Relevant • Independent • Objective

CERI Electricity Report Editorial Committee: Ganesh Doluweera, Paul Kralovic, Karen Mascarenhas, Dinara Millington, Megan Murphy, Allan Fogwill About CERI The Canadian Energy Research Institute is an independent, not-for-profit research establishment created through a partnership of industry, academia, and government in 1975. Our mission is to provide relevant, independent, objective economic research in energy and related environmental issues. For more information about CERI, please visit our website at www.ceri.ca or contact us at info@ceri.ca.

MW for import with BC.3 These interties support reliability, attract generation investment, and can provide immediate access to power to assist in emergency situations.4 Figure 1: Interties between Alberta and Neighbouring Jurisdictions

Source: AUC5

Figure 2 shows the flows on the BC-AB interconnection from the years 2012-2016. Over the past 5 years, export volumes out of AB (Table 1) have been steadily increasing. In 2016, AB was a net exporter (first time in 14 years), sending an average of 556 GWh to BC and receiving 283 GWh.6 This was due to low pool prices, leading to a decrease in imports, while encouraging greater exports. Figure 2: BC-AB Intertie: Alberta Flows

Source: AESO, CERI

Interprovincial Electricity Trade: The British Columbia-Alberta Intertie Karen Mascarenhas With special thanks to Laura Johnson and Faezeh Mosallat for their work in developing this quarterly report. Trading electricity via import and export between regions has many benefits. First, a province could benefit from having the ability to import power when electricity is cheaper in other markets and export surplus power when prices are higher, leading to economic efficiency. Second, exchanging power could have environmental benefits. For example, British Columbia (BC) produces over 90 percent of its electricity generation from hydro dams while Alberta (AB) currently generates more than 50 percent of its electricity from coal-fired power plants.1 BC’s hydroelectric supply can help Alberta to reduce its carbon emissions, by replacing power from higher emitting sources with cleaner power. Similarly, excess power in Alberta (mostly during off-peak hours), can be stored in BC’s pumped hydro storage facilities, which could ultimately be exported back to Alberta when wind or solar production are deficient.2 Currently, any excess power production in Alberta is exported to other provinces, with BC receiving about 65 percent of total exports in 2016. For these exchanges to occur, BC Hydro and the Alberta Electric System Operator (AESO) maintain an interconnection agreement for the intertie between AB and BC (WECC Path 1), with a rated capability of 1,000 MW for export to BC and 1,200 MW for import from BC. Figure 1 shows the interties between Alberta and BC, including other neighbouring jurisdictions. The current total transfer capability is 1,000 MW for export and 800

March 2017

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Table 1: Annual Intertie Statistics for Alberta

*System totals include BC, SK and Montana Source: AESO

Flows on the intertie do not run at full capacity. Certain factors would prevent larger volumes of power exchanges between AB and BC. For instance, BC has an option to export power to the United States (US) at the Mid‐Columbia (Mid‐C) trading hub, or to sell its power to AB at the intertie. To maximize revenues, BC sends more power along the intertie when prices of electricity in AB are higher, usually during peak demand hours.7 During low off peak prices, BC benefits from importing excess power and saving water for future electricity generation. BC applies similar strategies with the US markets, using the difference in prices to make import and export decisions. Another factor for under-utilization of the intertie could be related to the different market structures in the two provinces. AB transmission rights follow dispatch of generation through Power Pool bidding, while BC gives users explicit transmission rights which must be purchased on an hourly basis. AB importers are price-takers who must consider both potential losses and transmission payments. Therefore, under utilization of intertie capacity could occur due to wholesale price differentials, as well as a lack of market incentives. The electric systems of AB and BC are interconnected through the following lines:8

500 kV Bennett (AB) to Cranbrook (BC) - 1201L/5L94 138 kV Pocaterra(AB) to Natal (BC) - 887L/1L274 138 kV Coleman (AB) to Natal - 786L/1L275 BC Hydro owns British Columbia’s portion of the 500 kV Cranbrook-Bennett (CBK) line, while Alberta’s portion is owned by AltaLink.9 The CBK bus voltage has a nominal value of 525 kV and ranges from 545 kV for light load/zero interchange to 500 kV for heavy load/high interchange. The line’s end reactors are switched off for voltage control only during emergencies.10

BC Hydro operates the scheduling on the intertie with BC, and the AESO operates the scheduling in Alberta. The AESO manages intertie transactions through hourly scheduling, which sets out by at least 15 minutes in advance of a delivery hour, the potential flow of energy between regions along the intertie.11 This schedule starts at the beginning of the hour and finishes at the end of the hour, with no changes allowed within the hour (except for emergency or security reasons). This is not a technical constraint, but rather part of an agreement which perhaps could be re-negotiated if AB intends to take advantage of BC Hydro’s assets as storage for its renewables. To increase flows between the two provinces, the existing transmission intertie between AB and BC needs to be reinforced to utilize its full 1,200 MW capacity.12 A key project between the AESO and BC Hydro is to restore the BC-AB intertie to its full path rating.13 The double circuit 240 kV lines that connect Chapel Rock substation to the Castle Rock Ridge substation is significant in restoring Path 1 to its ratings (1,200 MW import from BC and 1,000 MW export to BC). The Castle Rock Ridge to Chapel Rock Transmission Project is part of an area transmission development called the Southern Alberta Transmission Reinforcement. The proposed project includes:14

building a new substation, to be called Chapel Rock

Substation; building a new 240 kV double circuit transmission

line (20-41 km approx.) from the existing Castle Rock Ridge Substation to one of the proposed Chapel Rock Substation locations;

building a new 500 kV transmission line (1-13 km approx.) depending on the location of the Chapel Rock Substation;

building a new telecommunications tower; expansion of the existing Castle Rock Ridge

Substation. A joint study between the Alberta Interconnected Electric System (AIES) and BC Hydro considers a range of scenarios, which include all the issues that limit the interchange to below its path ratings. Various scenarios for different years were created, with and without Chapel Rock, in order to analyze how the Chapel Rock substation would improve both system reliability and performance.15 This project provides an alternative transmission path for imports from BC and helps to

Year British Columbia (GWh) System Total (GWh)*

Imports Exports Net Imports

Imports Exports Net Imports

2012 3,064 59 3,006 3,579 82 3,497

2013 1,902 223 1,679 2,546 257 2,289

2014 1,311 384 926 2,050 557 1,493

2015 732 460 273 1,091 651 440

2016 283 556 -273 435 867 -432

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resolve the overload issues associated with the Bennett 500/240 kV transformer and the 500 kV line from Chapel Rock to Bennett substation. These projects expect to be completed in the year 2018. Endnotes 1Zakro Kolaric, Analysis of Power Trading Dynamics between British Columbia and Alberta with ZEMA, http://www.blog.ze.com/2014/11/power-trading-dynamics-between-british-columbia-and-alberta/ 2Jeffery English, The Role of British Columbia in Meeting Alberta’s Energy Goals, https://onlineacademiccommunity.uvic.ca/2060project/2016/04/20/663/. 3AESO, https://www.aeso.ca/market/current-market-initiatives/intertie-restoration/ 4Interties: Alberta’s Power Connector, http://www.atcoelectric.com/Projects/HVDC/Resources/Documents/Virtual%20Information%20Session%20Handouts/Interties-Albertas-Power-Connector-AESOFactSheet.pdf 5Alberta Utilities Commission: Objections to ISO rules Section 203.6 Available Transfer Capability and Transfer Path Management, Page5, http://www.auc.ab.ca/applications/decisions/Decisions/2013/2013-025.pdf 6AESO, Annual market statistics reports, https://www.aeso.ca/market/market-and-system-reporting/annual-market-statistic-reports/ 7http://web.uvic.ca/~kooten/documents/BCgeneratingSystem.pdf

8Intertie Restoration Project: AESO - BCH Joint Planning Study, AESO, 2015. 9Jeff Christian, Krista Hughes, The BC – Alberta Intertie: Impact of Regulatory Change, Lawson Lundell, 2004, http://www.lawsonlundell.com/media/news/241_BC-AlbertaIntertie.pdf 10BC Hydro Real Time Operations Operating Order 7T-17: BC-Alberta Interconnection, 2015 11http://www.auc.ab.ca/applications/decisions/Decisions/2013/2013-025.pdf 12AESO, (2015b). Intertie Restoration Project: AESO -BCH Joint Planning Study. Alberta Electric System Operator. Retrieved from http://www.aeso.ca/market/20238.html 13Government of Canada, Annex II: Provincial and territorial key actions and collaboration opportunities with the Government of Canada, https://www.canada.ca/en/services/environment/weather/climatechange/pan-canadian-framework/annex-key-actions-collaboration.html?=undefined&wbdisable=true 14http://www.altalink.ca/projects/view/48/castle-rock-ridge-to-chapel-rock-transmission-project 15Intertie Restoration Project: AESO - BCH Joint Planning Study, AESO, 2015

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Major Generation Projects in Canada

Major Transmission Projects in Canada

NameProvince/

Territory

Capacity

(MW)

Expected

In-Service DateStatus

Site C

(Hydroelectric dam)British Columbia 1,100 2024

Construction began in July 2015.

The Peace River construction bridge was completed in March

2016.

Romaine Hydro Project

(Hydroelectric complex consisting of 4 individual

plants)

Quebec 1,550

The first plant was commissioned in 2014.

The second, third and fourth scheduled for

2016, 2017 and 2020.

Construction of the Romaine-2 development began in 2009;

Romaine-2 was commissioned in 2014 and the Romaine-1

development was commissioned in 2015; Work on the

Romaine-3 and Romaine-4 developments, which will be

operational in 2017 and 2020, respectively is underway.

Lower Churchill Project

(Muskrat Falls and Gulf Island hydroelectric) Newfoundland

Muskrat Falls: 824

Gulf Island: 2,250

Muskrat Falls: 2017

Gulf Island: After Muskrat Falls

Construction on the Muskrat Falls Generating Facility started

in 2013;

Construction on the Labrador-Island Link started in 2014;

The Maritime Link is currently undergoing stakeholder

engagement and

is due to be completed in 2017

Keeyask Project

(Hydroelectric power plant)Manitoba 695 2021 Construction started in 2014

Bruce, Darlington and Pickering

(Nuclear Power Refurbishment) Ontario

Bruce: 6,300

Darlington: 3,500

Pickering: 3,100

6 Pickering units extended to 2022;

4 further extended to 2024

Darlington refurbishment will take

about 10 years to complete

Refurbishment commences in 2020 onwards

NameProvince/

Territory

Capacity

(kV)

Expected

In-Service DateStatus

Bipole III Transmission Reliability Project

(HVDC line)Manitoba 500 2018

The Environmental Protection Plan for the Riel Converter

Station Facilities; Infrastructure and Ground Electrode was

approved in August 2014; The first steel tower was raised in

March of 2016

Manitoba – Minnesota Transmission Project

(AC line)Manitoba 500 2020 Currently under regulatory review

Labrador - Island Transmission Link

(HVDC line)Newfoundland and Labrador 1,100 km 2020

Construction  is underway and expected to take five years

to complete.

Maritime Link Transmission

(HVDC and HVAC line)

Newfoundland and Labrador,

Nova Scotia 200 to 250

Commencement of operations

scheduled by the end of Q4 2017

Construction began in summer 2014 with clearing activities

for the 60 m wide transmission line right-of-way in Labrador.

Clearing on the island of Newfoundland began in winter

2015.

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