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.

Table 1: Current Installed Capacity in Alberta and Ontario1

The Alberta government’s Renewable Electricity Plan expects the development of 5,000 MW of renewable electricity between the years 2017 and 2030 (see Figure 1). The target of the program is to have at least 30% of the electric energy in Alberta produced from renewable energy resources.2 Moreover, the plan includes the phase-out of coal-fired electricity generation by 2030. The Alberta Electricity System Operator (AESO) is using an auction process to identify the lowest cost renewable electricity projects, which will qualify to receive support through a renewable energy credit payment mechanism.3 The results of Round 1 to procure a total of 400 MW that should be operational in 2019, and utilize the existing transmission system, will be announced this month.4 The current transition from the energy-only market design to a capacity market is also expected to spur investment and integrate renewables into the Alberta market.5 The Ontario government began its first renewable energy supply program in 2004, and subsequently enacted the Green Energy and Green Economy Act in 2009 to expand renewable energy supply.6 This included streamlining project construction and application processes, establishing a feed-in-tariff program with guaranteed prices under long-term contracts, and creating a process that exempted some projects from approval requirements under existing legislation. As shown in Figure 2, these policies resulted in the elimination of coal generation and a significant increase in solar and wind generation (<1% to 10%) over a decade. The target plan

Challenges of Transitioning to a Greener Grid in Canada Karen Mascarenhas Many countries are implementing environmental policies that oblige electric power generators to reduce their emissions. Canada’s new policies to reduce emissions are influencing the various transitions in the electricity sector of the different provinces. Some of these policies include phasing-out coal, implementing a carbon tax, and incentives and targets for integrating renewable energy generation sources. Demand-side management and energy efficiency policies, market and regulatory reform, and energy literacy, will all have a role to play in transitioning towards a cleaner grid. This article focuses on the transitions involved with integrating renewable energy in two major competitive electricity markets in Canada, namely Alberta and Ontario. Both provinces have implemented renewables policies, with Ontario leading the way since 2004, and Alberta just getting started. Alberta’s generation fleet is changing – the use of natural gas for power generation is increasing, coal units are retiring or converting to natural gas, and renewable resources are growing. With dissimilar resource structures (Table 1), Alberta could face different challenges than Ontario which has a greater penetration of hydro, wind, and nuclear.

December 2017

CERI Electricity Report

Resource Type Alberta (MW)

Ontario (MW)

Coal 6,273 -

Natural Gas 7,324 10,277

Hydro 916 8,480

Wind 1,490 4,213

Nuclear - 13,009

Biogas & Biomass 423 495

Solar - 380

Total 16,525 36,854

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is to have a total of 20,000 MW of renewable energy generation online by 2020, which amounts to around half of Ontario’s installed capacity.7 Figure 2: Ontario Generation Profile Year 2005 and 2016

Source: IESO

The addition of renewables to the grid comes with various challenges. First, it will either require the addition of new energy transmission infrastructure or it will affect the existing transmission system by rendering some assets stranded. If existing and planned capacity is utilized efficiently, new generation may be connected without significant building new transmission. Developers could also be incentivized to build new generation near existing transmission lines. The AESO estimates that with existing steel in the ground,

approximately 2,600 MW of renewable generation could be added to the grid.8 Long-term transmission and system planning would need to manage uncertainties, increase incremental capacity in a timely manner, and enable transmission capacity in areas with higher resource potential such as southern and eastern Alberta. To better utilize existing transmission assets, other technical options could be examined. For example, instead of building new lines, new standards to increase line ratings could be added to existing lines according to current environmental conditions. An example of this standard is “dynamic thermal line rating” and real-time line loading. Research is being conducted on ways to benefit from the relationship between temperature, conductor resistance and voltage drop across a line, with the final objective of increasing the rating of a non-thermally limited line.9 Furthermore, as integrating renewables will change traditional power flow patterns, transmission adequacy is vital. The AESO transmission planning team proposes HVDC lines, as these support a robust grid capable of handling new flow patterns. Increased investment in transmission in Ontario enabled the integration of new renewable energy sources and expanded access to neighboring electricity markets.10 The long-term value of a more integrated system between the various systems, provinces, and jurisdictions has its own set of challenges, and therefore,

Figure 1: Alberta Generation Profile Forecast

Source: AESO

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needs further assessment. Expanding the interties between provinces could help with grid stability, especially when there are larger amounts of variable generation. Second, increasing variable generation will require flexible resources to successfully maintain reliability. Ontario’s transition experience identified potential operating challenges that included resource flexibility, frequency regulation, operating reserve, and voltage control. To this end, the province recognized the need for more flexibility from their resources, additional regulation capability, and for greater dynamic and static reactive control devices to better manage voltages.11 Other issues included load and distribution-connected generation modelling, system inertia, and performance.12 Alberta could learn by accounting for these challenges as variability and uncertainty might need to be addressed through a restructure of the market. Third, some other technical challenges include improving forecasting and storage.13 The rise in renewables will bring about a need for new and more accurate forecasting techniques for both demand and variable supply like wind energy. To address issues related to variability and dispatchability, bulk energy storage such as pumped hydro or other storage options could provide system reliability. Energy storage is valuable in creating capacity and ramping capabilities to complement other sources of generation.14 Ontario focused on four important areas related to renewable generation when planning their system integration. These include forecasting, dispatch, visibility and future markets. Final design principles prepared in 2010 included: 15

“1: The IESO will implement a centralized forecast for all wind and solar resources with an installed capacity of 5 MW or greater and all wind and solar resources directly connected to the IESO-controlled grid. 2: Real-time forecast data will be used for variable generation dispatch and actual real-time data will be used for calculating foregone energy to support Ontario Power Authority contract settlement. 3: The costs paid to the centralized forecast service providers will be treated as procured service charges and will be recovered from

consumers through existing procurement market recovery mechanisms. 4: All variable resources subject to centralized forecasting will provide static plant information and data. 5: All variable resources subject to centralized forecasting will provide dynamic data (real-time telemetry). 6: All forecasts of facility output for resources subject to centralized forecasting will be publicly available. 7: All variable resources connected to the IESO-controlled grid, and embedded variable resources that are registered market participants, will be actively dispatched on a five-minute economic basis. 8: Variable generators will operate within a compliance deadband when ambient conditions offer sufficient fuel. 9: Variable generators will be entitled to Congestion Management Settlement Credit payments. 10: The IESO may establish various floor prices for offers from baseload generators (e.g., wind, must-run hydro, nuclear, etc.) to ensure efficient dispatches during periods of local and/or global surplus baseload generation (SBG) events. 11: Directly connected variable resources (and embedded resources that are market participants) will be eligible to participate in operating reserve and ancillary markets where technically feasible (such integration will be considered on a cost-benefit basis, and is not likely to be addressed in the near term).”

The issues related to renewable energy integration could be managed by aiming for generation profile diversity. They could also potentially influence the cost of generation and transmission, and consequently electricity rates paid by residential, commercial, and industrial customers. Future studies would need to analyze these impacts in further detail. In recent years, the electricity landscape has been changing rapidly. Grid modernization, the rise of distributed energy resources, net-metering policies, and growing energy efficiency requirements are challenging the traditional business model of utilities. Disruptions such as the emergence of prosumers, microgrids, digital tools, and new technology will require utilities to plan to meet all these demands.

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Endnotes 1AESO and IESO 2017 capacity values 2https://www.alberta.ca/climate-leadership-plan.aspx 3National Energy Board’s Energy Futures Series, Canada’s Energy Future 2017: Energy Supply and Demand Projections to 2040 (Energy Futures 2017) 4https://www.aeso.ca/market/renewable-electricity-program/first-competition/ 5See CERI article on Alberta’s Capacity Market: https://www.ceri.ca/market-updates/alberta-capacity-market-the-new-market-unfolds 6https://www.ontario.ca/laws/statute/S09012 7https://www.ontario.ca/document/2013-long-term-energy-plan 8https://www.aeso.ca/assets/Uploads/REP-QA.pdf

9Leanne Dawson, Andrew Knight. Applicability of Dynamic Thermal Line Rating for Long Lines, April 6, 2017: http://ieeexplore.ieee.org/document/7893791/ 10Ontario Planning Outlook “A technical report on the electricity system prepared by the IESO,” September 2016 11David Short, IESO Market Awareness Session, May 5, 2016 12IESO 2016 operability study 13https://www.aps.org/policy/reports/popa-reports/upload/integratingelec.pdf 14G. Kent Fellows, Michal C. Moore and Blake Shaffer. “The Challenge of Integrating Renewable Generation in the Alberta Electricity Market”. 15http://www.mccarthy.ca/article_detail.aspx?id=5438

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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 province has decided to

finish construction on this controversial project after the

BCUC review

Romaine Hydro Project

(Hydroelectric complex consisting of 4 individual

plants)

Quebec 1,550

The first generating station was

commissioned in 2014 and the

second in 2016.

The third and fourth generating

stations will be operational in 2017

and 2020 respectively

Construction Work on the Romaine-3 and Romaine-4

developments is underway.

Lower Churchill Project

(Muskrat Falls and Gull Island hydroelectric) Newfoundland

Muskrat Falls: 824

Gull Island: 2,250

Muskrat Falls: 2018

Gull Island: 3 years after Muskrat

Falls

Construction on the Muskrat Falls Generating Facility started

in 2013 and is currently ongoing.

Keeyask Project

(Hydroelectric power plant)Manitoba 695 August of 2021 Construction started in 2014 and is progressing.

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

Refurbishement of the Darlington station is underway. Bruce

and Pickering commences in 2020 onwards.

Genesee 4 & 5

(Combined cycle natural gas-fired generation) Alberta 1,060 Awaiting decision

Received all regulatory approvals. Awaiting market structure

certainty- project completion in 2 phases

Brazeau hydro (pumped storage) Alberta 900 2025 Currently under review

NameProvince/

Territory

Capacity

(kV)

Expected

In-Service DateStatus

Bipole III Transmission Reliability Project

(HVDC line)Manitoba 500 2018 Project construction is almost complete

Manitoba – Minnesota Transmission Project

(AC line)Manitoba 500 2020 Currently under regulatory review

Labrador - Island Transmission Link

(HVDC line)Newfoundland and Labrador 450 2020 Transmission towers installed

Maritime Link Transmission

(HVDC and HVAC line)

Newfoundland and Labrador,

Nova Scotia 200 to 250 2017 Construction began in 2014

Fort McMurray West Transmission Project (AC line) Alberta 500 2019

West route option approved while the east route option is

currently awaiting approval

Chamouchouane–Bout-de-l’Île Transmission Line Quebec 735 2018 Construction began in 2015

Romaine Complex Transmission Line Quebec

500 km lines- 315 and

735 kV 2020 Construction began in 2011

Atlantic Link project (110-mile submarine HVDC) New Brunswick 1,000 MW unknown Currently in public review process

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