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«18 Month Outlook An Assessment of the Reliability and Operability of the Ontario Electricity System FROM APRIL 2015 TO SEPTEMBER 2016 18-Month ...»

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The existing transmission infrastructure in some areas in the province, as described below, have been identified as currently having or anticipated to have some limitations to supply the local needs. Hydro One and the IESO are considering long-term options to address these situations in accordance with local communities under the Regional Planning Process established by the Ontario Energy Board (OEB). Plans are currently active in the GTA, Greater Ottawa, Southwest Ontario, Northwest Ontario, and Western Ontario regions.

5.2.1 Toronto and Surrounding Area The load supply capability to the GTA is expected to be adequate to meet the forecast demand through to the end of this 18-month period.

The upgrading of the 115 kV breakers at Leaside Transformer Station (TS) and Manby TS was completed in Q4 2014. The remaining work at Manby TS covering bus reinforcement and insulator replacement is scheduled for completion by Q2 2016. These upgrades will allow additional generation to be incorporated into the Toronto 115 kV system and the distribution level by increasing the short-circuit capability of the 115 kV system.

March 23, 2015 Public Page 19 18-Month Outlook Update The development of Clarington TS has started with a scheduled in-service date of fall 2017.

This will ensure that the additional 500 kV to 230 kV transformation capacity required to maintain supply reliability, will be available before Pickering GS is shutdown. Without this additional capacity there would have been an increased risk of overloading the existing autotransformers at Cherrywood TS.

The associated 230 kV switching facilities at Clarington TS will also improve the supply reliability to the loads in the Pickering, Ajax, Whitby, Oshawa and Clarington areas by providing a full, alternative source of supply to these loads.

In central Toronto, Copeland TS was originally expected to be in service in Q3 2015 but is now scheduled to be in service in Q1 2016. The new station will allow some load to be transferred from John TS. This will help meet the short and mid-term need for additional supply capacity in the area and will also facilitate the refurbishment of the facilities at John TS.

High voltages in southern Ontario continue to present operational challenges during periods of light load requiring the temporary removal from service of at least one of the 500 kV circuits between Lennox TS and Bowmanville SS during those periods. The situation has become especially acute during those periods when the shunt reactors at Lennox TS have been unavailable due either to repair or maintenance activities. While the IESO and Hydro One are currently managing this situation with day-to-day operating procedures, the situation is expected to become more difficult once Pickering GS is shut down. Planning work for the installation of new voltage control devices has been initiated.

In order to increase the load-meeting capability of the two 230 kV circuits between Claireville TS and Minden TS and allow the proposed Vaughan TS No. 4 to be connected, Hydro One is planning to install two 230 kV in-line breakers at Holland TS, together with a load rejection scheme. These facilities are scheduled to be in service by early 2017. Until these facilities become available, operational measures will be required to avoid possible overloading of these circuits during peak load periods.

Transmission transfer capability in Toronto and surrounding area is expected to be sufficient for the purpose of supplying load in this area with a margin to allow for planned outages.

5.2.2 Bruce and Southwest Zones In the Guelph area, Hydro One has begun construction on the Guelph Area Transmission Refurbishment project to improve the transmission capability into the Guelph area by reinforcing the supply into Guelph-Cedar TS, with an expected completion date in Q2 2016. As part of this project, circuit switchers are to be installed at Guelph North Junction that will allow the 230 kV system between Detweiler TS and Orangeville TS to be sectionalized. These devices will reduce the restoration times for the loads in the Waterloo, Guelph and Fergus areas following a supply interruption.

Plans for a second 230/115 kV autotransformer at Preston TS, together with the associated switching and reactive facilities, are currently being revisited. Hydro One and the IESO are exploring options that will not only improve the load restoration capability to those customers in the Cambridge area affected by a major transmission outage, but also accommodate the March 23, 2015 Public Page 20 18-Month Outlook Update development of the Cambridge No. 2 transformer station on the 115 kV system between Preston TS and Detweiler TS to meet load growth in the area.

Further planning work is required to address the longer-term supply needs of the area beyond 2016 and also to satisfy the IESO's load restoration criteria.

Construction on Evergreen, a new 500 kV switching station, was completed in Q4 2014.

Ashfield, another 500 kV switching station, is planned to be in service by the end of Q1 2015.

These stations will incorporate close to 700 MW of renewable generation onto the system.

Hydro One is planning to replace the aging infrastructure at the Bruce 230 kV switchyard, with a completion date of June 2018. While this work is being implemented, careful coordination of the transmission and generation outages will be needed.





The transmission transfer capability in the Southwest zone and its vicinity is expected to be sufficient to supply the load in this area with a margin to allow for planned outages.

5.2.3 Niagara Zone Completion of the transmission reinforcements from the Niagara region into the HamiltonBurlington area continues to be delayed and the transmission congestion will still restrict connection of new generation in the area. This project, if completed, would increase the transfer capability from the Niagara region to the rest of the Ontario system by approximately 700 MW.

Hydro One completed work to replace existing 115 kV breakers at Allanburg TS in Q4 2014.

The new equipment will alleviate the short circuit capability issue which restricted connection of new generation in the area.

Transmission transfer capability in Niagara and its vicinity is expected to be sufficient for the purpose of supplying load in this area with a margin to allow for planned outages.

5.2.4 East Zone and Ottawa Zone To address load growth in the Ottawa area, a new load supply transformer station, Orleans TS, is expected to come into service by Q2 2015.

With further increases in the amount of load supplied from the 230 kV system in the Merivale area and with a minimum threshold of 400 MW on the level to which the transfers from Hydro Québec can be automatically reduced following the loss of one of the 230 kV Hawthorne-toMerivale circuits, there is an increased possibility that imports may need to be restricted during peak load periods. The situation may be especially challenging during periods of low hydroelectric output from the plants on the Ottawa and Madawaska Rivers, which is not uncommon during summer peak periods.

Transmission transfer capability in East Zone and Ottawa Zone is expected to be sufficient for the purpose of supplying load in this area with a margin to allow for planned outages.

5.2.5 West Zone Transmission constraints in this zone may restrict resources in southwestern Ontario. This is evident in the constrained generation amounts shown for the Bruce and West zones in Tables A3 and A6.

March 23, 2015 Public Page 21 18-Month Outlook Update Transmission transfer capability into the West zone is expected to be sufficient to supply load in this area with a margin to allow for planned outages.

5.2.6 Northeast and Northwest Zones In northeast Ontario, Hydro One is expected to finish the transmission work required to accommodate the increased output from the Lower Mattagami generation expansion project by the end of Q4 2015. Currently, Hydro One is reviewing changes to the existing line-connected reactors at Hanmer TS to allow post-contingency switching of these reactors to occur, thereby increasing the transfer capability of the Flow South Interface.

The limited reactive absorption facilities that are available in the Timmins area are proving to be a major obstacle to the restoration of the system in the northeast following an outage involving either of the 500 kV circuits. Maintaining the voltage below the agreed maximum of 550 kV during the restoration process, before the system can be loaded, has been challenging, particularly with the reduction that has occurred to the loads in the Timmins area.

Some loads in the north of Dryden to Pickle Lake area experienced significant growth over the last few years and recently indicated their intention to expand operations. The transmission circuits in the area are currently operating close to their capability. The IESO has issued an

Integrated Regional Resource Plan (IRRP) which recommends the following:

Building a new single circuit 230 kV transmission line from Dryden/Ignace area to Pickle • Lake (for the Pickle Lake subsystem), installing a new 230/115 kV autotransformer, related switching facilities, and the necessary voltage control devices at Pickle Lake, and transferring the existing load on the line between Ear Falls to Red Lake (E1C) to be supplied by this new line;

Upgrading the existing 115 kV from Dryden to Ear Falls (E4D) and from Ear Falls to Red • Lake (E2R) (for the Red Lake subsystem) and install the necessary voltage control devices;

and Having the IESO initiate discussions with Ontario Power Generation for new reactive power • services provided by Manitou Falls GS if it is confirmed to be beneficial to the ratepayer.

Transmission transfer capability in the Northeast and Northwest zones is expected to be sufficient to supply load in this area with a margin to allow for planned outages.

–  –  –

6 Operability Assessment This section highlights any existing or emerging operability issues that could potentially impact system reliability of Ontario’s power system.

6.1 Operation during Nuclear Outages Voltage control will be challenging during major scheduled outages, especially during off-peak periods. Studies to determine the best ways of controlling voltages have been completed and plans to manage grid security are already in place.

For the major nuclear outages scheduled for spring and fall 2015, the IESO has been actively working with transmitters, generators, natural gas pipelines and our interconnected neighbours to ensure reliable operation during this period.

6.2 Surplus Baseload Generation (SBG) Forecast Baseload generation is made up of nuclear, run-of-the-river hydroelectric and variable generation such as wind and solar. SBG conditions occur when the amount of baseload generation exceeds Ontario demand. However, when the baseload supply is expected to exceed Ontario demand plus scheduled exports, the IESO typically balances the system via export scheduling, nuclear curtailments and wind dispatch scheduled through the IESO-administered markets.

Nuclear maneuvering capability and dispatchable variable generation has provided additional flexibility to manage SBG, while also mitigating the need for manual control actions. These actions usually, but not always occur when Ontario demand is at its lowest.

Figure 6.1 shows the forecast SBG for the next 18 months and the flexibility from nuclear and variable generation.

Figure 6.1: Minimum Ontario Demand and Baseload Generation March 23, 2015 Public Page 23 18-Month Outlook Update Ontario will continue to experience SBG conditions during this Outlook period.

The steep decline in SBG in the spring and fall of 2015 is attributed to planned generation outages, as previously discussed in section 4.2 of this report. The vast majority of SBG can be managed through normal market mechanisms including export scheduling and nuclear maneuvering.

IESO’s variable generation dispatch tools have provided additional flexibility to alleviate most SBG events.

The baseload generation assumptions include market participant-submitted minimum production data, the latest planned outage information, in-service dates for new or refurbished generation, and reliable export capability. The expected contribution from self-scheduling and intermittent generation has also been updated to reflect the latest data. Output from commissioning units is explicitly excluded from this analysis due to uncertainty and the highly variable nature of commissioning schedules. Table 6.1 shows the monthly Off-Peak WCC values (with simulated wind output and actual historic wind output up to February 28, 2014).

These values are updated annually to coincide with the release of summer 18-Month Outlook.

Table 6.1: Monthly Off-Peak Wind Capacity Contribution Values Month Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Off-Peak WCC (% of Installed 33.

1% 33.1% 30.0% 33.0% 24.1% 15.2% 15.2% 15.2% 21.6% 28.4% 31.8% 33.1% Capacity)

6.3 Gas-Electric Interdependency The IESO continues to work on enhancing our existing communication protocols with gas pipeline and distribution system operators to facilitate information sharing, especially under tight supply conditions in either sector (gas or electric). This initiative may require Market Rule changes as well as technical interface changes. In addition to this, to prepare for the peak seasons, IESO meets with gas pipeline operators every six months (in April and October) to discuss gas supply and planned maintenance on the gas and electric systems.

The IESO continues to be involved in the Eastern Interconnection Planning Collaborative (EIPC) study work to evaluate the effects of gas infrastructure contingencies on the electrical system and vice-versa.

Full details pertaining to the EIPC effort, including study results and future activity plans can

be found via the following link:

http://www.eipconline.com/Gas-Electric_Documents.html

–  –  –

Phone: 905.403.6900 Toll-free: 1.888.448.7777 E-mail: customer.relations@ieso.ca ieso.ca @IESO_Tweets facebook.com/OntarioIESO

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