISO- NE encourages increased coordination and communication with the gas control divisions of both pipelines and LDCs, to ensure that any gas sector problem is readily known and the resulting impacts on the electric generation sector can be understood and assessed. Within New England, enhanced communication between the electric and natural gas sectors contributes to maintaining system reliability during all seasons. However, if the aforementioned inter-industry communication fails to provide the advance notice necessary to develop and implement a remedial action plan, other solutions available to help mitigate the effects from gas-fired unit outages or reductions may include invocation of special market rules and/or operating procedures. Appendix H of Market Rule 1- Operations During Cold Weather Events83 is a market rule that works to optimize the synchronization of electric market bidding timelines with the regional natural gas nomination deadlines. Appendix H of Market Rule 1 can also request voluntary fuel switching from dual-fuel units and can trigger requests for regional electric conservation. In addition, ISO-NE can also invoke Operating Procedure No. 21, Action During an Energy Emergency,84 (OP 21) which was developed to mitigate reliability impacts resulting from all types of fuel supply constraints, shortages or other abnormal system conditions impacting the regional generation sector, during any time of the year. Since no major transmission or operational constraints that would significantly impact regional reliability are anticipated during the winter of 2009/2010, and also because New England is a summer peaking system, ISO-NE has not performed any dynamic or static reactive power studies for the 2009/2010 winter period. Subregion Description ISO New England Inc. is a Regional Transmission Organization (RTO), serving Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont. It is responsible for the reliable day-to-day operation of New England’s bulk power generation and transmission system, and also administers the region’s wholesale electricity markets and manages the comprehensive planning of the regional bulk power system. The New England regional electric power system serves 14 million people living in a 68,000 square-mile area. New England is a summer-peaking electric system, which recorded its all-time record electrical peak demand of 28,130 MW on August 2, 2006. 83 Appendix H of Market Rule 1 may be found on the ISO New England web site at: http://www.iso-ne.com/regulatory/tariff/sect_3/index.html. 84 OP 21 is located on the ISO New England web site at: http://www.iso-ne.com/rules_proceds/operating/isone/op21/index.html. 2009/2010 Winter Reliability Assessment Page 70 Regional Reliability Self-Assessments New York The New York Balancing Authority 2009 winter peak load forecast is 24,998 MW, which is 295 MW lower than the forecast of 25,293 MW for the 2008 Winter and 325 MW more than the 24,673 MW 2008 actual winter peak. This forecast load is 0.98 percent lower than the all-time winter peak load of 25,541 MW that occurred on December 20, 2004. The 2009 forecast is lower due to the impact of the current economic recession on electric energy consumption. The existing, Certain Capacity in the New York Control Area (NYCA) for the upcoming winter operating period is 37,823 MW. 511 MW of Certain Capacity has been added since winter ‘08- ‘09. There is 46 MW of capacity expected to be added during this period and is largely due to several new wind farms and a Hydro plant rerating. An 890 MW Fuel Oil and Natural Gas Generating station is scheduled to retire in February 2010. The Prospective Capacity Resource Reserve Margin is 54.3 percent. This exceeds the 16.5 percent annual Reserve Margin set by the New York State Reliability Council. Since the previous winter, stations splitting the Willis – Plattsburg 230kV circuits have been added, as well as stations splitting the Stolle Rd – Meyer 230kV circuit. These additions have been added to connect new wind farms. Two 120 MVar capacitor banks have been added to Millwood 345. A Variable Frequency Transformer with three 100 MW channels connecting between PJM and New York City is expected to be in-service before the time frame of this assessment. There is no single outstanding challenge aside from the typical challenges in operating the Bulk Power System. There are no special assessments or studies performed through the assessment timeframe that are detailed in our Regional Assessment. Demand The 2009 winter forecast assumes normal weather conditions for both energy use and peak demand. The economic outlook is derived from the New York forecast provided to the NYISO by Moody's Economy.com. Econometric models are used to obtain energy forecasts for each of the eleven zones in New York. A winter load factor is used to derive the winter peak from the annual energy forecast. The New York Balancing Authority 2009 winter peak load forecast is 24,998 MW, which is 295 MW lower than the forecast of 25,293 MW for the 2008 winter and 325 MW more than the 24,673 MW 2008 actual winter peak. This forecast load is 0.98 percent lower than the all-time winter peak load of 25,541 MW that occurred on December 20, 2004. The 2009 forecast is lower due to the impact of the current economic recession on electric energy consumption. Peak load forecasts are provided by Consolidated Edison for its service territory, and by the Long Island Power Authority for Long Island. Con-Ed's service territory includes New York City and nearby Westchester, and is contained within the NYISO Zones H, I and J. The LIPA service territory is contained within the NYISO Zone K. Con-Ed and LIPA provide the NYISO with both coincident and non-coincident peak demands. The NYISO aggregates the utility forecasts with the remaining zones A through G that comprise the New York Control Area. Page 71 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments NEW YORK CONTROL AREA LOAD ZONES D A - WEST B - GENESSE C - CENTRAL E D - NORTH B E – MHK VL F F - CAPITL G – HUD VL H - MILLWD C I - DUNWOD A J – N.Y.C. K - LONGIL B G H I K J The daily peak demand observed by New York during the Winter Operating Period occurs in the late afternoon to early evening. For daily forecasting purposes, the NYISO uses a weather index that relates dry bulb air temperature and wind speed to the load response in the determination of the forecast. At the peak load conditions, a one-degree decrease in this index will result in approximately 100 MW of additional load. The expected temperature at which the New York load could reach the forecast peak is 12.9 °F (-11 °C). The NYISO has two Demand Response programs: the Emergency Demand Response Program (EDRP) and ICAP Special Case Resources (SCR) program. Both programs can be deployed in energy shortage situations to maintain the reliability of the bulk power grid. The Emergency Demand Response Program is designed to reduce power use through the voluntary shutting down of businesses and large power users. Companies, mostly industrial and commercial, sign up to take part in the EDRP. The companies are paid by the NYISO for reducing energy consumption when asked to do so by the NYISO. Special Case Resources is a program designed to reduce power use through the shutting down of businesses and large power users. Companies, mostly industrial and commercial, sign up to become SCRs. The companies must, as part of their agreement, curtail power use, usually by shutting down when asked by the NYISO. In exchange, they are paid in advance for agreeing to cut power use upon request. 2009/2010 Winter Reliability Assessment Page 72 Regional Reliability Self-Assessments The NYISO's Day-Ahead Demand Response Program (DADRP) allows energy users to bid their load reductions, into the Day-Ahead energy market as generators do. Offers determined to be economic are paid at the market clearing price. DADRP allows flexible loads to effectively increase the amount of supply in the market and moderate prices. SCR participants represent 1,954 MW and DRP participants represent 219 MW. Combined, this can reduce the peak demand of 24,998 MW by 8.7 percent. All SCR and EDRP program participants submit hourly interval data to the NYISO so that actual performance indexes may be calculated. The NYISO files reports to the FERC on a period basis regarding the performance of these programs. The Public Service Commission of New York (NYPSC) issued an order in June 2008 that directed state organizations to begin implementation of its Energy Efficiency Portfolio Standard (EEPS), whose goal is to reduce the projected energy consumption in the year 2015 by 15 percent of forecasted demand levels (approximately 27,500 GWh). The estimated reduction in peak demand, if the full impact of these programs were achieved, would reduce summer peak demand by about 5,600 MW. The full impact for winter peak demand would total about 2,800 MW. The NYPSC made provisions for the funding of measurement and verification of the EEPS. The NYISO is a member of the Evaluation Advisory Group, which provides input to the Public Service Commission on methods and standards used to verify the level of savings the EEPS achieves in practice. The New York State Energy Research and Development Agency (NYSERDA) also implements state-funded energy efficiency programs as authorized by the Public Service Commission. NYSERDA publishes annual reports on the measurement and verification of the programs it implements. The NYISO 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. Generation For 2009 the New York Balancing Area expects 40,935 MW of existing capacity. Capacity classified as “Existing-Certain” total 37,823 MW. Of that, 452 MW is from wind generation and 333 MW is from biomass generation. Based on historical performance, a 7.6 percent de-rate factor is applied for the majority of generators. This includes biomass, but excludes wind. For wind generation the NYISO de-rates all wind generators to 30 percent of rated capacity, a 70 percent de-rate factor, in the winter operating period. Hydro conditions are anticipated to be sufficient to meet the expected demand this winter. The New York area is not experiencing continued effects of a drought or any conditions that would create capacity reductions. Reservoir levels are expected to be normal for the upcoming winter. NYISO is not experiencing or expecting conditions that would reduce capacity. An 890 MW fuel Page 73 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments oil and natural gas generating station is scheduled to retire in February 2010, however this is not expected to cause any reliability issues due to sufficient capacity in the local area. Capacity Transactions on Peak The NYISO projects net imports into the New York Balancing Authority area of 85 MW. 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 but adequate transmission rights must be available to assure delivery to New York when scheduled. External capacity is also subject to external availability rights. Availability on the import interface is available on a first-come first-serve basis. The total capacity purchased for this winter operating period may increase since there remains both time and external rights availability. Due to NYISO market rules, information on specific import and export transactions is considered confidential. Information on the aggregated or net expected capacity imports and exports during peak summer conditions is not yet known. Capacity is traded in the NYISO market as a monthly product, and total imports and exports are not finalized until shortly before the month begins. NYISO does not rely on external resources for emergency assistance. Transmission Two substations have been added on the Willis – Plattsburg 230kV circuits for connecting wind farms, and three substations around Stolle Rd – Meyer 230kV also for wind farm connections. A Variable Frequency Transformer has been added between PJM and New York City consisting of three 100 MW channels. Any delays in meeting in-service dates for new transmission facilities would not be expected to impact reliability. The forced outage to the 230 kV circuit BP76 on the Ontario-New York interconnection at Niagara continues to reduce the total Ontario-New York import and export capability until its scheduled return to service in the third quarter of 2010. The Millwood 345 kV 240 MVar capacitor bank was added in summer 2009 for added voltage support in the lower Hudson Valley. The NYISO does not have any transmission constraints that could significantly impact reliability. New York Balancing Authority area import capability is summarized in the table below. These values are derived by joint studies with adjoining Regions and recognize transmission and generation constraints. New York Table 1: 2009/2010 Winter Transfer Capability Import Area Transfer Capability PJM 2,500 MW Linden VFT 300 MW Neptune Cable 660 MW Québec 1,500 MW Cedars-Dennison 200 MW New England 2,100 MW Cross Sound Cable 340 MW 1385 Cable 100 MW Ontario 1,900 MW 2009/2010 Winter Reliability Assessment Page 74 Regional Reliability Self-Assessments The NYISO participates in the seasonal and future ERAG RFC-NPCC inter-regional assessment studies. Operational Issues There have been no significant special operating studies performed. NYISO has put in a protocol with ISO New England to manage a Phase Angle Regulator controlled tie line as a means to integrate wind resources. NYISO does not have any reliability concerns resulting from minimum demand and over generation due to variable resources. Wind is integrated into the security constrained dispatch (SCD). As a result, wind can be curtailed to address transmission constraints based on their shift factors and economic offers. Through November 1, 2009 the System Operators will call the Transmission Owner (TO) to request wind to back down if needed. After this date, it is expected that wind resources be able to receive basepoints from the TO and financial penalties will be assessed for non-response. Because wind is managed through SCD the need for special operating procedures has been limited. There have not been any operating issues associated with wind generation. The NYISO does not expect any reliability concerns resulting from its’ Demand Response Program. The Regional Greenhouse Gas Initiative (RGGI) became effective January 1, 2009. The program is an agreement among ten northeast states designed to reduce the emissions of carbon dioxide from power plants greater than 25 MW. The RGGI program caps carbon dioxide emissions at existing levels initially, and then, beginning in 2015, requires a 2.5 percent reduction per year through 2018. The RGGI system is administered through the use of permits known as allowances. One allowance is required for each ton of CO2 that has been emitted by an affected facility. RGGI established an annual emissions cap for each of the member states that approximates recent emission patterns. The allowances are mostly distributed through a series of auctions. Program compliance is measured over a three year period with the first compliance period running between 2009 through 2011. If the market price of allowances increases above threshold prices then the compliance period is extended one more year. If the new RGGI Allowance market operates as set forth by the modeling conducted by the State, bulk power system reliability is not expected to be negatively impacted in the near term. If a gas pipeline failure were to cause dual fueled plants to convert to oil resulting in increase emissions of carbon dioxide and allowances were not available to cover the increased emissions, then some states have provided for the suspension of the RGGI program. New York State Department of Environmental Conservation administers the program in New York. The NYSDEC Commissioner has stated in the rule making process, that in such a situation, he would act to maintain electric system reliability. Furthermore, there are no anticipated unusual operating conditions that could significantly impact reliability for the upcoming winter. Page 75 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments Reliability Assessment Analysis The Prospective Capacity Resource Reserve Margin is 54.3 percent.. This exceeds the 16.5 percent annual Reserve Margin set by the New York State Reliability Council. NYISO complies with NPCC and NYSRC resource adequacy criteria of no more than one occurrence of loss of load per ten years due to a resource deficiency, as measured by 0.10 days/year LOLE. The assumptions take into account demand uncertainty, scheduled outages and deratings, forced outages and deratings, assistance over interconnections with neighboring control areas, NYS Transmission System emergency transfer capability, and capacity and/or load relief from available operating procedures. The NYSRC establishes the IRM85 based on a technical study conducted by the NYISO and the Installed Capacity Subcommittee (of the NYSRC). This study find the required amount of installed capacity needed to meet the 0.1 days/year LOLE criterion. Following this study, the NYISO conducts the Locational installed Capacity Requirements (LCR) study86. This study determines the amount of Unforced Capacity (UCAP) that load serving entities must procure to reliably meet demand in New York’s high load Areas. NYISO has the New York State Gas-Electric Coordination Protocol as Appendix BB 87in the Open Access Transmission Tariff (OATT). This Coordination Protocol applies to circumstances in which the NYISO has determined (for the bulk power system) or a Transmission Owner has determined (for the local power system) that the loss of a Generator due to a Gas System Event would likely lead to the loss of firm electric load. This Coordination Protocol also applies to communications following the declaration of an Operational Flow Order or an Emergency Energy Alert. There are no anticipated fuel delivery problems for this winter operating period. Dynamic and static reactive power studies are performed based on anticipation of issues. No reactive power issues are anticipated for this winter. Subregion Description NYISO is the only Balancing Authority in the New York Control Area. The NYCA is over 48,000 sq miles serving a total population of about 18.5 million people and peaks annually in the summer. 85 NYSRC Report titled New York Control Area Installed Capacity Requirements for the Period May 2009 Through April 2010 (December 5, 2008). 86 NYISO Report titled “LOCATIONAL MINIMUM INSTALLED CAPACITY REQUIREMENTS STUDY COVERING THE NEW YORK CONTROL AREA For the 2008 – 2009 Capability, February 28, 2009. 87 New York State Gas-Electric Coordination Protocol, Attachment BB of the NYISO Open Access Tariff (OATT), September 30, 2008. 2009/2010 Winter Reliability Assessment Page 76 Regional Reliability Self-Assessments Ontario Demand Ontario’s forecast winter peak demand is 22,848 MW based on Monthly Normal weather and taking into consideration the impacts of planned conservation, growth in embedded generation and the economic retrenchment. The forecast peak for winter 2009/2010 is 0.6 percent lower than the 22,983 MW actual peak demand for this past winter, which occurred on January 15, 2009. Also, the 2009/2010 winter forecast is 0.2 percent lower than last winter’s weather- corrected peak demand of 22,901 MW. Last winter, the relatively high forecasted peak of 23,710 MW had not yet captured the impact of the economic recession. The current forecast’s declining peak is the result of reductions due to economic forecast and conservation initiatives offsetting the demand growth from an increasing building stock. Despite a growth in the number of customers – i.e. building stock – overall demand will decrease, as savings from existing customers will be greater than the increase due to the growth in new customers. Ontario demand is the aggregation of generator injections (and net exports). Since there is no market or sectoral segmentation of load the forecast is generated at the aggregated level. However, it is recognized that the demand is made up of these various sectors. As such, these are model drivers that would represent different market segments. Households are used as a driver for residential demand. Employment is used as a d river for the commercial sector and manufacturing employment is used as a driver for the industrial sector. The Ontario Power Authority (OPA) is responsible for promoting conservation and demand management within Ontario. The OPA provides the IESO with projected conservation based on their programs. Validation and verification of these savings are the purview of the OPA. A sizeable number of loads within the province bid their load into the market and are responsive to price and to dispatch instructions. Other loads have been contracted by the OPA to provide Demand Response under tight supply conditions. The forecast amount of these demand measures has been steadily increasing and now amounts to approximately 1,441 MW in total of which 1,027 MW is included for seasonal capacity planning purposes, with 593 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 winter peak of 22,848 MW, the LFU is 581 MW. Economic factors do not have a significant impact in seasonal assessments. Since Ontario is a large geographic area, the IESO uses six weather stations to capture the weather variability across the province. Although the analysis is driven from the system’s perspective the individual zones reflect their weather and economic diversity. The IESO addresses winter extreme weather conditions by using the most severe weather experienced since 1970 for each time period of the analysis. Generation The total capacity of existing installed generation resources (35,370 MW) and loads as a capacity resource (823 MW) connected to the IESO controlled grid is 36,193 MW, of which the amount Page 77 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments of ‘Certain’ capacity is 28,118 MW for December 2009. The remainder, 8,075 MW, is ‘Other’ capacity for December 2009 which includes the on-peak resource deratings, planned outages, and transmission-limited resources. The certain capacities for January and February are 30,659 MW, and 28,446 MW respectively. East Windsor Cogeneration project with an on-peak value of 84 MW is scheduled to come into service before December 2009. By January peak, it is expected that the natural gas fired Fort Frances Cogeneration plant (105 MW) will be converted to biomass to produce 47 MW and an additional 204 MW of demand measures will be added. Capacity contribution from wind for winter months, December, January and February, is assumed at 31 percent of the installed capacity. Wind capacity contribution values (percent of installed capacity) are determined by picking the lower value between the actual historic median wind generator contribution and the simulated 10 year wind historic median value at the top 5 demand hours of the day for each month. No other variable resources (solar etc) are connected to the IESO controlled grid or are expected to be connected between now and February 2010. For wind, the ‘Certain’ capacity is 336 MW and ‘Other’ capacity is 748 MW. For biomass, the ‘Certain’ capacity is 47 MW and ‘Other’ capacity is 28 MW for December 2009. These values are 94 MW and 28 MW for January and February. IESO resource adequacy assessments include hydroelectric generation capacity contributions based on median historical values of hydroelectric production plus operating reserve provided during weekday peak demand hours. The capacity assumptions are updated annually, in the second quarter of each year. Energy capability is provided by market participants’ forecasts. The amount of available hydroelectric generation is greatly influenced both by water-flow conditions on the respective river systems and by the way in which water is used by the generation owner. Material deviations from median conditions are not anticipated at this time. In the operating timeframe, water resources are managed by market participants through market offers to meet the hourly demands of the day. Since most hydro storages are energy limited, hydroelectric operators identify weekly and daily limitations for near-term planning in advance of real-time operations. The province does not anticipate any weather or fuel related constraints that would reduce generating capacity. No generators are expected to be retired ahead of or during the upcoming winter. Capacity Transactions on Peak 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. No firm exports are projected during peak demand. 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. 2009/2010 Winter Reliability Assessment Page 78 Regional Reliability Self-Assessments Transmission Since last winter, a new interconnection between Hawthorne transformer station (TS) in Ontario and Outaouais station in Québec went in service. The new interconnection is designed for an ultimate capacity of 1,250 MW; however, the import and export capability could be limited to less than the nominal capacity, depending on level of load and generation in the Outaouais Region. After the completion of transmission reinforcement work in Québec, anticipated for May 2010, the interconnection will be able to operate up to its nominal capacity. The following bulk power system transmission projects are planned before the upcoming winter. Ontario Table 1: New Transmission Facilities Description Proposed I/S Date Nanticoke TS: new 2x250 Mvar shunt capacitors 2009-Q3 Middleport TS: new 4x250 Mvar shunt capacitors 2009-Q4 Buchanan TS: new 200 Mvar shunt capacitors 2009-Q4 The transmission facilities listed in the table above are currently on schedule for their expected in-service dates. None are critical to the reliability of the bulk system for the winter. The forced outage to the 230 kV circuit BP76 on the Ontario-New York interconnection at Niagara continues to reduces the total Ontario-New York import and export capability until its scheduled return to service in the third quarter of 2010. Phase angle regulators are installed on three of the four Michigan to Ontario interconnections. One phase angle regulator, on the Keith to Waterman 230 kV circuit J5D, is in service and regulating. The other two available phase angle regulators, on circuits L51D and L4D at Lambton TS, are currently bypassed during normal operations, but are available for use during emergency operations. The fourth phase angle regulator, on the 230 kV circuit B3N, is scheduled for replacement in 2010. They will become operational once agreements between the IESO, the Midwest ISO, Hydro One and the International Transmission Company, are finalized. The operation of the phase angle regulators will assist in the control of circulating flows. However, Ontario meets all reliability criteria without dependence on any external resources. Ontario has many operating limits and instructions that could limit transfers under specific conditions, but for the forecast conditions including design-criteria contingencies, sufficient resources and bulk system transfer capability is expected to be available to manage potential congestion and supply forecast demand. In the winter, Ontario’s theoretical maximum capability for coincident exports could be up to 5,750 MW and coincident imports up to 6,200 MW. These values represent theoretical levels that could be achieved only with a substantial reduction in generation dispatch in the West and Niagara transmission zones. In practice, the generation dispatch required for this high transfer levels would rarely, if ever materialize. Therefore, at best, due to internal constraints in the Ontario transmission network, Ontario has an expected coincident import capability of approximately 4, 600 MW. This amount does not recognize transmission or generation constraints external to the area. Page 79 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments No significant substation equipments such as SVC, FACTS devices, etc. were added since the last winter. Operational Issues IESO addresses winter extreme weather conditions by doing planning studies using the most severe weather experienced since 1970. Studies show that Ontario will have sufficient reserve over the winter period under extreme weather conditions. Ontario experienced surplus baseload generation under minimum demand conditions over the spring and summer months of 2009. However, the risk of surplus baseload generation conditions is expected to be low over the upcoming winter period. Intermittent variable generators are not economically dispatched to assist with surplus generation management; their contracts permit them to inject energy when they chose. They can, however be curtailed for reliability reasons. Future renewable project contracts are expected to provide incentives to self-curtail production during minimum demand conditions. IESO will start a centralized wind forecasting service in 2010 to improve the accuracy of wind generation forecast. This will assist with the management of wind variability and its influence on load-generation balance. Demand measures, currently, comprise only less than 4 percent of total resources and is about 6.3 percent of projected peak demand. It does not pose any significant concern to reliability. Demand measures are grouped into two categories, price sensitive and voluntary. IESO considers only price sensitive demand for adequacy assessment purposes and to be dispatched, they have to bid into the market, like other resources. There are no unusual operating conditions, environmental, or regulatory restrictions that are expected to impact reliability for this winter. The Ontario program to reduce emissions from coal-fired generation is achievable without impacting on reliability. 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”.88 The Reserve Margin target used for Ontario is 17.5 percent based on the NPCC criteria. Planning reserves, determined on the basis of the IESO’s requirements for Ontario self- sufficiency, are above target levels for all weeks over this period. On average, the projected Reserve Margins for the upcoming winter are 2.9 percent higher than the projected margin for the winter of 2008/2009. Reserve requirements are established in conformance with the NPCC Regional criteria. The latest study results are published in the 18-Month Outlook.89 88 http://www.ieso.ca/imoweb/monthsYears/monthsAhead.asp 89 http://www.ieso.ca/imoweb/pubs/marketReports/18MonthOutlook_2009aug.pdf 2009/2010 Winter Reliability Assessment Page 80 Regional Reliability Self-Assessments Due to the convergence of the natural gas and electricity sectors, the IESO continues to work with the Ontario gas transportation industry to identify and address issues. There are communication protocols in effect between the IESO and the gas pipe lines to manage and share information under tight supply conditions in either sector (gas or electricity). The IESO regularly conducts transmission studies that include results of stability, voltage and thermal and short-circuit analyses in conformance with NPCC criteria. The IESO’s interim transmission studies in 2008 were conducted to comply with the NERC TPL standards, in addition to NPCC criteria. The IESO has market rules and connection requirements that establish minimum dynamic reactive requirements, and the requirement to operate in voltage control mode for all resources connected to the IESO-controlled grid. In addition, the IESO’s transmission assessment criteria includes requirements for absolute voltage ranges, and permissible voltage changes, transient voltage-dip criteria, steady-state voltage stability and requirements for adequate margin demonstrated via pre and post-contingency P-V curve analysis. These requirements are applied in facility planning studies. Seasonal operating limit studies review and confirm the limiting phenomenon identified in planning studies. Subregion Description The province of Ontario covers an area of 1,000,000 square kilometres (415,000 square miles) with a population of 12 million. The Independent Electricity System Operator (IESO) directs the operations of the IESO-controlled grid (ICG) and administers the electricity market in Ontario. The ICG experiences its peak demand during the summer, although winter peaks still remain strong. Page 81 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments Québec Demand Concerning weather assumptions for the demand forecast, Hydro-Québec Distribution (HQD) introduced in 2007 a new weather pattern in its load forecast which is based on the average climatic conditions observed from 1971 to 2006 (36 years) adjusted for a global warming effect of 0.30°C per decade starting in 1971. Climatic uncertainty is modeled by recreating each hour of this 36-year period under the current load forecast conditions. Moreover, each year of historic data is shifted up to ± 3 days to gain information on conditions that occurred during either a weekend or a weekday. Such an exercise generates a set of 252 different demand scenarios. The base case scenario is the arithmetical average of those 252 scenarios. Given the global uncertainty, and assuming a normal distribution, the peak demand standard deviation is 1,690 MW for the 2009/2010 Winter Operating Period. The latest forecast – based on economic, demographic and energy-use assumptions – will be made public in the next HQD 2008-2017 Procurement Plan Progress Report to be filed with the Régie de l’énergie du Québec (Québec Energy Board) in November 2009. The 2009 Progress Report will be available on the Québec Energy Board website in early November. HQD is the only Load Serving Entity in the Québec Balancing Authority Area. Thus, there is no demand aggregating in the forecasts. The observed peak internal demand for the 2008/2009 winter was 37,230 MW reached on January 16th, 2009 at 8h00 EST. This is a new all-time record for demand in Québec. Internal demand was approximately 850 MW higher than the forecast. This is due to a short but sharp cold spell, culminating on January 16th. Montréal temperature at the time of peak was -26°C (- 11°F) and wind speed was about 11 km/hour (7 mph). The rest of the 2008/2009 winter experienced close to normal temperatures and internal demand values were close to projected values. The internal demand forecast for the 2009/2010 winter is 36,116 MW. This forecast is about 300 MW less than last year’s winter forecast. This decline in electrical demand is driven mainly by the industrial sector, especially from pulp and paper and from smelting and refining industrial loads. The Québec area is still affected by the general economic slowdown observed in the United States and Canada. There are two interruptible load programs in Québec totalling 1,250 MW. Each program addresses different industrial customers. Moreover, the area can rely on 250 MW of direct control load management in the form of voltage reduction. Therefore, for the Winter Operating Period Québec relies on a total of 1,500 MW of Demand Response programs. This represents 4.2 percent of the internal demand forecast. These interruptible load programs have existed for quite a number of years and each time customers were called to curtail their loads, response was very good. Industrial customers participating in these programs are bound by contract to interrupt their load when required by the System Controller. Customers may thus be required to interrupt load up to 20 times per winter period totalling 100 hours. Operating instructions addressing the interruptible load programs are reviewed every year to make sure that the communication 2009/2010 Winter Reliability Assessment Page 82 Regional Reliability Self-Assessments flowchart between TransÉnergie and the customers are updated (Customer name, address, phone number, personnel to be contacted, etc.). Follow-up of the interruptible load programs is done by compiling differences between the customers’ real consumption and an anticipated hourly load profile of customers at the time the program is scheduled to be in effect. Concerning current and projected energy efficiency programs, on a yearly basis Hydro-Québec Distribution presents its Energy Efficiency Plan Update (Plan global en efficacité énergétique – PGEÉ) to the Québec Energy Board for the next and upcoming years. The capacity contribution of the different programs implemented by Hydro-Québec in the last few years is estimated to be about 1,910 MW at peak. Of this amount, the PGEÉ program contributes about 570 MW. The PGEÉ focuses on energy conservation measures and includes programs tailored to residential customers, commercial and institutional markets, small and medium industrial customers, and large-power customers.90 The programs and tools for promoting energy savings are the following: For residential customers Energy Wise home diagnostic Recyc-Frigo (old refrigerator recycling) Electronic thermostats Energy Star qualified appliances Lighting Pool-filter timers Energy Star windows and patio doors Rénoclimat renovating grant Geothermal energy For business customers – small and medium power users Empower program for buildings optimization Empower program for industrial systems Efficient products program Traffic light optimization program Energy Wise diagnostic For business customers – large power users Building initiatives program Industrial analysis and demonstration program Plant retrofit program Industrial initiatives program In addition to these energy saving programs, a “dual energy” program has been ongoing for some years in Québec. Recently, the number of interested customers has increased. Program subscribers are fitted with automatic devices that switch from electrical energy to fuel as a heating source when outdoor temperature is -12°C or lower. According to the most recent 90 http://www.hydroquebec.com/energywise/index.html Page 83 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments program evaluations the peak load for next winter would be 840 MW higher without this program. Since the Québec Balancing Authority Area is winter peaking winter conditions are obviously explicitly addressed in assessing variability in projected demand. For the next winter, the overall uncertainty (one standard deviation) represents ± 1,690 MW around the peak forecast. Climatic uncertainty accounts for 1,530 MW (one standard deviation) of this global uncertainty. Generation To increase the visibility and transparency of supply-side resource options being considered in the Québec Balancing Authority Area the following information concerning capacity resources is supplied in this assessment. Existing-Certain Resources: 39,830 MW Existing-Other Resources: 1,844 MW Exiting Inoperable Resources: 547 MW The vast majority of capacity resources in the Québec Area are hydro-electric resources. The variable resources in the area are wind resources. Nameplate capacity is 642 MW. Of this, 195 MW is under contract with Hydro-Québec Production (HQP) and is de-rated by 100 percent for this report (as in earlier reports) since studies are still ongoing to assess the de-rate factor for HQP. The rest, 447 MW, is under contract with HQD and results from the so-called “first call for tenders” which, when construction ends, will result in approximately 990 MW of wind capacity for HQD. In previous assessments, the entire wind capacity on the system was de-rated by 100 percent. Little capacity existed on the system and little diversity was observed. Longer term observation and a larger overall wind capacity in the last year have now prompted HQD to review the de-rating factor for 2009/2010. Simulations have now shown that a 70 percent de-rate factor can be safely applied to HQD wind capacity. A small amount of the capacity in Québec is generated by biomass. This is approximately 180 MW. No new resources are expected to be placed in-service through this assessment’s timeframe. Hydro conditions for this upcoming Winter Operating Period are such that reservoir levels are higher than average. Reservoir levels are sufficient to meet both peak demand and the daily energy demand throughout the winter. To assess its energy reliability Hydro-Québec has developed an energy criterion stating that sufficient resources should be available to go through sequences of 2 or 4 consecutive years of low water inflows totalling 64 TWh and 98 TWh respectively and having a 2 percent probability of occurrence. Reliability assessments based on this criterion are presented three times a year to the Québec Energy Board.91 91 Available in French at this web address: http://www.regie-energie.qc.ca/audiences/Suivis/Suivi_HQD_CriteresFiabilite_D-2008-133.html 2009/2010 Winter Reliability Assessment Page 84 Regional Reliability Self-Assessments Fuel supply and transportation is not an issue in Québec, as oil generation is used for peaking purpose only and adequate supplies are stored nearby. No other conditions that would create capacity reductions are expected for the 2009/2010 winter period. Finally, as was mentioned in previous assessments, the 547-MW natural gas unit operated by TransCanada Energy at Bécancour has been mothballed for the last two years. On July 2, 2009, HQD and TCE again filed a contract modification with the Québec Energy Board to renew the temporary shutdown for 2010 with possible renewals for future years. Deliveries could resume on January 1, 2011, depending on the evolution of the demand forecast. One 150-MW fossil fuel generation unit will be out of service this winter. Resource adequacy and reliability are not affected by these outages. Hydro unit availability is expected to be almost 100 percent. Capacity Transactions on Peak Concerning capacity transactions, the Québec Balancing Authority Area does not need external purchases to ensure resource adequacy for the 2009/2010 Winter Operating Period. However, HQP has a firm purchase of 200 MW from the Maritimes Area during this period. This is backed by a firm contract for generation and by a firm reservation on a Maritimes - Hydro-Québec interconnection path. This transaction adds 200 MW to the Québec Reserve Margin but does not affect the Regional Reserve Margin. On the other hand, the Québec Area has firm contracts for total exports of 705 MW to New England (310 MW), Ontario (145 MW) and New-Brunswick (250 MW). Again, firm generation and transmission have been secured for these transactions. Moreover, expected sales of 1,050 MW in December, 350 MW in January and 650 MW in February are projected to other Areas and are under negotiation. The Québec Balancing Authority Area’s Reserve Margin is higher than the required reserve to meet its resource adequacy criterion. These firm and expected sales do reduce Reserve Margins but they still remain higher than the required target. Finally, for the next Winter Operating Period, it is not expected that the Québec Balancing Authority Area will need external resources for reliability purposes. Transmission On July 2, 2009, TransÉnergie commissioned the first HVdc converter of the new Outaouais substation and its interconnection with IESO in the Ottawa-Gatineau area across the Ottawa River. The interconnection consists of two 625-MW back-to-back HVdc converters in Québec and a double-circuit 240 kV line to Hawthorne substation in Ottawa. On the Québec side of the converters a 315 kV switchyard integrates the interconnection into the existing system. Chénier 735/315 kV substation, north of Montréal is the source station feeding this interconnection. The second converter is scheduled for commissioning in November 2009 and both converters will be available for the 2009/2010 Winter Operating Period. A double-circuit 315 kV line from Chénier feeds the interconnection. These circuits also feed local load and integrate local generation so that full interconnection capability will not be Page 85 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments available at all times. Winter capability during peak periods is expected to be 810 MW in the export mode and 1020 MW in the import mode. In summer 2010, a fourth 1,650 MVA 735/315 kV transformer will be added at Chénier along with a new double-circuit 315 kV line from Chénier to Outaouais. This will then permit full use of the 1,250-MW interconnection capability. In the meantime, the commissioning of the second converter of the Outaouais Interconnection should follow the proposed schedule. As was mentioned earlier, the Québec Balancing Authority Area is winter peaking. Thus no significant transmission line maintenance is done during the Winter Operating Period and no transmission line is expected to be out of service during that period. No internal transmission constraints that could significantly impact reliability are expected in the Québec Balancing Authority Area. In Québec, transmission and generation maintenance is done during the summer period. However, no maintenance is scheduled that will impact interconnection transfer capability to other subregions during peak periods. Synchronous condenser CS23 at Duvernay substation in the Montréal area, which became unavailable in June 2008 due to a major transformer fault may not be back in service for the 2009/2010 Winter Operating Period. The Duvernay Synchronous Condenser outage causes 100 to 400 MW of restrictions on three 735 kV interfaces on the system. The normal transfer capability on these interfaces is usually well over 10,000 MW so that this is not expected to significantly impact transmission reliability for the 2009/2010 Winter Operating Period. One phase of transformer T8 at Micoua 735/315 kV substation failed on September 12, 2008 and is being replaced. This transformer station is situated in the Manicouagan sub-system and integrates generation from the Manicouagan, Toulnustouc and Outardes river systems (Approximately 5,000 MW). Presently, the delivery date for the new phase is November 22, 2009 for an in-service date of January 31, 2010. It was also mentioned in the Winter 2008/2009 Assessment that Carignan 735/230 kV substation East of Montréal had one of its two transformers on forced outage. This transformer was returned to service March 27, 2009. The substation will be operated with both transformers for the 2009/2010 Winter Operating Period. Finally, it was mentioned in the 2009 Summer Assessment that on March 8, 2009, one of the two back-to-back 500-MW HVdc converters at Châteauguay substation, south of Montréal, had tripped out with multiple thyristor failure. The converter was back in service on June 21, 2009. The interconnection with the New York Balancing Authority Area is scheduled to be in service throughout the 2009/2010 Winter Operating Period. The following table indicates the interregional transfer capabilities out and into Québec with its neighbor systems for the 2009/2010 Winter Operating Period.92 These limits represent Normal 92 Limits obtained and updated from the NPCC Reliability Assessment for Winter 2008/2009. 2009/2010 Winter Reliability Assessment Page 86 Regional Reliability Self-Assessments Transfer Capability values for the Winter Operating Period. Actual Feasible Transfer Capability (FTC) values during peak periods in Québec may be lower. For example, the limit into Québec from New England (Sandy Pond) at the Québec peak is zero because the interconnection is required for internal Québec transmission needs. Both NTC and FTC values are shown in the NPCC Seasonal Reliability Assessments. Québec Table 1: 2009/2010 Winter Interconnection Normal Transfer Capability (MW) Interconnection Limit out of Québec Limit into Québec Ontario North (D4Z, H4Z) 85 110 Ontario Ottawa (X2Y, P33C, Q4C) 410 140 Ontario Brookfield (D5A, H9A) 250 200 Ontario Beauharnois (B5D, B31L) 800 470 Ontario Ottawa (Outaouais 1,250 1,250 Interconnection) New York (CD11, CD22) 325 100 New York (7040) 1,500 1,000 New England (Highgate) 220 170 New England (Stanstead-Derby) 50 0 New England (Sandy Pond) 2,000 1,700 New Brunswick (Madawaska + Eel 985 to 101793 770 River) These limits recognize transmission or generation constraints in both Québec and its neighbors. They are reviewed periodically with neighboring systems and are posted in the NPCC Reliability Assessments. Finally, since the last winter season, no significant substation equipment such as SVCs, FACTS controllers and HVdc systems have been added in the Québec Balancing Authority Area except the HVdc and associated equipment that was commissioned at the Outaouais interconnection substation in July 2009. Operational Issues In its review of resource adequacy for the NPCC, HQD includes a high load forecast scenario. The economic, demographic and energy parameters used for the study are set higher relative to the base case scenario. The load uncertainty then becomes dependent on weather conditions only. If the criterion (0.1 day/year of LOLE) is not met, actions to restore reliability are identified and established (new calls for tenders, new interruptible load contracts or an in service date for new generation units sooner than expected). 93 Transfer capability is dependant on New Brunswick radial load. Page 87 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments Moreover, TransÉnergie continually performs load flow and stability studies to assess system reliability and transfer capabilities on all its internal interfaces. A peak load study is performed annually integrating new generation, new transmission and the latest demand forecasts as well as any unusual operating conditions such as generation and transmission outages. Extreme cold weather conditions result in a large load pickup over the normal weather forecast and are included in TransÉnergie’s Transmission Design Criteria. When designing the system, both steady state and stability assessments are made with winter scenarios involving demands 4,000 MW higher than the normal weather peak demand forecast. This is equivalent to 110 percent of peak winter demand. The Québec Balancing Authority Area also participates in the seasonal CO-12 and CP-8 NPCC Working Group assessments of system reliability. A recent planning study has shown a transfer increase of about 700 MW across the Southern interface of the TransÉnergie system over the last few years. This is due to a steady load increase in the southern part of the system combined with a steady load decrease in the northern part of the system. This change impacts system performance beginning in 2012. Moreover, during Winter Operating Periods, TransÉnergie has to cope with voltage variations due to stiff load rises during cold spells coupled with positive ramping at the interconnections. To reduce the number of Automatic Shunt Reactor Disconnecting System (French acronym: MAIS) operations ─ MAIS is designed to operate following extreme contingencies to restore 735 kV system voltages ─ a new operating tool to control capacitor bank switching in the Montréal area was implemented. Also, the assessment of system performance concerning voltage variations led to the implementation of a new design criterion to specifically address this problem. This has led ─ along with the previously mentioned planning study ─ TransÉnergie to bring forth a project to upgrade its transmission system by 2012. The upgrade consists mainly of series compensation additions at Jacques-Cartier 735 kV substation, the addition of two SVCs at Chénier 735 kV substation, other 735 kV series compensation upgrades and 735 kV line protection modifications. This project has been filed with the Régie de l’énergie du Québec (Québec Energy board) on April 8, 2009 and approved by the Régie on August 25, 2009. The upgrades to the system for 2012 have also been presented and studied in the last NPCC Comprehensive Review Assessment of the Québec Transmission System for 2012 approved by the NPCC Reliability Coordinating Committee on May 28, 2008. No other particular operational problems have been observed for the oncoming 2009/2010 Winter Operating Period. To date, the Québec Balancing Authority Area has no special operating procedures resulting from integration of variable resources in Québec. Moreover, the Area does not anticipate any reliability concerns resulting from minimum demand and over generation resulting from variable resources for the 2009/2010 Winter Operating Period. In Québec, minimum demand periods occur during the Summer Operating Period. A certain amount of hydro generation at run of the river installations must be generated along with 2009/2010 Winter Reliability Assessment Page 88 Regional Reliability Self-Assessments more and more wind generation being integrated on the system ─ which may be contributing if the right conditions occur ─ so that such conditions may occur on the longer term during summer. Most of the generation in the Area is hydro with large medium or large size reservoirs and can be modulated to follow load variations. No reliability concerns resulting from high levels of Demand Response resources are anticipated. In the Québec Balancing Authority Area Demand Response resources are uniquely under the form of interruptible load programs. Contracts with large high voltage industrial customers and smaller industrial loads permit precise use of Demand Response resources as needed according to system needs at specific times and intervals during the Winter Operating Period. There are no environmental and/or regulatory restrictions that could impact reliability in Québec for the 2009/2010 Winter Operating Period. No other unusual operating conditions that could significantly impact reliability for the upcoming winter are anticipated in Québec. Reliability Assessment Analysis The Québec Area reliability criterion complies with the NPCC Resource Adequacy Criterion which uses Loss of Load Expectation (LOLE) of 0.1 day per year as its resource adequacy criterion. Last year’s report indicated that for the 2009/2010 winter peak period, Québec required a reserve of 10.4 percent (Reserve Margin over Net Internal Demand). On a less than one year horizon the required reserve is inferior to 10 percent. In this assessment, the 11 percent projected reserve is sufficient to cover the 10 percent target required reserve.94 The assessment of short term reliability for the 2009/2010 winter peak period is now in progress. Preliminary results indicate that the required reserve should be smaller than 10 percent. Final results of the study will be filed with NPCC in November within the framework of the 2009 Québec Interim Report on Resource Adequacy. Concerning the adequacy of fuel supplies it was mentioned earlier that the Québec Area fossil fuel generation stations are used for peaking purposes only. The energy contribution of these generating stations is minimal. All have adequate fuel reserves as part of their installations and all are fueled at the beginning of the Winter Operating Period. Voltage support in the southern part of the system (load area) is a concern during the Winter Operating Period especially during episodes of heavy load. Hydro-Québec Production (the largest producer on the system) ensures that maintenance on generators is be finished by December 1, and that all possible generation is available. This, along with yearly testing of reactive capability of the generators, ensures maximum availability of both active and reactive power. The end of TransÉnergie maintenance on the high voltage transmission system is also targeted for December 1. Also, TransÉnergie has a target for the availability of both high voltage and low voltage capacitor banks. No more than 200 Mvar of high voltage banks on a total capacity of approximately 9,000 Mvar should be unavailable during the Winter Operating 94 The 2008 Quebec Comprehensive Review of Resource Adequacy can be found at the following internet address: http://www.npcc.org/documents/reviews/Resource.aspx Page 89 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments Period. The target for the low voltage banks is 90 percent availability based on installed capacity in the load area of the system (About 5,500 Mvar). As mentioned above, voltage variations on the high voltage transmission system are also of some concern. These are normal variations due to changes in transmitted power from North to South during load pickup and interconnection ramping. Under peak load conditions, these variations may be large enough to trigger the Automatic Shunt Reactor Switching System and must be contained. In 2008 TransÉnergie had recommended and undertaken a number of actions to optimize shunt reactor switching such as: New software (CTRM) for the Montréal Area voltage control at the Control Center Enhancement of reactive power control at Châteauguay Converters Optimization of DC interconnection power ramping as a function of system conditions Study of dynamic shunt compensation additions in the Montréal Area for the 2011-2012 horizon This study and others have led, as mentioned, to transmission upgrade projects filed with the Régie de l’énergie du Québec in April 2009. Subregion Description The Québec Balancing Authority Area is winter peaking. The all-time internal peak demand was 37,230 MW set on January 16, 2009. The summer peak demands are in the order of 21,000 MW. The installed capacity in 2009 is 42,370 MW of which 39,000 MW (92 percent) is hydroelectric capacity. The transmission voltages on the system are 735, 315, 230, 161 and 120 kV. Transmission line length totals about 33,058 km (20,540 miles). The Québec Balancing Authority Area is a separate Interconnection from the Eastern Interconnection into which other NPCC Areas are interconnected. TransÉnergie ─ the Transmission Owner and Operator in Québec ─ has interconnections with Ontario, New York, New England and the Maritimes. Interconnections consist of either HVdc ties or radial generation or load to and from the neighboring systems. The population served is around 7 million and the Québec Area covers about 1,668,000 square km (644,300 square miles). Most of the population is grouped along the St-Lawrence River axis and the largest load area is in the Southwest part of the province, mainly around the Greater Montréal area, extending down to the Québec City area. 2009/2010 Winter Reliability Assessment Page 90 Regional Reliability Self-Assessments Region Description The Northeast Power Coordinating Council, Inc. (NPCC Inc.) is the international Regional Reliability Organization (RRO) for Northeastern North America. Its purpose is to promote the reliable and efficient operation of the international, interconnected bulk power systems in Northeastern North America through the establishment of Regionally-specific criteria, coordination of system planning, design and operations, assessment of reliability and monitoring and enforcement of compliance with such criteria, and other applicable criteria. In the development of reliability criteria, NPCC Inc., to the extent possible, facilitates attainment of fair, effective and efficient competitive electric markets. NPCC Inc. is a not-for-profit New York corporation. The geographic area covered includes New York, the six New England states, and Ontario, Québec, and Maritime Provinces in Canada. The total population served is approximately 56 million over approximately 1 million square miles. NPCC was originally formed shortly after the 1965 Northeast Blackout to promote the reliability and efficiency of the interconnected power systems within its geographic area. NPCC restructured in response to U.S. energy legislation signed into law August, 2005, in preparation for the certification of an Electric Reliability Organization (ERO) and subsequent execution of a Regional Delegation Agreement and Memorandums of Understanding with appropriate Canadian Provincial regulatory and governmental authorities. Membership interests were transferred to NPCC Inc., and a separate and independent, affiliated, not-for-profit corporation, NPCC: Cross-Border Regional Entity, Inc. (NPCC CBRE). NPCC CBRE will perform functions delegated or contracted to it from the ERO, to be backstopped by the Federal Energy Regulatory Commission (FERC) and Canadian Provincial authorities. Additional information can be found on the NPCC Web site (http://www.npcc.org/). Page 91 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments RF C Regional Assessment Summary 2009/2010 Winter Projected Peak Demand MW On-Peak Capacity by Fuel Type Total Internal Demand 145,800 Dual Direct Control Load Management 600 Gas Fuel Contractually Interruptible (Curtailable) 4,300 Nuclear 20% 8% Critical Peak-Pricing with Control 0 15% Other Load as a Capacity Resource 0 2% Net Internal Demand 140,900 Oil Coal 8% 2008/2009 Winter Comparison MW % Change 47% Pumped 2008/2009 Winter Projected Peak Demand 143,123 -1.6% 2008/2009 Winter Actual Peak Demand 146,139 -3.6% Storage All-Time Winter Peak Demand 150,640 -6.5% 2% 2009/2010 Winter Projected Peak Capacity MW Margin Existing Certain and Net Firm Transactions 215,800 53.2% Deliverable Capacity Resources 215,800 53.2% Prospective Capacity Resources 217,200 54.2% NERC Reference Margin Level - 15.0% All ReliabilityFirst Corporation (RFC) members are affiliated with either the Midwest ISO or the PJM Interconnection (PJM) Regional Transmission Organization (RTO) for market operations and reliability coordination. Ohio Valley Electric Corporation (OVEC), a generation and transmission company located in Indiana, Kentucky and Ohio, is not with a member of either RTO and is not affiliated with their markets; however, PJM performs OVEC’s Reliability Coordinator services. Also, RFC does not have officially designated subregions. The Midwest ISO and PJM each operate as a single Balancing Authority area. Since all RFC demand is in either Midwest ISO or PJM except for a small load (less than 100 MW) within the OVEC Balancing Authority area, the reliability of the PJM RTO and Midwest ISO are assessed and the results used to indicate the reliability of the RFC Region. This assessment provides information on the projected resource adequacy for the upcoming winter season across the RFC Region. The RFC Resource Adequacy Assessment Standard BAL- 502-RFC-02, requires Planning Coordinators to identify the minimum planning reserves to maintain resource adequacy for their respective areas of RFC. PJM and Midwest ISO are the Planning Coordinators for their market areas. The reserve requirements in this assessment are based upon the explicit probability analyses conducted by these two Planning Coordinators in RFC. In this report, Demand Response (DR) is defined as the demand that can be interrupted for system emergencies. This report will divide the RFC Region into the areas operated by PJM and Midwest ISO. The remaining area of PJM operates within the SERC Region, and the remaining area of Midwest ISO operates in the MRO or SERC Regions. Demand, capacity and interchange values in this report are rounded to the nearest 100 MW. 2009/2010 Winter Reliability Assessment Page 92 Regional Reliability Self-Assessments PJM RTO Demand Total Internal Demand (TID) represents the total forecast electric system demand. The forecast is developed by PJM staff for each of its load zones, and aggregated as the PJM coincident peak demand. This demand forecast is based on an expected or “50/50” weather forecast. This 50/50 demand forecast uses a winter temperature profile on the peak day at the 50th percentile for cold weather. This means that there is a 50 percent probability that the temperature on the peak day would be warmer and 50 percent probability that the temperature would be colder. The winter demand forecast is from data provided earlier this year. Since the forecast is dated January 2009, and is based on economic data from late 2008, the demand forecast may not reflect the full impact of the current economic recession Energy Efficiency (EE) programs included within the PJM load forecast are programs that have committed through the PJM Reliability Pricing Model (RPM). No EE programs have been committed as an RPM resource for this winter. Information on PJM’s measurement and verification protocols for EE programs are available on PJM’s website95. Demand Response in this assessment only includes demand that can be interrupted for system emergencies. PJM currently has two categories of DR, Direct Control and Interruptible. Since Direct Control is used to reduce air-conditioning demand, there is no Direct Control DR during the winter for PJM. The 2009/2010 winter Interruptible Demand is 3,300 MW. This is 700 MW lower than the 2008/2009 interruptible demand of 4,000 MW. The total demand reduction for DR is the maximum controlled demand mitigation that is expected to be available during peak demand conditions. Since DR is a contractual management of system demand, use of DR reduces the Reserve Margin requirement for the RTO. Net internal demand is TID less DR. Reserve margin requirements are based on Net Internal Demand. The Net Internal Demand peak of the entire PJM RTO for the 2009/2010 winter season is projected to be 109,500 MW and to occur during January 2010. This value is based on the TID forecast of 112,800 MW with the full use of the 3,300 MW (2.9 percent of TID) of Demand Response programs (see Table RFC-1). TABLE RFC - 1: PJM RTO PROJECTED PEAK DEMANDS (MW)1 WINTER 2009/2010 DECEMBER JANUARY FEBRUARY TOTAL INTERNAL DEMAND 109,400 112,800 108,700 Direct Control Load Management 0 0 0 Interruptible Demand (3,300) (3,300) (3,300) NET INTERNAL DEMAND 106,100 109,500 105,400  - All demand totals are rounded to the nearest 100 MW. 95 PJM Energy Efficiency protocols: http://www.pjm.com/documents/~/media/documents/manuals/m18b.ashx Page 93 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments Comparing this forecast of TID to the winter 2008/2009 metered peak demand of 117,169 MW, the 2009/2010 forecast is 4,369 MW (3.7 percent) lower than the actual 2008/2009 winter peak demand. In addition, the 2008 forecast of 2009/2010 winter peak demand was 116,408 MW, making this year’s winter peak demand forecast 3,608 MW (3.1 percent) lower than last year’s forecast for the winter 2009/2010 peak demand. Although the demand forecasts used in this assessment were collected in recent months, some of these forecasts were prepared months earlier. Both weather and economic conditions have significant influence on electrical peak demands. Any deviation from the original forecast assumptions for those parameters could cause the aggregate 2009/2010 winter peak to be significantly different from the forecast. For the winter of 2009/2010, a high demand forecast was prepared by PJM staff. This 90/10 TID forecast uses a winter temperature profile on the peak day at the 90th percentile for (extreme) cold weather. This means that there is a 90 percent probability that the temperature on the peak day would be warmer and 10 percent probability that the temperature on the peak day would be colder. The PJM RTO is forecast to have a coincident 90/10 demand of 119,600 MW, a 6.0 percent increase over the 50/50 demand forecast. The impact of this demand sensitivity is included within the Reliability Assessment Analysis section of this assessment. Generation There are two general categories used when analyzing seasonal capacity resources. “Existing” capacity represents resources that have been built and are in commercial service. “Future” capacity represents planned resources that are under construction, have an interconnection service agreement and are expected to be in commercial service at the start of the planning period. The generating capacity on Table RFC-2 represents the capacity of the generation within the PJM RTO market area. The capacity category of Existing-Certain represents existing resources within PJM and committed to the market. The PJM RTO has 166,200 MW of capacity (143,600 MW within RFC) for this winter that is identified as Existing-Certain in this assessment. 2009/2010 Winter Reliability Assessment Page 94 Regional Reliability Self-Assessments TABLE RFC - 2: PJM RTO PROJECTED CAPACITY RESOURCES (MW) WINTER 2009/2010 Capacity as of June 1, 2009 EXISTING CAPACITY 168,000 Inoperable (Scheduled Maintenance) 0 Energy Only Resources (including variable gen) (1,800) Uncommitted Resources 0 Transmission Limited Resources 0 OTHER EXISTING CAPACITY (1,800) EXISTING CERTAIN CAPACITY 166,200 CAPACITY TRANSACTIONS - IMPORTS Purchases 500 Owned Capability outside the RTO 3,200 3,700 CAPACITY TRANSACTIONS - EXPORTS Sales (500) Owner Capability outside the RTO (1,900) (2,400) Net Interchange 1,300 Net Capacity Resources 167,500 The Existing-Other category includes the existing resources that represent expected on-peak wind/variable resource deratings, and other existing capacity resources within the RTO market that can participate in the PJM market as energy-only generation. There is up to 1,800 MW of these types of capacity resources. Since these resources are not in the RPM market, the deliverability 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. Only capacity additions that are in service prior to the planning year, which starts in June, are included in determining the winter Reserve Margins. Any Planned, Future capacity additions expected to go in-service during the winter period would not be included within the Reserve Margin calculations. There are no Planned, Future capacity additions included in this winter assessment. The total nameplate amount of variable generation in PJM is about 1,300 MW. This is nearly all wind power (with only 3 MW of solar), with the amount of available on-peak variable generation capability included in the reserve calculations at about 200 MW. PJM uses a three-year average of actual wind capability during the summer daily peak periods as the expected on-peak wind capability rating. Until three years of operating data is available for a specific wind project, 13 Page 95 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments percent of nameplate capability is assigned for each missing year of data for that project. The difference between the nameplate rating and the expected on-peak wind capability rating is accounted for in the Existing-Other category. There is also 700 MW of biomass (renewable) resources included in the PJM Reserve Margins. Each generator operator is expected to coordinate with the fuel industry regarding fuel supplies and deliveries. The PJM market rules are designed to encourage generator owners and operators to maintain adequate fuel supplies. PJM does not communicate directly with the fuel industry on supply adequacy or potential problems, however as an RTO, PJM does receive operational notices from the gas pipeline operators. There are no known or expected conditions or situations regarding fuel supply or delivery, hydro-electric reservoirs, adverse weather, generator availability, or capacity retirement that are anticipated to adversely impact system reliability during the 2009/2010 winter. Capacity Transactions on Peak Only specific transactions identified by PJM as interchange with firm transmission reservations are included in the Reserve Margin calculations. Some of the total interchange reported by PJM is due to jointly-owned generation. These resources are located in one RTO but have owners in both RTOs with entitlements to that generation. In addition, some of the interchange into PJM comes from OVEC entitlements. Firm power transfers into PJM are projected to be 3,700 MW. Firm power transfers out are projected to be 2,400 MW. Net interchange is therefore a 1,300 MW power import flowing into the PJM RTO. All these imports and exports are firm and fully backed by firm transmission and firm generation. There are no Liquidated Damages Contracts included in these firm capacity transfers. The emergency operating benefit from being interconnected within the Eastern Interconnection is reflected in the determination of PJM’s RTO Reserve Margin requirement. PJM does not rely on emergency imports to meet its Reserve Margin requirement. Reliability Assessment Analysis This resource assessment relies on the Reserve Margin requirements determined by PJM to satisfy the RFC Loss of Load Expectation (LOLE) criterion of not exceeding 0.1 day per year. The LOLE analysis conducted by PJM includes demand forecast uncertainty, generator outage schedules, and other relevant factors when determining the probability of forced outages exceeding the available margin for contingencies. Study criteria used in the evaluation can be found in the PJM Planning Manual M-20, “PJM Resource Adequacy Analysis”.96 The PJM Resource Adequacy Planning study can be found on the PJM website.97 96 PJM study criteria: http://www.pjm.com/documents/~/media/documents/manuals/m20.ashx 97 PJM Resource Adequacy study: http://www.pjm.com/planning/resource-adequacy-planning/reserve-requirement-dev- process.aspx 2009/2010 Winter Reliability Assessment Page 96 Regional Reliability Self-Assessments It is important to note that the capacity resources identified as Existing-Certain in this assessment have been “pre-certified” by PJM for use within their RTO market area. This means that these resources were determined to satisfy the deliverability requirements and are considered to be fully deliverable within the PJM RTO. Other existing resources may be available to serve load, but since they have not been pre-certified as deliverable, or are not in the PJM capacity market, they are not included within the Reserve Margin calculations. In Table RFC-3, the projected reserves during the 2009/2010 winter peak are 58,000 MW for the PJM RTO, which is 8,900 MW higher than the 49,100 MW of reserves last winter. This is a 53.0 percent Reserve Margin (NID) compared with a 44.4 percent Reserve Margin in the winter of 2008/2009. Since the PJM reserve requirement is based upon the summer peak demand, the total required capacity is 150,300 MW. The PJM net capacity resources are 167,500 MW, which are 17,200 MW greater than the requirement. Therefore, the PJM RTO has adequate reserves to serve the 2009/2010 winter peak demand. TABLE RFC - 3: PJM RTO PROJECTED RESERVE MARGINS WINTER 2009/2010 DECEMBER JANUARY FEBRUARY NET INTERNAL DEMAND (MW) 106,100 109,500 105,400 NET CAPACITY RESOURCES (MW) 167,500 167,500 167,500 NID RESERVE MARGINS -- MW 61,400 58,000 62,100 -- percent of NID 57.9% 53.0% 58.9% PJM Reserve Requirement -- Summer NID (MW) 130,700 -- Total MW Resources 150,300 -- percent of Summer NID 15.0% Page 97 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments Midwest ISO Demand Total Internal Demand represents the total forecast electric system demand. The forecast is developed by Midwest ISO Load Serving Entities (LSEs), aggregated to Midwest ISO Local Balancing Authorities (LBAs), and finally aggregated by Midwest ISO as the coincident peak demand. This demand forecast is based on an expected or “50/50” demand forecast. This means that there is a 50 percent probability the demand on the peak day would be expected to be lower than forecast and a 50 percent probability the peak day demand would be expected to be higher than what was forecast. The winter demand forecast is from data provided earlier this year. Since the forecast is based on economic data from late 2008 and early 2009 the demand forecast may not reflect the full impact of the current economic recession Energy Efficiency (EE) programs have not been explicitly included in the Midwest ISO load forecast for the 2009/2010 winter. At this time, Midwest ISO’s measurement and verification protocols for energy efficiency programs are under development. Demand Response (DR) in this assessment only includes demand that can be interrupted for system emergencies. Midwest ISO currently has two categories of DR, Direct Control and Interruptible. The amount of Direct Control that is expected in the winter is 600 MW. The winter Interruptible Demand is 1,800 MW. The total demand reduction for DR is the maximum controlled demand mitigation that is expected to be available during peak demand conditions, which totals 2,400 MW. Since DR is a contractual management of system demand, use of DR reduces the Reserve Margin requirement for the RTO. Net internal demand is TID less DR. Reserve margin requirements are based on Net Internal Demand. The net internal peak demand of the entire Midwest ISO RTO for the 2009/2010 winter season is projected to be 79,500 MW and to occur during January 2010. This value is based on the TID forecast prepared by Midwest ISO staff from member demand forecasts of 81,900 MW with the full use of the 2,400 MW (2.9 percent of TID) of Demand Response programs (see Table RFC- 4). TABLE RFC - 4: MIDWEST ISO PROJECTED PEAK DEMANDS (MW)1 WINTER 2009/2010 DECEMBER JANUARY FEBRUARY TOTAL INTERNAL DEMAND 81,700 81,900 79,000 Direct Control Load Management (600) (600) (600) Interruptible Demand (1,800) (1,800) (1,800) NET INTERNAL DEMAND 79,300 79,500 76,600  - All demand totals are rounded to the nearest 100 MW. 2009/2010 Winter Reliability Assessment Page 98 Regional Reliability Self-Assessments The 2009/2010 forecast NID is 4,544 MW less than the actual winter 2008/2009 peak demand of 84,044 MW. The 2009/2010 forecast TID is 2,144 MW (2.6 percent) lower than the actual 2008/2009 winter peak demand. In addition, the 2008 forecast of 2009/2010 winter peak demand is 83,300 MW, making this year’s winter TID forecast 1,400 MW (1.7 percent) lower than last year’s winter TID forecast. Although the demand forecasts used in this assessment were collected in recent months, some of these forecasts were prepared months earlier. Both weather and economic conditions have significant influence on electrical peak demands. Any deviation from the original forecast assumptions for those parameters could cause the aggregate 2009/2010 winter peak to be significantly different from the forecast. A high demand forecast was calculated by Midwest ISO, based upon a statistical analysis of the participant’s 50/50 TID forecast and historical demand data. This is a 90/10 TID forecast for the winter of 2009/2010. This means that there is a 90 percent probability the demand on the peak day would be expected to be lower than forecast and a 10 percent probability on the peak day that demand would be expected to be higher. The Midwest ISO RTO is forecast to have a coincident 90/10 demand of 86,000 MW, a 5.0 percent increase over the 50/50 demand forecast. The impact of this demand sensitivity is included within the Reliability Assessment Analysis section of this assessment. Generation There are two general categories used when analyzing seasonal capacity resources. “Existing” capacity represents resources that have been built and are in commercial service. “Future” capacity represents planned resources that are under construction, have an interconnection service agreement and are expected to be in commercial service at the start of the planning period. The generating capacity on Table RFC-5 represents the capability of the generation in the Midwest ISO RTO market area. The capacity category of Existing-Certain represents existing resources committed to the Midwest ISO market. The Midwest ISO RTO has 117,400 MW of capacity (69,800 MW within RFC) for this winter that is identified as Existing-Certain in this assessment. Page 99 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments TABLE RFC - 5: Midwest ISO PROJECTED CAPACITY RESOURCES (MW) WINTER 2009/2010 Capacity as of June 1, 2009 EXISTING CAPACITY 129,700 Inoperable (Scheduled Maintenance) (1,900) Energy Only Resources (including variable gen) (5,900) Uncommitted Resources (4,500) Transmission Limited Resources 0 OTHER EXISTING CAPACITY (12,300) EXISTING CERTAIN CAPACITY 117,400 CAPACITY TRANSACTIONS - IMPORTS 1 Purchases 4,300 Owned Capability outside the RTO 0 4,300 CAPACITY TRANSACTIONS - EXPORTS 2 Sales 0 2 Owner Capability outside the RTO 0 0 Net Interchange 4,300 Net Capacity Resources 121,700 1 - Midwest ISO reports only the power imports committed to the market area 2 - This information is not available; exported power comes from uncommitted resources in the Midwest ISO market area The Existing-Other category includes the existing resources that represent expected on-peak wind/variable resource deratings, and other existing capacity resources connected to Midwest ISO member’s transmission systems but are not committed to participating in the Midwest ISO market. There is up to 12,300 MW of these types of capacity resources. Since these resources are not in the Midwest ISO market, none of this capacity is included in the Midwest ISO Reserve Margins. Only capacity additions that are in service prior to the planning year, which starts in June, are included in determining the winter Reserve Margins. Any “Future-Planned” capacity additions expected to go in-service during the winter period would not be included in the Reserve Margin calculations. There are no Future-Planned capacity additions included in this winter assessment. 2009/2010 Winter Reliability Assessment Page 100 Regional Reliability Self-Assessments The total nameplate amount of variable generation in Midwest ISO is about 6,600 MW. This is all wind power, with the amount of available on-peak wind capability included in the reserve calculations at about 1,400 MW. In Midwest ISO, wind power providers may declare up to 20 percent of their nameplate capability as a capacity resource. The difference between the nameplate rating and the expected on-peak wind capability rating is accounted for in the Existing-Other category. There is also 200 MW of biomass (renewable) resources included in the Midwest ISO Reserve Margins. Each generator operator is expected to coordinate with the fuel industry regarding fuel supplies and deliveries. Midwest ISO market rules encourage generator owners and operators to maintain adequate fuel supplies. Midwest ISO does not communicate directly with the fuel industry on supply adequacy or potential problems, however as an RTO, Midwest ISO does receive operational notices from the gas pipeline operators. There are no known or expected conditions or situations regarding fuel supply or delivery, hydroelectric reservoirs, adverse weather, generator availability, or capacity retirement that are anticipated to adversely impact system reliability during the 2009/2010 winter. Capacity Transactions on Peak Midwest ISO reports only firm capacity imports to the Midwest ISO market. Export capacity comes from resources not in the Midwest ISO market, therefore there are no reported Midwest ISO exports. Some of the total interchange reported by Midwest ISO 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 into Midwest ISO comes from OVEC entitlements. There are no Liquidated Damages Contracts included in these firm power transfers. All these imports are fully backed by firm transmission and firm generation; therefore, they are included in the Reserve Margin calculations. The reported net import capacity into Midwest ISO is 4,300 MW. The emergency operating benefit from being interconnected within the Eastern Interconnection is reflected in the determination of Midwest ISO’s Reserve Margin requirement. Midwest ISO does not rely on emergency imports to meet its Reserve Margin requirement. Reliability Assessment Analysis This resource assessment relies on the Reserve Margin requirements determined by Midwest ISO to satisfy the RFC Loss of Load Expectation (LOLE) criterion of not exceeding 0.1 day per year. The LOLE analysis conducted by Midwest ISO includes demand forecast uncertainty, generator outage schedules, and other relevant factors when determining the probability of forced outages exceeding the available margin for contingencies. The study criteria can be found in the Midwest Page 101 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments ISO Business Practice Manual (BPM 11).98 The Midwest ISO Planning study can be found on the Midwest ISO website.99 It is important to note that the capacity resources identified as Existing-Certain in this assessment have been “pre-certified” by Midwest ISO for use within their RTO market area. This means that these resources were determined to satisfy the deliverability requirements and are considered fully deliverable within the Midwest ISO. Other existing resources may be connected to Midwest ISO member’s transmission systems, but since they have not been certified as deliverable, or are not in the Midwest ISO market, they are not included within the Reserve Margin calculations. In Table RFC-6, the projected reserves during the 2009/2010 winter peak are 42,200 MW for the Midwest ISO RTO, which is 6,400 MW higher than the 35,800 MW of reserves last winter. This is a 53.1 percent Reserve Margin (NID) compared with a 46.5 percent Reserve Margin in the winter of 2008/2009. The Midwest ISO reserve requirement is 15.4 percent of the monthly peak demand; therefore, the Midwest ISO RTO has adequate reserves to serve the 2009/2010 winter peak demand. TABLE RFC – 6: Midwest ISO PROJECTED RESERVE MARGINS WINTER 2009/2010 DECEMBER JANUARY FEBRUARY NET INTERNAL DEMAND (MW) 79,300 79,500 76,600 NET CAPACITY RESOURCES (MW) 121,700 121,700 121,700 NID RESERVE MARGINS -- MW 42,400 42,200 45,100 -- percent of NID 53.5% 53.1% 58.9% Midwest ISO Reserve Requirement -- MW 12,200 -- percent of NID 15.4% 98 Midwest ISO study criteria: http://www.midwestiso.org/publish/Document/20f443_ffd16ced4b_-7e630a3207d2?rev=15 99 Midwest ISO Resource Adequacy study: http://www.midwestiso.org/publish/Document/62c6cd_120e7409639_-7f2a0a48324a 2009/2010 Winter Reliability Assessment Page 102 Regional Reliability Self-Assessments ReliabilityFirst Corporation Demand In this assessment, the data related to the RFC areas of PJM (RFC-PJM) and Midwest ISO (RFC-MISO) are combined with the data from OVEC to develop the RFC Regional data. The demand forecasts used in this assessment are all based on the coincident peak demand of Midwest ISO’s local balancing authorities and the coincident peak of PJM’s load zones. Both PJM and Midwest ISO demand forecasts are based on an expected or 50/50 demand forecast. Actual data from the past three years indicates minimal diversity (less than 100 MW) between the RTO coincident peak demands and the RFC coincident peak demands. For this assessment, no additional diversity is included for the RFC Region; therefore, the RFC coincident peak demand is simply the sum of the PJM, Midwest ISO and OVEC peak demands (rounded to nearest 100 MW). The composite RFC Region forecast is considered a 50/50 demand forecast. Neither PJM nor Midwest ISO has identified any demand reduction to the winter demand forecast explicitly due to Energy Efficiency (EE) programs. However, the two categories of Demand Response, Direct Control and Interruptible, are expected to provide for a combined potential Demand Response reduction of 4,900 MW within the RFC Region. The Direct Control during the winter is 600 MW and the winter Interruptible Demand is 4,300 MW. The total demand reduction for DR is the maximum controlled demand mitigation that is expected to be available during peak demand conditions. Since DR is a contractual management of system demand, use of DR reduces the Reserve Margin requirement for the RTO. Net internal demand is TID less DR. Reserve margin requirements are based on Net Internal Demand. The Net Internal Demand peak of the RFC Region for the 2009/2010 winter season is 140,900 MW and is projected to occur during January 2010. This value is based on a TID forecast of 145,800 MW, with the full reduction of 4,900 MW (3.4 percent of TID) from the Demand Response programs within the Region (see Table RFC-7). Page 103 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments TABLE RFC – 7: RFC PROJECTED PEAK DEMANDS (MW)1 WINTER 2009/2010 DECEMBER JANUARY FEBRUARY RFC - PJM Area TOTAL INTERNAL DEMAND 94,300 96,600 93,100 Direct Control Load Management 0 0 0 Interruptible Demand (3,200) (3,200) (3,200) NET INTERNAL DEMAND 91,100 93,400 89,900 RFC - MISO Area TOTAL INTERNAL DEMAND 49,100 49,100 47,500 Direct Control Load Management (600) (600) (600) Interruptible Demand (1,100) (1,100) (1,100) NET INTERNAL DEMAND 47,400 47,400 45,800 RFC Totals  TOTAL INTERNAL DEMAND 143,500 145,800 140,700 Direct Control Load Management (600) (600) (600) Interruptible Demand (4,300) (4,300) (4,300) NET INTERNAL DEMAND 138,600 140,900 135,800  - All demand totals are rounded to the nearest 100 MW.  - The RFC Regional demand includes OVEC with the PJM and Midwest ISO areas of RFC. Compared to the actual winter 2008/2009 peak demand of 146,039 MW, the 2009/2010 forecast TID is 239 MW (0.2 percent) lower than the actual 2008/2009 winter peak demand. In addition, the 2008 forecast of 2009/2010 winter peak demand was 149,100 MW, making this year’s winter peak demand forecast 3,300MW (2.2 percent) lower than last year’s 2009/2010 winter peak demand forecast. Weather and economic conditions have significant influence on electrical peak demands. Any deviation from the original forecast assumptions for those parameters could cause the aggregate 2009/2010 winter peak to be significantly different from the forecast. For the winter of 2009/2010, the high demand forecasts for PJM and Midwest ISO were combined with the OVEC demand to create a high demand forecast for the RFC Region. The forecast high demand is 154,100 MW, a 5.7 percent increase over the 50/50 demand forecast. The impact of this demand sensitivity is included within the Reliability Assessment Analysis section of this assessment. 2009/2010 Winter Reliability Assessment Page 104 Regional Reliability Self-Assessments Generation There are two general categories used when analyzing seasonal capacity resources. Existing capacity represents resources that have been built and are in commercial service. Future capacity represents planned resources that are under construction, have an interconnection service agreement and are expected to be in commercial service at the start of the planning period. The generating capacity on Table RFC-8 represents the capacity of the generation in the RFC Region. The capacity category of Existing-Certain represents existing resources in the RFC areas of PJM and Midwest ISO and the capability of OVEC generation. The RFC Region has 215,600 MW of capacity for this winter that is identified as Existing-Certain in this assessment. TABLE 8; RFC PROJECTED CAPACITY RESOURCES (MW) WINTER 2009/2010 RFC - PJM RFC-MISO RFC Capacity as of June 1, 2009 EXISTING CAPACITY 145,400 72,500 220,100 Inoperable (Scheduled Maintenance) 0 (800) (800) Energy Only Resources (including variable gen) (1,800) (300) (2,100) Uncommitted Resources 0 (1,600) (1,600) Transmission Limited Resources 0 0 0 OTHER EXISTING CAPACITY (1,800) (2,700) (4,500) EXISTING CERTAIN CAPACITY 143,600 69,800 215,600 CAPACITY TRANSACTIONS - IMPORTS 1 2 Purchases 200 1,000 1,200 Owned Capability outside the RFC Region 100 0 100 300 1,000 1,300 CAPACITY TRANSACTIONS - EXPORTS 1 3 Sales (700) 0 (700) 3 Other Owner Capability transferred outside the RFC Region (400) 0 (400) (1,100) 0 (1,100) Net Interchange (800) 1,000 200 Net Capacity Resources 142,800 70,800 215,800 1 - Intra-regional transfers reported by the RTOs (between RTOs and with OVEC) have been removed 2 - Midwest ISO reports only the power imports committed to the market area 3 - This information is not available; exported power comes from uncommitted resources in the Midwest ISO market area Page 105 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments The Existing-Other category includes the existing resources that represent expected on-peak wind/variable resource deratings, and other existing capacity resources within the RFC Region that are not part of the PJM or Midwest ISO markets. There is up to 4,500 MW of these types of capacity resources. Since these resources are not in the respective PJM and Midwest ISO markets, none of this capacity is included in the Reserve Margins. Only capacity additions that are in service prior to the planning year, which starts in June, are included in determining the winter Reserve Margins. Any Future-Planned capacity additions expected to go in-service during the winter period would not be included within the Reserve Margin calculations. There are no Future-Planned capacity additions included in this winter assessment. The total nameplate amount of variable generation in RFC is about 1,700 MW. This is nearly all wind power (with only 3 MW solar), with the amount of available on-peak variable generation capability included in the reserve calculations at about 300 MW. The difference between the nameplate rating and the on-peak expected wind capability rating is accounted for in the Existing-Other category. There is also 700 MW of biomass (renewable) resources included in the RFC Reserve Margins. Each generator operator is expected to coordinate with the fuel industry regarding fuel supplies and deliveries. Although PJM and Midwest ISO do not explicitly communicate with the fuel industry regarding fuel supply issues, their respective market rules encourage generator owners and operators to have adequate fuel supplies. RFC does not communicate directly with the fuel industry on supply adequacy or potential problems; however, RFC does periodically survey its generator owners and operators about relevant fuel issues. The last survey was in 2008. There are no known or expected conditions or situations regarding fuel supply or delivery, hydro-electric reservoirs, adverse weather, generator availability, or capacity retirement that are anticipated to adversely impact system reliability during the 2009/2010 winter. Capacity Transactions on Peak PJM and Midwest ISO have reported expected imports and exports of capacity across their RTO boundaries at the time of the winter peak demand. Only specific transactions identified as interchange with firm transmission reservations are included within the Reserve Margin calculations. The capacity imports and exports include both contracted transactions as well as member ownership interest in generation outside the RTO boundary. Since the jointly-owned generation and OVEC generation is all located in the RFC Region, the jointly-owned and OVEC generation is included in RFC’s generation and is not included in RFC capacity imports and exports. Therefore, the firm capacity transactions for the RFC Region are not a simple summation of the PJM, Midwest ISO and OVEC capacity imports and exports. 2009/2010 Winter Reliability Assessment Page 106 Regional Reliability Self-Assessments The firm capacity imports for the RFC Region is projected to be 1,300 MW. The firm capacity exports is projected to be 1,100 MW. At the time of the winter peak, this results in a net 200 MW capacity import into RFC. There are no Liquidated Damages Contracts included in these firm power transactions. For both Midwest ISO and PJM, any firm capacity from outside the Region could be used for emergency and reserve sharing purposes; however, it is not necessary for PJM or Midwest ISO to rely on emergency imports to meet its respective Reserve Margin requirement. Transmission New transmission additions to the bulk power system, since last winter, that have been placed in- service include a total of 83 miles of transmission line(s) at 138 kV and above, plus ten transformers with a total capacity rating of about 6,100 MVA. An additional total of 43 miles of transmission line(s) at 138 kV and above is expected to be placed in-service by this winter, plus three transformers with a total capacity rating of about 4,500 MVA. These system changes are expected to enhance reliability of the bulk power system. The tables below shows the new bulk- power transmission (line) projects and transformer projects expected to be in-service for the winter of 2009/2010. Transmission Project Voltage Length In-service Description/Status Name (kV) (Miles) Date(s) RTO North Longview-Fort Completed PJM 500 2.0 May-2009 Martin Pontiac-Cayuga Ridge PJM 345 10 December-2009 South-Wilton Center Under Construction Cresent-Brunot Island 345 7.1 December-2009 Under Construction PJM Branchburg-Flagtown 230 4 May-2009 Completed PJM Orchard-Churchtown- Under Construction PJM 230 15 December-2009 Cumberland Remer-St. Clair #2 138 2.9 April-2009 Completed MISO Elliott-Scott 138 6 May-2009 Completed MISO Relocate Carlisle Completed MISO 138 1.5 June-2009 Substation Culley-Oak Grove 138 10 June-2009 Completed MISO Indiana Arsenal Under Construction MISO Junction-Clark 138 8.5 December-2009 Maritime Center Delta-ZincOx-Waseon 138 0.85 December-2009 Under Construction MISO Albright-Garrett 138 1 May-2009 Completed PJM Cheswick-Plum 138 8.27 June-2009 Completed PJM Oak Hall-Wattsville 138 3 June-2009 Completed PJM Waverly-Don Marquis- Completed PJM 138 13 August-2009 Lick Valley-Legionville 138 14.13 August-2009 Completed PJM Legionville-Koppel Under Construction PJM 138 1.72 December-2009 Steel-Hopewell Page 107 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments High- Low- Transformer Side Side In-service Description/Status RTO Project Name Voltage Voltage Date(s) (kV) (kV) Kammer 765 500 November-2009 Under Construction PJM Brighton 500 230 June-2009 Completed PJM Bedington 500 230 June-2009 Completed PJM Waugh Chapel 500 230 December-2009 Under Construction PJM Pierce 345 138 May-2009 Completed MISO Hiple 345 138 May-2009 Completed MISO Tangy 345 138 June-2009 Completed MISO Avon 92-AV-T 345 138 June-2009 Completed MISO Murphy 345 138 June-2009 Completed MISO Don Marquis 345 138 November-2009 Under Construction PJM Red Lion 230 138 May-2009 Completed PJM Roseland 230 138 June-2009 Completed PJM Cumberland 230 138 July-2009 Completed PJM There are no reliability concerns in meeting the in-service dates for the above facilities. PJM does anticipate that some existing transmission lines will be out-of-service this winter, and will maintain reliability by re-dispatch, re-configuration, Market-to-Market re-dispatch with Midwest ISO, and use of the NERC transmission loading relief (TLR) procedure, if necessary. One new significant transmission facility that has been added to the bulk power system is the Linden Variable Frequency Transformer (VFT), which is a merchant transmission project that is an AC tie with 300 MW of transmission transfer capability. This project will connect the Linden Cogen plant located in New Jersey and within PJM to the Goethals station on Staten Island in the New York system . The VFT is a transmission technology that provides for a continuously controllable, variable phase-shift connection to control the direction and magnitude of AC power flows. The Linden VFT will become a transmission owner within PJM, who will have the operational authority over the facility. The VFT is expected to have power flowing across it by November 1, 2009. The VFT will be the first merchant transmission project with multiple parties holding the entitlements to the new transmission capacity. Developing this unique project involved numerous technical, economic feasibility, and interconnection studies by the developer, PJM and the New York ISO (NYISO), which culminated in an auction process to sell the new transmission rights.100 There are no other significant substation equipment additions, such as SVCs, FACTS devices, or HVdc, planned to be in-service for the winter of 2009/2010. 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 power flow from RFC to NPCC. The Michigan-Ontario PARs have not yet achieved 100 More information on this project can be found at: http://www.gepower.com/prod_serv/products/transformers_vft/en/downloads/C1_107_2008.pdf. 2009/2010 Winter Reliability Assessment Page 108 Regional Reliability Self-Assessments long-term operation for all four units. The B3N PAR in Michigan, that previously failed, will be replaced by two series 800 MVA PARs sometime in early 2010. An Operating Agreement for controlling the transmission interface will be completed for use once all four PARs are in-service and regulating. This delay is not expected to adversely impact system reliability for this winter. Historically, ReliabilityFirst transmission systems have experienced widely varying power flows due to various transactions and prevailing weather conditions across the Region. As a result, the transmission system could become constrained during peak demand periods because of unit unavailability and unplanned transmission outages, concurrent with large power transactions. Generation re-dispatch has the potential to mitigate these potential constraints. Notwithstanding the benefits of this re-dispatch, should transmission constraint conditions occur, local operating procedures, system re-configuration, as well as the NERC TLR procedure, are all available to transmission owners/operators to maintain adequate transmission system reliability. RFC representatives and staff actively participate in all three of the Eastern Interconnection Reliability Assessment Group (ERAG), interregional seasonal transmission assessment efforts. However, for the winter of 2009/2010, ERAG decided to perform a long-term summer assessment in lieu of the normal 2009/2010 winter assessment. In 2010, ERAG plans to perform its normal winter assessment (for the winter of 2010/2011). RFC also conducts its own winter transmission transfer capability analyses and assessment.101 Incremental transfer capability results are included within the separate RFC winter transmission assessment report and are shown in the table below. Simultaneous import capabilities are projected to be adequate for this winter. These values do reflect transmission and generation constraints external to RFC. Transfer Direction Incremental Transfer Capability (MW) for 2009/2010 Winter RFC-MISO to PJM No limit found at 6,000 MW incremental transfer level PJM to RFC-MISO No limit found at 6,000 MW incremental transfer level SERC East to RFC-MISO No limit found at 6,000 MW incremental transfer level SERC East to PJM No limit found at 5,000 MW incremental transfer level NPCC to RFC-MISO 2,800 MW NPCC to PJM 2,800 MW MRO to RFC West 5,200 MW SPP to RFC West 2,300 MW SERC West to RFC West 2,600 MW Operational Issues PJM performs pre-seasonal summer and winter operational assessments. These assessments are studied using peak seasonal demand forecasts. At the Regional level, the operational problems are primarily West-to-East transfers. At the local level, the operational problems are high loadings on local equipment. PJM has not yet identified any special operating problem from the integration of variable resources. 101 http://www.rfirst.org/Reliability/ReliabilityHome.aspx Page 109 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments PJM does not anticipate any reliability concerns resulting from over-generation by variable resources at the current level of penetration, nor does it anticipate any reliability concerns from Demand Response resources at the current level of implementation. While some generators within the PJM RTO may be temporarily limited due to environmental or emissions restrictions, PJM does not anticipate that these limitations will impact system reliability. The Midwest ISO, as a Reliability Coordinator and Balancing Authority, does not expect any reliability concerns resulting from variable resources during minimum demand and over- generation conditions for the 2009/2010 winter assessment period. The Midwest ISO’s Public Emergency Procedure entitled “Supply Surplus Procedure” (RTO-EOP-003) steps the Reliability Coordinator and Balancing Authority through the steps necessary to continuously balance load and generation during these types of conditions, including variable resources as necessary. 102 No unusual operating conditions are foreseen within RFC that could impact system reliability for this winter. Reliability Assessment Analysis This resource assessment relies on the Reserve Margin requirements determined by PJM and Midwest ISO to satisfy the RFC Loss of Load Expectation (LOLE) criterion of not exceeding 0.1 day per year. These LOLE analyses are conducted by PJM and Midwest ISO in accordance with RFC’s “Planning Resource Adequacy Analysis, Assessment and Documentation” Standard, BAL-502-RFC-02.103 The assessment of PJM and Midwest ISO resource adequacy is therefore based on the results from these LOLE analyses. It is not meaningful to calculate a specific Reserve Margin requirement for all of RFC, since each RTO operates as a single Balancing Authority and has different demand characteristics, capacity resource availabilities and calculated reserve requirements. However, it follows that when PJM and Midwest ISO have satisfied their respective reserve requirements, then the RFC Region can be considered to have resource adequacy. Since the PJM RTO reserve requirement is based on the summer peak demand, the total required capacity is 150,300 MW. The PJM net capacity resources are 167,500 MW, which is 17,200 MW greater than the requirement. Therefore, the PJM RTO has adequate reserves for the 2009/2010 winter peak demand. The projected reserves during the 2009/2010 winter peak demand for the Midwest ISO are 42,200 MW, which is a 53.1 percent Reserve Margin (NID). Since the Midwest ISO reserve requirement is 15.4 percent of the monthly peak, Midwest ISO has adequate reserves for the 2009/2010 winter peak demand. 102 http://www.midwestiso.org/publish/Document/24743f_11ad9f8f05b_-7b610a48324a?rev=5 103 http://www.rfirst.org/Documents/Standards/Approved/BAL-502-RFC-02.pdf 2009/2010 Winter Reliability Assessment Page 110 Regional Reliability Self-Assessments In Table RFC-9, the calculated Reserve Margin for RFC is 74,900 MW, which is 53.2 percent based on Net Internal Demand and Net Capacity Resources. This compares to a 49.8 percent Reserve Margin found within last winter’s assessment. Since PJM and Midwest ISO have sufficient resources to satisfy their respective Reserve Margin requirements, the RFC Region has adequate resources for the 2009/2010 winter period. TABLE RFC – 9: RFC PROJECTED RESERVE MARGINS WINTER 2009/2010 DECEMBER JANUARY FEBRUARY NET INTERNAL DEMAND (MW) 138,600 140,900 135,800 NET CAPACITY RESOURCES (MW) 215,800 215,800 215,800 NID RESERVE MARGINS -- MW 77,200 74,900 80,000 -- percent of NID 55.7% 53.2% 58.9% For winter 2009/2010, a high demand forecast was used to prepare a Reserve Margin sensitivity case across the RFC Region. This high demand forecast was developed by adding the 90/10 demand forecasts of PJM and Midwest ISO to the OVEC demand. This high demand forecast for the RFC Regional area is being used to evaluate the sensitivity to higher than expected demand. On Table RFC-10, this high demand forecast amounts to a potential demand increase of about 8,300 MW in January 2010 under this scenario. On a Net Internal Demand basis, the Reserve Margin would be 66,600 MW or 44.6 percent. TABLE RFC – 10: SIMULATED EXTREME DEMAND (MW) WINTER 2009/2010 TOTAL TOTAL TOTAL PJM MISO RFC EXTREME DEMAND1 PJM 90/10 TID in RFC2 102,400 MISO 90/10 TID in RFC2 51,600 TOTAL INTERNAL DEMAND [TID] 119,600 86,000 154,100 PJM 90/10 NID in RFC2 99,200 MISO 90/10 NID in RFC2 49,900 NET INTERNAL DEMAND [NID] 115,800 83,600 149,200 NET CAPACITY RESOURCES 167,500 121,700 215,800 NID RESERVE MARGINS -- MW 51,700 38,100 66,600 -- percent of NID 44.6% 45.6% 44.6%  - The combination of the 90/10 demand forecasts for the PJM and Midwest ISO areas of RFC is not a 90/10 forecast for RFC. These values are used to simulate conditions of extreme demand.  - These are the coincident LBA or Load Zone peak demands within the RFC Region. Page 111 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments This analysis illustrates that higher than expected demand can significantly reduce the Reserve Margin available (from 53.2 percent to 44.6 percent) to cover potential generator outages. However, at this level of reserves, it is highly unlikely that additional demand would create any reliability problems within the RFC Region. Region Description RFC currently consists of 47 Regular Members, 22 Associate Members, and 4 Adjunct Members operating within 3 NERC Balancing Authorities (Midwest ISO, OVEC, and PJM), which includes over 350 owners, users, and operators of the bulk-power system. They serve the electrical requirements of more than 72 million people in a 238,000 square-mile area covering 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 RFC area demand is primarily summer peaking. Additional details are available on the RFC website (http://www.rfirst.org). 2009/2010 Winter Reliability Assessment Page 112 Regional Reliability Self-Assessments SERC Regional Assessment Summary 2009/2010 Winter Projected Peak Demand MW On-Peak Capacity by Fuel Type Total Internal Demand 179,659 Direct Control Load Management 646 Dual Oil Gas Contractually Interruptible (Curtailable) 4,180 22% Fuel 3% Critical Peak-Pricing with Control 0 16% Hydro Load as a Capacity Resource 184 Nuclear 5% Net Internal Demand 174,649 14% Coal Pumped 2008/2009 Winter Comparison MW % Change 36% Storage 2008/2009 Winter Projected Peak Demand 177,929 -1.8% 4% 2008/2009 Winter Actual Peak Demand 186,225 -6.2% All-Time Winter Peak Demand 186,446 -6.3% 2009/2010 Winter Projected Peak Capacity MW Margin Existing Certain and Net Firm Transactions 248,181 42.1% Deliverable Capacity Resources 248,680 42.4% Prospective Capacity Resources 259,037 48.3% NERC Reference Margin Level - 15.0% SERC is the Regional Entity (RE) for all or portions of 16 central and southeastern states. For purposes of reporting data and assessing reliability, the utilities within the SERC Region are assigned to one of five subregions: Central, Delta, Gateway, Southeastern, and VACAR, that together supply power to more than 20 percent of the electric customers in the United States. Most electric utilities within SERC operate under some degree of traditional vertical integration with planning philosophies based on an obligation to serve ensuring that designated generation operates under optimal economic dispatch to serve local area customers. Some utilities in the SERC Region however, have selected or have 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 (ICT) contract or a Regional Transmission Organization (RTO) that manages transmission flows to customers over a broader Regional area through congestion-based locational marginal pricing. Transmission systems within the SERC footprint are closely interconnected and the Region has operated with high reliability for many years. Page 113 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments Demand SERC is a summer-peaking Region. The actual 2008/2009 winter peak for the utilities in the SERC Region was 186,225 MW. The total aggregate internal demand for the 2009/2010 winter is forecast to be 179,659 MW; this is 3,984 MW (2.2 percent) lower than the forecast 2008/2009 winter Total Internal Demand of 183,643 MW. The actual winter peak demand does not take into account new energy-efficiency programs, diversity stand-by load or additions for non-member load, whereas the internal peak demand values account for these factors This projection is based on average historical winter weather and is the sum of non-coincident forecast data reported by utilities in the SERC Region. Some entities have lowered their forecasts due to the economic recession. Because of the varied nature of energy-efficiency programs, they are separately described in the subregion portions of this report. A number of utilities in the SERC Region have some form of efficiency program or Demand-side Management (DSM) efforts in place or under development. Entities measure and verify their programs in various ways. Some entities use measurement verification programs to measure energy savings and costs programs. Other entities use third- party vendors to assess their programs and analyze results. These techniques have been useful to fine-tune energy-efficiency programs and to determine each program’s cost effectiveness. 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 DSM capabilities for 2009/2010 winter are 5,237 MW as compared with the 5,836 MW reported last winter. This year’s Demand Response is 2.9 percent of the Total Internal Demand forecast for 2009/2010. Traditional Demand Response programs include monetary incentives to reduce demand during peak periods. Some examples are real-time pricing programs and voluntary curtailment riders. The programs are more fully described in each subregion as part of the more detailed reports below. There are no measurement verification programs implemented at the SERC Region level. SERC Table 1: SERC Demand Response Programs MW 2008/2009 2009/2010 Program Winter Winter Direct Control Load Management 428 MW 646 MW Contractually Interruptible (Curtailable) 4,943 MW 4,180 MW Critical Peak-Pricing (CPP) with Control 215 MW 0 MW Load as a Capacity Resource 127 MW 184 MW Energy-Efficiency Programs 123 MW 227 MW Ambient temperatures that are higher or lower than normal and the degree to which interruptible demand and DSM is used, result in actual peak demands that vary from the forecast. The utilities within the SERC Region perform detailed extreme weather and/or load sensitivity analyses in their respective operational and planning studies. While utility methodologies vary, many common attributes exist. Common attributes include: 2009/2010 Winter Reliability Assessment Page 114 Regional Reliability Self-Assessments • 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 using these forecasts. In addition, many utilities within the SERC Region use sophisticated, industry-accepted methodologies to evaluate load sensitivities in the development of load forecasts. Utilities in the SERC Region adhere to their respective state commissions’ regulations, RTO requirements, and internal business practices for determining their reserve requirements. Generation In aggregate, utilities within the SERC Region expect to have 266,346 MW of resources including 251,792 MW of Existing-Certain resources, 12,166 MW of Existing-Other resources, and 2,388 MW of inoperable resources during the winter 2009/2010 period. The utilities within SERC report 12,100 MW of Existing-Certain variable generation and 850 MW of Existing-Other variable generation during the winter 2009/2010 period. The utilities in the SERC Region anticipate a nominal amount of Future-Planned and Future-Other capacity resources during the assessment period. Generation facilities are planned and constructed to ensure that aggregate generation capacity keeps pace with the electric demand and allows for adequate planning (and operating) reserves. Among the utilities in the SERC Region, generation reserve capacity is sufficient to mitigate postulated generation and transmission contingencies. Additionally, a number of independent power generating units are interconnected to the transmission system and selling their output into the electricity market where such markets exist within the SERC Region. In the SERC Region there has been significant merchant generation development. 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 may be deliverable during certain system conditions. There are small amounts of Biomass104 generation in the SERC Region totaling 193 MW. The amount of variable generation (Hydro) is 5.1 percent of the SERC Region’s capacity resources. In the recent past years, utilities in the SERC Region had experienced various levels of impacts on generation due to drought within the Region. Currently drought conditions have moderated in the SERC Region. Regarding hydro conditions and its impact on production for the upcoming winter season, the SERC Region thermal and hydro production are expected to experience no impact relative to 2009/2010 winter load-serving obligations. Entities within the Region are currently not experiencing or expecting to experience any conditions that would impact reliability negatively. It is common amongst the entities to rely on a 104 Defined by EIA as: “organic non-fossil material of biological origin constituting a renewable energy source” Page 115 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments portfolio of firm-fuel resources to ensure adequate fuel supplies to generating facilities during projected winter peak demand. Forecasts are based on normal weather conditions for winter peaks. In addition, entities within SERC are not expecting a significant amount of generation to be out of service during the winter, though a few large units are scheduled out of service for overhaul or nuclear refueling. Outages are routinely scheduled for some generating units during the winter. Outage plans are developed so that anticipated loads can be met with available resources. A few plants have also been proposed to be retired for this winter period. These retirements coupled with the planned outages are not expected to result in any reliability issues for the winter 2009/2010 period. Capacity Transactions on Peak These firm purchases have been included in the Reserve Margin calculations for the Region and are backed by firm contracts for both generation and transmission. No entities reported import or export assumptions that are based on partial path reservations. Utilities in the Region are not considered to be dependent on purchases or transfers outside the SERC Region to meet the demands of the load in the Region. Several entities within the Region reported use of contracts within their subregions that are Liquidated Damages Contracts (LDCs). These contracts are considered to be make-whole contracts. SERC Table 2: SERC Region Purchases/Sales MW Transaction Type Purchases Sales Firm 1,147 MW 5,058 MW Non-Firm 0 MW 0 MW Expected 0 MW 0 MW Provisional 0 MW 0 MW Transmission New bulk power transmission facilities projects anticipated to be in-service for the 2009/2010 winter that were added since the 2008/2009 winter are listed in detail within the SERC subregional sections of the report. There are no reported project delays that create concerns for reliability. Reported delays are expected to be mitigated appropriately to ensure no impacts on the system for the upcoming winter. No significant lines are planned to be out of service throughout the Region at this time. All significant, planned transmission facility outages are scheduled for spring and fall (off-peak seasons). Utilities commonly study and plan transmission facility outages based on forecasted system conditions and potential reliability impacts. In the event of forced, weather-related outages (i.e., ice storm), companies will activate individual transmission emergency operations centers to coordinate restoration of service to customers. There are no transmission constraints that could significantly impact reliability of the utilities in the SERC Region during winter 2009/2010. Discussions in subregional portions of the report for certain utilities indicate a few situations which require monitoring. With load projected to be lower as compared to the prior year, the system has been tested at greater load levels. 2009/2010 Winter Reliability Assessment Page 116 Regional Reliability Self-Assessments Coordinated interregional transmission reliability and transfer capability studies for the 2009/2010 winter season are in process among all the SERC subregions. Preliminary results of these studies indicate the bulk transmission systems within the SERC Region have no issues that will significantly impact reliability The SERC Region has extensive transmission interconnections between its subregions. 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 323 miles of 115 kV, 138 kV, 161 kV, 230 kV, 345 kV, and 500 kV transmission lines are scheduled for completion by winter 2009/2010. There are no concerns with respect to the impact on reliability performance relating to the completion of these projects because summer is the more demanding season in the SERC Region. While utilities within the SERC Region plan to add new substation equipment for the coming winter, none of these new facilities are considered to be significant. Operational Issues Operational planning studies are done individually by utilities within the SERC Region. Individual company studies were reported to be done daily, weekly, and monthly, taking into consideration demand and unit availability. This helps to address any inadequacies as well as mitigate potential risks. No generation or operational problems have been identified in recently completed planning studies. Entities within the Region participate in SERC study groups that assess the Region on a seasonal basis. An assessment is currently being conducted in the SERC NTSG 2009/2010 Winter Reliability report. No special operating procedures are reported to be in place as a result of variable resource integration. Most of the SERC Region is in the lowest wind resource area of the country. One operational change to note is that for the utilities in the Gateway subregion who are members of the Midwest Independent Transmission System Operator (Midwest ISO), on January 6, 2009, the Midwest ISO began operation as a single balancing authority in conjunction with the commencement of the Midwest ISO Ancillary Services Market. In addition, no significant reliability concerns resulting from high-levels of Demand Response resources or minimum demand and over-generation have been identified or anticipated for the upcoming season. Environmental and/or regulatory restrictions are not a reliability issue for the Region, even though some entities have reported insignificant factors resulting from Selective Catalytic Reduction (SCR) device limits and continued restoration of dams within the Central subregion. To mitigate these concerns, limits are studied by individual companies and are taken into account during resource planning. These limits are not a concern for reliability or economic dispatch situations. Unusual operating conditions are not expected to impact reliability for the upcoming winter season. Entities will rely on redispatch plans, modest increases in imports, or implementation of operating guidelines to help mitigate reliability concerns as needed. Page 117 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments Reliability Assessment Analysis In aggregate, the utilities in the SERC Region expect 499 MW of planned capacity to be placed in service by January 1, 2010. The aggregate projected 2009/2010 winter Reserve Margin for the utilities in the SERC Region is 42.2 percent indicating capacity resources are expected to be adequate to supply the projected firm winter demand. The Reserve Margin projected for winter 2008/2009 was 35.2 percent. Approximately 266,350 MW of generating capability is expected to be connected in the Region. An extreme peak for 2009/2010 winter equates to 190,440 MW of peak demand for the Region. The Reserve Margin for this scenario is estimated to be 33.9 percent, which, although reduced from margins based on 50/50 forecasts, is an adequate level for these conditions. SERC does not implement a Regional or subregional reserve requirement. As described in more detail within the subregional reports, many utilities in the SERC Region adhere to their respective state commissions’ regulations or internal business practices regarding maintaining adequate resources. For example, a target margin is implemented by regulatory authorities in the state of Georgia, where the regulation is only applicable to the investor-owned utilities in that state. Based on a recent review of resource adequacy assessment practices, many utilities in the SERC Region use a probabilistic generation and load model to assess and determine that adequate resources are available and deliverable to the load. All utilities with the SERC Region project fuel supplies to be adequate for this coming winter. Communication between utilities and suppliers and transporters in the fuel industry is ongoing. This topic is covered in detail in the subregional sections of this report. Although fuel deliverability problems are possible for limited periods of time due to weather extremes such as flooding, rail, pipeline and other transportation system disruptions, assessments indicate that this should not have a negative impact on reliability. The immediate impact will likely be economic as some production is shifted to other fuels. Secondary impacts could involve changes in emission levels and increased deliveries from alternate fuel suppliers. The utilities within the SERC Region anticipate that fuel deliverability constraints would not reduce the availability of capacity resources due to strength of the utilities’ programs coupled with the economic recession which have reduced pressure on rail service providers and pipelines. The projected 2009/2010 winter capacity mix reported by utilities within the SERC Region is well diversified at approximately 36.4 percent coal, 13.7 percent nuclear, 3.7 percent hydro/pumped storage, 40.7 percent gas and/or oil, and 5.5 percent for purchases and miscellaneous other capacity. Generation with coal, nuclear, and hydro fuels continues to lead the Regional fuel mix accounting for roughly 55.1 percent of net operable capacity. 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 the utilities within SERC to reduce reliability risks due to fuel supply issues. Dual fuel units are tested to ensure their availability and that back-up fuel supplies are adequately maintained and positioned for immediate availability. Some generating units have provisions to switch between two different natural-gas pipeline systems, reducing the dependence on any single interstate pipeline system. Moreover, the diversity of generating 2009/2010 Winter Reliability Assessment Page 118 Regional Reliability Self-Assessments resources further reduces the risk. Current projections indicate that the fuel supply infrastructure and fuel inventories for the winter period are adequate even considering possible impacts due to weather extremes. SERC does not have Regional criteria for dynamic, voltage, or small signal stability; however, utilities within the Region maintain individual criteria to address any stability issues and these processes are discussed in the subregional reports. There are no issues in this area on a SERC- wide basis. There is also no overarching summary that can be provided except to assure that each utility involved in planning has clear criteria for voltage and transient performance. The Annual Report of the SERC Reliability Review Subcommittee (RRS) to the SERC Engineering Committee (EC) summarizes the work of the SERC subcommittees relative to the transmission and generation adequacy and provides the overview of the state of the systems within SERC. 105 Other Region Specific Issues To minimize reliability concerns within the Region, entities are relying on a variety of procedures to avoid negative impacts on the system. Some activities such as monthly, weekly, and daily operational planning analyses, improvement of vegetation management procedure programs, preventative maintenance on units during the off-peak period, routine maintenance on transmission equipment and maintaining adequate reserves are examples of steps that utilities within SERC have implemented to maintain the reliability of the bulk power system. Even though negative impacts are not expected, these steps show that entities are focused on mitigating risks and maintaining reliability. 105 Because it is considered CEII, the SERC RRS Annual Report to the Engineering Committee is available only upon request through the SERC website at www.serc1.org. Page 119 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments Central Demand The actual 2008/2009 winter peak for the utilities in the Central subregion was 43,961 MW. The projected Total Internal Demand for the 2009/2010 winter season is 43,230 MW; this is 548 MW (1.3 percent) lower than the forecast 2008/2009 winter Total Internal Demand of 43,778 MW. The actual winter peak demand does not take into account energy efficiency, diversity stand-by load or additions for non-member load, whereas the internal peak demand values account for these values. The winter peak forecast in 2008/2009 was higher than the 2009/2010 forecast due to lower temperatures and the effects of the economic recession on industrial demand. The change in demand from prior forecasts for 2009/2010 also reflects the effects of the economic recession which were due to continued reductions or shutdowns during 2009 at several large facilities that had been operating in January. Declining economic conditions have also slowed household formation and manufacturing employment, which have contributed to the significant changes in the forecast as well. However, some entities within the Central subregion are reporting an increase in forecasted demand driven by an expectation of additional customers added to the system. The 2009/2010 winter demand forecast is based on normal weather conditions and economic data from population, income, expected demographics for the area, employment, energy exports, and gross Regional product increases and decreases. Economic data from the national level is also considered. To assess variability, members within the subregion use forecasts assuming normal weather and then develop models for milder and more historical peaks and demand models to predict variance. Optimistic and pessimistic economic growth scenarios, price, number of households, and commercial and industrial growth are also taken into account as variables in long-term base case models. As with other subregions, strong emphasis is placed on energy efficiency and consideration of renewables. Entities within this subregion reported 1.9 percent of Total Internal Demand as Demand Response that can reduce peak demand. Programs such as voluntary curtailment tariffs for larger industrial customers, direct control load management programs and other interruptible demand programs that reduce peak demand are common around the subregion. Most voluntary curtailment programs are driven by economics. As part of the Region’s energy-efficiency program implementation, energy audits, low-income assistance, HVAC system improvements, lighting, and verification/measurement groups are in place. Residential programs currently focus on building-shell thermal efficiency, high-efficiency heat pumps, new manufactured-homes, and self-administered paper and electronic online energy audits. Some entities measure the impact of the interruptible demand program by comparing the magnitude of the customer’s load before and during an interruption. Other companies report that a load must be interruptible with no more than 60 minutes notice to qualify as interruptible for planning purposes. During the 2009/2010 winter, approximately 820 MW of load is expected to be available for interruption. Although most of the programs mentioned above are used only during summer operation, these programs are reported to be active and are a part of company 2009/2010 Winter Reliability Assessment Page 120 Regional Reliability Self-Assessments supply portfolios around the subregion for the use of peak reduction and energy efficiency. Generation Utilities in the Central subregion expect to have the following capacity in-service through the assessment timeframe. This capacity is expected to help meet demand during this time period. Central Table 1: Winter 2009/2010 Capacity Breakdown Capacity Type Winter 2009/2010 Existing-Certain 54,324 MW Wind 0 MW Solar 0 MW Biomass 18 MW Hydro 4,124 MW Existing-Other 1,108 MW Wind 0 MW Solar 0 MW Biomass 0 MW Hydro 762 MW Energy Only 0 MW Existing Inoperable 0 MW Future-Planned 0 MW Future-Other 0 MW As seen in the table above, 4,124 MW of hydro and 18 MW of biomass capacity are expected on-peak for the upcoming season. To address variable capacity calculations, entities within the subregion either have no variable capacity or do not consider them toward capacity requirements. Hydro conditions are currently anticipated to be normal in the Central subregion for the period. Marginal capacity needs have been addressed without dependence on hydro capacity. Sufficient reservoir levels are expected for the Dix Dam hydro station, Laurel Dam, Greenup hydro, etc. Although hydro generation is still limited at Wolf Creek Dam, short-term purchases will be available as necessary to meet peak demand for the season. Hydro generation estimates are based on the analysis of historic operating practices and flow conditions. The numbers quoted above are consistent with the latest long-term hydro forecast. Currently, the Central Region of the National Climatic Data Center is indicating that no significant areas within the subregion are experiencing moisture levels consistent with any level of drought condition as measured by the Palmer Drought Severity Index. However, dryer than normal conditions resulting from prior years’ drought have created capacity reductions. These reductions have been taken into consideration in company capacity planning. Most entities in the subregion only count Existing-Certain capacity toward firm capacity requirements. Purchases are made from short-term markets as needed to compensate from any reductions that may occur during abnormal seasons. Page 121 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments River conditions remain sufficient, with very little flooding or drought conditions creating delays in inland river transportation via barge. Coal trucks have continued to maintain current and planned deliveries. There is no reason to believe, at this time, that fuel deliveries will not be made according to contractual agreements and forecasts for delivery. No significant generating units that will affect reliability within the subregion are expected to be out of service or retired for the upcoming season. However, 71 MW is planned to be on inactive reserve this winter due to the economic recession. Approximately 812 MW will be on planned maintenance at some point during the winter season. No outages have been scheduled during the upcoming winter peaking month. These planned outages have been accounted for in generation planning with no impact to overall reliability. Again, entities within the subregion use purchases from the short-term markets, as necessary. Capacity Transactions on Peak Central subregional utilities have reported the following imports and exports for the upcoming 2009/2010 winter season. The majority of these exports/imports are backed by firm contracts, which include dedicated generation, transmission reservations and fuel transportation that count toward firm capacity. There are no reports of imports/exports based on partial path reservations or associated with LDCs. These reports have been included in the aggregate Reserve Margin for utilities in the subregion. Central Table 2: Subregional Imports/Exports Transaction Type Winter 2009/2010 Firm Imports (Internal Subregion) 0 MW Firm Exports (Internal Subregion) 95 MW Non-Firm Imports (Internal Subregion) 0 MW Non-Firm Exports (Internal Subregion) 0 MW Expected Imports (Internal Subregion) 0 MW Expected Exports (Internal Subregion) 0 MW Firm Imports (External Subregion) 916 MW Firm Exports (External Subregion) 842 MW Non-Firm Imports (External Subregion) 0 MW Non-Firm Exports (External Subregion) 0 MW Expected Imports (External Subregion) 0 MW Expected Exports (External Subregion) 0 MW For reliability analysis/Reserve Margin calculations, entities within this subregion may use a request for proposal (RFP) system for forward-capacity markets or use firm contract purchases (both generation and transmission) toward firm capacity. Overall, the utilities in the subregion do not depend on outside purchases or transfers from other Regions or subregions to meet their demand requirements. Transmission The following table shows bulk power system transmission categorized as under construction, planned, or conceptual that is expected to be in-service for the upcoming 2009/2010 winter 2009/2010 Winter Reliability Assessment Page 122 Regional Reliability Self-Assessments season since the winter season of 2008. Information on in-service dates associated with various facilities that will be in-service this winter is also listed in the table below. Central Table 3: Expected Under-construction, Planned, Conceptual Transmission Transmission Project Transmission Type In-Service Concerns in Reliability Mitigation Name (Under Date(s) meeting Issues with In- Plans to Construction, In-Service Service Date Address Planned, or Date? Delay? Delay Conceptual) (yes/no) (yes/no) Pineville-West Garrard Under Construction 10/2009 No NA NA J.K. Smith-West Under Construction 12/31/2009 Yes No Purchase Garrard 345kV additional Interconnection power off- system E.ON U.S.-Cinergy Under Construction 12/31/2009 No NA NA 345kV Interconnection Trimble County - Under Construction 06/30/2009 NA NA NA Ghent-Speed Line Rutherford - Almaville Planned 07/08/2009 No NA NA Tilton - Resaca Planned 09/30/2009 No NA NA J.K.Smith 345/138kV In-service 06/2009 No NA NA Second Autotransformer Huntsville-McCreary Planned 11/2009 No NA NA Mill Creek-Hardin Under Construction 12/2009 Yes No None County needed Higby Mill-West Under Construction 11/2009 Yes No None Lexington needed. Date moved to 06/2010 Middletown-Collins Under Construction 12/2009 No NA NA Tyner-Fallen Rock Under Construction 05/2009 No NA NA No significant lines are planned to be out of service throughout the Central subregion at this time. In the event of forced, weather-related outages (i.e., ice storm), companies will activate individual transmission emergency operations centers to coordinate restoration of service to customers. No major constraints have been identified that could significantly impact reliability for the 2009/2010 winter season. Companies continuously evaluate the transmission system to identify any future constraints that could significantly impact reliability. These future constraints and proposed solutions are annually published in transmission expansion plans on file with the ITO (SPP) and other Regional reliability studies for the season. Although no major constraints have been reported for the upcoming winter season, repairs at Wolf Creek Dam and the resulting lowered level of Lake Cumberland are expected to be an issue within southern Kentucky and will result in reduced availability of the Wolf Creek hydroelectric generating units. A subsequent outage of both Cooper units during peak load periods can result in unacceptably low voltages on the 161 kV transmission system in the area. Entities within this area are continuing to assess the situation with the development of operating guides for this Page 123 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments scenario. Possible mitigation measures include use of the Laurel Dam hydroelectric generating unit for support (if possible), use of the Wolf Creek hydroelectric units for real and/or reactive support (if possible), and/or load shedding in the area. Subregional entities reported no new plans to install significant substation equipment. An Operator Training Simulator (OTS) is projected to be in-service in the last quarter of 2009. Operational Issues Monthly, weekly, and daily operational planning efforts take into consideration demand and unit availability. This helps to address any inadequacies as well as mitigate these risks. Based on recent planning studies that have been conducted, no generation or operational problems have been identified. Most entities within this subregion count Existing-Certain capacity toward firm capacity requirements. These entities do not generally depend on Existing-Uncertain, Planned, or Proposed capacity resources to meet capacity requirements. Therefore, there are no special operating procedures required for variable resources. In addition, no reliability concerns resulting from high-levels of Demand Response resources or minimum demand and over-generation have been identified or anticipated for the upcoming season. Also, no major generating unit outages, generation additions, environmental/regulatory restrictions, temporary operating measures, or unusual operating conditions are expected to affect the reliability of the Central subregion this winter season. Resource Assessment Analysis The projected January 2010 winter peak Reserve Margin for the utilities in the subregion is 28.0 percent. This is 11.5 percent higher compared to last year’s peak Reserve Margin at 16.5 percent. The subregion does not have a Regional or subregional marginal target for comparison purposes. The Reserve Margin analysis in the company-integrated resource plans incorporate sensitivities on load unit availability, production cost, purchase power availability, unserved energy cost, and varying Reserve Margin levels. Monthly and long-term resource planning efforts take into consideration demand and unit availability. This helps to address any inadequacies in achieving the desired Reserve Margin. If resource inadequacies cause the reserves to be reduced below the desired level, companies within the subregion can make use of purchases from the short-term markets in the near-term and various ownership options in the long-term, as necessary. Several entities within the Central subregion are members of the Midwest Contingency Reserve Sharing Group (MCRSG) which includes the Midwest ISO and 10 other Balancing Authorities in SERC and MRO. The MCRSG is intended to provide immediate response to contingencies enabling the group to comply with the DCS standard. Utilities within the subregion are not relying on short-term outside purchases or transfers from other Regions or subregions to meet demand requirements. Options to meet long-term demand needs may include building capacity, using existing capacity, expanding current capacity, or contracting for capacity. 2009/2010 Winter Reliability Assessment Page 124 Regional Reliability Self-Assessments In order to ensure fuel delivery, the practice of having a diverse portfolio of suppliers, including purchase of high-sulfur coal from Northern and Central Appalachia (West Virginia, East Kentucky), Ohio and the Illinois Basin (West Kentucky, Indiana, Illinois) is common within the subregion. Fuel departments typically monitor supply conditions on a daily basis through review of receipts and coal burns and interact daily with both coal and transportation suppliers to review situations and foreseeable interruptions. Any identifiable interruptions are assessed with regard to current and desired inventory levels. By purchasing from different Regions, coal is expected to move upstream and downstream to various plants. Some plants have the ability to re-route deliveries between them. Some stations having coal delivered by rail can also use trucks to supplement deliveries. Utilities have reported that they maintain targets greater than 30 days of on-site coal inventory. Fuel supplies are adequate and readily available for the upcoming winter. Multiple contracts are in place for local coal from area mines. Companies within the subregion maintain individual criteria to address any problems with stability issues. Recent stability studies identified no stability issues that could impact the system reliability during the 2009/2010 winter season. Criteria for dynamic reactive requirements are addressed on an individual company basis. Utilities employ study methodologies designed to assess dynamic reactive margins. Programs such as Reactive Monitoring Systems give operators an indication of reactive reserves within defined zones on the system. Voltage stability margins are also upheld by utilities on an individual basis. Some utilities follow the procedure of making sure that the steady-state operating point be at least 5 percent below the voltage collapse point at all times to maintain voltage stability. Studies are performed on peak cases to verify system stability margins. Other utilities follow guidelines to ensure that voltage stability will be maintained via Q-V analysis. Utilities within the Central subregion are not anticipating reliability concerns for the upcoming winter season. Monthly, weekly, and daily operational planning efforts take into consideration demand and unit availability. This helps to address any inadequacies as well as mitigate these risks. Page 125 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments Delta Demand The actual 2008/2009 winter peak for utilities in the Delta subregion was 23,386 MW. The projected Total Internal Demand for the 2009/2010 winter season is forecast to be 22,064 MW; this forecast is 2,737 MW (11.0 percent) lower than the forecast 2008/2009 winter Total Internal Demand of 24,801 MW. The actual winter peak demand does not take into account energy efficiency, diversity stand-by load, or additions for non-member load, whereas the internal peak demand values account for these factors. The year-over-year decline primarily reflects the anticipated impacts of increased energy efficiency and conservation, reductions in wholesale load and electric use, and an economic recession. The 2009/2010 forecast is based on a new forecast study which produced new econometrically based forecasts of commercial/industrial load, future economic/demographic conditions, and historical data. Distribution cooperative personnel assess the likelihood of these potential new loads and a probability adjusted load is incorporated into cooperative load forecast. DSM programs among the utilities in the subregion include traditional industrial and large commercial interruptible rate programs and a range of conservation/load management programs for all customer segments. The terms and conditions of these tariffs permit load curtailment at anytime, including winter months. The amount of interruptible load can vary from year-to-year because of changes in customer operations, adding or removing customers from participation in interruptible rate programs, and increasing or decreasing the amount of interruptible load under contract. Entities within this subregion reported 3.6 percent of Total Internal Demand as Demand Response that can reduce peak demand. There are no significant changes in the amount and availability of load management and interruptible demand since last year. Various energy-efficiency programs are offered within the subregion. Examples of these voluntary programs are home energy audits, CFL lighting, Energy Star-rated washing machines and dishwashers, and Energy Star-rated heat pumps and air conditioners. In general, the programs are available for every customer class and provide incentives for improvements that go beyond established efficiency standards. Companies within the subregion adhere to the measurement and verification (M&V)protocol established by the regulating entity. Utilities plan to offer these types of programs as long as they are determined to be cost-effective. In 2008, the M&V program was started to measure energy savings and costs for each of the energy-efficiency programs. Information from this M&V program will be used to fine tune energy-efficiency programs and to determine each program’s cost effectiveness. The current forecast includes energy-efficiency programs that have received regulatory approval and have been incorporated into the sales and load forecasts. Load scenarios for outage planning purposes are developed regularly to address variability issues in demand. These load scenarios include load forecasts based on high and low load scenarios for energy sales and scenarios for alternative capacity factors. Load scenarios for load-flow analyses in transmission planning are also developed and posted to OASIS. Some of these scenarios developed within the subregion were reported to be based on an assumption of extreme weather, which were more severe than the expected peaking conditions but less severe than the most severe conditions found in the historical records. Special analyses are performed to examine 2009/2010 Winter Reliability Assessment Page 126 Regional Reliability Self-Assessments expected peak loads associated with cold fronts, ice storms, hurricanes, and heat waves. These analyses are performed on an ad-hoc basis and may be conducted for various parts of the Delta subregion. Generation Companies within the Delta subregion expect to have the following capacity on-peak. This capacity is expected to help meet demand during this time period. Delta Table 1: Winter 2009/2010 Capacity Breakdown Capacity Type Winter 2009/2010 Existing-Certain 39,719 MW Wind 0 MW Solar 0 MW Biomass 0 MW Hydro 228 MW Existing-Other 1,471 MW Wind 0 MW Solar 0 MW Biomass 0 MW Hydro 70 MW Energy Only 1,235 MW Existing Inoperable 1,985 MW Future-Planned 103 MW Future-Other 0 MW As seen in the table above, 228 MW of hydro capacity is expected on-peak for the upcoming season. Reservoirs are currently projected to be near 100 percent moving into the fall/winter season. Therefore, reservoir levels are sufficient to meet both projected peak demand and the daily energy demand throughout the winter season. If river levels are inadequate to operate the hydro facility at maximum capacity, agreements are in place to serve demand with firm energy and transmission. To address variable capacity calculations, entities within the subregion either have no variable capacity or do not consider them toward peak capacity requirements. Utilities within the subregion are not currently experiencing or expecting to experience any conditions that would impact reliability negatively. It is common amongst the entities to 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 located at the dual-fuel generating plants, approximately 10 Bcf of natural gas in storage at a company-owned natural gas storage facility, and short-term purchases of firm natural gas generally supplied from other gas storage facilities and delivered using firm gas transportation contracts. This mix of resources provides diversity of fuel supply and minimizes the likelihood and impact of weather, fuel supply, and fuel transportation conditions that might otherwise reduce capacity. Page 127 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments Routine scheduled maintenance outages are scheduled for some generating units during the winter. Outage plans are developed so that anticipated loads can be met with available resources. There are no other anticipated system conditions expected for the winter. Capacity Transactions on Peak Delta subregional utilities expect the following imports and exports for the upcoming 2009/2010 winter season. These imports and exports have been accounted for in the Reserve Margin calculations for the subregion. Utilities within the subregion use certain emergency short-term imports, transfers, or contracts in the form of reserve sharing to meet the demands of its load. All contracts for these imports/exports are considered to be backed by firm transmission and are tied to specified generators. No imports are based on partial path reservations. The majority of the contracts are not LDCs, but the LDCs that are in the subregion are considered to be all make- whole contracts. Overall, the utilities in the subregion do not depend on outside purchases or transfers from other Regions or subregions to meet their demand requirements. Entities within the Delta subregion participate in reserve sharing groups for their external resources. These sharing groups allow entities to receive emergency short term imports from remote balancing authorities in SPP as well as from the Delta subregion. Delta Table 2: Subregional Imports/Exports Winter Transaction Type 2009/2010 Firm Imports (Internal Subregion) 406 MW Firm Exports (Internal Subregion) 70 MW Non-Firm Imports (Internal Subregion) 0 MW Non-Firm Exports (Internal Subregion) 0 MW Expected Imports (Internal Subregion) 0 MW Expected Exports (Internal Subregion) 0 MW Firm Imports (External Subregion) 814 MW Firm Exports (External Subregion) 1,371 MW Non-Firm Imports (External Subregion) 0 MW Non-Firm Exports (External Subregion) 0 MW Expected Imports (External Subregion) 0 MW Expected Exports (External Subregion) 0 MW Transmission The following table shows bulk power system transmission categorized as under construction, planned, or conceptual that is expected to be in-service for the upcoming 2009/2010 winter season since the 2008 winter season. Utilities do not expect any delays in meeting in-service dates for projects to be completed this season. Unexpected significant transmission facility outages that would impact bulk power system reliability for the 2009/2010 winter season were not reported. Any planned maintenance outages would be studied to identify impacts to reliability 2009/2010 Winter Reliability Assessment Page 128 Regional Reliability Self-Assessments Delta Table 3: Expected Under-construction, Planned, Conceptual Transmission Transmission Transmission In-Service Concerns in Reliability Issues Mitigation Plans Project Name Type Date(s) meeting with In-Service to Address Delay (Under In-Service Date Delay? Construction, Date? (yes/no) Planned, or (yes/no) Conceptual) Thomas Hill - Under 12/2009 No N/A N/A Higbee Construction Conway West - Under 12/2009 No N/A N/A Donaghey - Construction Conway South Gillette 115 kV Under 12/2009 No N/A N/A capacitor bank Construction Rich Fountain- Under 12/2009 N/A N/A N/A Osage Construction Panama-Dutch In-Service 02/2009 N/A N/A N/A Bayou new 230 kV line Conway-Bagatelle In-Service 03/2009 N/A N/A N/A 230 kV line upgrade Liberty-Gloster In-Service 04/2009 N/A N/A N/A 115 kV line upgrade Acadia 138 kV In-Service 06/2009 N/A N/A N/A capacitor bank Several improvement projects are planned to be in-service by the end of 2009 to enhance bulk system reliability. These include 115 kV through 161 kV projects to improve line loading and voltage conditions. Within the subregion, various improvements have been completed since the last winter assessment. Completed projects to improve transfer capability within the Amite South area in south Louisiana include 230 kV line upgrades and a new line construction. Originally intended to be in service by 2007, the projects were delayed to 2009 due to the effects of Hurricane Katrina on the load pocket, including load loss. Another project includes the Paterson substation, which was flooded in New Orleans during Hurricane Katrina damaging all major transmission equipment. The station has since been operated in a split through-bus configuration. This project entails the rebuilding of the substation to join two buses and connecting four transmission lines. The Natchez, Mississippi area improvement plans are also another example of improvement projects to enhance the system during the winter season. The area is served by five long (40-50 miles) transmission 115 kV lines. When one of these lines is out of service, the area has a potential for low voltages and overloads on the remaining lines. This project entails the upgrade of the existing Liberty - Gloster 115 kV segment to 190 MVA and installation of 60 MVAr of capacitor banks and 16 MVAr of dynamic reactive power. No transmission constraints are expected to significantly impact bulk system reliability for the upcoming winter peak season. Several entities participate in the SERC Near-term Study Group (NTSG) 2009/2010 Winter Reliability Study. The preliminary results of this study indicate that imports into the subregion can be limited due to the McAdams 500/230 kV autotransformer for the loss of the McAdams - Lakeover 500 kV flowgate. This flowgate, which is located near a Page 129 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments 500 kV tie to the Central subregion, can be constrained due to excess generation on the interface along with transactions across the interface. Real-time operating limits have been addressed using the appropriate NERC operating procedures. Additional fans were added to the McAdams autotransformer in July 2008 to increase its rating, and further upgrades have been identified in the area with a projected completion date of 2011. To address transfer capability studies, some entities currently use an Available Flowgate Capability (AFC) process to calculate available transfer capability and evaluate transmission service requests in the Day 1 to Month 18 time frame. Because of the inherent granularity and update frequency provided by the AFC process, specific seasonal transfer capabilities are not calculated. Entities are also currently participating in the SERC NTSG 2009/2010 Winter Reliability Study. This study, which has not yet been finalized, tests transmission transfer capabilities between the Delta subregion and other SERC subregions. The analyses performed to calculate the transfer limits presented in the SERC NTSG 2009/2010 Winter Reliability Study consider all transmission elements identified by participating member companies within SERC. There were no new technologies, systems, or tools put in service since last winter season. Some utilities are currently operating static var compensation (SVC) devices in order to provide reactive power support and maintain voltage stability. Series compensation has been installed on two key transmission lines on the system in order to regulate power flows. Utilities plan to continue to employ and research these technologies in order to improve and maintain bulk power system reliability. Operational Issues No reliability concerns are anticipated for the upcoming peak season. Resource availability, fuel availability and hydro conditions are expected to be normal during the winter. Loss-of-Load studies are performed annually for the regulated utilities in the subregion for the current year based on updated load forecast and unit availability data. The long-term test of resource adequacy is met by achieving adequate planning Reserve Margin. Entities within the subregion reported no special operating procedures resulting from integration of variable resources. There are also no reliability concerns resulting from high levels of Demand Response resources, unusual operating conditions, local environmental or regulatory restrictions, or minimum demand and over generation from variable resources. Because Level 3 Energy Emergency Alerts (EEA-3s) were issued in the Acadiana area during this past summer, the SPP RTO will continue to monitor this area closely as part of its Reliability Coordinator function. Reliability Assessment Analysis The projected February 2010 winter peak Reserve Margin for the utilities in the subregion is 85.9 percent. This is 36.5 percent higher compared to last year’s peak (January 2009) Reserve Margin at 49.4 percent. The increase is largely due to more complete reporting using NERC’s new capacity definitions for 2009/2010. Increases in capacity for the upcoming season are expected to be adequate to meet demand for the upcoming winter season. There are no required state Reserve Margins for the subregion. Due to NERC’s new reporting requirements and capacity definitions, the 85.9 percent peak Reserve Margin is higher than previously reported as it includes both 2009/2010 Winter Reliability Assessment Page 130 Regional Reliability Self-Assessments committed and uncommitted resources within the subregion. This revised calculation method does not reflect the deliverability of certain uncommitted resources. Discounting the impact of uncommitted resources, the subregion expects the upcoming winter peak Reserve Margin to be adequate. Various utility resource planning departments in the subregion conduct studies annually (either in-house or through contract) to assess resource adequacy. Sophisticated modeling is used throughout the subregion in all phases of the study. An example of this type of modeling is the Entergy Reliability Analysis with Interruptible Loads (ERAILS) model that is used to perform resource requirements analyses. The ERAILS model uses Monte Carlo statistical techniques to estimate each day’s “actual” peak load based on the forecast load and the load forecast variance, the total resources available to serve that load based on available resources, forced outages, and the characteristics of each resource, and the probability of being able to meet the load, plus off- system sales and operating reserves. The fundamental objective of the process is to identify the amount of incremental resources necessary to serve firm load at a reliability level of no more than 1d/10y loss-of-load expectation and to serve interruptible retail and limited-firm wholesale loads with an average of ten or fewer days of interruption during the year. Studies like these are used to ensure resources are available at the time of system peak. Some companies have reported that results are approved by the board of directors internally. Subregional transmission planning departments also conduct sophisticated studies to ensure transfer capability is adequate under various contingency conditions. The balancing authority has a full requirements contract to ensure studies are performed, upon request of the supplier, by the transmission provider. These studies will evaluate the availability of firm transmission from resources. All resources were considered to meet the criteria or target margin level for last winter and for the upcoming winter. Fuel supplies are anticipated to be adequate. Coal stockpiles are maintained at 30 or more days. Natural gas contracts are firm. Extreme weather conditions will not affect deliverability of natural gas. Typically, supplies are limited only when there are hurricanes in the Gulf. There is access to local gas storage to offset typical gas curtailments. Many utilities maintain portfolios of firm-fuel resources to ensure adequate fuel supplies to generating facilities during projected peak demand. Those firm-fuel resources include nuclear and coal-fired generation that are relatively unaffected by winter weather events. Various portfolios contain fuel oil inventories located at the dual-fuel generating plants, approximately 10 Bcf of natural gas in storage at a company-owned natural gas storage facility, and short-term purchases of firm natural gas generally supplied from other gas storage facilities and firm gas transportation contracts. This mix of resources provides diversity of fuel supply and minimizes the likelihood and impact of potentially problematic issues on system reliability. Close relationships are maintained with coal mines, gas pipelines, gas producers, and railroads that serve its coal power plants. These close relationships have been beneficial to ensure adequate fuel supplies are on hand to meet load requirements. Companies throughout the subregion individually perform studies to assess transient dynamics, voltage and small-signal stability issues for winter conditions in the near-term planning horizons as required by NERC Reliability Standards. As part of annual winter assessments, some companies model single and multiple contingencies across the system. In load-flow analysis, bus voltages are monitored and were found to remain within acceptable range. In stability simulations, generator reactive power outputs were monitored and were found to stay within Page 131 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments adequate limits. These studies confirm that the available reactive power resources (generators, capacitors, reactors, SVCs) are adequate for the 2009/2010 winter and no critical impacts to the bulk electric power system are expected. While there are no common subregion-wide criteria to address transient dynamics, voltage and small-signal stability issues, some utilities have noted they adhere to voltage schedules and voltage stability margins. In addition, some utilities employ static var compensation devices to provide reactive power support and voltage stability. Under- voltage load-shedding (UVLS) programs are also used to maintain voltage stability and protect against bulk power system cascading events. Although certain areas within the Delta subregion are susceptible to multiple forms of weather events including hurricanes, tornadoes and ice storms, entities have reported that they have developed emergency restoration plans to respond to such events. These plans are periodically tested through drills where opportunities for process improvements are identified. However, Delta subregion companies do not anticipate reliability concerns outside of normal operational planning processes for the 2009/2010 winter season. 2009/2010 Winter Reliability Assessment Page 132 Regional Reliability Self-Assessments Gateway Demand The actual 2008/2009 winter peak for the utilities in the Gateway subregion was 15,323 MW. Total aggregate internal demand for 2009/2010 winter season is forecast to be 15,640 MW and is 675 MW (4.5 percent) higher than the 2008/2009 winter forecast Total Internal Demand of 14,965 MW. The actual winter peak demand may not take into account energy efficiency, diversity stand-by load or additions for non-member load, whereas the forecast internal peak demand values account for these factors. The Gateway subregion’s peak forecast is non-coincident and capacity reserves are evaluated for summer conditions. The increase in the 2009/2010 forecast load compared to the 2008/2009 forecast load is largely the result of an adjustment made by a larger entity due to the higher load and temperature conditions that were experienced in January, 2009, although four of the seven load-reporting entities provided load forecasts that were higher than last year’s. The higher load experienced is partially offset by reductions due to the economic recession and large industrial customer outages that are expected to extend into 2010. The normal forecast weather assumptions are based on 10 to 30 years of historical data along with adjustments for observation practices and economic conditions. Economic data was taken from sources such as Economy.com, which forecasts GDP growth of -4.4 percent in 2009 and 0.7 percent in 2010 for the service territories of the larger members of the subregion. Entities within this subregion reported no significant Demand Response that can reduce peak demand in the winter season. This is not surprising as many of the Demand Response programs are designed to curtail air conditioning load, which is not present in the winter. Also, there are no needs for demand-side programs during winter peak conditions because the capacity reserves that were acquired to cover the summer peak load will adequately cover the forecast winter peak loads. The Gateway forecast 2009/2010 winter peak load is approximately 82 percent of the forecast 2009 summer peak load. Several entities within this subregion have recently begun making significant investments in energy-efficiency programs. These programs are typically designed for summer and have not been forecasted to make a material impact on the peak forecast for winter 2009/2010. Programs that are available for customer use include energy- efficient lighting rebate programs, appliance recycling, energy audits, and HVAC rebate programs. The final reports on the effectiveness of these programs in Illinois are due to the Illinois Commerce Commission by the end of the year. In order to assess the uncertainty and variability in projected demand, some utilities within the Gateway subregion use regression models, multiple forecast scenario models, and econometric models. Economic assumptions, alternative fuel pricing, electric pricing, and historical temperature and weather (pessimistic and optimistic conditions) pattern information are considered individually by each subregional utility. These models are developed individually using different variables to establish the best standard statistical tests. DSM programs are not commonly modeled separately since their impact is reflected in the peak demand information used for forecasting purposes. All of these measurements provide information with which to assess potential variability around the forecasted peak. Page 133 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments Generation Member companies within the Gateway subregion expect to have the following aggregate capacity on peak. This capacity is expected to help meet demand during this time period. Gateway Table 1: Winter 2009/2010/10 Capacity Breakdown Capacity Type Winter 2009/2010 Existing-Certain 25,626 MW Wind 0 MW Solar 0 MW Biomass 0 MW Hydro 372 MW Existing-Other 811 MW Wind 0 MW Solar 0 MW Biomass 0 MW Hydro 1 MW Energy Only 0 MW Existing Inoperable 360 MW Future-Planned 0 MW Future-Other 0 MW The generation resources to serve the Gateway loads for this winter are predominantly located within the Gateway subregion. No variable resources are included in the capacity breakdown of the Gateway members. However, a 100 MW wind farm was connected to the Ameren-Illinois transmission system during the summer of 2009. Hydro capacity of 372 MW of hydro is expected to be available on-peak for the upcoming winter season. Hydro conditions are expected to be normal; reservoir levels are expected to be sufficient. Changes to the Existing-Certain capacity totals from last year include the addition of the CWLP (Springfield Illinois) Dallman unit #4 200 MW coal-fired unit. CWLP’s Dallman unit #1 (86 MW), which was out of service last winter, has been returned to service. Entities do not expect weather to impact the utility generation in the subregion. Coal is sufficiently available to service coal-fired plants. Firm gas transportation or oil back-up for the generating units is expected to be adequate as well. Entities within the subregion have reported adequate capacity for the upcoming season, and some are also planning for scheduled generation outages during the assessment period. The following units are expected to be out of service some time during the winter period: Coffeen unit #2 (560 MW) and Rush Island unit #2 (600 MW) are scheduled for major unit overhauls. Clinton Nuclear Plant (1078 MW) is scheduled for a refuel outage. Meredosia unit #3 will be out of service to install low NOx burners. Grand Tower combined-cycle plant (525 MW), Meredosia unit #4 (166 MW), and the MEPI CTGs (240 MW) will be on seasonal shutdown. Venice CTG #1 (25 MW) and the Taum Sauk pumped storage plant (400 MW) will also remain out of service through the 2009/2010 winter. 2009/2010 Winter Reliability Assessment Page 134 Regional Reliability Self-Assessments CWLP’s Lakeside units #6 and #7 (76 MW total) are being retired this fall; however, they are being replaced by the new Dallman #4 unit (200 MW). Meredosia units #1 and #2 (120 MW) are expected to be retired before this winter period, contingent upon approval from the Midwest ISO Attachment Y process. The above outages are not expected to affect reliability on the system for the upcoming winter season. Midwest ISO monitors generation availability throughout its footprint and has procedures in place if generation shortfalls would occur. Capacity Transactions on Peak The Gateway subregion reported the following imports and exports for the upcoming 2009/2010 winter season. These firm imports and exports have been accounted for in the Reserve Margin calculations for the subregion. All capacity purchases and sales are on firm transmission within the Midwest ISO footprint and direct ties with neighbors. Day-to-day capacity and energy transactions are managed by Midwest ISO with security-constrained economic dispatch and LMP. Overall, the subregion is not dependent on outside imports or transfers to meet the demands of its load. Gateway Table 2: Subregional Imports/Exports Winter Transaction Type 2009/2010 Firm Imports (Internal Subregion) 0 MW Firm Exports (Internal Subregion) 559 MW Non-Firm Imports (Internal Subregion) 0 MW Non-Firm Exports (Internal Subregion) 0 MW Expected Imports (Internal Subregion) 0 MW Expected Exports (Internal Subregion) 0 MW Firm Imports (External Subregion) 190 MW Firm Exports (External Subregion) 3,389 MW Non-Firm Imports (External Subregion) 0 MW Non-Firm Exports (External Subregion) 0 MW Expected Imports (External Subregion) 0 MW Expected Exports (External Subregion) 0 MW Several contracts within the subregion are LDCs and are considered to be all make-whole contracts. Many of the Gateway entities reported that they are a part of Midwest ISO and count on Midwest ISO to supply its needs during emergencies. Most of the Gateway members are also members of Midwest ISO and participate in Midwest ISO reserve-sharing group and ancillary service markets to ensure their resource needs. Transmission The following table shows bulk power system transmission additions since the 2008/2009 winter season, categorized as under construction, planned, or conceptual for the Gateway subregion. Page 135 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments Gateway Table 3: Expected Under Construction, Planned, Conceptual Transmission Transmission Project Transmission In-Service Concerns in Reliability Mitigation Name Type Date(s) meeting In- Issues with In- Plans to (Under Service Service Date Address Construction, Date? Delay? Delay Planned, or (yes/no) (yes/no) Conceptual) Interstate - East In-Service 06/01/2009 NA NA NA Springfield Interstate - San Jose Rail In-Service 06/01/2009 NA NA NA Hamilton Substation - Under 12/01/2009 NA NA NA Norris City Substation Construction The new Ameren-CWLP 138 kV interconnection at CWLP’s Interstate Substation was completed this summer to provide additional transmission outlet for the CWLP Dallman unit #4 generator addition. A new Hamilton-Norris City 138kV transmission tie line is under construction and is planned to be in-service by the upcoming winter season. This tie line is being constructed to increase the reliability on the SIPC transmission system. A number of upgrade projects involving terminal equipment have been completed since winter 2008/2009, resulting in increased thermal rating for several transmission facilities. Reconductoring work was completed on the Havana-Monmouth 138 kV line and Havana-Ipava 138 kV line prior to 2009 summer. Work to increase ground clearances on the St. Francois- Rivermines-1 138 kV line is expected to be completed before winter 2009. Several transmission line additions are proposed for the Gateway subregion over the next several years, but these lines will not be able to enhance transmission reliability for the 2009/2010 winter period. Longer lead-times are being reported by several members as it is becoming increasingly difficult to obtain permits and transmission rights-of-way to support new line construction. These delays presently are not impacting the reliability of the bulk power system, but local reliability may be degrading until these facilities can be constructed. The local entities will continue to rely on operational solutions until such facilities are in service. Gateway utilities have not scheduled any significant transmission facilities being out of service for the upcoming winter season. All significant, planned transmission facility outages are scheduled for spring and fall (off-peak seasons) and are coordinated and approved by Midwest ISO. However, some equipment that has recently failed, including the St. Francois 345/138 kV transformer #1, and may be out of service during the winter period as its replacement is not needed for reliable operation until next summer. Refer to the SERC section of this report for the aggregate view of transfers. Gateway members are planning the expanded installation of phasor measurement equipment, at various plants and substations around the subregion, to enhance the collection of pre- and post- disturbance generation and transmission data. These installations, in combination with other such phasor-measuring equipment installed elsewhere on the interconnected system, may provide another tool to operations personnel in assessing immediate near-term conditions on the 2009/2010 Winter Reliability Assessment Page 136 Regional Reliability Self-Assessments interconnected system. Some utilities are investigating the implementation of a "smart grid" on their systems, and the use of D-FACTS devices on its transmission system for loss reduction, transmission system flow control, and voltage control. Operational Issues Based on studies and previous winter operating experience, reliability problems are not expected on the Gateway transmission system for this winter. Operating conditions similar to last year are expected, and near-term operating studies performed to date have not identified any major reliability concerns. As unique operating problems have not been experienced and reliability concerns have not been identified in studies, no special operating studies have been performed. Entities reported that they have capacity and energy plans in place for emergencies or problems caused by extreme weather conditions. Midwest ISO also has procedures in place to address reliability concerns. Utilities reported greater operating concerns during off-peak or light load conditions than for winter peak conditions. During off-peak periods when generation is plentiful in the Midwest, heavy transmission flows to the east and south often occur as the available coal, nuclear, and wind capacity can be used to economically displace gas and oil-fired generation. Generation in the Gateway subregion contributes to these heavy line loadings. At times, the transmission system limits the amount of power that can be economically transferred, and Midwest ISO must redispatch some generation through LMP and security constrained economic dispatch to keep transmission flows within facility ratings. TLR may need to be called if the local generation redispatch is ineffective. The Renshaw-Livingston 161 kV tie line between SIPC and Big Rivers Electric Cooperative is an example of this phenomenon. The line has been reported to have occasional heavy loading during off-peak times, and TLR has been requested in an attempt to alleviate the line loading. This constraint does not impact the reliability of the bulk power system. Other entities within the subregion are not anticipating constraints that will affect reliability on the system. During light load or minimum load conditions, too much generation may be operated causing overgeneration in the system. The continuing addition of variable resources, including wind generation in the subregion and throughout the Midwest exacerbates the problem. Some entities have reported that variable resources, particularly wind, have presented new operating challenges at minimum load levels, as Midwest ISO has issued several minimum generation alerts, warnings, and emergencies. As a result, some entities within the subregion have responded by taking generating units off-line and by reducing online units to absolute minimum levels to comply with Midwest ISO orders. No significant reliability concerns have been experienced or are expected due to Demand Response, minimum demand levels, and over generation resulting from the integration of variable resources. . Environmental and regulatory restrictions are a factor for some entities within the subregion. One Gateway utility reported the loss of net generation capability of approximately 20 MW due to the installation of Selective Catalytic Reduction (SCR) devices. Other entities reported that their gas- fired CTGs, which are typically used to cover summer peak load conditions, are limited by emissions to 950 hours of operation per year because of the type of regulatory air permit Page 137 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments acquired. CTG hours of operation are reviewed by individual companies on a continuing basis and are considered during resource planning and for availability to the Midwest ISO market. Although environmental restrictions exist for some units around the subregion, to date, these restrictions have not limited or prevented the use of the units for reliability or economic dispatch situations. Overall, Gateway entities do not expect unusual operating conditions which could impact reliability for the upcoming winter season. Reliability Assessment Analysis The projected January 2010 winter peak Reserve Margin for the utilities in the subregion is 39.8 percent, which is much lower than last year’s peak (January 2009) Reserve Margin at 66.4 percent. The decrease is largely due to more complete capacity reporting using NERC’s new definitions for 2009/2010. Entities within the SERC Region perform individual studies to assess their individual systems. Some entities within the Region participate in various study groups to assess the reliability of the system on a near-term and long-term basis. Some utilities have filed integrated resource plans with their local commissions, but there are no required state Reserve Margins for the utilities in the subregion. Although Gateway subregion utilities have traditionally tried to maintain a planning Reserve Margin of at least 15 percent, this requirement has been reduced to a minimum of 12.7 percent based on the latest loss-of-load-expectation studies performed by Midwest ISO. The Illinois Power Authority, which procures capacity resources for Ameren Illinois Utilities, has no long-term capacity contract requirements at this time but would follow the planning reserve requirements of Midwest ISO. The capacity and reserves acquired for summer 2009 will be more than adequate to cover the load for the winter 2009/2010. Midwest ISO resource adequacy and operational procedures are located within the Midwest ISO Resource Adequacy Business Practice Manual106. A 50/50 load uncertainty was used in their latest LOLE analysis. A 90/10 load forecast was not done; however, if it were done it is not expected to increase the reserve requirements significantly due to the geographical size and load diversity within Midwest ISO. The use of a 90/10 forecast would increase demand by about 5 percent above the 50/50 forecast level for the Gateway subregion. Capacity resources in the Gateway subregion are expected to be adequate for the upcoming peak-demand winter season. Most load-serving entities within this subregion are members of the Midwest ISO Contingency Reserve Sharing Group. Entity membership within this group also ensures coverage on any short-term emergency imports, generation tests, Demand Response, or renewable portfolio procedures (variable resource requirements can be found under the Midwest ISO Resource Adequacy Business Practice Manual). Other entities use contracts with various companies to supply them with access to variable generating resources and renewable energy. Midwest ISO is studying the impacts of integrating large amounts of variable resources on the system. This issue of wind integration has been elevated to a higher level as the amount of wind generation is expected to increase dramatically in Midwest ISO and throughout the midwest over the next several years. 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. 106 Midwest ISO Resource Adequacy Business Practice Manual can be found at: http://www.misostates.org/OMSModuleEadopted27NOV07FINAL%20.pdf 2009/2010 Winter Reliability Assessment Page 138 Regional Reliability Self-Assessments Several entity 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. Communication maintained with suppliers to ensure adequate supplies are available and all potential problems are known by all parties as soon as possible. Members within the Gateway subregion individually perform dynamic and static reactive power studies as part of their annual assessment to comply with NERC Standards TPL-001 through TPL-004. Some generating entities have reported that the procedures of the reactive power studies are performed specific to the NERC Standard MOD-025 testing parameters. Because load power factors are generally higher during the winter season than during the summer season, and the loads are generally lower, this reduces the reactive power requirements in the subregion during the winter period. For these reasons, most entities reported that no specific tests were performed for the winter 2009/2010 period. Page 139 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments Southeastern Demand The actual 2008/2009 winter peak for utilities in the Southeastern subregion was 43,969 MW. Total aggregate internal demand for the 2009/2010 winter season is forecast to be 41,740 MW; this is 675 MW (1.6 percent) lower than the forecast 2008/2009 winter peak demand of 42,415 MW. This projection is based on average historical winter weather and is the sum of non- coincident forecast data reported by utilities in the SERC Region. Some entities have lowered their forecasts due to the economic recession. The actual winter peak demand does not take into account energy efficiency, diversity, stand-by load, or additions for non-member load, whereas the internal peak demand values account for these factors. Most forecast assumptions are based on median (50/50) weather conditions. One Southeastern entity reported that these particular weather conditions are determined by using hourly dry bulb temperatures for six weather stations that are strategically located within their service area. A single “weighted average” is calculated for each hour. The weighted averages are derived based on the amount of load served near the weather stations as well as taking into consideration the weather patterns that cross the company’s territory. Entities factor historical years of weather data into their modeling processes to determine a median “expected normal” winter peak demand. This year’s forecast was reported to be based on actual data; the peak demand models have been updated to better reflect current conditions. Demand response programs are typically not used to reduce peak demand in the winter periods. External adjustments are normally made to the load and energy forecast for demand side programs; however, the majority of demand adjustments are not applied during winter months as most programs are designed for application during summer months. Adjustments are based on price response to certain demand-side programs in the system. The subregion has a mix of various demand-response programs including interruptible demand, customer curtailing programs, and direct load control (irrigation, A/C and water heater controls). Entities within this subregion reported 4.3 percent of Total Internal Demand as Demand Response that can reduce peak demand. To address M&V, some entities have reported that two-way communication devices have been used as a functionality to allow customers to perform M&V at any desired level. An entity also reports small pilot tests scheduled for 2010 regarding HVAC cycling and direct load for pool pumps. Utilities within the subregion have a variety of energy-efficiency programs. Residential programs may include home energy audits, compact fluorescent light bulbs, electric water heater incentives, heat pump incentives (geothermal or ground-source), EPA-approved ventilation and air-conditioning (HVAC) technology, energy-efficient new home programs, Energy Star appliance promotions, loans or financing options, weatherization, programmable thermostats, and ceiling insulation. Commercial programs including energy audits, lighting programs, and plan review services are available to various customers within this subregion. Some energy- efficiency programs are measured by engineering models. The Conserve101 energy- efficiency/conservation program was put in place by one utility in 2009 to educate residential consumers about no-cost/low-cost methods they can use in order to reduce their monthly household electric use and to provide methods on how to wisely use electricity in their home. 2009/2010 Winter Reliability Assessment Page 140 Regional Reliability Self-Assessments These methods are simple to implement, inexpensive, and non-intrusive to the consumers’ lifestyles. Other programs such as business assistance/audits, weatherization assistance for low- income customers, residential energy audits, and comfort advantage energy-efficient home programs promote reduced energy consumption, supply information, and develop energy- efficiency presentations for various customers and organizations. Utilities also work with the State Energy Division on energy-efficiency planning efforts. Training seminars addressing energy efficiency, HVAC sizing, and energy related end-use technologies are also offered to educate customers. External adjustments are made to the load and energy forecast for energy- efficiency programs. Energy efficiency and Demand Response adjustments are not applied during winter months as most programs are designed for application during summer months. The 2009/2010 winter demand forecast is based on normal weather conditions and uses normal/median weather, normal load growth and conservative economic scenarios. To assess variability, some subregional entities develop forecasts using econometric analysis based on approximately 30 to 40 year weather (normal, extreme, and mild), economics and demographics. Others within the subregion use the analysis of historical peaks, Reserve Margins, and demand models to predict variance. One entity who used demand models reported that winter peaks are projected for each of these weather years and then the peaks are ranked from the mildest to the most extreme. The median peak is typically used in its forecasting process to best determine normal weather conditions. The median forecast has been used in past studies because the mean and midpoint forecast tend to be impacted by particular values obtained in the extreme weather years, primarily during the 1980’s and the winter of 2003. Variables are compared to actual weather conditions and adjusted to determine a forecast that this normal or extreme for the service area. Reserves are built into the system to take into account factors such as weather volatility and load forecast error. Companies continue to study the impacts of all factors to perfect their processes in determining peak demand. Generation Utilities within the Southeastern subregion expect to have the following aggregate capacity on- peak to help meet demand during this time period. Southeastern Table 1: Winter 2009/2010 Capacity Breakdown Capacity Type Winter 2009/2010 Existing-Certain 58,528 MW Wind 0 MW Solar 0 MW Biomass 0 MW Hydro 3,300 MW Existing-Other 7,905 MW Wind 0 MW Solar 0 MW Biomass 0 MW Hydro 0 MW Energy Only 0 MW Existing Inoperable 0 MW Future-Planned 350 MW Future-Other 426 MW Page 141 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments For planning purposes, potential future biomass generation is included in the Integrated Resource Plan at half of the nameplate capacity for converted boilers and close to nameplate for units receiving new boilers. Currently no variable resources are planned for the upcoming season. Hydro conditions are expected to be normal. Some entities have reported that, based on current weather and operational forecasts for this winter, the output of total hydro-generation will be below normal. The major weather factor contributing to this would be the forecasted strengthening of El Nino. If lower than normal rainfall occurs, it is anticipated that reservoirs can be managed to meet the short-duration peak demand that is typical of winter hydro-peaking operations. However, recent prolonged heavy rain in the subregion area has likely addressed any below normal hydro concerns. Utilities in the subregion are not experiencing or expecting conditions (i.e., weather, fuel supply, fuel transportation) that would reduce capacity for the upcoming season. Supplies are expected to be adequate and communications are in place to reduce any unanticipated impacts. The utilities anticipate only regular scheduled generation maintenance for the winter season totaling 315 MW in the peak month of January 2010. Although multiple large units are planned to have overlapping outages during other months of this winter season, plans are already taken into account to minimize impacts on reliability. These outage plans are routinely monitored and revised if necessary to ensure availability of adequate reserves. The system has ample reserves to replace the outages. System winter season loads typically peak at approximately 85 percent of average summer peak and reserve level are further increased due to cost-saving capacity additions and load erosion driven by the economic recession. There are no unit retirements expected during the 2009/2010 winter season. Capacity Transactions on Peak Southeastern utilities reported the following imports and exports for the upcoming 2009/2010 winter season. The majority of these imports/exports are backed by firm contracts, with none associated with LDCs. These firm imports and exports have been included in the Reserve Margin calculations for the subregion. None of the reported imports or exports are based on partial path reservations. Overall, the subregion is not dependent on outside imports or transfers to meet the demands of its load. Southeastern Table 2: Subregional Imports/Exports Transaction Type Winter 2009/2010 Firm Imports (Internal Subregion) 624 MW Firm Exports (Internal Subregion) 0 MW Non-Firm Imports (Internal Subregion) 0 MW Non-Firm Exports (Internal Subregion) 0 MW Expected Imports (Internal Subregion) 0 MW Expected Exports (Internal Subregion) 0 MW Firm Imports (External Subregion) 1,901 MW Firm Exports (External Subregion) 2,780 MW Non-Firm Imports (External Subregion) 0 MW Non-Firm Exports (External Subregion) 0 MW Expected Imports (External Subregion) 0 MW Expected Exports (External Subregion) 0 MW 2009/2010 Winter Reliability Assessment Page 142 Regional Reliability Self-Assessments Entities do not rely on resources outside of the Region. However, some of the companies within the subregion participate in the SPP reserve sharing group (external to subregion) or market models to acquire resources. Forced outage rates, weather anomalies, and load forecast errors are continuously monitored to maintain reliability. Transmission The following table shows bulk power system transmission that either has entered or is expected to enter service between the 2008/2009 and 2009/2010 winter seasons. Southeastern Table 3: Transmission Expected In-service Since 2008/2009 Winter Transmission Transmission In-Service Concerns in Reliability Issues Mitigation Plans to Project Name Type Date(s) meeting with In-Service Address Delay (Under In-Service Date Delay? Construction, Date? (yes/no) Planned, or (yes/no) Conceptual) Calvert SS - In-service 03/12/2009 NA NA NA Tensaw SS Tensaw SS - TK In-service 03/24/2009 NA NA NA Rolling Mill Tensaw SS - TK In-service 03/24/2009 NA NA NA Rolling Mill Tensaw SS - TK In-service 06/24/2009 NA NA NA EAF Tensaw SS - TK In-service 06/24/2009 NA NA NA EAF Tensaw SS - TK In-service 06/24/2009 NA NA NA EAF Bucks SS - Under 10/06/2009 No No NA Tensaw SS Construction Bio - Airline In-service NA NA NA NA McConnell Road - In-service NA NA NA NA Woodlore Woodlore - In-service NA NA NA NA Battlefield Nebo - New Under 11/30/2009 No No NA Georgia Construction Chevron Cogen - In-service 11/28/2008 NA NA NA Chevron PRCP Bowen - Villa In-service NA NA NA NA Rica Primary 500 kV line conversion to 230 kV Black Pond Tap - In-service 08/04/2009 NA NA NA Black Pond DS 161 kV line Cavender Drive In-service NA NA NA NA 230 kV SS Battlefield – Frey Under 11/15/2009 No No NA Road 230 kV line Construction Frey Road 230 kV Under 11/15/2009 No No NA SS Construction Page 143 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments Southeastern Table 3: Transmission Expected In-service Since 2008/2009 Winter Transmission Transmission In-Service Concerns in Reliability Issues Mitigation Plans to Project Name Type Date(s) meeting with In-Service Address Delay (Under In-Service Date Delay? Construction, Date? (yes/no) Planned, or (yes/no) Conceptual) Bethabara Under 12/1/2009 No No NA 230/115 kV Construction substation Bethabara – Under 12/1/2009 No No NA Georgia Square Construction 115 kV line Thomasville Under 12/31/2009 No No NA Primary 230kV Construction and 115kV bus tie breakers East Pelham In-Service 9/30/2009 NA NA NA 230kV substation Several significant bulk power transmission facilities have entered service since the previous winter assessment. Examples of these are the Bonaire Primary and East Social Circle 230/115 kV transformer upgrades expected to be in-service June 2009 and conversion of the Bowen-Villa Rica 500kV line to 230kV operation by the end of 2009. All of these projects are expected to improve reliability with no concerns with the in-service dates. Entities coordinate maintenance outages around the subregion. All planned transmission facility outages are thoroughly studied based on forecasted system conditions and evaluated for potential reliability impacts. When required, procedures are developed to mitigate potential reliability impacts. No significant transmission line outages are scheduled for this winter season except for 115kV outages associated with the Plant McIntosh Units 4 & 5 addition project. However, these have been scheduled to avoid winter peak conditions and a detailed system impact study did not identify any reliability issues for the temporary system configuration. The utilities in the subregion have not identified any anticipated unusual transmission constraints that could significantly impact reliability. However, to further improve reliability, some entities within the subregion have reported efforts to install more Remote Controlled Motor Operated Switches (RCMOS) on the transmission system and replace electromechanical protective relays with microprocessor relays. The deployment of these relays will provide for additional analysis of events and allow faster clearing times using communication-assisted schemes. Operational Issues Entities within the subregion reported to have performed routine system studies for the 2009/2010 winter season which include the most up-to-date information regarding transmission status, generation status, and load forecasts. The studies are updated on a monthly basis to capture operating conditions for 12 months into the future. The current operational planning studies do not identify any unique operational problems. Special operating studies are not commonly performed unless dictated by changing system conditions. Most entities do not integrate any variable resources into their generation supply portfolios; therefore, they do not 2009/2010 Winter Reliability Assessment Page 144 Regional Reliability Self-Assessments have special operating procedures with regard to variable resources. Southeastern entities have not identified any reliability concerns related to environmental or regulatory restrictions, Demand Response or minimum demand and over generation resulting from variable resources. Unusual conditions are not expected to be a concern for the upcoming season. However, some parts of the subregion routinely experience significant loop flows due to transactions external to the service area. 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 service area, rather than by loading within the various control area. Significant changes in gas pricing dramatically impact dispatch patterns. All transmission constraints identified in current operational planning studies for the 2009/2010 winter can be mitigated through generation adjustments, system reconfiguration, or system purchases. Reliability Assessment Analysis The projected Reserve Margin in the Southeastern subregion is 46.8 percent compared to 42.9 percent last year. Entities within the subregion reported that Reserve Margins have been slightly affected due to the economic recession and the corresponding downward sloping load forecast. Even though entities have reported that the State of Georgia requires utility companies to maintain 15 percent long-term capacity reserves, the Southeastern subregion as a whole does not have a single target margin or guideline. Individual company analyses account for planned generation additions, retirements, and deratings due to environmental control additions, load deviations, weather uncertainties, forced outages, and other factors. Resource adequacy is determined by extensive analysis of costs associated with expected unserved energy, market purchases and new capacity. These costs are balanced to identify a minimum cost point which is the optimum Reserve Margin level. The latest resource adequacy studies show that Reserve Margin for winter 2009/2010 is expected to have a wide range of Reserve Margins between 15 percent and 75 percent for utilities within the subregion. It is not expected to drop below 15 percent for any single entity due primarily to winter peaks within the subregion being only a portion of the subregion’s summer peak. Even though utilities use purchases and reserve sharing agreements, they are not relying on resources from outside the Region or subregion to meet load. Additionally, post-peak assessments are conducted on an as-needed basis, to evaluate system capability resulting from an extreme-peak season. Results indicate that existing and planned resources exceed the target Reserve Margin for the upcoming season; therefore, no significant changes in planned external resources to establish the margins during these periods are anticipated. The fuel supply infrastructure, fuel delivery system, and fuel reserves are all adequate to meet peak gas demand. As with other subregions within SERC, communications with suppliers and transportation agents are considered to be strong. For example, one entity reported receiving daily email updates/alerts from Florida Gas Transmission regarding any problems or potential problems that may affect the transport of natural gas to their facilities. Daily communications are also common between gas production companies and suppliers through which entities can be made aware of any potential problems. Page 145 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments Various companies within the subregion have firm transportation diversity, gas storage, firm pipeline capacity, and on-site fuel, oil, and coal supplies to meet the peak demand. Many utilities reported that fuel vulnerability is not an expected reliability concern for the winter reporting period. The utilities have a highly diverse fuel mix to supply its demand, including nuclear, PRB coal, Eastern coal, natural gas, and hydro. Some utilities have implemented fuel storage, coal conservation programs, and various fuel policies to address this concern. Policies have been put in place to ensure that storages are filled well in advance of hurricane season (by June 1 of each year). These tactics help to ensure balance and flexibility to serve anticipated generation needs. Relationships with coal mines, coal suppliers, daily communications with railroads for transportation updates, ongoing communications with the coal plants, and constant communication with The Energy Authority ensure that supplies are adequate and potential problems are communicated well in advance to enable adequate response time. The Energy Authority maintains daily contact with suppliers, pipelines, and other utilities that may be able to assist in an emergency. The Southeastern subregion does not have subregional criteria for dynamics, voltage, or small signal stability; however, various utilities within the subregion maintain individual criteria to address any stability issues. Appropriate entities perform annual transmission assessments that analyze system voltage and reactive performance under contingencies as required by the TPL Reliability Standards, including system stability studies to analyze the dynamic characteristics of the system. Current year studies show that reactive resources are adequate for base case as well as contingency conditions and have not identified any deficiencies that would need to be addressed for winter 2009/2010. In order to minimize system reliability concerns for this winter, entities within the subregion plan to perform preventative maintenance on units during the off-peak period, continue to perform operating studies ahead of the season and continue routine maintenance on transmission equipment on the system. These steps should help to avoid negative impacts on the system and improve the performance of the system for upcoming seasons. 2009/2010 Winter Reliability Assessment Page 146 Regional Reliability Self-Assessments VACAR Demand The actual 2008/2009 winter peak demand for the utilities in the VACAR subregion was 59,586MW. The total aggregate internal demand for the 2009/2010 winter season is forecast to be 57,210 MW based on normal weather conditions; this is 474 MW (0.8 percent) lower than the forecast 2008/2009 winter Total Internal Demand of 57,684 MW. The actual winter peak demand does not take into account energy efficiency, diversity stand-by load, or additions for non-member load, whereas the internal peak demand values account for these factors. A variety of reasons account for the decreases in demand from last year’s reporting to this year. Some of those reasons are due to economic recession, an increase in load management, regressing demographics, a loss of large customers, winter peak adjusted to normal peaking temperatures, and the slowdown in growth in residential and commercial sales. Slowed growth trends are expected to continue into 2010. Projected demands have been adjusted to account for downward and normalizing weather conditions. As with other subregions within SERC, entities within VACAR use multiple years of historical weather data to develop weather variables for forecasting peak demands. One entity reported that it factors in the sum of heating degree hours on the winter peak day and the heating degree hours on the day before the winter peak day as two weather variables, to assess forecasted winter peak demands. Another factor that is commonly used around the subregion to assess forecast is economic projections. Economy.com seems to be a common economic consulting firm for the development of SERC demand forecasts. The utilities in the subregion have a variety of programs offered to their customers that support energy efficiency and Demand Response. Some of the programs are current energy-efficiency and DSM programs that include interruptible capacity, load control curtailing programs, residential air conditioning direct load, energy products loan program, standby generator control, residential time-of-use, Demand Response programs, Power Manager PowerShare conservation programs, residential Energy Star rates, Good Cents new and improved home program, commercial Good Cents program, thermal storage cooling program, H20 Advantage water heater program, general service and industrial time-of-use, and hourly pricing for incremental load interruptible, etc. These programs can be used to reduce the affects of winter peaks and are considered as part of the utilities’ resource planning. Historically, load management is not needed or anticipated to be used in the winter, but entities are committed to the use of these programs as part of a long-term, balanced energy strategy to meet future energy needs. Winter assessment reporting for the VACAR Region shows that 3 percent of Total Internal Demand as Demand Response can be used to reduce peak demand. Future M&V analyses along with new product development and ongoing product management decisions are used to incorporate updated information into the resource plans. Some of the approaches of M&V are: monitoring parameters and variables, monitoring interval and period, measurement equipment specifications, measurement data collection and management, data validation, editing and estimating plan, accuracy of monitoring and verification method, savings uncertainty and confidence level, and factors most uncertain or difficult to quantify. Some of the calculations and adjustments during this process account for verification of equations, calculations, the analysis of procedures for baseline and post-installation demand and energy Page 147 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments consumption, performance model development, population description, sample size calculations, methods of sampling, demand and energy savings calculations, and the method of adjustments to the data. More information of this method can be found in the PJM manual 18B. To assess demand variability, some utilities within the subregion use a variety of assumptions to create forecasts. These assumptions are developed using economic models, historical weather (normal and extreme) conditions, energy consumption, and demographics. Others assess variability of forecast demand by accounting for Reserve Margins through continuous evaluation of inputs used in forecasting processes, high and low forecasts, tracking of forecast versus actual, and multiple forecasts per year. Generation Companies within the VACAR subregion expect to have the following aggregate capacity on peak. This capacity is expected to help meet demand during this time period. VACAR Table 1: Winter 2009/2010 Capacity Breakdown Capacity Type Winter 2009/2010 Existing-Certain 73,281 MW Wind 0 MW Solar 0 MW Biomass 175 MW Hydro 3,889 MW Existing-Other 1,571 MW Wind 0 MW Solar 0 MW Biomass 0 MW Hydro 0 MW Energy Only 48 MW Existing Inoperable 43 MW Future-Planned 46 MW Future-Other 0 MW Very few entities within the VACAR subregion have reported use of biomass as a resource within their portfolios within the subregion. The table above shows that 175 MW of biomass is captured as a resource in the subregion. One of the entities within the subregion reported that this capacity (namely, landfill gas) is calculated from published unit ratings and is commensurate with actual operating capabilities of these resources. Hydro conditions are expected to be normal. Reservoir levels are sufficient to meet peak demand and daily energy demand throughout the winter; however, entities are recovering from the prior year’s drought. Some entities have reported that the effects of the prior year’s drought have been an impact on a small run of river hydro units that make up a small portion of total generating capacity. If the drought conditions continue, approximately 576 MW of pumped storage and 415 MW of fossil generation could be potentially impacted. Currently, companies do not expect to experience capacity reductions. They plan to continue to monitor water levels and will take appropriate actions if these levels get to the point where capacity could be affected. Coupled with 2009/2010 Winter Reliability Assessment Page 148 Regional Reliability Self-Assessments other resources in resource portfolios, projected hydro generation and reservoir levels are expected to be adequate to meet both normal and emergency energy demands for the 2009/2010 winter. There are no known or expected conditions that would reduce capacity in the VACAR subregion. No peak capacity reductions are expected for the coming season. Significant generators within the subregion are not expected to be out of service or retired. Planned outage schedules and retirements are coordinated ahead of time with the transmission operators to preserve the reliability of the bulk power system. Capacity Transactions on Peak Utilities within the VACAR area reported the following imports and exports for the upcoming 2009/2010 winter season. These sales and purchases are external and internal to the Region and subregion and help to ensure resource adequacy for the utilities within the VACAR area. VACAR Table 2: Subregional Imports/Exports Winter Transaction Type 2009/2010 Firm Imports (Internal Subregion) 0 MW Firm Exports (Internal Subregion) 0 MW Non-Firm Imports (Internal Subregion) 0 MW Non-Firm Exports (Internal Subregion) 0 MW Expected Imports (Internal Subregion) 0 MW Expected Exports (Internal Subregion) 0 MW Firm Imports (External Subregion) 1,687 MW Firm Exports (External Subregion) 737 MW Non-Firm Imports (External Subregion) 0 MW Non-Firm Exports (External Subregion) 0 MW Expected Imports (External Subregion) 0 MW Expected Exports (External Subregion) 0 MW Contracts that were identified are backed by both firm generation and firm transmission commitment. VACAR entities reported that approximately 455 MW are associated with LDCs. The majority of the reported contracts are considered to be make-whole. Outside imports or transfers of capacity from other Regions or subregions are not expected to be relied on to meet emergency imports and reserve sharing requirements for the upcoming season. However, some VACAR companies have reported that they are a member of the VACAR Reserve Sharing Group and occasionally use their participation to meet emergency import and reserve requirements. This arrangement is based upon a collection of bilateral contracts between Reserve Sharing Group members within the VACAR subregion of SERC. Transmission Several improvements to transmission facilities of utilities within VACAR have been completed or planned to be completed by the winter of 2009/2010. The following table shows bulk power system transmission categorized as under construction, planned or conceptual that is expected to be in-service for the upcoming 2009/2010 winter season since 2008. Page 149 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments VACAR Table 3: Expected Under Construction, Planned, Conceptual Transmission Transmission Transmission In-Service Concerns in Reliability Issues Mitigation Plans Project Name Type Date(s) meeting with In-Service to Address Delay (Under In-Service Date Delay? Construction, Date? (yes/no) Planned, or (yes/no) Conceptual) Clarendon - Planned 02/2010 N/A No None Rosslyn Bristers - In-service 05/2009 N/A N/A N/A Gainesville Rockingham - Under 06/01/2009 No No None Wadesboro Construction Bowman School Nantahala Hydro - In-service 02/2009 N/A N/A N/A Santeetlah and Fontana Pepperhill In-service 07/15/2009 N/A N/A N/A 230/115 kV Substation Transformer w/ Terminals Lake Murray – In-service 11/13/2008 N/A N/A N/A Lexington Junction Westvaco – In-service 10/15/2008 N/A N/A N/A Thomas Island 115 kV extension Several other improvements were reported within the subregion to improve reliability. Examples of these improvements are Graniteville - Aiken #1 115 kV upgrade to 1272 ACSR and Goose Creek - Ashley Phosphate 115 kV upgrade to 1272 ACSR. A 230-115 kV transformation (90/120/150 MVA) was established at the Shamrock 115 kV Switching Station, providing local transmission service support from the Cross-Aiken 230 kV Line. Close coordination between construction management and operations planning ensures schedule requirements and completion requirements are well understood. Several other large-scale construction projects are planned and implemented in phases around seasonal peak load periods to mitigate line clearances and non-routine operating arrangements during higher seasonal load periods. There are no concerns with the projected in-service dates with the reported improvement projects. However, some existing transmission lines are expected to be out of service this winter. The McGuire-Harrisburg 230kV line (Mecklenburg White line) is anticipated to be out of service for much of the 2009/2010 winter season. Studies have indicated that there are no reliability concerns with this extended outage. Companies will maintain reliability by re-dispatch, re- configuration, market-to-market re-dispatch with Midwest ISO, and NERC TLR if necessary. Transmission maintenance schedules are carefully reviewed and evaluated to insure reliability concerns are addressed prior to seasonal peak periods. Regional studies are performed on a routine basis both internally as well as externally. Coordinated single transfer capability studies with external utilities are performed quarterly through the SERC NTSG. Projected seasonal import and export capabilities are consistent with 2009/2010 Winter Reliability Assessment Page 150 Regional Reliability Self-Assessments those identified in these assessments. Constraints that are external to the SERC subregion are evaluated as part of the SERC East RFC seasonal study group efforts. No transmission constraints have been identified that are anticipated to significantly impact reliability. Entities within the subregion are monitoring industry activities involving the installation and use of synchro phasors and have the capability to retrofit many existing relays to convert them to Phasor Measurement Units (PMU). Smart grid technology is also being investigated for installation around the subregion. Operational Issues To assess operating issues and studies, entities reported that they forecast typical/severe weather cases and plans and secure additional firm capacity on a seasonal basis for typical/severe demand forecasts. Other short-term firm purchases with firm transmission service are made on an as- needed basis if situations on the system occur. Entities within this subregion participate in SERC study groups that assess the subregion on a seasonal basis. An assessment within this study can be found in the SERC NTSG 2009/2010 Winter Reliability report which is submitted to FERC via FERC filings. For the projected 2009/2010 winter peak season, study efforts do not identify any unique or significant operational problems that would impact the reliable operation of the bulk transmission system. VACAR entities have not identified special operating problems from the integration of variable resources. Additionally, they do not anticipate any reliability problems resulting from minimum demand over generation due to variable resources, Demand Response, or unusual operating conditions for the upcoming winter season. There are no anticipated local environmental and/or regulatory restrictions that could potentially impact reliability. Reliability Assessment Analysis The projected aggregate Reserve Margin of the utilities within the VACAR area is 33.9 percent, compared to 29.9 percent last winter. Capacity in the subregion should be adequate to supply forecast demand. Although some utilities within this subregion adhere to North Carolina Utility Commission regulations, VACAR entities individually use various methods to establish Regional/subregional Reserve Margin criterions. There currently is not a target margin for the subregion. Companies have reported using techniques such as: Loss-Of-Load Expectation studies (1d/10y), generation resource plans (plant availability, plant forced outages, VACAR reserve sharing agreement, adverse weather impacts, loss of load probability, and the sizes of units), multi-regional studies, and historical performances. There are a number of increased risks involved with these factors that need to be considered with regard to Reserve Margin targets. These risks include: 1) the increasing age of existing units on the system; 2) the inclusion of a significant amount of renewables (which are generally less available than traditional supply-side resources) in the plan due to the enactment of the REPS in North Carolina; 3) uncertainty regarding the impacts associated with significant increases in company energy efficiency and DSM programs; 4) longer lead times for building baseload capacity such as coal and nuclear; 5) increasing environmental pressures which may cause additional unit derates and/or unit retirements; and 6) increases in derates of units due to drought conditions. Each of these risks would negatively impact the Page 151 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments resources available to provide reliable service to customers. Companies will continue to monitor these risks in the future and make any necessary adjustments to the Reserve Margin target in future plans. Resource adequacy is assessed by forecasted normal/severe weather cases with additional firm capacity (existing, future, and outage models included) and forecasted demand plans on a seasonal basis. In addition, forecast of peak demand is made under a variety of both weather and economic conditions as required under RUS 1710 requirements. From this analysis, resources are planned accordingly. This year’s studies are expected to be adequate based on the current forecast, generation, and demand side resources. Communication amongst entities and the fuel industry is considered to be strong. On an ongoing and regular basis, supply adequacy, whether the fuel be oil-based or gas-based, is discussed and assessed in conjunction with suppliers taking into account historical and projected demand. In those discussions, issues such as market trends, vendor performances, and associated potential resource constraints are framed to ensure potential interruptions can be mitigated and addressed in a timely manner. Utilities have reported that their generation facilities are expected to maintain enough diesel fuel to run the units for an order cycle of fuel. Fuel supply or delivery problems during the projected winter are not anticipated, as coal demand is expected to be somewhat lower in 2009/2010 and general demand for rail capacity is down as well. Coal stockpiles are adequate to meet peak demand and to accommodate short-term supply disruptions. Sites that have the capability to maintain redundant and diversified fuel supplies will do so in order to be prepared to respond to various emergency and or economic scenarios. Some unit outages were also reported to be mitigated through exchange agreements or alternative fuel sources. Tests are also done to assess various stability-study criterion as well as stressed system scenarios and contingencies. Studies of this type are routinely performed, both internally and through subregional and Regional study group efforts. Stability assessments/criteria are performed and produced on an individual company basis within the VACAR area. Some utilities follow practices such as using a reactive power supply operating strategy based on adopted generating station voltage schedules and electric system operating voltages managed through real-time Reactive Area Control Error (RACE) calculations. Through this operating practice, primary support of generator switchyard bus voltage schedules using transmission system reactive resources, dynamic reactive capability of spinning generators may be held in reserve to provide near-instantaneous support in the event of a transmission system disturbance. Other utilities may develop Reactive Transfer Interfaces to ensure sufficient dynamic MVAR reserve in load centers that rely on economic imports to serve load. Day-ahead and real-time Security Analysis ensure sufficient generation is scheduled/committed to control pre-/post-contingency voltages and voltage drop criteria within acceptable predetermined limits. Reactive transfer limits are calculated based on a predetermined back-off margin from the last convergent case. System operations around the subregion also track the available static and dynamic reactive reserves in real time via the EMS system as a regular process. Overall, no stability issues have been identified as impacting reliability during the 2009/2010 winter season. Although no expected reliability impacts are expected to occur this winter season, certain entities have reported that they are taking steps to prevent reliability concerns for the upcoming season. 2009/2010 Winter Reliability Assessment Page 152 Regional Reliability Self-Assessments The following techniques are expected to be used this season to avoid situations that will compromise reliability on the system: ensuring that all forced outages have a short duration, focus on maintaining adequate reserves, prepare and review seasonal assessment studies configured to peak loading conditions, pre-arranging construction schedules, and taking steps to mitigate risks. Page 153 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments SPP Regional Assessment Summary 2009/2010 Winter Projected Peak Demand MW On-Peak Capacity by Fuel Type Total Internal Demand 32,636 Dual Direct Control Load Management 33 Gas Fuel Contractually Interruptible (Curtailable) 377 43% 7% Critical Peak-Pricing with Control 35 Other Load as a Capacity Resource 203 Net Internal Demand 31,988 Oil 2% Coal 2% Nuclear 2008/2009 Winter Comparison MW % Change 38% 2% 2008/2009 Winter Projected Peak Demand 31,146 2.7% Hydro 2008/2009 Winter Actual Peak Demand 32,809 -2.5% 6% All-Time Winter Peak Demand 32,361 -1.2% 2009/2010 Winter Projected Peak Capacity MW Margin Existing Certain and Net Firm Transactions 49,549 54.9% Deliverable Capacity Resources 49,972 56.2% Prospective Capacity Resources 58,822 83.9% NERC Reference Margin Level - 15.0% Demand Although actual demand is very dependent on the fluctuation of weather and economic conditions, SPP’s forecasted Net Internal Demand is based on 10-year average winter weather. This is similar to a 50/50 forecast, in which the actual weather on the peak winter day is expected to have a 50 percent likelihood of being hotter and a 50 percent likelihood of being cooler than the weather assumed in deriving the load forecast. The SPP RTO does not explicitly address extreme winter conditions in the Region, as SPP is a summer peaking Region with relatively mild winters. However, the Region has a 13.6 percent Reserve Margin to address any such extreme winter weather scenario. The non-coincident Total Internal Demand forecast for the 2009/2010 winter peak is 32,636 MW, a 0.5 percent decrease compared to the 2008/2009 actual winter peak monthly non- coincident Total Internal Demand of 32,809 MW. Actual 2008/2009 winter demand was 2.6 percent higher than the forecasted projection of 31,964 MW for the same period (see Table SPP- 1). In 2009, SPP experienced an increase in demand from the normal forecast due to cooler than expected temperatures throughout the SPP footprint. Table SPP-1: Winter Demand Summary Year Total Demand MW (Forecast) Total Demand MW (Actual) 2008/2009 31,964 32,809 2009/2010 32,636 N/A Forecast data is collected from individual reporting entities as monthly peak values and summed 2009/2010 Winter Reliability Assessment Page 154 Regional Reliability Self-Assessments to produce the SPP RTO’s total forecast. This forecasted data is aggregated to create a non- coincident value for the SPP RTO Region. Each SPP reporting entity also provides its Demand Response program information, then subtracts that value from its load forecast to report the net load forecast. Based on the SPP’s reporting entity inputs, the Region has 377 MW of interruptible demand, 33 MW of load management, 35 MW of critical peak pricing, and 203 MW of load as a capacity resource. Currently, SPP does not have its own Demand Response program in place. Generation The SPP RTO expects to have 59,441 MW of total internal capacity for the 2009/2010 winter season. This consists of Existing-Certain capacity of 48,954 MW, Existing-Other capacity of 9,520 MW, and Future-Planned capacity of 423 MW. The SPP RTO does not forecast any variable capacity resources to come into service during the assessment timeframe. The SPP RTO relies on its reporting entities to submit generation output (portion of variable) towards certain capacity based on historical and actual test data. This data is routinely scrutinized by SPP staff for accuracy. In addition, SPP performs an internal supply adequacy audit every five years to verify and document historical and test data for all capacity resources. The amount of expected on peak variable resources available during the 2009/2010 winter is 70 MW of wind and 2,850 MW of hydro. Guidelines for calculating the expected on peak values are in SPP Criteria 188.8.131.52.g. No biomass capacity is reported for the winter. Hydro capacity within the SPP RTO Region represents a small fraction (approx. 1 percent) of total capacity resources. The SPP RTO’s operations group monitors potential fuel supply limitations for hydro and gas resources by consulting with its generation owning/controlling members at the beginning of each year. It is anticipated that reservoir levels will be sufficient to meet peak and daily energy demands during the 2009/2010 winter season. The SPP RTO footprint has been experiencing normal rainfall and is not forecasted to experience drought-like conditions during the winter season that would prevent the Region from meeting its capacity needs. There are no known or forecasted conditions with the Region that would reduce capacity resources. The SPP RTO does not anticipate significant generating units being out of service or retired during the winter season. Capacity Transactions on Peak The SPP RTO has 1,339 MW of projected imports from firm contracts. None of the import contracts are Liquidated Damage Contracts. SPP has adequate transmission capability to back firm imports with no partial path reservations. The SPP RTO has 744 MW of firm exports for 2009/2010 winter to Regions external to the Region. None of the export contracts are liquidated damage contracts. SPP has adequate transmission capability to back firm exports with no partial path reservations. There are no non-firm contracts for the upcoming winter season. Page 155 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments SPP RTO members, along with neighboring entities such as Entergy from the SERC Region, have a Reserve Sharing Group. Members can receive contingency reserve assistance from other SPP Reserve Sharing Group members. The SPP’s Operating Reliability Working Group sets the minimum daily contingency reserve requirement for the SPP Reserve Sharing Group. The SPP Reserve Sharing Group maintains a minimum first contingency reserve equal to the generating capacity of the largest unit scheduled to be on-line. Transmission The SPP RTO has five projects that are either under construction or were put in-service since the end of winter 2008/2009. There are no concerns about meeting target in-service dates. There are two new lines in New Mexico: a 16.3 mile 230 kV line from Potash to Pecos, and a 17.5 mile 230 kV line from Seven Rivers to Pecos. Details of these two projects can be found in Table SPP-2. Table SPP-2: Transmission Additions Transmission Project Name Voltage Length In-Service Description / Status (kV) (miles) Date Potash Junction to Pecos 230 16.3 06/01/09 New 230kV line Seven Rivers to Pecos 230 17.5 06/01/09 New 230kV lines There is a new transformer at the Pecos Interchange to increase voltage from 138 kV to 230 kV. At the Iatan substation south of Kansas City, Missouri a new sub (345/161) is planned to be installed as part of Iatan unit #2. There are also plans to install a new 345/115 transformer at Stranger Creek located northeast of Kansas City. The SPP RTO continues to participate in the ERAG MRSWS (Eastern Interconnection Reliability Assessment Group MRO, RFC, SERC West and SPP) inter-regional assessment. The ERAG Steering Committee concluded that in 2009 the group will conduct a long-term 2014 summer study and will use 2008/2009 winter study results for this year’s assessment. The 2008/2009 winter study results indicated adequate import capability into SPP Region. There is no known transmission planned to be out-of-service during the 2009/2010 winter season that would affect Regional reliability. No transmission constraints that could significantly impact reliability have been identified for intraregional transmission transfer capability. From a reliability perspective, SPP expects the transfer capability for imports and exports to be adequate. Operational Issues The SPP RTO formed the Wind Integration Task Force (WITF) in January 2009. The WITF is conducting and reviewing studies to determine the impact of integrating wind generation into SPP’s transmission system and energy markets. These impacts include both planning and operational issues. The WITF report should lead to recommendations for developing new tools SPP needs to properly evaluate requests for interconnecting wind generating resources to the transmission system. The result of the WITF report is expected in the first quarter of 2010. SPP 2009/2010 Winter Reliability Assessment Page 156 Regional Reliability Self-Assessments RTO members are not conducting any other special operating studies at this time. SPP does not have a high level of Demand Response resources so there are no known reliability concerns. Due to the integration of potential variable resources, additional data collection and situational awareness tools have been put in place to begin assessing regulation and spinning reserve needs. Within the SPP Region there are no scheduled maintenance outages of operational concern that will impact reliability during the 2009/2010 winter months. SPP operations staff does not anticipate any environmental and/or regulatory restrictions that could potentially impact reliability. There are no unusual operating conditions for the 2009/2010 winter as a result of flowgate analysis. Reliability Assessment Analysis SPP Criteria requires members to maintain a minimum Reserve Margin of 13.6 percent. The SPP Reserve Margin based on certain resources is forecasted to be 54.9 percent for 2009/2010 winter, which exceeds the SPP minimal Reserve Margin criteria107. SPP’s projected 2009/2010 Reserve Margin is 54.9 percent, compared to the 2008/2009 Reserve Margin of 47 percent. SPP RTO staff recently completed Loss-of-Load Expectation (LOLE) and Expected Unserved Energy studies. Results of these studies indicated some potential concerns during the summer peak of 2011 conditions in the western part of the SPP system. Based on inputs received from SPP members in that part of the footprint, the SPP RTO conducted a sensitivity analysis with wind penetration. Many different mitigation options were examined to address this issue. As a near-term mitigation plan, emergency import across DC ties will lower the LOLE number to an acceptable level (i.e. less than one day in 10 years). In addition, SPP members in this area anticipate an ATC increase on the SPS North-South Flowgate, as some transmission and generation has recently been added. The long-term solution includes construction of a 345 kV line from Mooreland-Woodward District EHV–Tuco. This project has been approved by the SPP Board of Directors as a part of a Balanced Portfolio of transmission projects.108 Historically, the SPP RTO has adhered to a 13.6 percent Reserve Margin to ensure that the minimum LOLE of one day in 10 years is met. This 13.6 percent Reserve Margin requirement is checked annually in EIA-411 reporting as well as through supply adequacy audits of SPP members that are conducted every five years. The last supply adequacy audit was conducted in 2007. Due to future transmission expansion and possible imports from the Western Interconnection, SPP does not foresee the need to raise the Reserve Margin above 13.6 percent at this time. Due to the SPP RTO’s diverse generation portfolio, there is no concern about fuel supply being affected by winter weather extremes. If a fuel shortage is expected, it is communicated to SPP RTO operations staff in advance so they can take appropriate measures. In such a situation, the SPP RTO would assess if capacity or reserves would become insufficient due to unavailable generation. If so, SPP would declare either an EEA (Energy Emergency Alert) or OEC (Other Extreme Contingency) and post as needed on the RCIS (Reliability Coordinator Information System). 107 http://www.spp.org/publications/Criteria07282009-with%20AppendicesCurrent.pdf 108 http://www.spp.org/publications/2009%20Balanced%20Portfolio%20-%20Final%20Approved%20Report.pdf Page 157 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments The SPP RTO develops an annual SPP Transmission Expansion Plan (STEP) that includes a Regional group of transmission expansion projects needed to address system reliability needs for the next 10 years (2009/2010 through 2018/19). The latest STEP approved by the SPP Board of Directors is available on the Engineering section of SPP.org109. In addition to STEP process, SPP performs a dynamic stability analysis. The dynamic study completed for the 2009/2010 winter operating condition did not indicate any dynamic stability issues for the SPP RTO Region. The SPP RTO also performs an annual review of reactive reserve requirements for load pockets within the Region. SPP does not have specific criteria for maintaining minimum dynamic reactive requirement or transient voltage dip criteria. However, according to the reactive requirement study scope, which is completed as a STEP process, each load pocket or constrained area was studied to verify that sufficient reactive reserves are available to cover loss of the largest unit. The STEP did not indicate any dynamic or static reactive power limited areas on the bulk power system. SPP has not conducted an investigation on small signal damping. SPP has an under-voltage load shedding program in western Arkansas within the AEP-West footprint. This program targets about 140 MW of load shed during peak winter conditions to protect the bulk power system against under-voltage events. Because SPP is summer peaking Region, it does not conduct an operation planning study to evaluate extreme cold weather conditions. SPP’s capacity (reserve) margin criteria is intended to address the load forecast uncertainty. Other Region-Specific Issues The western part of the SPP Region continues to see a surge in wind development. Although wind–generated capacity is currently only a small fraction of the total Region capacity (approximately two percent) SPP will begin monitoring operational issues this winter, especially in the western part of the SPP RTO footprint. In the coming years, the SPP RTO will develop additional criteria, such as requiring voltage support, to handle issues native to variable wind farm operations. Region Description The Southwest Power Pool (SPP) RTO Region covers a geographic area of 370,000 square miles and has members in nine states: Arkansas, Kansas, Louisiana, Missouri, Mississippi, Nebraska, New Mexico, Oklahoma, and Texas. SPP manages transmission in eight of those states. SPP’s RTO footprint includes 29 balancing authorities and 47,000 miles of transmission lines. The SPP RTO has 54 members that serve over 5 million customers. SPP’s RTO membership consists of 12 investor– owned utilities, 11 generation and transmission cooperatives, 10 power marketers, 9 municipal systems, 5 independent power producers, 4 state authorities, and 3 independent transmission companies. SPP experiences its peak annual demand in the summer. Additional information can be found on the SPP Web site at http://www.spp.org. 70 http://www.spp.org/publications/2007%20SPP%20Transmission%20Expansion%20Plan%2020080131_BOD_Public.pdf 2009/2010 Winter Reliability Assessment Page 158 Regional Reliability Self-Assessments WECC Regional Assessment Summary 2009/2010 Winter Projected Peak Demand MW On-Peak Capacity by Fuel Type Total Internal Demand 133,864 Dual Direct Control Load Management 654 Fuel Gas Contractually Interruptible (Curtailable) 1,913 37% 6% Other Critical Peak-Pricing with Control 5 4% Load as a Capacity Resource 217 Coal Net Internal Demand 131,075 Pumped 18% Storage 2008/2009 Winter Comparison MW % Change Hydro 2% 2008/2009 Winter Projected Peak Demand 136,515 -4.0% 28% Nuclear 2008/2009 Winter Actual Peak Demand 136,592 -4.0% 5% All-Time Winter Peak Demand 136,592 -4.0% 2009/2010 Winter Projected Peak Capacity MW Margin Existing Certain and Net Firm Transactions 193,940 48.0% Deliverable Capacity Resources 197,834 50.9% Prospective Capacity Resources 197,834 50.9% NERC Reference Margin Level - 16.1% Western Electricity Coordinating Council (WECC) is one of eight electric reliability councils in North America. WECC is responsible for coordinating and promoting bulk electric system reliability in the Western Interconnection. WECC ensures open and nondiscriminatory transmission access among its members, provides a forum for resolving transmission access disputes, and provides an environment for coordinating the operating and planning activities of its members as set forth in the WECC Bylaws. WECC is geographically the largest and most diverse of the eight Regional Entities that have Delegation Agreements with the North American Electric Reliability Corporation (NERC). WECC’s service territory extends from Canada to Mexico. It includes the provinces of Alberta and British Columbia in Canada, the northern portion of Baja California in Mexico, and all or portions of the 14 Western states in between. Due to the vast and diverse characteristics of the Region, WECC and its members face unique challenges in coordinating the day-to-day interconnected system operation and the long-range planning needed to provide reliable electric service across nearly 1.8 million square miles. WECC is divided into four subregions: The Northwest Power Pool (NWPP), the Rocky Mountain Power Area (RMPA), the Arizona-New Mexico-Southern Nevada Area (AZ-NM- SNV) and the California-Mexico Power Area (CAMX). The NWPP is a winter peaking subregion with a large amount of hydro resources. Because it is winter peaking, the NWPP is the main focus of this winter assessment. The RMPA’s peak can occur in either the summer or Page 159 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments the winter, and it has a large amount of coal generation. The AZ-NM-SNV and the CAMX subregions peak in the summer and the majority of their resources are gas fired. WECC expects to have adequate generation capacity, reserves, and transmission for the forecasted 2009/2010 winter peak demands and energy loads. This is attributed to the combination of a lower demand forecast, additional generation resources, and transmission system enhancements. Demand The aggregate WECC 2009/2010 winter Total Internal Demand is forecast to be 133,864 MW (U.S. systems 110,921 MW, Canadian systems 21,548 MW, and Mexican system 1,395 MW) and is projected to occur in December 2009. The forecast is based on normal weather and reflects generally adverse economic conditions. The forecast is 2.0 percent below last winter’s actual peak demand which was established under generally above normal temperatures in the Region. The 2009/2010 winter Total Internal Demand forecast is 3.8 percent less than last winter’s forecast peak demand of 139,135 MW for winter 2008/2009. WECC REGION & SUBREGION GROWTH RATES WINTER PEAK WECC NWPP RMPA AZ-NM-SNV CA/MX 2008/2009 Forecast 139,135 62,689 10,529 19,508 46,565 2008/2009 Actual 136,592 65,660 10,298 17,992 42,919 Difference (MW) -2,543 2,971 -231 -1,516 -3,646 Difference % -1.83% 4.74% -2.19% -7.77% -7.83% 2008/2009 Actual 136,592 65,660 10,298 17,992 42,919 2009/2010 Forecast 133,864 62,215 9,859 18,880 43,226 Difference (MW) -2,728 -3,445 -439 888 307 Difference % -2.00% -5.25% -4.26% 4.94% 0.72% 2008/2009 Forecast 139,135 62,689 10,529 19,508 46,565 2009/2010 Forecast 133,864 62,215 9,859 18,880 43,226 Difference (MW) -5,271 -474 -670 -628 -3,339 Difference % -3.79% -0.76% -6.36% -3.22% -7.17% Note: All actual and forecast loads are monthly non-coincident WECC specifically directs its balancing authorities (BAs) to submit forecasts with a 50 percent probability of occurrence. These forecasts generally consider various factors such as population growth, economic conditions and normalized weather so that there is a 50 percent probability of exceeding the forecast. The internal peak demand forecasts presented here are non-coincident sums of the forecasted demands from WECC’s load-serving BAs. Comparisons with hourly demand data indicate that WECC non-coincident peak demands generally exceed coincident peak demands by two to four percent. The peak demand forecasting methods used by entities vary widely and range from not making any weather or economic assumptions to using a combination of the EPRI-developed Residential End-Use Energy Planning System (REEPS) and the Commercial End-Use Model (COMMEND) to forecast the commercial sector energy demands by end-use and then using an 2009/2010 Winter Reliability Assessment Page 160 Regional Reliability Self-Assessments econometric method by major Standard Industrial Classification codes. WECC does not assess the demand forecasting methods of the various entities. Energy efficiency programs vary by location and are generally offered by the Load Serving Entity (LSE). Programs include: ENERGY STAR builder incentive programs, business lighting rebate programs, retail compact fluorescent light bulb (CFL) programs, home efficiency assistance programs, and programs to identify and develop ways to streamline energy use in agriculture, manufacturing, water systems, etc. For purposes of verification, some LSEs retain independent third parties to evaluate their programs. Demand-side management (DSM) programs offered by BAs or LSEs vary widely. The 2009/2010 internal demand forecast includes 654 MW of direct control load management, 1,913 MW of interruptible demand capability, 217 MW of load as a capacity resource and 5 MW of critical-peak-pricing with control. Direct control load management programs largely focus on air conditioner cycling programs while interruptible demand programs are focused primarily on large water pumping operations and large industrial operations such as mining. For a variety of reasons, the winter forecast DSM of 2,789 MW is 263 MW less than the DSM forecast for last winter. Approximately 68 percent of the total DSM is located in California and most of the DSM decline occurred in California. Each LSE is responsible for verifying the accuracy of its DSM and energy efficiency programs. Methods for verification include: Direct end-use metering, sample end-use metering, and baseline comparisons of metered demand and use. Generation For the peak winter month of December, WECC expects a Reserve Margin of 50.9 percent (66,759 MW), which significantly exceeds this year’s supply adequacy model planning Reserve Margin of about 16.1 percent. The net capacity resources for this winter are expected to be 197,834 MW compared to 185,758 MW for winter 2008/2009. The net capacity resources include no firm capacity transactions with Regions external to WECC. No significant generating units are scheduled to be out of service or retired during the winter period. The following table presents the existing and planned resources through the end of the winter period. Existing and Potential Resources (WECC through February, 2010) Existing-Certain Existing-Other Future-Planned (MW) (MW) & Other (MW) Total On-Peak Resources 189,395 5,584 Conventional Expected On-Peak 126,707 4,487 Wind Expected On-Peak 2,063 470 Solar Expected On-Peak 87 314 Hydro Expected On-Peak 58,852 84 Biomass Expected On-Peak 1,686 229 Derates 14,572 4,404 Wind Derate On-Peak 6,782 2,883 Solar Derate On-Peak 470 1,484 Hydro Derate On-Peak 7,028 0 Biomass Derate On-Peak 292 37 Existing, Inoperable 0 0 0 Page 161 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments The projected hydro levels for the 2009/2010 winter season are below normal, but the hydro generation is expected to be sufficient to meet the winter peak demands and energy loads. Hydro resources have been derated to reflect low hydro conditions, and are not expected to have any further impact on margins. WECC does not analyze possible fuel supply interruption. Historically, coal-fired plants have been built at or near their fuel source and generally have long-term fuel contracts with the mine operators, or actually own the mines. Gas-fired plants are historically located near major load centers and rely on relatively abundant western gas supplies. Many of the older gas-fired generators in the Region have backup fuel capability and normally carry an inventory of backup fuel, 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. Some of the WECC entities have taken steps to mitigate possible fuel supply vulnerabilities through obtaining long-term, firm transport capacity on gas lines, having multiple pipeline services, natural gas storage, back-up oil supplies, maintaining adequate coal supplies or acquiring purchase power agreements for periods of possible adverse hydro conditions. A survey of major power plant operators indicates that their natural gas supplies largely come from the San Juan Basin in northwest New Mexico and the Permian Basin in western Texas, from the gas fields in the Rocky Mountains, and from the Sedimentary Basin in western Canada. Individual entities may have fuel supply interruption mitigation procedures in place, including on-site coal storage facilities. Extreme winter weather during peak load conditions is not expected to have a significant impact on the fuel supply. Capacity Transactions on Peak Some WECC entities rely heavily on short-term power markets, generally using the Western System Power Pool (WSPP) contracts. The WSPP Agreement is a set of FERC-approved standardized power sales contracts used by jurisdictional and non-jurisdictional entities. The most commonly used WSPP contract is the firm capacity/ energy sale or exchange, which contains liquidated damage (LD) provisions and is heavily relied upon as the template for such transactions. These contracts do not reference specific generating units or a system of units, and LDs are the only remedy for non-delivery. This assessment does not include firm capacity transactions with entities located in the Eastern Interconnection. However, the individual subregion resources include firm transfers between subregions within WECC. These transfers represent assumed firm purchases and/or sales and plant contingent transfers from one subregion to another. The plant contingent transfers usually have transmission rights associated with them. Most balancing authorities are associated with one to the three reserve sharing groups within WECC. These reserve sharing groups do not cross the WECC Regional boundary and do not rely on outside assistance from other Regions for emergency imports. Transmission WECC and subregional entities have processes in place to assess generation deliverability. WECC prepares an annual power supply assessment that is designed to identify major load zones 2009/2010 Winter Reliability Assessment Page 162 Regional Reliability Self-Assessments within the Region that may experience load curtailments due to physically-constrained paths and internal resource limitations. In addition, extensive operating studies are prepared that model the transmission system under a number of load and resource scenarios, and operating procedures are developed to maintain safe and reliable operations. Also, major power system operators have internal processes for identifying and addressing local area resource limitations, and independent grid operators have formal procedures for obtaining reliability must run capability, including voltage support capability, for resource-constrained areas. The resources reported in this assessment have been reduced by 25 MW to reflect deliverability constraints identified by transfer capability studies, interconnection agreement studies, etc. 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. Operational Issues WECC does not expect any major scheduled generating unit outages, transmission facility outages, or unusual operating conditions that would adversely impact reliable operations this winter. The BAs and Planning Authorities coordinate the planning of long range scheduled maintenance outages. This assures that there is sufficient generation availability during scheduled transmission outages and that there is sufficient transmission availability during scheduled generation outages to access other resources. No environmental or regulatory restrictions have been reported that are expected to adversely impact reliability. The integration of wind generation will continue to require modifications to the way system operators dispatch generation resources in order to provide sufficient operating flexibility. WECC does not anticipate reliability issues related to renewables generation during minimum demand periods and does not anticipate reliability issues related to high levels of Demand Response resources. Reliability Assessment Analysis For the winter assessment, WECC requested information from its Balancing Authorities (BAs) about any studies they have performed for the winter assessment period. WECC also requests BAs to update any applicable data (actual loads, forecasts, outages, future and existing resource status changes) that have been previously submitted to WECC. The submitted information and data is then reviewed and compiled into the resulting resource assessment for the WECC Region and subregions. The loads and resources are compared against the target Reserve Margins that were developed for WECC’s Power Supply Assessment110 (PSA) and WECC’s Long Term Reliability Assessment111 (LTRA). The target Reserve Margins were developed using a building block method for developing Planning Reserve Margins. The building block approach has four elements: contingency reserves, regulating reserves, reserves for additional forced outages, and reserves for 1-in-10 weather events. The building block values were developed for each 110 WECC Power Supply Assessment 111 WECC Long Term Reliability Assessment Page 163 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments balancing authority and then aggregated by subregions and the entire WECC for the PSA, LTRA and the seasonal assessment analyses. The aggregated winter season Planning Reserve Margin target for WECC was 16.06 percent. This Reserve Margin maybe lower or higher than some of the state, provincial or Load Serving Entity requirements within WECC, but was developed specifically for use in the above mentioned assessments. Individual entities within the Western Interconnection have established generator interconnection requirements that include power flow and stability studies to identify adverse impacts from proposed projects. In addition, WECC has established a review procedure that is applied to larger transmission projects that could impact the interconnected system. The details of this review procedure are located in Section III of the WECC Planning Coordinating Committee’s Handbook. These processes identify potential deliverability issues that may result in actions such as the implementation of system protection schemes designed to enhance deliverability and to mitigate possible adverse power system conditions. Transmission Providers use the method and criteria contained in the appropriate standards including WECC Standard TOP-STD-007-0- Operating Transfer Capability and FAC-012-1- Transfer Capability Methodology. Each of WECC’s transmission authorities or transmission planners performs reliability studies on its own system and compares the study results to NERC and/or WECC standards. As mentioned earlier in the transmission section, WECC staff and the System Review Working Group help develop various base cases and studies as reported in the Annual Study Report. As part of the studies, WECC staff performs selective transient dynamics and post-transient analyses on the base cases and publishes the analyses in WECC’s Annual Study Report. WECC’s Annual Study Program provides an assessment of the transmission system in the Western Interconnection and helps support compliance with the following requirements in the NERC Reliability Standards relating to reliability assessment, Special Protection Schemes, and system data: • MOD 010,012 – Steady State and Dynamics Data for Transmission System Modeling and Simulation • FAC 005 – Electrical Facility Ratings for System Modeling • PRC 006 – UFLS Dynamics Data Base • PRC 014 – Special Protection System Assessment • PRC 020 – UVLS Dynamics Data Base • TPL 001-004 – Transmission Planning (System Performance) If the study results do not meet expected performance levels established in the criteria, the responsible organizations are obligated to provide a written response that specifies how and when they expect to achieve compliance with the criteria. Other measures that have been implemented to reduce the likelihood of widespread system disturbances include: an islanding scheme for loss of the AC Pacific Intertie that separates the Western Interconnection into two islands and drops load in the generation-deficit southern island; a coordinated off-nominal frequency load shedding and restoration plan; measures to maintain voltage stability; a 2009/2010 Winter Reliability Assessment Page 164 Regional Reliability Self-Assessments comprehensive generator testing program; enhancements to the processes for conducting system studies; and a reliability management system. Operating studies are reviewed to ensure that simultaneous transfer limitations of critical transmission paths are identified and managed through nomograms and operating procedures. Four subregional study groups prepare seasonal transfer capability studies for all major paths in a coordinated subregional approach for submission to WECC’s Operating Transfer Capability Policy Committee. On the basis of these ongoing activities, transmission system reliability within the Western Interconnection is expected to meet NERC and WECC standards. Page 165 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments Rocky Mountain Power Area (RMPA) The Rocky Mountain Power Area’s (RMPA) peak demand may occur in either summer or winter. The 2009/2010 winter peak demand of 9,859 MW is projected to occur in December and is 4.3 percent less than last winter’s actual peak demand of 10,298 MW, which occurred in December. The 2009/2010 winter peak forecast is 6.4 percent less than last winter’s projected forecast peak demand of 10,529 MW which was projected to occur in December 2008. The expected load growth decline for the 2009/2010 winter season is largely attributed to the economic decline that has affected the area. Last winter’s peak demand was 2.2 percent less than the forecast peak demand. For the 2009/2010 winter period, direct control load management demand, contractually interruptible demand, critical peak-priding with control demand and load as a capacity resources demand total 179MW. The projected Reserve Margin for the peak month is 46.9 percent. Hydro conditions for the 2009/2010 winter period are expected to be below normal but the reservoir releases should be similar to last year. The following table presents the existing and planned resources through the end of the winter period. Existing and Potential Resources (RMPA through February, 2010) Existing- Existing- Future- Certain Other Planned & (MW) (MW) Other (MW) Total On-Peak Resources 13,279 1,092 Conventional Expected On-Peak 11,956 1,073 Wind Expected On-Peak 137 19 Solar Expected On-Peak 0 0 Hydro Expected On-Peak 1,183 0 Biomass Expected On-Peak 3 0 Derates 1,102 168 Wind Derate On-Peak 972 131 Solar Derate On-Peak 8 0 Hydro Derate On-Peak 122 0 Biomass Derate On-Peak 0 37 Existing, Inoperable 0 0 0 The transmission system is expected to be adequate for all firm transfers and most economy energy transfers. However, the transmission path between southeastern Wyoming and Colorado often becomes heavily loaded, as do the transmission interconnections to Utah and New Mexico. WECC’s Unscheduled Flow Mitigation Plan112 may be invoked to provide line loading relief for these paths, if needed. 112 WECC Unscheduled Flow Mitigation Plan 2009/2010 Winter Reliability Assessment Page 166 Regional Reliability Self-Assessments Arizona-New Mexico-Southern Nevada Power Area (AZ-NM-SNV) This is a summer-peaking area. The 2009/2010 winter peak demand of 18,880 MW, which is projected to occur in January, is 4.9 percent above last winter’s actual peak demand of 17,992 MW, which occurred in January. The 2009/2010 peak forecast is 3.2 percent less than last winter’s forecast peak demand of 19,508 MW which was projected to occur in December 2008. Last winter’s peak demand was higher than normal due to cooler temperatures. For the 2009/2010 winter period, direct control load management demand, contractually interruptible demand, critical peak-priding with control demand and load as a capacity resources demand total 692 MW. The projected Reserve Margin for the peak month is 111.0 percent and excludes 25 MW of transmission limited resources. The following table presents the existing and planned resources through the end of the winter period. Existing and Potential Resources (AZ-NM-SNV through February, 2010) Existing- Existing- Future- Certain Other Planned & (MW) (MW) Other (MW) Total On-Peak Resources 38,790 1,190 Conventional Expected On-Peak 34,564 1,190 Wind Expected On-Peak 197 0 Solar Expected On-Peak 22 0 Hydro Expected On-Peak 3,936 0 Biomass Expected On-Peak 71 0 Derates 922 0 Wind Derate On-Peak 213 0 Solar Derate On-Peak 58 0 Hydro Derate On-Peak 651 0 Biomass Derate On-Peak 0 0 Existing, Inoperable 0 0 0 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 winter peak demand and energy load conditions. In addition, firm coal supply and transportation contracts are in place, and sufficient coal inventories are anticipated for the winter season. Page 167 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments California–Mexico Power Area (CA-MX) The California-Mexico power area is a summer-peaking area. The 2009/2010 winter peak demand of 43,226 MW, which is projected to occur in December, is 0.7 percent greater than last winter’s actual peak demand of 42,919 MW and is 7.2 percent less than last winter’s forecast peak demand of 46,565 MW. The areas’ 2008/2009 winter peak demand occurred during a period of generally normal to warmer than normal temperatures and was 7.8 percent below the forecast for that month. For the 2009/2010 winter period, direct control load management demand, contractually interruptible demand, critical peak-priding with control demand and load as a capacity resources demand total 1,893 MW. The projected Reserve Margin for the peak month is 58.7 percent. California is currently in a low hydro condition with low reservoir levels, but they report they have sufficient resources to meet their winter peak demand and energy resources. The following table presents the existing and planned resources through the end of the winter period. Existing and Potential Resources (CAMX through February, 2010) Existing- Existing- Future- Certain Other Planned & (MW) (MW) Other (MW) Total On-Peak Resources 57,117 2,677 Conventional Expected On-Peak 43,530 1,852 Wind Expected On-Peak 522 283 Solar Expected On-Peak 65 314 Hydro Expected On-Peak 12,262 29 Biomass Expected On-Peak 738 199 Derates 4,664 2,734 Wind Derate On-Peak 2,568 1,234 Solar Derate On-Peak 404 1,484 Hydro Derate On-Peak 1,400 0 Biomass Derate On-Peak 292 16 Existing, Inoperable 0 0 0 Although several major constrained transmission paths have been upgraded in recent years, path constraints can still exist. Operating procedures are in place to manage any high loading conditions that may occur during the winter. 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 during the upcoming winter season. 2009/2010 Winter Reliability Assessment Page 168 Regional Reliability Self-Assessments Northwest Power Pool (NWPP) The Northwest Power Pool (NWPP) area is one of the four subregions of the Western Electricity Coordinating Council (WECC) and is comprised of all or major portions of the states of Washington, Oregon, Idaho, Wyoming, Montana, Nevada, and Utah; a small portion of Northern California; and the Canadian provinces of British Columbia and Alberta. This vast area covers 1.2 million square miles of the WECC’s 1.8 million square miles. The NWPP, in collaboration with it members (18 Balancing Authorities), has conducted an assessment of reliability in response to questions raised regarding the ability of the NWPP to meet the load requirements during the winter 2009/2010. Since the NWPP covers a large and diverse area of the Western Interconnection, its members face unique issues in the day-to-day coordinated operations of the system. The NWPP area in aggregate is a winter peaking subregion with a large amount of hydro resources. Analyses indicate the NWPP area will have adequate generation capacity and energy, required operating reserves (regulating reserve and contingency reserve), and available transmission to meet the forecasted firm loads for the 2009/2010 winter operations, assuming normal ambient temperature and normal weather conditions. This assessment is valid for the NWPP area as a whole. However, these overall results do not necessarily apply to all sub-areas (individual members, balancing authorities, states or provinces) when assessed separately. In 2007, Sacramento Municipal Utility District (SMUD) and Turlock Irrigation District (TID) joined the NWPP and will be fully integrated into the NWPP Reserve Sharing Group for the 2009/2010 winter season. However, for purposes of the 2009/2010 winter assessment, SMUD (Sacramento) and TID (Turlock) are included in the California subregion and not in the NWPP area assessment. The NWPP has a publicly available document on its website that addresses 2009/2010 winter conditions.113 Demand The NWPP 2008/2009 coincidental winter peak demand of 63,435 MW occurred on December 15, 2008. The 2008/2009 coincidental winter peak demand was 104 percent of the forecast; however, the coincidental peak demand occurred during below normal temperature conditions. There is still a large component of electric space heating load within the NWPP area. Normalizing for temperature variance (50 percent probability), the 2008 coincidental peak demand would have been 60,500 MW or 99.18 percent of the forecast. The economic recession that began in 2007 has had an impact on the NWPP power use and future forecasts. The 2009 summer coincident peak demand forecast for the NWPP area was 54,500 MW. The actual was 50,000 MW adjusted for temperature. The recession that has taken place has reduced the NWPP area peak demand by 5 to 10 percent. Historically, the NWPP area lags the economic recovery by approximately one year. 113 That document is available at: http://www.nwpp.org/publications.html. Page 169 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments The 2009/2010 winter coincident peak demand forecast for the NWPP of 59,000 MW is based on normal weather, reflects the prevailing economic climate (down-turn), and has a 50 percent probability of not being exceeded. The NWPP area has approximately 255 MW of interruptible demand capability and load management. In addition, the load forecast incorporates any benefit (load reduction) associated with demand-side resources not controlled by the individual utilities. Some of the entities within the NWPP area have specific programs to manage peak issues during extreme conditions. Normally these programs are used to meet the entities’ operating reserve requirements and have no discernable impacts on the projected NWPP area peak load. Under normal weather conditions, the NWPP area does not anticipate dependence on imports from external areas during winter peak demand periods. However, if much lower than normal precipitation occurs, it may be extremely advantageous to use transfer capabilities from outside the NWPP area to reduce reservoir drafts and aid reservoir filling. Generation Approximately 60 percent of the NWPP resource capability is from hydro generation. The remaining generation resources are conventional thermal plants and miscellaneous resources such as non-utility owned gas-fired cogeneration or wind. The following table presents the existing and planned resources through the end of the winter period. Existing and Potential Resources (NWPP through February, 2010) Existing- Existing- Future- Certain Other Planned & (MW) (MW) Other (MW) Total On-Peak Resources 80,209 625 Conventional Expected On-Peak 36,657 372 Wind Expected On-Peak 1,207 168 Solar Expected On-Peak 0 0 Hydro Expected On-Peak 41,471 55 Biomass Expected On-Peak 874 30 Derates 7,884 1,539 Wind Derate On-Peak 3,029 1,518 Solar Derate On-Peak 0 0 Hydro Derate On-Peak 4,855 0 Biomass Derate On-Peak 0 21 Existing, Inoperable 0 0 0 Hydro Capability – NWPP 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 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 2009/2010 Winter Reliability Assessment Page 170 Regional Reliability Self-Assessments carrying capability, when reservoirs start full. Under Average water year conditions, the additional non-firm energy available is approximately 3,000 average megawatts. The Coordinated System hydro reservoirs refilled to approximately 80 percent of the energy content curve by July 31, 2009. 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; and 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 winter 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 Reserve Margin at time of peak can be calculated to be greater than 20 percent, this can be misleading. Since hydro can be limited due to conditions (either lack of water or imposed restrictions), the expected sustainable capacity must be determined before establishing a representative Reserve Margin. In other words, the firm energy load carrying capability (FELCC) is the amount of energy that the system may be called on to produce on a firm or guaranteed basis during actual operations. The FELCC is highly dependent upon the availability of water for hydroelectric generation. The NWPP 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 greater than two hours during daily peak periods assuming various conditions. This aggregated information yielded a reduction for sustained capability of approximately 7,000 MW. This reduction is more relevant to the Northwest in the winter; however, under summer extreme low water conditions, it impacts summer conditions, too. Thermal Generation Capacity – 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 winter peak period. Wind Generation Capacity – Several states have enacted renewable portfolio standards that will require some NWPP members, by the mid-2010 decade, to satisfy at least 20 percent of their load with energy generated from renewable resources. With the significant increase in variable generation within the NWPP area, new operational issues are arising and will continue to be addressed into the future. Some of the safety net programs such as contingency reserve and under frequency load shedding will be re-evaluated for effectiveness. The NWPP area estimated the installed wind generation capacity for the winter season will be approximately 5,900 MW, contributing about 1,100 MW of capacity on-peak. With the increasing variable generation, conventional operation of the existing hydro and thermal resources will be impacted. Page 171 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments The wind generation manufacturers’ standard operating temperature for wind turbines range from -10° C to + 40° C (14° F to 104° F). During the winter peaking period, the temperature in the areas where the majority of the wind turbines are located can go below 14°F, leaving no capability from the wind generation during those periods. In addition, there is a risk of over- generation in the spring and fall. When both the wind and hydro generation are in high generation mode, and given the environmental constraints on dissolved gases in the river, there are times when desired generation may exceed expected load plus the ability to export. Operating procedures have been introduced to address this situation. Biomass Generation – The installed capacity of biomass generation within the NWPP area is 670 MW with expected on-peak amounts of 895 MW. Other Generation – Within the NWPP area there is an underground natural gas storage facility that is 100 percent full. This storage is located near many of the gas plants located in the NWPP area, minimizing any effect that a Regional gas problem may cause. In addition, one entity in the NWPP area has over 700 MW of generation that can be fired on diesel fuel. External Resources – No reliance on resources external to the NWPP area is assumed for the winter season. However, one BA located in the NWPP area has an exchange agreement with an entity in the California Region for additional energy, up to 300 MW per hour, delivered firm to the BA system. This exchange agreement is for the period November through February with a total potential import of 413,000 MWh. Transmission Several BAs are constructing new transmission within the NWPP area to address load service issues. No significant transmission lines are scheduled to be out-of-service during the winter season. Constrained paths within the NWPP area are known and operating studies modeling these constraints have been performed. As a result of these studies, operating procedures have been developed to assure safe and reliable operations. System Operating Limits (SOL) – The interregional transmission transfer capabilities based on System Operating limits as determined by the Northwest Operational Planning Group have been approved by WECC’s Operating Transfer Capability Policy Committee. These limits recognize transmission or generation constraints in systems external to the Region or subregion. Outage Coordination – The NWPP coordinated outage (transmission) system was designed to assure that outages could be coordinated among all stakeholders (operators, maintenance personnel, transmission users, and operations planners) in an open process. This process had to assure that proper operating studies were accomplished and transmission impacts and limits known, to fulfill a requirement from the 1996 west coast disturbances that the system be operated only under studied conditions. The WECC Reliability Coordinator is involved in the outage coordination process and has direct access to the outage database. 2009/2010 Winter Reliability Assessment Page 172 Regional Reliability Self-Assessments Monthly Coordination – The outage coordination process requires NWPP members to designate significant facilities that, if out of service by itself or in conjunction with another outage, will impact system capabilities. The significant facilities are defined and updated annually by the NWPP members. The scheduled outage of these critical facilities is posted on a common database. All utilities post proposed significant outages on WECC’s Coordinated Outages System (COS). Outages are to be submitted to the COS at least 45 days ahead of the month they are proposed to occur so they can be viewed by interested entities. The involved entities then facilitate the NWPP coordination of all these outages. Entities can comment on the preliminary impacts and schedules may be adjusted to maximize reliability and minimize market impacts. If coincidental outages cause too severe an impact, the requesting utilities work together to adjust schedules accordingly. A final outage plan is posted with estimated path capabilities 30 days prior to the month in which the outages will occur. Detailed operational transfer capability studies are then performed and the limits for each affected path are posted at least 15 days prior to the outage. Emergency outages can be requested outside these schedule guidelines. Emergency outages are coordinated among adjacent utilities to minimize system exposure. Utilities can use the COS system to assure the system topology is correct for the next-day operating studies. As transmission operators increase the number of short term outages in addition to the significant outages, the WECC Reliability Coordinator will be able to access the WECC COS data base and use the final outage schedule in its real-time system analysis. This coordinated outage process has been very effective. The outage information is used by NWPP member utilities to perform system studies to maximize system reliability. Semi-annual planning - Long-Range Significant Outage Planning (LRSOP) – The NWPP staff facilitates outage meetings every six months with each utility’s outage coordinator to discuss proposed longer term outages. Utilities discuss anticipated outages needed for time- critical construction and periods where transmission capacity may need to be maximized. The outages are posted on the WECC COS and on the individual companies’ OASIS sites. Specific responsibilities of LRSOP include: Share outage information with all parties affected by outages of significant equipment (i.e., equipment that affects the transfer capability of rated paths). Information is shared two times each year for a minimum of a six-month period. The first meeting each year coordinates outages for July through December. The second meeting coordinates outages for January through June. Review the outage schedules to assure that needed outages can be reliably accomplished with minimal impact on critical transmission use. Outage coordinators are to post the outages on the Coordinated Outages System within the applicable timeframes. Next-Day Operating Studies – Additional path curtailments may be required depending upon current system conditions and outages. These curtailment studies are performed by the individual path operators based on the outage schedule developed through the COS process. According to the COS process, these studies are performed at least 15 days prior to the outage. Page 173 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments Individual path operators and transmission owners may also perform updated next-day studies to capture emergency outage requests and current system conditions such as generation dispatch to determine if the SOL studies and limits are still accurate. Based on these studies, additional SOL curtailments may be made by the path operators. The modified SOLs are posted on the individual transmission owner’s OASIS and the Reliability Coordinator is notified. The WECC Reliability Coordinator also performs system studies to ensure interconnected system reliability. The WECC Reliability Coordinator performs real-time system thermal studies to evaluate current operating conditions across the entire Interconnection. The WECC Reliability Coordinator is in the process of incorporating real-time voltage tools to complement the thermal analysis currently being performed. Transient stability analysis capability is planned in the future. When the WECC Reliability Coordinator observes real-time reliability problems it contacts the path operator to discuss the issue and work on a solution. The WECC Reliability Coordinator will make a directive for action if there is an imminent reliability threat and the balancing authority does not eliminate the reliability issue within an appropriate time frame. Voltage Stability – The WECC-1-CR System Performance Criteria, requirement WRS3 is used to plan adequate voltage stability margin in the NWPP area as appropriate. Simulations are used to assure system performance is adequate and meets the required criteria. Operational Issues The NWPP area does not anticipate any operating issues for the 2009/2010 winter season. The NWPP has developed an Adequacy Response Process whereby a team addresses the area’s ability to avoid a power emergency by promoting Regional coordination and communications. Essential pieces of that effort include timely analyses of the power situation and communication of that information to all parties including but not limited to utility officials, elected officials and the general public. In the fall of 2000, the area developed an Emergency Response Process to address immediate power emergencies. The 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 NWPP. Reliability Assessment Analysis The NWPP area does not have one explicit method for determining an adequacy margin. Bonneville Power Administration uses the NWPP and Conservation Council’s resource adequacy standard, which establishes targets for both the energy and capacity adequacy metrics derived from a loss of load probability analysis. Others use a Reserve Margin approach. Since no one method exists for the entire NWPP area, the NWPP has elected to use a Reserve Margin analysis for the winter assessment. The 2009/2010 NWPP area generating capability is projected to be 80,000 MW, prior to adjusting for maintenance. In determining planning margin for the current winter season one must further adjust for operating reserve requirement, which is 2009/2010 Winter Reliability Assessment Page 174 Regional Reliability Self-Assessments approximately 4,200 MW. At this point, based on a load of 50 percent probability of not being exceeded, the planning margin is approximately 27 percent. A severe weather event for the entire NWPP area will add approximately 6,000 MW of load while at the same time, under extreme water restrictions, the sustained hydro generation capability would be reduced by 7,000 MW. In addition, under the severe weather, wind generation is expected to be minimal. Accounting for the severe weather event and the operating reserve yields a planning margin of approximately 5 percent. Contingency Reserve Sharing Procedure As permitted by NERC and WECC criteria and standards, the Operating Committee of the NWPP has instituted a Reserve Sharing Program for contingency reserve. The reserve sharing process for the NWPP has been automated. A manual backup process is in place if communication links are down or the computer system for reserve sharing is not functioning correctly. The NWPP is designated as a reserve sharing group (RSG) as provided under WECC Operating Reliability Criteria. Each member of the RSG submits its contingency reserve obligation (CRO) and most severe single contingency (MSSC) to a central computer. The combined member CRO must be larger than the RSG MSSC. If not, then each member’s CRO is proportionally increased until this requirement is met. When any RSG member loses generation they have the right to call upon reserves from the other RSG members as long as they have first committed their own CRO. A request for contingency reserve must be sent within four minutes after the generation loss and the received contingency reserve can only be held for 60 minutes. A request is sent via the member’s energy management system to the central computer. The central computer then distributes the request proportionally among members within the RSG. Each member may be called to provide reserve up to its CRO. Critical transmission paths are monitored in this process to ensure SOL limits are not exceeded. If a transmission path SOL is exceeded the automated program redistributes the request among RSG members that are delivering reserve along non- congested paths. The WECC Reliability Coordinator continuously monitors the adequacy of the RSG reserve obligation, MSSC, and the deployment of reserve. If a reserve request fails due to various reasons, backup procedures are in place to fully address the requirements. Conclusions In view of the present overall power conditions, including the forecasted water condition, the area represented by the NWPP is estimating that it will be able to meet firm loads including the required operating reserve. Should any resources be lost to the area beyond the contingency reserve requirement and or loads are greater than expected as a result of extreme weather, the NWPP area may have to look to alternatives which may include emergency measures to meet obligations. Page 175 2009/2010 Winter Reliability Assessment Regional Reliability Self-Assessments Regional Description WECC’s 243 members, including 37 balancing authorities, represent the entire spectrum of organizations with an interest in the bulk power system. Serving an area of nearly 1.8 million square miles and 71 million people, it is the largest and most diverse of the eight NERC Regional reliability organizations. Additional information regarding WECC can be found on its Web site (www.wecc.biz). AZ/NM/SNV — 230,100 Sq. Mi. RMPA — 167,000 Sq. Mi. CAMX — 156,000 Sq. Mi. NWPP — 1,214,000 Sq. Mi. WECC TOTAL — 1,760,000 Sq. Mi. 2009/2010 Winter Reliability Assessment Page 176 About This Report About This Report The 2009/2010 Winter Reliability Assessment represents NERC’s independent judgment of the reliability of the bulk power system in North America for the 2009/2010 winter season (Table 2).114 The report specifically provides a high-level reliability assessment of 2009/2010 winter resource adequacy and operating reliability, an overview of projected electricity demand growth, Regional highlights, and Regional self-assessments. NERC’s primary objective in providing this assessment is to identify areas of Table B: NERC’s Annual Assessments concern regarding the reliability of the Assessment Outlook Published North American bulk power system and to Summer make recommendations for their remedy Assessment Upcoming season May as needed. The assessment process enables bulk power system users, owners, Long-Term 10 year October and operators to systematically document Assessment their operational preparations for the coming season and exchange vital system Winter Assessment Upcoming season November reliability information. This assessment is prepared by NERC in its capacity as the Electric Reliability Organization.115 NERC cannot order construction of generation or transmission or adopt enforceable standards having that effect, as that authority is explicitly withheld by Section 215 of the U.S. Federal Power Act and similar restrictions in Canada.116 In addition, NERC does not make any projections or draw any conclusions regarding expected electricity prices or the efficiency of electricity markets. Report Preparation NERC prepared the 2009/2010 Winter Reliability Assessment with support from the Reliability Assessment Subcommittee (RAS), which is under the direction of the NERC Planning Committee (PC). The report is based on data and information submitted by each of the eight Regional Entities in September 2009 and updated, as required, throughout the drafting process. Any other data sources consulted by NERC staff in the preparation of this document are identified in the report. NERC’s staff performed detailed data checking on the reference information received by the Regions, as well as review of all self-assessments to form its independent view and assessment of the reliability of the 2009/2010 winter season. NERC also uses an active peer review process in developing reliability assessments. The peer review process takes full advantage of industry subject matter expertise from many sectors of the industry. This process also provides an 114 Bulk power system reliability, as defined in the How NERC Defines Bulk Power System Reliability section of this report, does not include the reliability of the lower voltage distribution systems, which systems account for 80 percent of all electricity supply interruptions to end-use customers. 115 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.” 116 http://frwebgate.access.gpo.gov/cgi-bin/getdoc.cgi?dbname=109_cong_bills&docid=f:h6enr.txt.pdf Page 177 2009/2010 Winter Reliability Assessment About this Report essential check and balance for ensuring the validity of the information provided by the Regional entities. Each Region prepares a self-assessment, which is assigned to three or four RAS members, including NERC Operating Committee (OC) liaisons, from other Regions for an in-depth and comprehensive review. Reviewer comments are discussed with the Regional Entity’s representative and refinements and adjustments are made as necessary. The Regional self- assessments are then subjected to scrutiny and review by the entire subcommittee. This review ensures members of the subcommittee are fully convinced that each Regional self-assessment is accurate, thorough, and complete. The PC endorses the report for NERC’s Board of Trustee (BOT) approval, considering comments from the OC. The entire document, including the Regional self-assessments, is then reviewed in detail by the Member Representatives Committee (MRC) and NERC management before being submitted to NERC’s BOT for final approval. In the 2009/2010 Winter Reliability Assessment, the baseline information on future electricity supply and demand is based on several assumptions:117 Supply and demand projections are based on industry forecasts submitted in September 2009. Any subsequent demand forecast or resource plan changes may not be fully represented. Peak demand and Reserve Margins are based on average weather conditions and assumed forecast economic activity at the time of submittal. Weather variability is discussed in each Region’s self-assessment. Generating and transmission equipment will perform at historical availability levels. Future generation and transmission facilities are commissioned and in-service as planned; planned outages take place as scheduled. Demand reductions expected from Demand Response programs will yield the forecast results, if they are called on. Other peak Demand-Side Management programs are reflected in the forecasts of Net Internal Demand. Enhancements to the 2009/2010 Winter Reliability Assessment In light of the guidance in FERC’s Order 672 and comments received from other authorities and industry representatives, NERC’s Planning Committee (PC) concluded the Seasonal and Long- Term Reliability Assessment processes required improvement. To achieve this goal, the PC formed a task force, the Reliability Assessment Improvement Task Force, and directed it to develop recommendations and a plan for improvement. 117 Forecasts cannot precisely predict the future. Instead, many forecasts report probabilities with a range of possible outcomes. For example, each Regional demand projection is assumed to represent the expected midpoint of possible future outcomes. This means that a future year’s actual demand may deviate from the projection due to the inherent variability of the key factors that drive electrical use, such as weather. In the case of the NERC Regional projections, there is a 50 percent probability that actual demand will be higher than the forecast midpoint and a 50 percent probability that it will be lower (50/50 forecast). 2009/2010 Winter Reliability Assessment Page 178 About This Report A number of the task force’s recommendations118 were incorporated into the 2009/2010 Winter Reliability Assessment, including: 1. The Reliability Assessment Guidebook Task Force released its Reliability Assessment Guidebook (Version 1.2),119 to provide increased transparency on the reliability assessments process, resource reporting, load forecasting, and general assumptions made in NERC’s Assessments. Regions referenced the guidebook to enhance their contributions to this report. 2. In order to improve data accuracy, NERC has implemented improved data checking methods. A brief summary of these data checking methods is summarized in the Data Checking Methods Applied Section. 3. In order to broaden stakeholder input, OC involvement was incorporated to support the assessment development and approval process. 4. Supply categories have been enhanced to better assess capacity. Notably, this assessment uses the following supply categories: “Existing-Certain,” “Existing-Other” and “Existing, but Inoperable.” A brief summary of these terms are provided in the Resources, Demand and Reserve Margins Section. 5. “Reserve Margin” replaced “Capacity Margin” used in the 2008/2009 Winter Assessment to be consistent with industry practices and reduce confusion. An explanation for this change is provided in the Capacity Margin to Reserve Margin Changes Section. Report Content Responsibility The following NERC industry groups have collaborated efforts to produce NERC’s 2009/2010 Winter Reliability Assessment: NERC Group Relationship Contribution Planning Committee (PC) Reports to NERC’s Review Assessment and Board of Trustees Endorse Operating Committee (OC) Reports to NERC’s Review Assessment and Board of Trustees provide comments to PC Reliability Assessment Reports to the PC Provide Regional Subcommittee (RAS) Self-Assessments Peer Reviews Review Report Reliability Assessment Reports to the PC Develop Reliability Guidebook Task Force Assessment Guidebook (RAGTF) Data Coordination Working Reports to the RAS Develop data and Regional Group (DCWG) reliability narrative requests Board of Trustees NERC’s Independent ● Review Assessment Board ● Approve for publication 118 See http://www.nerc.com/files/Reliability%20Improvement%20Report%20RAITF%20100208.pdf 119 For the Reliability Assessment Guidebook, Version 1.2, see http://www.nerc.com/docs/pc/ragtf/Reliability_Assessment_%20Guidebook%20v1.2%20031909.pdf Page 179 2009/2010 Winter Reliability Assessment Reliability Concepts Used in This Report Reliability Concepts Used in This Report How NERC Defines Bulk Power System Reliability NERC defines the reliability of the interconnected BPS in terms of two basic and functional aspects120: Adequacy — is the ability of the electric system to supply the aggregate electric power and energy requirements of the electricity consumers at all times, taking into account scheduled and reasonably expected unscheduled outages of system components. Operating Reliability — is the ability of the electric system to withstand sudden disturbances such as electric short circuits or unanticipated loss of system components. Regarding adequacy, system operators can and should take “controlled” actions or procedures to maintain a continual balance between supply and demand within a balancing area (formerly control area). These actions include: Public appeals. Interruptible demand — demand that the end-use customer makes available to its LSE via contract or agreement for curtailment.121 Voltage reductions (sometimes referred to as “brownouts” because incandescent lights will dim as voltage is lowered, sometimes as much as 5 percent). Rotating blackouts — the term “rotating” is used because each set of distribution feeders is interrupted for a limited time, typically 20–30 minutes, and then those feeders are put back in service and another set is interrupted, and so on, rotating the outages among individual feeders. Under the heading of Operating Reliability, are all other system disturbances that result in the unplanned and/or uncontrolled interruption of customer demand, regardless of cause. When these interruptions are contained within a localized area, they are considered unplanned interruptions or disturbances. When they spread over a wide area of the grid, they are referred to as “cascading blackouts” — the uncontrolled successive loss of system elements triggered by an incident at any location. 120 See http://www.nerc.com/docs/pc/Definition-of-ALR-approved-at-Dec-07-OC-PC-mtgs.pdf more information about the Adequate Level of Reliability (ALR). 121 Interruptible Demand (or Interruptible Load) is a term used in NERC Reliability Standards. See Glossary of Terms Used in Reliability Standards, February 12, 2008, at http://www.nerc.com/files/Glossary_12Feb08.pdf. 2009/2010 Winter Reliability Assessment Page 180 Reliability Concepts Used in This Report Demand Response Concepts and Categorization As the industry’s use of Demand-Side Management (DSM) evolves, NERC’s data collection and reliability assessment need to change highlighting programs and demand-side service offerings that have an impact on bulk system reliability. NERC’s seasonal and long-term reliability assessments currently assume projected energy efficiency EE programs are included in the Total Internal Demand forecasts, including adjustments for utility indirect Demand Response programs such as conservation programs, improvements in efficiency of electric energy use, rate incentives, and rebates. DSM involves all activities or programs undertaken to influence the amount and timing of electricity use (See Figure Demand 1). Note the context of these activities and programs is DSM, rather than bulk power systems and, therefore, they are not meant to mirror those used in the system context. The Demand Response categories defined in Terms Used in this Report support Figure Demand 1 Figure Demand 1: Demand-Side Management and NERC’s Data Collection Demand-Side Management (DSM) Demand Response (DR) New Energy Efficiency Dispatchable Non-Dispatchable Controllable Economic Time-Sensitive Pricing Energy- Time-of-Use Capacity Ancillary Voluntary Energy-Price Critical Peak Pricing Direct Demand Load Spinning Emergency Bidding & Control Reserves Real Time Pricing Buyback Interruptible Non-Spin System Peak Response Demand Reserves Transmission Tariff Critical Peak Regulation Future Areas of Interest Pricing w/Control NERC Inaugurated Projected Load as a DR Data Collection in 2008 Capacity Resource . Page 181 2009/2010 Winter Reliability Assessment Data Checking Methods Applied Data Checking Methods Applied NERC's Reliability Assessment Data Validation and Error Checking Program ensures the Reliability Assessment Database operates with consistent data. It uses routines, often called “validation rules,” that check for correctness, meaningfulness, and security of data that are added into the system. Internal data checking and validation refers to the practice of validating and checking data through internal processes (e.g., Historical Comparison, Range and Limits, Data Entry Completeness, Correct Summations) to maintain high quality data (See Table Data Checking 1). The rules are implemented through automated processes — data dictionary for data checking and logic for validation. Incorrect data can lead to data corruption or a loss of data integrity. Data validation verifies it is valid, sensible, and secure before it is processed for analysis. The program uses scripts, developed on a composite Microsoft Excel and Microsoft Access platform, to provide a semi-automated solution. Table Data Checking 1: NERC Data Quality Framework and Attributes Data Quality Attribute Responsible Entity Data Check Performed Accuracy Industry Validation rules Ensure data are the correct Consistent with other values external sources Accessibility DCWG, NERC, and RE Data is submitted in the Data items should be easily provided template obtainable and in a usable format Comprehensiveness DCWG, RE, and Check for null values All required data items are Stakeholders Compare to prior year’s submitted null values Inquiries to the RE Currentness RE and Stakeholders Consistent with other The data should be up-to-date external sources Consistency DCWG, NERC DCWG leads in Definitions of the data elements this effort should be the same across Assumptions are different reporting entities verified with the RE Definition DCWG, NERC Staff The DCWG leads in Clear definitions should be this effort provided so the current and future data users can understand the assumptions 2009/2010 Winter Reliability Assessment Page 182 Data Checking Methods Applied In 2009, NERC implemented a two-phase approach to data checking and validation. Phase I is a data collection form-side validation procedure based on defined rules. It also specifies the error type or condition not met. This phase was applied to the data collection forms to prevent the incorrect entry of data and prompts the user with feedback explaining the error. Validation rules are used to ensure entered data meets defined thresholds, ranges, or both. An error halts the input of data until a valid entry is provided. For example, the reported deratings of existing generating units is a subset of the “Existing-Other” supply category; therefore, the sum of all deratings must be less than or equal to the value reported as “Existing-Other.” This example is shown below: Incorrect Correct 6b Existing-Other (Note: The sum of 6b1 through 6b7 must be <= 6b) 5,000 5,000 6b1 Wind Derate On-Peak 800 400 6b2 Solar Derate On-Peak 445 232 6b3 Hydro Derate On-Peak 789 0 6b4 Biomass Derate On-Peak 0 0 6b5 Load as a Capacity Resource Derate On-Peak 0 0 6b6 Energy Only 435 1,345 6b7 Scheduled Outage - Maintenance 4,000 2,398 6b8 Transmission-Limited Resources 0 0 Once data is submitted to NERC, reported values can be analyzed for validity. Phase II of NERC’s data checking and validation effort involves comparing submitted data to historical submissions. For this phase, a back-end database is used to compare key values, such as peak demand projections and installed capacity to what was reported in prior years. Only values with comparable definitions are considered. In addition, a preliminary analysis can identify potential errors. If a potential error is detected, it is flagged and categorized by one of the following error types: Categorization — values may be incorrectly categorized Summation — values are incorrectly summed Double Count — identifies a possible double counting issue Missing Data — key values are null Confirmation — a notable discrepancy which must be confirmed The Reliability Assessment Data Validation and Error Checking Program identifies potential errors and generates a report for further investigation. Thresholds are determined for each value and flagged when a major deviation is determined. For example, peak demand projections must be within a +/- 2 percent threshold to pass; all others are flagged. When errors are identified, NERC staff can send a request for data corrections to the Regional Entities. The Regional Entities then have the opportunity to update their data submittals or explain the flagged error. In addition, NERC’s Data Coordination Working Group (DCWG) monitors the quality of data reported. The DCWG serves as a point of contact responsible for supporting NERC staff, continuously maintaining high quality data and provide enhancements to current practices. Due to improved data checking processes in 2009 and increased coordination between NERC staff and Regional representatives, data errors were minimal for the 2009/2010 Winter Reliability Assessment. Page 183 2009/2010 Winter Reliability Assessment Capacity Margin to Reserve Margin Changes Capacity Margin to Reserve Margin Changes Background The term Reserve Margin is widely used throughout the power industry. However, the word “reserve” engendered much misunderstanding on the part of policy makers. Therefore, the NERC Board of Trustees adopted the use of “Capacity Margin” to measure supply adequacy in 1984. Although NERC adopted the term Capacity Margin (25 years ago), the majority of the power industry continues to use “Reserve Margin.” 122 Discussion The Reliability Assessment Subcommittee (RAS) has reviewed the use of Reserve Margin and Capacity Margin terms. Both terms are used throughout the Long-Term Reliability Assessment and seasonal reliability assessments. This multiple use has caused significant confusion to the readers. In a recent survey conducted by the Resource Issues Subcommittee (RIS), 29 of 38 Planning Authorities (PA) perform their work relying on “Reserve Margin.” In contrast, only one PA referenced “Capacity Margin.” The same survey shows that five of eight Regional Entities reference “Reserve Margin” as the metric they use to measure resource adequacy and while none reference “Capacity Margin.” Since the audience of NERC’s assessments consists of a wide range of readers (including state and local regulatory bodies), industry terms should be consistent. NERC’s goal is to convey reliability assessments in a way that reduces confusion. Since NERC’s focus is to maintain BPS reliability in order to serve customer load and therefore, it is appropriate to express resource margins normalized by customer load (“Reserve Margin”). Approval Upon recommendations from the Figure: Reserve Margin to be Used for Future RAS and RIS, the Planning NERC Reliability Assessments Committee approved the use of “Reserve Margin” in place of Capacity Margin Reserve Margin “Capacity Margin,” on December 3, 2008 for all future reliability (Capacity – Demand) (Capacity – Demand) assessments, beginning with reliability assessments in 2009. Capacity Demand This report uses only Reserve Margin for adequacy assessment. 122 http://www.nerc.com/docs/pc/Updated_PC_Agenda_3-4Dec2008.doc 2009/2010 Winter Reliability Assessment Page 184 Terms Used in This Report Terms Used in This Report Ancillary (Controllable Demand Response) — Demand-side resource displaces generation deployed as operating reserves and/or regulation; penalties are assessed for nonperformance. Capacity (Controllable Demand Response) — Demand-side resource displaces or augments generation for planning and/or operating resource adequacy; penalties are assessed for nonperformance. Capacity Categories — See Existing Generation Resources, Future Generation Resources, and Conceptual Generation Resources. Capacity Margin (%) — See Deliverable Capacity Margin (%) and Prospective Capacity Margin (%). Roughly, Capacity minus Demand, divided by Capacity or (Capacity- Demand)/Capacity. Replaced in 2009 with Reserve Margin(s) (%) for NERC Assessments. Conceptual Generation Resources — This category includes generation resources that are not included in Existing Generation Resources or Future Generation Resources, but have been identified and/or announced on a resource planning basis through one or more of the following sources: 1. Corporate announcement 2. Entered into or is in the early stages of an approval process 3. Is in a generator interconnection (or other) queue for study 4. “Place-holder” generation for use in modeling, such as generator modeling needed to support NERC Standard TPL analysis, as well as, integrated resource planning resource studies. Resources included in this category may be adjusted using a confidence factor (%) to reflect uncertainties associated with siting, project development or queue position. Conservation – see Energy Conservation Contractually Interruptible (Curtailable) (Controllable Capacity Demand Response) — Dispatchable, Controllable, Demand-side management achieved by a customer reducing its load upon notification from a control center. The interruption must be mandatory at times of system emergency. Curtailment options integrated into retail tariffs that provide a rate discount or bill credit for agreeing to reduce load during system contingencies. It is the magnitude of customer demand that, in accordance with contractual arrangements, can be interrupted at the time of the Regional Entity’s seasonal peak. In some instances, the demand reduction may be effected by action of the System Operator (remote tripping) after notice to the customer in accordance with contractual provisions. Controllable (Demand Response) — Dispatchable Demand Response, demand-side resources used to supplement generation resources resolving system and/or local capacity constraints. Critical Peak Pricing (CPP) (Non-dispatchable Time-Sensitive Pricing Demand Response) — Rate and/or price structure designed to encourage reduced consumption during periods of high wholesale market prices or system contingencies by imposing a pre-specified high rate for a limited number of days or hours. Critical Peak Pricing (CPP) with Control (Controllable Capacity Demand Response) — Dispatchable, Controllable, Demand-side management that combines direct remote control with Page 185 2009/2010 Winter Reliability Assessment Terms Used in This Report a pre-specified high price for use during designated critical peak periods, triggered by system contingencies or high wholesale market prices. Curtailable — See Contractually Interruptible Deliverable Capacity Margin (%) — Deliverable Capacity Resources minus Net Internal Demand shown as a percent of Deliverable Capacity Resources. Replaced in 2009 with Deliverable Capacity Reserve Margin (%) for NERC Assessments. Deliverable Capacity Resources – Existing-Certain and Net Firm Transactions plus Future- Planned capacity resources plus Expected Imports, minus Expected Exports. (MW) Deliverable Reserve Margin (%) –Deliverable Capacity Resources minus Net Internal Demand shown as a percent of Net Internal Demand. Demand – See Net Internal Demand, Total Internal Demand Demand Bidding & Buyback (Controllable Energy-Price Demand Response) — Demand-side resource that enable large consumers to offer specific bid or posted prices for specified load reductions. Customers stay at fixed rates, but receive higher payments for load reductions when the wholesale prices are high. Demand Response — Changes in electric use by demand-side resources from their normal consumption patterns in response to changes in the price of electricity, or to incentive payments designed to induce lower electricity use at times of high wholesale market prices or when system reliability is jeopardized. Derate (Capacity) — The amount of capacity that is expected to be unavailable on seasonal peak. Direct Control Load Management (DCLM) or Direct Load Control (DLC) (Controllable Capacity Demand Response) — Demand-Side Management that is under the direct control of the system operator. DCLM may control the electric supply to individual appliances or equipment on customer premises. DCLM as defined here does not include Interruptible Demand.123 Dispatchable (Demand Response) — Demand-side resource curtails according to instruction from a control center. Economic (Controllable Demand Response) — Demand-side resource that is dispatched based on an economic decision. Emergency (Controllable Energy-Voluntary Demand Response) — Demand-side resource curtails during system and/or local capacity constraints. Energy Conservation — The practice of decreasing the quantity of energy used. Energy Efficiency — Permanent changes to electricity use through replacement with more efficient end-use devices or more effective operation of existing devices. Generally, it results in reduced consumption across all hours rather than event-driven targeted load reductions. 123 DCLM is a term defined in NERC Reliability Standards. See Glossary of Terms Used in Reliability Standards, Updated April 20, 2009 www.nerc.com/files/Glossary_2009April20.pdf 2009/2010 Winter Reliability Assessment Page 186 Terms Used in This Report Energy Emergency Alert Levels — The categories for capacity and emergency events based on Reliability Standard EOP—002-0: Level 1 — All available resources in use. Balancing Authority, Reserve Sharing Group, or Load Serving Entity foresees or is experiencing conditions where all available resources are committed to meet firm load, firm transactions, and reserve commitments, and is concerned about sustaining its required Operating Reserves, and Non-firm wholesale energy sales (other than those that are recallable to meet reserve requirements) have been curtailed. Level 2 — Load management procedures in effect. Balancing Authority, Reserve Sharing Group, or Load Serving Entity is no longer able to provide its customers’ expected energy requirements, and is designated an Energy Deficient Entity. Energy Deficient Entity foresees or has implemented procedures up to, but excluding, interruption of firm load commitments. When time permits, these procedures may include, but are not limited to: Public appeals to reduce demand, Voltage reduction, Interruption of non-firm end use loads in accordance with applicable contracts, Demand-side management, and Utility load conservation measures. Level 3 — Firm load interruption imminent or in progress. Balancing Authority or Load Serving Entity foresees or has implemented firm load obligation interruption. The available energy to the Energy Deficient Entity, as determined from Level (Alert) 2, is only accessible with actions taken to increase transmission transfer capabilities. Energy Only (Capacity) — Energy Only Resources are generally generating resources that are designated as energy-only resources or have elected to be classified as energy-only resources and may include generating capacity that can be delivered within the area but may be recallable to another area. Energy-Price (Controllable Economic Demand Response) — Demand-side resource that reduces energy for incentives. Energy-Voluntary (Controllable Demand Response) — Demand-side resource curtails voluntarily when offered the opportunity to do so for compensation, but nonperformance is not penalized. Existing-Certain (Existing Generation Resources) — Existing generation resources available to operate and deliver power within or into the Region during the period of analysis in the assessment. Resources included in this category may be reported as a portion of the full capability of the resource, plant, or unit. This category includes, but is not limited to the following: 1. Contracted (or firm) or other similar resource confirmed able to serve load during the period of analysis in the assessment. 2. Where organized markets exist, designated market resource124 that is eligible to bid into a market or has been designated as a firm network resource. 3. Network Resource125, as that term is used for FERC pro forma or other regulatory approved tariffs. 124 Curtailable demand or load that is designated as a network resource or bid into a market is not included in this category, but rather must be subtracted from the appropriate category in the demand section. Page 187 2009/2010 Winter Reliability Assessment Terms Used in This Report 4. Energy-only resources126 confirmed able to serve load during the period of analysis in the assessment and will not be curtailed.127 5. Capacity resources that can not be sold elsewhere. 6. Other resources not included in the above categories that have been confirmed able to serve load and not to be curtailed128 during the period of analysis in the assessment. Existing-Certain & Net Firm Transactions – Existing-Certain capacity resources plus Firm Imports, minus Firm Exports. (MW) Existing-Certain and Net Firm Transactions (%) (Margin Category) – Existing-Certain & Net Firm Transactions minus Net Internal Demand shown as a percent of Net Internal Demand. Existing Generation Resources — See Existing-Certain, Existing-Other, Existing, but Inoperable. Existing, Inoperable (Existing Generation Resources) — This category contains the existing portion of generation resources that are out-of-service and cannot be brought back into service to serve load during the period of analysis in the assessment. However, this category can include inoperable resources that could return to service at some point in the future. This value may vary for future seasons and can be reported as zero. This includes all existing generation not included in categories Existing-Certain or Existing-Other, but is not limited to, the following: 1. Mothballed generation (that can not be returned to service for the period of the assessment). 2. Other existing but out-of-service generation (that can not be returned to service for the period of the assessment). 3. This category does not include behind-the-meter generation or non-connected emergency generators that normally do not run. 4. This category does not include partially dismantled units that are not forecasted to return to service. Existing-Other (Existing Generation Resources) — Existing generation resources that may be available to operate and deliver power within or into the Region during the period of analysis in the assessment, but may be curtailed or interrupted at any time for various reasons. This category also includes portions of intermittent generation not included in Existing-Certain. This category includes, but is not limited to the following: 1. A resource with non-firm or other similar transmission arrangements. 2. Energy-only resources that have been confirmed able to serve load for any reason during the period of analysis in the assessment, but may be curtailed for any reason. 3. Mothballed generation (that may be returned to service for the period of the assessment). 4. Portions of variable generation not counted in the Existing-Certain category (e.g., wind, solar, etc. that may not be available or derated during the assessment period). 5. Hydro generation not counted as Existing-Certain or derated. 6. Generation resources constrained for other reasons. 125 Curtailable demand or load that is designated as a network resource or bid into a market is not included in this category, but rather must be subtracted from the appropriate category in the demand section. 126 Energy Only Resources are generally generating resources that are designated as energy-only resources or have elected to be classified as energy-only resources and may include generating capacity that can be delivered within the area but may be recallable to another area (Source: 2008 EIA 411 document OMB No. 1905-0129).” Note: Other than wind and solar energy, WECC does not have energy-only resources that are counted towards capacity. 127 Energy only resources with transmission service constraints are to be considered in category Existing, Other. 128 Energy only resources with transmission service constraints are to be considered in category Existing, Other. 2009/2010 Winter Reliability Assessment Page 188 Terms Used in This Report Expected (Transaction Category) — A category of Purchases/Imports and Sales/Exports contract including: 1. Expected implies that a contract has not been executed, but in negotiation, projected or other. These Purchases or Sales are expected to be firm. 2. Expected Purchases and Sales should be considered in the reliability assessments. Firm (Transaction Category) — A category of Purchases/Imports and Sales/Exports contract including: 1. Firm implies a contract has been signed and may be recallable. 2. Firm Purchases and Sales should be reported in the reliability assessments. The purchasing entity should count such capacity in margin calculations. Care should be taken by both entities to appropriate report the generating capacity that is subject to such Firm contract. Future Generation Resources (See also Future-Planned and Future-Other) — This category includes generation resources the reporting entity has a reasonable expectation of coming online during the period of the assessment. As such, to qualify in either of the Future categories, the resource must have achieved one or more of these milestones: 1. Construction has started. 2. Regulatory permits being approved, any one of the following: a. Site permit b. Construction permit c. Environmental permit 3. Regulatory approval has been received to be in the rate base. 4. Approved power purchase agreement. 5. Approved and/or designated as a resource by a market operator. Future-Other (Future Generation Resources) — This category includes future generating resources that do not qualify in Future-Planned and are not included in the Conceptual category. This category includes, but is not limited to, generation resources during the period of analysis in the assessment that may: 1. Be curtailed or interrupted at any time for any reason. 2. Energy-only resources that may not be able to serve load during the period of analysis in the assessment. 3. Variable generation not counted in the Future-Planned category or may not be available or is derated during the assessment period. 4. Hydro generation not counted in category Future-Planned or derated. 5. Resources included in this category may be adjusted using a confidence factor to reflect uncertainties associated with siting, project development or queue position. Future-Planned (Future Generation Resources) — Generation resources anticipated to be available to operate and deliver power within or into the Region during the period of analysis in the assessment. This category includes, but is not limited to, the following: 1. Contracted (or firm) or other similar resource. 2. Where organized markets exist, designated market resource129 that is eligible to bid into a market or has been designated as a firm network resource. 129 Curtailable demand or load that is designated as a network resource or bid into a market is not included in this category, but rather must be subtracted from the appropriate category in the demand section. Page 189 2009/2010 Winter Reliability Assessment Terms Used in This Report 3. Network Resource130, as that term is used for FERC pro forma or other regulatory approved tariffs. 4. Energy-only resources confirmed able to serve load during the period of analysis in the assessment and will not be curtailed.131 5. Where applicable, included in an integrated resource plan under a regulatory environment that mandates resource adequacy requirements and the obligation to serve. Load as a Capacity Resource (Controllable Capacity Demand Response) — the magnitude of customer demand that, in accordance with contractual arrangements, is committed to pre- specified load reductions when called upon by a balancing authority. These resources are not limited to being dispatched during system contingencies and may be subject to economic dispatch from wholesale balancing authorities. Additionally, this capacity may be used to meet resource adequacy obligations when determining planning Reserve Margins. NERC Reference Reserve Margin Level (%) — Either the Target Reserve Margin provided by the Region/subregion or NERC assigned based on capacity mix (i.e., thermal/hydro). Each Region/subregion may have their own specific margin level based on load, generation, and transmission characteristics as well as regulatory requirements. If provided in the data submittals, the Regional/subregional Target Reserve Margin level is adopted as the NERC Reference Reserve Margin Level. If not, NERC assigned 15 percent Reserve Margin for predominately thermal systems and for predominately hydro systems, 10 percent. Net Internal Demand: Equals the Total Internal Demand reduced by the total Dispatchable, Controllable, Capacity Demand Response equaling the sum of Direct Control Load Management, Contractually Interruptible (Curtailable), Critical Peak Pricing (CPP) with Control, and Load as a Capacity Resource. Non-dispatchable (Demand Response) — Demand-side resource curtails according to tariff structure, not instruction from a control center. Non-Firm (Transaction Category) — A category of Purchases/Imports and Sales/Exports contract including: 1. Non-Firm implies a non-firm contract has been signed. 2. Non-Firm Purchases and Sales should not be considered in the reliability assessments. Non-Spin Reserves (Controllable Ancillary Demand Response) — Demand-side resource not connected to the system but capable of serving demand within a specified time. On-Peak (Capacity) — The amount of capacity that is expected to be available on seasonal peak. Prospective Capacity Margin (%) — Prospective Capacity Resources minus Net Internal Demand shown as a percent of Prospective Capacity Resources. Replaced in 2009 with Prospective Capacity Reserve Margin (%) for NERC Assessments. Prospective Capacity Reserve Margin (%) – Prospective Capacity Resources minus Net Internal Demand shown as a percent of Net Internal Demand. Prospective Capacity Resources – Deliverable Capacity Resources plus Existing-Other capacity resources, minus all Existing-Other deratings (Includes derates from variable resources, 130 Curtailable demand or load that is designated as a network resource or bid into a market is not included in this category, but rather must be subtracted from the appropriate category in the demand section. 131 Energy only resources with transmission service constraints are to be considered in category Future-Other. 2009/2010 Winter Reliability Assessment Page 190 Terms Used in This Report energy only resources, scheduled outages for maintenance, and transmission-limited resources), plus Future-Other capacity resources, minus all Future-Other deratings. (MW) Provisional (Transaction Category) — A category of Purchases/Imports and Sales/Exports contract including: 1. Provisional implies that the transactions are under study, but negotiations have not begun. These Purchases and Sales are expected to be provisionally firm. 2. Provisional Purchases and Sales should be considered in the reliability assessments. Purchases/Imports Contracts – See Transaction Categories Real Time Pricing (RTP) (Non-dispatchable Time-Sensitive Pricing Demand Response) — Rate and price structure in which the price for electricity typically fluctuates to reflect changes in the wholesale price of electricity on either a day-ahead or hour-ahead basis. Reference Reserve Margin Level – See NERC Reference Reserve Margin Level Regulation (Controllable Ancillary Demand Response) — Demand-side resources responsive to Automatic Generation Control (AGC) to provide normal regulating margin. Renewable Energy — The United States Department of Energy, Energy Efficiency & Renewable Energy glossary defines “Renewable Energy” as “energy derived from resources that are regenerative or for all practical purposes can not be depleted. Types of renewable energy resources include moving water (hydro, tidal and wave power), thermal gradients in ocean water, biomass, geothermal energy, solar energy, and wind energy. Municipal solid waste (MSW) is also considered to be a renewable energy resource.”132 The government of Canada has a similar definition.133 Variable generation is a subset of Renewable Energy—See Variable Generation. Renewables — See Renewable Energy Reserve Margin (%) — See Deliverable Capacity Reserve Margin (%) and Prospective Capacity Reserve Margin (%). Roughly, Capacity minus Demand, divided by Demand or (Capacity-Demand)/Demand. Replaced Capacity Margin(s) (%) for NERC Assessments in 2009. Sales/Exports Contracts – See Transaction Categories Spinning/Responsive Reserves (Controllable Ancillary Demand Response) — Demand-side resources that is synchronized and ready to provide solutions for energy supply and demand imbalance within the first few minutes of an electric grid event. System Peak Response Transmission Tariff (Non-dispatchable Time-Sensitive Pricing Demand Response) - Rate and/or price structure in which interval metered customers reduce load during coincident peaks as a way of reducing transmission charges. Target Reserve Margin (%) — Established target for Reserve Margin by the Region or subregion. Not all Regions report a Target Reserve Margin. The NERC Reference Reserve Margin Level is used in those cases where a Target Reserve Margin is not provided. Total Internal Demand: The sum of the metered (net) outputs of all generators within the system and the metered line flows into the system, less the metered line flows out of the system. The demands for station service or auxiliary needs (such as fan motors, pump motors, and other equipment essential to the operation of the generating units) are not included. Internal Demand 132 http://www1.eere.energy.gov/site_administration/ glossary.html#R 133 http://www.cleanenergy.gc.ca/faq/ index_e.asp#whatiscleanenergy Page 191 2009/2010 Winter Reliability Assessment Terms Used in This Report includes adjustments for indirect Demand-Side Management programs such as conservation programs, improvements in efficiency of electric energy use, all non-dispatchable Demand Response programs (such as Time-of-Use, Critical Peak Pricing, Real Time Pricing and System Peak Response Transmission Tariffs) and some dispatchable Demand Response (such as Demand Bidding and Buy-Back). Adjustments for controllable Demand Response should not be incorporated in this value. Time-of-Use (TOU) (Non-dispatchable Time-Sensitive Pricing Demand Response) — Rate and/or price structures with different unit prices for use during different blocks of time. Time-Sensitive Pricing (Non-dispatchable Demand Response) — Retail rates and/or price structures designed to reflect time-varying differences in wholesale electricity costs, and thus provide consumers with an incentive to modify consumption behavior during high-cost and/or peak periods. Transaction Categories (See also Firm, Non-Firm, Expected and Provisional) — Contracts for Capacity are defined as an agreement between two or more parties for the Purchase and Sale of generating capacity. Purchase contracts refer to imported capacity that is transmitted from an outside Region or subregion to the reporting Region or subregion. Sales contracts refer to exported capacity that is transmitted from the reporting Region or subregion to an outside Region or subregion. For example, if a resource subject to a contract is located in one Region and sold to another Region, the Region in which the resource is located reports the capacity of the resource and reports the sale of such capacity that is being sold to the outside Region. The purchasing Region reports such capacity as a purchase, but does not report the capacity of such resource. Transmission must be available for all reported Purchases and Sales. Transmission-Limited Resources — The amount of transmission-limited generation resources that have known physical deliverability limitations to serve load within the Region. Example: If capacity is limited by both studied transmission limitations and generator derates, the generator derates take precedence. For example, a 100 MW wind farm with a wind capacity variation reduction of 50 MW and a transmission limitation of 60 MW would take the 50 MW wind variation reduction first and list 10 MW in the transmission limitation. Transmission Status Categories — Transmission additions were categorized using the following criteria: Under Construction Construction of the line has begun Planned (any of the following) Permits have been approved to proceed Design is complete Needed in order to meet a regulatory requirement Conceptual (any of the following) A line projected in the transmission plan A line that is required to meet a NERC TPL Standard or included in a powerflow model and cannot be categorized as “Under Construction” or “Planned” Projected transmission lines that are not “Under Construction” or “Planned” Variable Generation — Variable generation technologies generally refer to generating technologies whose primary energy source varies over time and cannot reasonably be stored to 2009/2010 Winter Reliability Assessment Page 192 Terms Used in This Report address such variation.134 Variable generation sources which include wind, solar, ocean and some hydro generation resources are all renewable based. Variable generation in this report refers only to wind and solar resources. There are two major attributes of a variable generator that distinguish it from conventional forms of generation and may impact the bulk power system planning and operations: variability and uncertainty. Variability: The output of variable generation changes according to the availability of the primary fuel (wind, sunlight and moving water) resulting in fluctuations in the plant output on all time scales. Uncertainty: The magnitude and timing of variable generation output is less predictable than for conventional generation. References: Glossary of Terms Used in Reliability Standards, Updated April 20, 2009 www.nerc.com/files/Glossary_2009April20.pdf Instructions for NERC Winter Reliability Assessment – Data Reporting Form ERO-2009W, May 15, 2009 Reliability Assessments Guidebook, Version 1.2, March 18, 2008 http://www.nerc.com/docs/pc/ragtf/Reliability_Assessment_%20Guidebook%20v1.2%20031909 .pdf Reliability Standards for the Bulk Electric Systems in North America, Updated May 20, 2009 http://www.nerc.com/files/Reliability_Standards_Complete_Set_2009May20.pdf 134 http://www.nerc.com/files/IVGTF_Report_041609.pdf Page 193 2009/2010 Winter Reliability Assessment Abbreviations Used in This Report Abbreviations Used in This Report A/C Air Conditioning AEP American Electric Power AFC Available Flowgate Capability ASM Ancillary Services Market ATCLLC American Transmission Company ATR AREA Transmission Review (of NYISO) AWEA American Wind Energy Association AZ-NM-SNV Arizona-New Mexico-Southern Nevada (Subregion of WECC) BA Balancing Authorities BCF Billion cubic feet BCFD Billion cubic feet per day CA-MX-US California-México (Subregion of WECC) CFE Commission Federal de Electricidad CFL Compact Fluorescent Light CMPA California-Mexico Power Area COI California-Oregon Intertie COS Coordinated Outage (transmission) System CPUC California Public Utilities Commission CRO Contingency Reserve Obligation CRPP Comprehensive Reliability Planning Process (of NYISO) DADRP Day-Ahead Demand Response Program dc Direct Current DCLM Direct Controlled Load Management DFW Dallas/Fort Worth DLC Direct Load Control DOE U.S. Department of Energy DSG Dynamics Study Group DSI Direct-served Industry DSM Demand-Side Management DVAR D-VAR® reactive power compensation system EDRP Emergency Demand Response Program EE Energy Efficiency EEA Energy Emergency Alert EECP Emergency Electric Curtailment Plan EIA Energy Information Agency (of DOE) EILS Emergency Interruptible Load Service (of ERCOT) EISA Energy Independence and Security Act of 2007 (USA) ELCC Effective Load-carrying Capability EMTP Electromagnetic Transient Program ENS Energy Not Served EOP Emergency Operating Procedure ERAG Eastern Interconnection Reliability Assessment Group ERCOT Electric Reliability Council of Texas ERO Electric Reliability Organization FCITC First Contingency Incremental Transfer Capability FCM Forward Capacity Market FERC U.S. Federal Energy Regulatory Commission FP Future-Planned FO Future-Other 2009/2010 Winter Reliability Assessment Page 194 Abbreviations Used in This Report FRCC Florida Reliability Coordinating Council GADS Generating Availability Data System GDP Gross Domestic Product GGGS Gerald Gentleman Station Stability GHG Greenhouse Gas GRSP Generation Reserve Sharing Pool (of MAPP) GTA Greater Toronto Area GWh Gigawatt hours HDD Heating Degree Days HVac Heating, Ventilating, and Air Conditioning IA Interchange Authority ICAP Installed Capacity ICR Installed Capacity Requirement IESO Independent Electric System Operator (in Ontario) IOU Investor Owned Utility IPL/NRI International Power Line/Northeast Reliability Interconnect Project IPSI Integrated Power System Plan IRM Installed Reserve Margin IROL Interconnection Reliability Operating Limit IRP Integrated Resource Plan ISO Independent System Operator ISO-NE New England Independent System Operator kV Kilovolts (one thousand volts) LaaRs Loads acting as a Resource LCR Locational Installed Capacity Requirements LDC Load Duration Curve LFU Load Forecast Uncertainty LNG Liquefied Natural Gas LOLE Loss of Load Expectation LOLP Loss Of Load Probability LOOP Loss of off-site power LRP Long Range Plan LSE Load-serving Entities LTRA Long-Term Reliability Assessment LTSG Long-term Study Group MAAC Mid-Atlantic Area Council Maf Million acre-feet MAIN Mid-America Interconnected Network, Inc. MAPP Mid-Continent Area Power Pool MCRSG Midwest Contingency Reserve Sharing Group MISO Midwest Independent Transmission System Operator MPRP Maine Power Reliability Program MRO Midwest Reliability Organization MVA Megavolt amperes Mvar Mega-vars MW Megawatts (millions of watts) MWEX Minnesota Wisconsin Export NB New Brunswick NBSO New Brunswick System Operator NDEX North Dakota Export Stability Interface NEEWS New England East West Solution NERC North American Electric Reliability Corporation NIETC National Interest Electric Transmission Corridor Page 195 2009/2010 Winter Reliability Assessment Abbreviations Used in This Report NOPSG Northwest Operation and Planning Study Group NPCC Northeast Power Coordinating Council NPDES National Pollutant Discharge Elimination System NPPD Nebraska Public Power District NSPI Nova Scotia Power Inc. NTSG Near-term Study Group NWPP Northwest Power Pool Area (subregion of WECC) NYISO New York Independent System Operator NYPA New York Planning Authority NYRSC New York State Reliability Council, LLC NYSERDA New York State Energy and Research Development Agency OASIS Open Access Same Time Information Service OATT Open Access Transmission Tariff OP Operating Procedure OPA Ontario Power Authority OPPD Omaha Public Power District ORWG Operating Reliability Working Group OTC Operating Transfer Capability OVEC Ohio Valley Electric Corporation PA Planning Authority PACE PacifiCorp East PAR Phase Angle Regulators PC NERC Planning Committee PCAP Pre-Contingency Action Plans PCC Planning Coordination Committee (of WECC) PJM PJM Interconnection PRB Powder River Basin PRC Public Regulation Commission PRSG Planned Reserve Sharing Group PSA Power Supply Assessment PUCN Public Utilities Commission of Nevada QSE Qualified Scheduling Entities RA Resource Adequacy RAP Remedial Action Plan RAR Resource Adequacy Requirement RAS Reliability Assessment Subcommittee of NERC Planning Committee RC Reliability Coordinator RCC Reliability Coordinating Committee RFC ReliabilityFirst Corporation RFP Request For Proposal RGGI Regional Greenhouse Gas Initiative RIS Resource Issues Subcommittee of NERC Planning Committee RMPA Rocky Mountain Power Area (subregion of WECC) RMR Reliability Must Run RMRG Rocky Mountain Reserve Group RP Reliability Planner RPM Reliability Pricing Mode RRS Reliability Review Subcommittee RSG Reserve Sharing Group RTEP Regional Transmission Expansion Plan (for PJM) RTO Regional Transmission Organization RTP Real Time Pricing RTWG Renewable Technologies Working Group 2009/2010 Winter Reliability Assessment Page 196 Abbreviations Used in This Report SA Security Analysis SasKPower Saskatchewan Power Corp. SCADA Supervisory Control and Data Acquisition SCC Seasonal Claimed Capability SCD Security Constrained Dispatch SCDWG Short Circuit Database Working Group SCEC State Capacity Emergency Coordinator (of FRCC) SCR Special Case Resources SEMA Southeastern Massachusetts SEPA State Environmental Protection Administration SERC SERC Reliability Corporation SMUD Sacramento Municipal Utility District SOL System Operating Limits SPP Southwest Power Pool SPS Special Protection System SPS/RAS Special Protection Schemes / Remedial Action Schemes SRIS System Reliability Impact Studies SRWG System Review Working Group STATCOM Static Synchronous Compensator STEP SPP Transmission Expansion Plan SVC Static Var Compensation TCF Trillion Cubic Feet TFCP Task Force on Coordination of Planning THI Temperature Humidity Index TIC Total Import Capability TID Total Internal Demand TLR Transmission Loading Relief TOP Transmission Operator TPL Transmission Planning TRE Texas Regional Entity TRM Transmission Reliability Margins TS Transformer Station TSP Transmission Service Provider TSS Technical Studies Subcommittee TVA Tennessee Valley Authority USBRLC United States Bureau of Reclamation Lower Colorado Region UFLS Under Frequency Load Shedding Schemes UVLS Under Voltage Load-Shedding var Voltampre reactive VACAR Virginia and Carolinas (subregion of SERC) VSAT Voltage Stability Assessment Tool WALC Western Area Lower Colorado WECC Western Electricity Coordinating Council WTHI Weighted Temperature-Humidity Index WUMS Wisconsin-Upper Michigan Systems Page 197 2009/2010 Winter Reliability Assessment Reliability Assessment Subcommittee Roster Reliability Assessment Subcommittee Roster Chair William O. Bojorquez Hunt Transmission Services, L.L.C. (512) 721–2653 Vice President, 701 Brazos Street, Suite 970 (512) 721–2656 Fx Planning Austin, Texas 78701–2559 bbojorquez@hunttransmis sion.com Vice Mark J. Kuras PJM Interconnection, L.L.C. (610) 666-8924 Chair Senior Engineer, NERC 955 Jefferson Avenue (610) 666-4779 Fx and Regional Valley Forge Corporate Center email@example.com Coordination Norristown, Pennsylvania 19403–2497 ERCOT Dan Woodfin Electric Reliability Council of Texas, Inc. (512) 248–3115 Director, System 2705 West Lake Drive (512) 248–4235 Fx Planning Taylor, Texas 76574 firstname.lastname@example.org FRCC Vince Ordax Florida Reliability Coordinating Council (813) 207–7988 Manager of Planning 1408 N. Westshore Boulevard (813) 289–5646 Fx 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 firstname.lastname@example.org NPCC John G. Mosier, Jr. Northeast Power Coordinating Council, Inc. (917) 697–8565 Cell AVP-System 1040 Avenue of the Americas-10th floor (212) 840–4907 Operations New York, New York 10018–3703 (212) 302 –2782 Fx email@example.com RFC Jeffrey L. Mitchell ReliabilityFirst Corporation (330) 247–3043 Director - Engineering 320 Springside Drive (330) 456–3648 Fx Suite 300 firstname.lastname@example.org Akron, Ohio 44333 RFC Bernard M. Pasternack, American Electric Power (614) 552–1600 P.E. 700 Morrison Road (614) 552–1602 Fx Managing Director - Gahanna, Ohio 43230–8250 email@example.com Transmission Asset Management SERC Hubert C. Young South Carolina Electric & Gas Co. (803) 217–2030 Manager of 220 Operations Way (803) 933–7264 Fx Transmission Planning MC J37 firstname.lastname@example.org Cayce, South Carolina 29033 SPP Mak Nagle Southwest Power Pool (501) 614–3564 Manager of Technical 415 North McKinley (501) 666–0346 Fx Studies & Modeling Suite 140 email@example.com Little Rock, Arkansas 72205–3020 WECC James Leigh-Kendall Sacramento Municipal Utility District (916) 732–5357 Manager, Reliability Mail Stop B305 (916) 732–7527 Fx Compliance and P.O. Box 15830 firstname.lastname@example.org Coordination Sacramento, California 95852–1830 2009/2010 Winter Reliability Assessment Page 198 Reliability Assessment Subcommittee Roster WECC Bradley M. Nickell Western Electricity Coordinating Council (801) 455-7946 Renewable Integration 615 Arapeen Drive, Suite 210 (720) 635-3817 and Planning Director Salt Lake City, UT 84108 email@example.com Canadian- Daniel Rochester, P. Independent Electricity System Operator (905) 855-6363 At-Large Eng. Station A, Box 4474 (416).574.4018 Cell Manager, Reliability Toronto, Ontario, M5W 4E5 (905) 403-6932 Fx Standards and firstname.lastname@example.org Assessments IOU & K. R. Chakravarthi Southern Company Services, Inc. (205) 257–6125 DCWG Manager, 13N-8183 (205) 257–1040 Fx Chair Interconnection and P.O. Box 2641 email@example.com Special Studies Birmingham, Alabama 35291 LFWG Yves Nadeau Hydro-Québec (514) 879–4100 ext 6131 Chair Manager, Load and Complexe Desjardins, Tour Est 25 étage -- firstname.lastname@example.org Revenue Forecasting Case postale 10000 Montréal, Québec H5B 1H7 ISO/RTO Jesse Moser Midwest ISO (612) 718–6117 Manager-Regulatory P.O. Box 4202 email@example.com Studies Carmel, IN 46082–4202 ISO/RTO John Lawhorn, P.E. Midwest ISO, Inc. (651) 632–8479 Director, Regulatory 1125 Energy Park Drive (651) 632–8417 Fx and Economic St. Paul, Minnesota 55108 firstname.lastname@example.org Standards Transmission Asset 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 email@example.com FERC Keith N. Collins Federal Energy Regulatory Commission (202) 502-6383 Manager, Electric 888 First Street, NE (202) 219-6449 Fx Analysis Group Washington, D.C. 20426 firstname.lastname@example.org FERC Sedina Eric Federal Energy Regulatory Commission (202) 502–6441 Electrical Engineer, 888 First Street, NE, 92–77 (202) 219–1274 Fx Office of Electric Washington, D.C. 20426 email@example.com Reliability, Division of Bulk Power System Analysis DOE Patricia Hoffman Department of Energy (202) 586–1411 Acting Director 1000 Independence Avenue firstname.lastname@example.org. Research and SW 6e–069 gov Development Washington, D.C. 20045 Alternate Herbert Schrayshuen SERC Reliability Corporation (704) 940–8223 SERC Director Reliability 2815 Coliseum Centre Drive (315) 439–1390 Cell Assessment Charlotte, North Carolina 28217 email@example.com Page 199 2009/2010 Winter Reliability Assessment Reliability Assessment Subcommittee Roster Alternate John E. Odom, Jr. Florida Reliability Coordinating Council (813) 207–7985 FRCC Vice President of 1408 N. Westshore Blvd. (813) 289–5646 Fx Planning and Suite 1002 firstname.lastname@example.org Operations Tampa, Florida 33607 Alternate John Seidel Midwest Reliability Organization (651) 855–1716 MRO Reliability Assessment 2774 Cleveland Ave (651) 855–1712 Fx Manager Roseville, Minnesota 55113 ja.seidel@midwestreliabili ty.org Alternate Salva R. Andiappan Midwest Reliability Organization (651) 855–1719 MRO Principal Engineer 2774 Cleveland Ave (651) 855–1712 Fx Roseville, Minnesota 55113 sr.andiappan@midwestreli ability.org Alternate Paul D. Kure ReliabilityFirst Corporation (330) 247–3057 RFC Senior Consultant, 320 Springside Drive (330) 456–3648 Fx Resources Suite 300 email@example.com Akron, Ohio 44333 Alternate Alan C. Wahlstrom Southwest Power Pool (501) 688–1624 SPP Lead Engineer, 16101 La Grande Drive (501) 664–6923 Fx Compliance Suite 103 firstname.lastname@example.org Little Rock, Arkansas 72223 Member Jerry D. Rust Northwest Power Pool Corporation (503) 445–1074 President 7505 N.E. Ambassador Place (813) 445–1070 Fx Portland, Oregon 97220 email@example.com Member James Useldinger Kansas City Power & Light Co. (816) 654–1212 Manager, T&D System PO Box 418679 (816) 719–9718 Fx Operations Kansas City, Missouri, 64141 firstname.lastname@example.org Observer Stan Kaplan Congressional Research Service (202) 707–9529 Specialist in Energy 101 Independence Avenue, SE (301) 452–1349 Fx Policy Washington, D.C. 20540–7450 email@example.com 2009/2010 Winter Reliability Assessment Page 200 North American Electric Reliability Corporation Staff Roster North American Electric Reliability Corporation Staff Roster North American Electric Reliability Corporation Telephone: (609) 452-8060 116-390 Village Boulevard Fax: (609) 452-9550 Princeton, New Jersey 08540-5721 Reliability Assessment and Performance Analysis Mark G. Lauby Director of Reliability firstname.lastname@example.org Assessment and Performance Analysis Jessica Bian Manager of Benchmarking email@example.com Aaron Bennett Engineer of Reliability firstname.lastname@example.org Assessments John Moura Technical Analyst, Reliability email@example.com Assessment Rhaiza Villafranca Technical Analyst, firstname.lastname@example.org Benchmarking Contributing NERC Staff Kelly Ziegler Manager of Communications email@example.com Elizabeth Crouse Administrative Assistant firstname.lastname@example.org Karen Spolar Committee and Event email@example.com Services Administrator Page 201 2009/2010 Winter Reliability Assessment to ensure the reliability of the bulk power system
"20092010 Winter Reliability Assessment"