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Handbook on Electricity Markets edited by Jean-Michel Glachant, Paul Joskow, and Michael G. Pollitt. (Edward Elgar Publishing, 2021), 672 pages, Print ISBN 978-1-78897-994-8, Online ISBN 978-1-78897-995-5 In the Handbook on [...]

This article provides recommendations for the market design of Alberta's power market in the 21st century. The authors suggest adapting the market to accommodate a changing resource mix, ensure affordability and reliability, and promote decarbonization. They propose implementing a mandatory forward energy-contracting mechanism, modernizing the energy-only market with locational pricing and multi-settlement markets, and deploying interval meters to encourage flexible demand. The authors argue that these changes will enable the market to reflect the increasing variability on the supply side and flexibility on the demand side. They also address the need for regulatory intervention to ensure reliability in electricity markets and propose a standardized forward energy-contracting approach as a solution. Additionally, the article highlights the importance of changes to short-term markets to ensure reliability and security of supply during operations. The authors recommend implementing locational pricing, a day-ahead market, new ancillary service products, and widespread deployment of interval meters. They conclude that these recommendations, coupled with changes to short-term operations and increased involvement from the demand side, can improve reliability at a lower cost compared to alternative market designs. [Extracted from the article]

Alberta’s history with coal development goes back to 1874, but 21st century social, economic and environmental factors demonstrate that it’s not in the public interest to pursue coal mining on the Eastern Slopes of the Rocky Mountains. This paper uses a multiple account benefit-cost analysis to compare the positives and negatives of a hypothetical coal mine in the eastern foothills of the Rockies. We provide estimates of the economic, social and environmental impacts, and evaluate how coal mining affects different stakeholders. The economic benefits — $440 million in undiscounted incremental tax revenues and $35 million in undiscounted incremental employment earnings — are overshadowed by the costs arising from the displacement of ranching, tourism and the negative environmental effects on water, vegetation, air and wildlife. Compounding these effects is the non-zero probability that the Alberta government will pick up the tab for reclamation costs, and the adverse social impacts on local communities and on Indigenous Peoples’ rights and interests. Therefore, any new coal mine development is unlikely to provide the province with a net benefit. Following on the heels of the federal government’s rejection of the Grassy Mountain coal project in southwestern Alberta, the provincial government should consider banning coal mining in the Eastern Slopes. Any future coal development policy should include a public-interest test that examines both monetary and non-monetary impacts. This paper finds an estimated undiscounted profit before taxes and royalties of $511 million to the mine developer. Discounting that value by a rate of eight per cent, which would approximate the opportunity cost of investors’ capital, shows coal mines are at best a break-even proposition from a private perspective. Only under optimistic price and activity assumptions does the mine earn a net profit. Tax revenues would be marginal and additional labour income would accrue to only a few individuals. These benefits would be vastly outweighed by the adverse effects on a much greater population, including Indigenous Peoples. Further, the Eastern Slopes already suffer the effects of current forestry, oil and gas, ranching, road development and recreational activities. Water quality and habitat for such wildlife as the Westslope cutthroat trout would be significantly compromised. With coal markets in a long-term decline due to coal’s impact on climate change and the focus on transitioning to alternative energy sources, new coal mine projects in Alberta would be counter-productive in many ways. The comparatively small economic benefits derived from a new coal mine could not possibly justify the large and possibly irreversible damage done to the environment, local communities and to the rights and interests of Indigenous Peoples. [ABSTRACT FROM AUTHOR]

In roughly two years, and well ahead of schedule, Alberta is expected to have completely transformed its electrical grid from being largely powered by coal to instead being powered by natural gas, hydroelectricity, wind and solar. By 2030, however, it is likely that another fuel source will compete with natural gas as a major part of Alberta’s power grid: namely hydrogen. Fully decarbonizing Alberta’s electric power sector as Canada works to achieve its goal of net-zero greenhouse gas emissions will be challenging due to the lack of significant hydroelectric or any nuclear power in the province. However, Alberta has many advantages that make hydrogen feasible as a pathway to decarbonizing its power grid. First, the steam and combustion turbines that are powered by natural gas today to produce electricity in Alberta can be adapted to use hydrogen. Second, Alberta has vast amounts of natural gas that can be used to produce hydrogen, and ample geology for underground carbon capture and storage for the greenhouse gases emitted in producing hydrogen. And third, in periods where the province’s renewable energy sources produce excess electricity, that power can be used to produce hydrogen, which can be stored for later use when renewable energy is less available. These advantages, combined with certain federal and provincial policies, position hydrogen to play a significant role, providing low-emission firm power when variable solar and wind power are unable to meet the province’s power demands. Given the limits of battery storage capacity, cost, and technology beyond hourly & possibly overnight use, storing hydrogen for multi-hour, -day and seasonal storage in underground, salt caverns appears to be a practical alternative for Alberta. Absent government policy, hydrogen-based power costs would likely remain uncompetitive in Western Canada, where natural gas is abundant and cheap. However, Alberta’s climate policy, with its output-based allocations regime, is set to combine with the federal government’s plan to raise the carbon price to $170 per tonne to make all forms of hydrogen-based power production more cost-effective than natural gas in the province after 2030. The potential for Alberta to transition to a reliable, low-carbon electricity grid will require that any future adjustments to the output-based allocations regime consider the impact on the economics of hydrogen investment and production. The government should also ensure that Alberta reserves its salt caverns for eventual use as hydrogen storage and that any newly installed turbines are capable of being easily retrofitted to use hydrogen as fuel. Hydrogen is an opportunity to bridge today’s system, based on fossil fuels, to tomorrow’s net-zero fuels and technologies. It is an opportunity that Alberta is well-positioned to seize. [ABSTRACT FROM AUTHOR]

Electrifying as many end-uses as technically and economically feasible is a key strategy for achieving net-zero greenhouse gas (GHG) emissions. However, “electrifying everything” is not currently a practical or economical option for everything. In many of these hard-to-decarbonize sectors, hydrogen has a role to play. Hydrogen and hydrogen derivatives can play a key role in certain emission-intensive sectors that are important to Canada’s economy, including steel, chemical and clean fuel production, and possibly heavy freight, long distance rail, and other off-grid end-uses that currently depend on diesel motors. In a companion piece, we discuss the role for hydrogen in electricity systems. Unlike oil and gas, whose resources are isolated to only some parts of the country, hydrogen has the potential for broad participation across Canada due to the ability to produce it from hydrocarbons and clean electricity. The former is likely to dominate in the near term, whereas declining costs for hydrogen from electricity should tilt the economics in that direction in the longer run. In all cases, however, regulators and policy makers should be focused on life-cycle emissions from the production process rather than arbitrary colour classification schemes. Canada’s natural advantages in producing clean hydrogen also puts it in a position to capitalize on new export opportunities from hydrogen-derived products. It already has one of the cleanest steel-production facilities in the world in Québec, a technology that can be adapted to operate on 100% hydrogen. Opportunities exist for Canada to become a green iron or steel exporter, from Québec or even possibly Alberta with its unused iron ore deposits and abundance of hydrogen potential. For hydrogen to reach its potential, there are some key areas where government policy and support will be needed. From helping to establish clean hydrogen industrial clusters, where firms share production and storage infrastructure, to ensuring hydrogen refueling networks for transport are established with sufficient breadth needed for heavy freight transport, government has a role to play in setting up the landscape for innovators to thrive. Ultimately, hydrogen will not solve every decarbonization challenge Canada faces, but it will have a critical role to play as a complement to a variety of strategies aimed at reaching net-zero emissions. Hydrogen has had many “hype cycles” before, and while it is no panacea for decarbonization, it is now genuinely poised to help Canada achieve its net-zero goals. [ABSTRACT FROM AUTHOR]

The article offers information on a roundtable by the School of Public Policy that brings experts in electricity markets on March 18, 2019, to discuss the role of storage from policy, engineering and system design perspectives. It mentions that storage can play an important role in very short-term ancillary services for the electric grid to maintain reliability; and also mentions that storage can increase the ability of electricity demand to respond to swings in intermittent demand.