MODULE 5: Market and System Operations & Transmission and Distribution Outlook August 2016
Overview Over the next 20 years, several key factors and changes, including policy decisions related to integration of new resources and demand growth (e.g., Ontario s Climate Change Action Plan), increased adoption of distributed energy resources, retirement and refurbishment of major generation facilities, and end-of-life of transmission facilities, are expected to have an impact on the reliability and operability of the transmission and distribution system in Ontario. New investments, tools and measures may be required to respond to the evolving circumstances and to ensure the continued reliability and operability of the transmission and distribution system. There may be opportunities to maximize the use of existing assets and to align new investments with Provincial Policy Statement, which requires the consideration of existing sites and joint-use linear infrastructure corridors as part of infrastructure planning and development. This module examines key planning and operational considerations, including: - Potential transmission investments to facilitate integration of new resources - Managing the impact of electrification on the regional transmission and distribution system - Integration of DER and its impact on the transmission and distribution system - Opportunities to align end of life replacements with evolving priorities - Preparedness for extreme events - Tools and measures to manage changing operating conditions 2
POTENTIAL INVESTMENTS TO FACILITATE INTEGRATION OF NEW RESOURCES 3
Limited Remaining Transmission Capacity to Connect Resources Over the past decade, Ontario has focused on maximizing the use of the existing system. Over 7 GW of renewable energy resources have been added in Ontario since 2005 without major system expansion. However, most of Ontario s electricity system is at or nearing its capacity to connect additional resources. - Much of Ontario s remaining undeveloped renewable resource potential is located in areas of limited transmission capacity, either due to system constraints or by being located far from the existing grid - While non-renewable resources, such as gas or nuclear generation, have more flexibility in terms of where they can be located, these resources would likely be sited at existing generation sites in southern Ontario where there is limited remaining transmission capacity. 4
Major system reinforcements will be required to enable new resources in various parts of Ontario Should Ontario pursue a significant amount of new resources, major system reinforcements would be required to deliver these resources to the various load centres across the province. The type, location, and magnitude of resource development will drive the transmission investment requirements. Commitment of transmission facilities must be made with sufficient lead time to ensure they are available when needed. The lead time for new major transmission projects are usually in the order of 7 to 9 years, but some can involve longer timescales depending on the complexity of the project and the land-use and community impact. For example, even with an accelerated timeline and a well-defined scope, the Bruce to Milton transmission project required a lead time of 7 years. 5
Transmission to Enable Resources in Northern Ontario A large amount of Ontario s remaining renewable resource potential is located in Northern Ontario: Albany/Moose River Basin, the Sault and Algoma area, and east Nipigon area (up to 4,000 MW). North-South Reinforcements: To deliver power from these resources to load centres in southern Ontario, the major transmission pathway between Sudbury and GTA would need to be reinforced. Below are some North-South reinforcements options Potential Option Incremental Capacity Land Use Impact Convert the existing 500kV transmission lines to two HVDC 1,000-1,500 MW Utlizes existing right of way Bipoles Install a new HVDC bipole 2,000 MW Requires a new right of way 6
Transmission to Enable Resources in Northern Ontario (Con t) In addition, a number of transmission upgrades would be required within Northern Ontario to connect new resources and to enable power to be transferred within the region. Below are some examples: Sudbury North Reinforcements: Large hydroelectric development in Albany/Moose River Basin, biomass and wind developments would trigger the need for reinforcements of the Sudbury North transmission system Sudbury West Reinforcements: To incorporate large wind, solar and biomass along the eastern shore of Lake Superior and the Northwest, reinforcements of the West of Sudbury and East Lake Superior transmission system would be required. Enabling Facilities and Connection Lines: New connection lines between the Northwest transmission system and generation facilities would be required, depending on the location of the resource potential. There is limited information on resource potential in Northern Ontario beyond what has already been identified in Albany/Moose River Basin, the east Nipigon Sault and Algoma areas (up to 4000 MW). Transmission investments to connect resources beyond this level are not known at this time as it is dependent on the size, type and locations of these potential resources. 7
Transmission to Enable Resources in Southern Ontario If significant resources are developed, they will likely be located at existing generation sites in Southern Ontario to leverage existing facilities and to minimize the land use impact. Many of these sites have limited transmission capacity. Reinforcements would be required to enable these resources in Southern Ontario. Below are some examples: Bowmanville to GTA reinforcements: The incorporation of additional resources sited East of Toronto would trigger the need for new 500 kv double circuit lines between Bowmanville and GTA. West of London Reinforcements: Significant developments of resources in the Sarnia-Lambton area would require reinforcements of the transmission system between Sarnia and London Enabling Facilities: Enabling facilities, such as autotransformers and connection lines, could be built to enable some resources in the Southwest (e.g., 500 MW of renewable resources) should it be required. 8
Transmission to Facilitate Firm Capacity Imports from Quebec / Newfoundland The existing system in eastern Ontario and interties cannot accommodate a large amount of firm imports from Quebec/Newfoundland. To facilitate any potential large (i.e. more than 1,000 MW) firm import capacity deal from Quebec/Newfoundland, major system reinforcements in eastern Ontario would be required. Reinforcements would depend on the firm imports levels: For 2,000 MW of firm capacity import, a new HVDC line from Quebec to Lennox would be required. For 4,000 MW of firm capacity import, a second new HVDC line from Quebec to GTA would be required. 9
Transmission to Facilitate Firm Capacity Imports from Manitoba The existing northern Ontario electrical system cannot accommodate large firm imports from Manitoba to serve southern Ontario load, as there are a number of significant bottlenecks along the pathways from Kenora to the GTA area. Any import delivery to the GTA would require significant upgrades to the Ontario transmission system. Transmission reinforcements would vary depending on the firm import level. Below are a few examples: For 300-500 MW of firm capacity imports, a number of transmission reinforcements would required to alleviate constraints within Northern Ontario, including Sudbury West Reinforcements, North-South Reinforcements and reinforcements in Northwestern Ontario. Reinforcements of intertie between Ontario and Manitoba may also be required. For 1,000-2,000 MW of firm capacity imports, a new 1,700km HVDC line from Manitoba to the GTA area would be required. 10
INTEGRATION OF DISTRIBUTED ENERGY RESOURCES AND ITS IMPACT ON THE TRANSMISSION AND DISTRIBUTION SYSTEM 11
Increased Penetration of DERs As shown below, the installed capacity of DERs has increased by about 2000 MW over the past five years. 12
Data for Slide 12: Installed capacity of DERs (2010-2015) Year 2010 2011 2012 2013 2014 2015 DER Installed Capacity (MW) 3,764 4,049 4,339 4,779 5,570 5,837 13
DER and its impact on Transmission and Distribution system The increased penetration of DERs could have an impact on the distribution and transmission system. Traditionally, distribution and transmission system have been designed to deliver power one way to loads. Increasing levels of distributed energy resources can lead to bi-directional power flows that the electricity system was not initially designed to accommodate. This can lead to operating and safety concerns. The total amount of DERs that can be integrated into the distribution system can depend on technical constraints on the transmission and distribution equipment. Some examples of technical constraints include: Short circuit contribution levels beyond the capability of existing equipment or established codes Voltage and VAR regulation Power quality (Harmonics, Flicker, DC Injection) Unintentional islanding Protection and control system design and coordination (fault protection, reclosers, etc.) Equipment grounding Controllability of DERS, and load and generation imbalances Depending on the nature of the constraints, investments in the transmission and distribution system may be required to facilitate the integration of distributed energy resources. 14
MANAGING THE IMPACT OF ELECTRIFICATION ON THE REGIONAL TRANSMISSION AND DISTRIBUTION SYSTEM 15
Managing the Impact of Electrification on Regional Transmission and Distribution system At the regional level, the integration of EVs and electrification of mass public transit, and other forms of fuel switching, such as shifting from natural gas to electric-power heat pumps, could increase peak demand requirements and have an impact on the adequacy and reliability of the regional transmission and distribution systems, especially in urban centres. In addition, electrification can alter the profile of the demand and could impact the needs and solutions at the distribution and regional level. Transmitters, the IESO and LDCs are looking at ways to help manage and address these potential implications. Some examples include: The long-term implications of mass transit electrification will need to be considered as part of the regional planning process, especially in the GTA and surrounding areas and other urban centres. Investments to accommodate Go Transit electric train conversion, and the Eglinton Crosstown LRT project in Toronto. To manage the growth in personal EVs, utilities may need to adapt to the demands placed on their systems from EV charging facilities to effectively manage how and when customers charge their vehicles. Some local utilities have already undertaken analysis of their systems using smart metering data to determine the potential impact that high saturation of EVs will have on their system, and what mitigating measures can be taken to manage emerging needs in the most cost-effective manner 16
OPPORTUNITIES TO ALIGN END-OF-LIFE REPLACEMENTS WITH EVOLVING PRIORITIES 17
Transmission Infrastructure End-of-Life A substantial proportion of Ontario s transmission infrastructure will reach its end-of-life in the coming years. For example, the expected service life of a transformer, which is a major component of a transformer station, is about 60 years. Given the current demographics of the transformer fleet shown below, the number of transformers beyond their expected service life will increase significantly over the 20 year planning period. Demographics of Ontario s Transformer Fleet - 2015/2016 Source: Hydro One Networks, 2015-2016 Rate Application A similar trend is expected for other transmission infrastructures, such as key lines, switching and station facilities. 18
Better Alignment of End-of-Life Investments with Evolving Priorities Transmission assets reaching end of life have typically been replaced with assets of equivalent capacity and specification. This like for like approach has been applied most commonly in circumstances where minimal change was anticipated to the supply and demand outlook. However, where major change is anticipated, such an approach may not be appropriate. For example, in areas where demand is projected to flatten or decline, like for like replacement of transmission assets commissioned decades ago may lead to asset underutilization. The need to replace aging transmission assets will present opportunities to better align investments with evolving power system priorities, including issues and opportunities related to bulk system operability, bulk system resilience, customer reliability expectations, demand forecast uncertainties and integration of distributed energy resources. For example: Up-size equipment in areas with additional capacity needs to support growth or to integrate new resources Downsizing or even removing equipment that is no longer required Enhance or reconfigure assets for infrastructure hardening to improve system resilience In general, greater integration between asset management, bulk and regional planning, and planning for extreme events can help minimize unnecessary investment, maximize the value of existing assets and new facilities, and ultimately minimize cost impacts to Ontario s ratepayers. 19
PREPAREDNESS FOR EXTREME EVENTS 20
Preparedness for Extreme Events The province s electricity system is planned and operated according to established reliability standards. As such, customers in Ontario generally have access to a reliable supply of electricity. North American Electric Reliability Corporation (NERC) and Northeast Power Coordinating Council (NPCC) standards are designed to ensure the security of interconnection systems Ontario Resources and Transmission Assessment Criteria (ORTAC) ensures reliability to local areas, including limiting the impact of outages to customers when they do occur Power system equipment is designed to industry standards, such as those outlined by the Canadian Electricity Association and the Canadian Standard Association Major outages, including the 2003 Northeast Blackout, the 2013 Ice Storm and the 2013 flood in the western GTA, have brought system resilience and customer service reliability concerns into the public spotlight. This is an area of growing concern given the possibility of extreme events such as major storms and their impact on the power system. The consequences of extended power outages can include significant health and safety impacts for customers, particularly vulnerable and aging populations, as well as economic impacts for customers and society at large. Over the next decade, it will be come increasingly important for Ontario to examine opportunities to improve system resilience and to address concerns related to customer service reliability and expectations. 21
Impact of Extreme Events on the Power System Extreme events could result in the stress or loss of many system components, with the number of impacted elements exceeding the security standards that these systems are typically designed to endure. For example: Extreme Weather Associated with Climate Change Recent climatology studies indicate that due to climate change, some types of weather events will increase in frequency and severity in the coming decades. Frequent and severe weather, such as wind, ice and flooding could also cause widespread damage to equipment, resulting in prolonged power outages. Age-related Deterioration of Transmission Reliability As the transmission infrastructure ages, there may be an increased risk of power outages due to equipment failures. Much of the replacement equipment or parts may be obsolete and cannot be easily acquired. The need to schedule long outages to replace and refurbish aging equipment on major transmission corridors or stations could have an impact on the electricity system. Physical and Cyber Attack Events involving physical security breaches of transformer stations, such as vandalism, terrorism and accidental contact, can cause major outages. A cyber-attack on the electricity system can affect protection and control facilities and reduce the ability of system operators to effectively operate the power system. Areas where there is limited supply diversity (e.g., in rural or remote areas that rely on a single facility), or in areas that are more vulnerable to power loss (e.g., in urban centres) are particularly susceptible to potential impact of extreme events 22
Improving System Resilience System resilience is the ability of the power system to anticipate, withstand, adapt to, and rapidly recover from an extreme event by taking preventative actions to minimize the impact of outage and/or taking action to restore power and mitigate impact during/after an event A number of efforts already are underway in Ontario to improve system resilience: Operating policies and criteria require the IESO to take actions to improve system security under high risk conditions. Protection systems are implemented, where appropriate and necessary, to help mitigate the risk related to extreme events. The Ontario Electricity Emergency Plan and Ontario Power System Restoration Plan help coordinate electricity emergency planning efforts and to restore the grid in a timely manner n the event of partial or complete blackout. The IESO conducts large-scale integrated emergency exercises and power system restoration workshops to build on emergency preparedness and to assist market participants meet their obligations to test their emergency plans. The IESO partnered with the Ontario Climate Consortium to identify potential risks to transmission that could result from changing climate patterns and to develop a framework/process for future climate adaptation studies. Ontario will continue to assess system vulnerabilities and evaluate options for improving resilience by: Accounting for climate change in the development of extreme weather demand scenarios Designing and configuring facilities to better withstand extreme events Providing additional supply diversity, flexibility and security in a cost-effective manner and leveraging evolving technologies and distributed energy resources as well as coordinating with distributed and transmission solutions 23
Customer Service Reliability and Performance Expectations Service reliability and performance is measured based on customer exposure to power outages on the distribution and transmission system, which is expressed in terms of frequency (i.e., number of outages a year) and duration (e.g., length of time before the power is restored). System Average Interruption Duration Index (SAIDI) and System Average Interruption Frequency Index (SAIFI) and transmission customer delivery point standards are used to measure the service reliability and performance of the electricity system in Ontario. Given the growing concerns related to the impact of extreme events, customers have expressed interests in exploring opportunities to improve service reliability performance. For example, since extreme events can have an impact on a large number of people and services in a high-density area, urban areas may want higher levels of service reliability than provided for in the current service reliability standards. The cost of improving service reliability varies depending on geography, the nature of the issue and the local system configuration. Potential options could include enforcing higher minimum standards for redundancy, undergrounding of overhead facilities and/or enhancing distributed energy resources, such as customer-owned generation. For example, it can be very costly to provide the infrastructure needed to meet or improve service reliability in rural, remote and sparsely populated areas. As utilities and customers explore opportunities to improve service reliability and performances, the discussion of cost responsibility and willingness to pay would be an important consideration. According to the OEB s proposed beneficiary pays principle for cost-allocation, the responsibility to pay for higher reliability would likely be borne by the customers in the area. 24
TOOLS AND MEASURES TO MANAGE CHANGING OPERATING CONDITIONS 25
Changing Operating Conditions Over the planning period, changes such as increases in variable renewable generation and distributed energy resources, nuclear decommissioning and refurbishments, aging and end-of-life transmission facilities, and changing customer demand patterns could present new operating conditions and challenges, such as: System Voltage Performance Issues System Congestion Operating Variability and Uncertainty Surplus Baseload Generation Going forward, the IESO will continue to monitor, assess, and manage these issues. New facilities, tools and/or measures will need to be in place to help maintain system reliability and operability. 26
Managing Voltage Performance Issues System voltages are sensitive to changes in demand, system configuration, power flows on the transmission system, and the availability of voltage regulating devices. The electricity system must have the ability to control voltage within acceptable ranges defined by the reliability standards established for planning and operating the power system. System voltages are sensitive to changes in demand, system configuration, power flows on the transmission system, and the availability of voltage regulating devices. In general, low power transfers (e.g., low grid demand could reduce power flow) on the transmission system can lead to high voltage conditions while high power transfers can provide low voltage conditions. 27
Voltage Performance Issues Are Becoming More Prevalent High voltage conditions are already emerging in the GTA, Northwest and Northeast and are expected to be more severe and widespread over time due to evolving demand and supply conditions. Some examples are: Flat demand forecast and increasing distributed energy resources are expected to increase the prevalence of low grid demand conditions. Lower grid demand reduces power transfers across the transmission system, leading to high voltage conditions. Outages and retirement of large, transmission-connected generation facilities reduces the number of generators available to help control voltages The prevalence of variable renewable generation means that sizable amounts of generation output could abruptly drop in a region, resulting in high voltage conditions or short-term spikes. In other parts of the province, low voltage conditions are expected to arise High forecast demand growth in the Ottawa area coupled with potential increased power transfers with Quebec could lead to more frequent low voltages conditions and voltage instability in the event of a major outage. In northeastern Ontario, the retirement of local generation facilities could create low voltage conditions that would need to be managed. 28
Tools and Measures to Control System Voltage New facilities, tools and/or measures will need to be in place to help manage voltage performance issues across the province. This could include a combination of: Traditional devices used to control voltages include shunt reactors (to reduce voltage) and shunt capacitors (to increase voltage) Devices such as static-var compensators (SVC), static synchronous compensators (STATCOM), and synchronous condensers in circumstances where dynamic response or other reactive power services are required Generator voltage regulation control 29
Managing System Congestion System congestion refers to instances during the operation of the power system when there is not enough transmission capacity available to accommodate scheduled economic generation dispatch. This can result in some generators being uneconomically constrained off while others have to be constrained on, resulting in higher costs for that hour of operation. Over the long-term, a manageable level of congestion reflects an efficient utilization of transmission facilities. In an effort to maximize the use of the existing system to accommodate new resources, many parts of the system are becoming fully utilized and frequently congested, especially in Northern Ontario, West GTA and southwestern Ontario. The current system congestion level is still manageable. However, changes in demand and supply over the coming decades will have additional impacts on system congestion: Congestion is expected to increase as more variable and distributed energy resources come into service The retirement of nuclear facilities in the GTA may increase flows from southwestern Ontario towards the GTA, resulting in higher congestion in the southwest and western GTA areas. If demand in the north declines, congestion levels could increase. On the other hand, demand growth could provide congestion relief. The IESO will continue to manage system congestion by: Monitoring the system closely and exploring market designs and mechanisms to mitigate the its impacts Carefully evaluating the impact of congestion and considering transmission expansion to enable further integration of resources in future resource procurements 30
Variable Generation and Flexibility Variable generation penetration is increasing causing system operating conditions to become increasingly variable and uncertain. There is an underlying amount of uncertainty when scheduling variable generation due to the nature of the fuel source (wind, sun, water etc.). The impact of this uncertainty increases as the amount of VG on the system is increased. This will have an impact on real-time operations in terms of: load-following flexibility and potential surplus baseload generation. With increased variable generation in our changing supply mix, the nature of load-following and Ontario s SBG profile will become increasingly variable and uncertain. As total installed VG capacity increases, so too does the impact (MW magnitude) of forecast uncertainty 31
Managing Variability and Uncertainty System operability is a measure of how well resources can reliably be coordinated to deliver power to loads in real-time, in all expected conditions. There is an increasing need to implement and utilize tools and measures to manage the variability and uncertainty. Some examples are: Remedial Action Schemes (RAS): refer to automatic protection systems designed to detect and correct predetermined/abnormal system conditions. It is expected that additional RASs may be required in the future. Control Devices: Flexible Alternating Current Transmission Systems (FACTS) deliver continuous response to system conditions without need for operator control. It may become necessary to invest in additional FACTS. System Load-Following Capability and Flexibility: This can be provided by real-time generator dispatch and Operating Reserve (real-time market mechanisms) and frequency regulation (acquired through contracts). The IESO is currently quantifying the need for additional flexibility in the 30 minute timeframe. This need is a direct result of realtime forecast errors increasing in magnitude (e.g. from increasing VG capacity online) and the need to more frequently bring significant amounts of generation online with short notice. The solution may be to increase the amount of ancillary services scheduled (regulation, OR), design a new flexible load-following product, increase intertie scheduling frequency or some combination of these. Coordination with Distributed Energy Resources (DER): Several projects are currently in pilot stage, but DERs may eventually play a larger role in helping manage the bulk system, including providing load-following and flexibility. 32
Surplus Baseload Generation (SBG) Surplus Baseload Generation occurs when baseload generation* is higher than the Ontario Demand plus net exports. This is a function of both the supply mix (more baseload units more potential SBG) as well as the demand profile. To maintain a reliable and stable system, supply and demand must be kept in balance, requiring surplus energy mitigation tactics. Currently, most of Ontario s surplus is managed economically through the market via exports to neighbouring jurisdictions. The remaining SBG is managed by diverting water from hydro turbines ( hydro spill ); curtailing wind and solar; and manoeuvering or shutting down units at Bruce NGS. SBG levels decline overtime as units from Pickering NGS retire and as units at Darlington and Bruce NGS are brought outof-service for refurbishment. SBG as Percent of Ontario Net Demand 10% 8% 6% 4% 2% 0% 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 Year * The expected baseload generation includes nuclear generation, baseload hydroelectric generation, and intermittent generation such as wind and solar. 33
Data for Slide 33: SBG as Percent of Ontario Net Demand (Outlook B) Year Ontario SBG As Percent of Net Demand 2016 9% 2017 7% 2018 6% 2019 7% 2020 6% 2021 3% 2022 3% 2023 1% 2024 4% 2025 1% 2026 1% 2027 2% 2028 2% 2029 2% 2030 2% 2031 1% 2032 2% 2033 2% 2034 3% 2035 2% 34