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( 2021) directly address several key sectoral debates, especially the roles of variable wind and solar versus on-demand clean power options (e.g., geothermal, hydrogen turbines, nuclear, or fossil fuels with carbon capture and storage [CCS]), and human-made versus agricultural and land use sinks. There is wide agreement on the key strategies for deep decarbonization: (1) demand but not necessarily end-use service reductions (e.g., reduced home heating needs through efficiency and electric heat pumps), (2) decarbonization of the end-use electricity, liquid and gaseous fuels, and feedstocks used by households and firms, and (3) the use of land-use and human-made negative emissions measures, including biomass combustion or direct air CO2 capture (Keith et al., 2018) followed by CCS, to directly return CO2 to the geosphere (Baker et al., 2020; Bataille et al., 2016; Clarke et al., 2014; Grubler et al., 2018; Van Vuuren et al., 2018; Williams et al., 2012). Industry may bear further exploration, as it still consumes significant amounts of fossil-fuel crude oil and methane in the least cost scenario, and expensively but renewably sourced biomass liquid fuels and gases in the 100% renewable scenario; it's mainly business-as-usual with cleaner feedstocks and CCS. Since the Paris Agreement, which pushed the global target for this century from a maximum −80% reduction to net-zero & negative, transformational technical if not yet commercial means have been established to reduce all industrial emissions to very low or negative levels.

The Paris Agreement introduces long-term strategies as an instrument to inform progressively more ambitious emission reduction objectives, while holding development goals paramount in the context of national circumstances. In the lead up to the twenty-first Conference of the Parties, the Deep Decarbonization Pathways Project developed mid-century low-emission pathways for 16 countries, based on an innovative pathway design framework. In this Perspective, we describe this framework and show how it can support the development of sectorally and technologically detailed, policy-relevant and country-driven strategies consistent with the Paris Agreement climate goal. We also discuss how this framework can be used to engage stakeholder input and buy-in; design implementation policy packages; reveal necessary technological, financial and institutional enabling conditions; and support global stocktaking and increasing of ambition.The Deep Decarbonization Pathways Project develops a framework to design low-emission development pathways. This Perspective discusses the framework and how it can support the development of national strategies to meet climate targets, as well as help achieve stakeholder engagement.

This paper explores the role that hydrogen can play in helping Alberta decarbonize its electricity system. Alberta has an abundance of natural gas resources that can be converted to hydrogen fuel and further used to generate electricity either through a turbine or through a fuel cell. Since Alberta has a significant portion of its current electricity needs supplied by combustion and steam turbines, such turbines can be repurposed to use hydrogen fuels and therefore reduce the amount of stranded assets as the province moves towards lower emissions in the electricity industry. Using hydrogen in the electricity industry can also complement a higher percentage of variable renewable energy resources, like wind and solar, by absorbing excess generation via electrolysis and providing much needed reliability as a peaking product. The carbon price and associated carbon policy in Alberta appears to be a key driver incentivizing hydrogen use in the electricity industry. Our model comparing the marginal costs of natural gas versus hydrogen for electricity production concludes that with the current carbon policy in Alberta and a rising carbon price to $170 per tonne CO2e in 2030, hydrogen has the potential to compete with natural gas as a dominant, \"on-demand\" power source.

After nearly two decades of debate and fundamental disagreement, top-down and bottom-up energy-economy modelers, sometimes referred to as modeling 'tribes', began to engage in productive dialogue in the mid-1990s (IPCC 2001). From this methodological conversation have emerged modeling approaches that offer a hybrid of the two perspectives. Yet, while individual publications over the past decade have described efforts at hybrid modeling, there has not as yet been a systematic assessment of their prospects and challenges. To this end, several research teams that explore hybrid modeling held a workshop in Paris on April 20—21, 2005 to share and compare the strategies and techniques that each has applied to the development of hybrid modeling. This special issue provides the results of the workshop and of follow-up efforts between different researchers to exchange ideas.

With country-specific development objectives and constraints, multiple market failures and limited international transfers, carbon prices do not need to be uniform across countries, but must be part of broader policy packages.

Why do countries greenhouse gas (GHG) intensities differ? How much of a country's GHG intensity is set by inflexible national circumstances, and how much may be altered by policy? These questions are common in climate change policy discourse and may influence emission reduction allocations. Despite the policy relevance of the discussion, little quantitative analysis has been done. In this paper we address these questions in the context of the G7 by applying a pair of simple quantitative methodologies: decomposition analysis and allocation of fossil fuel production emissions to end-users instead of producers. According to our analysis and available data, climate and geographic size -both inflexible national characteristics -can have a significant effect on a country's GHG intensity. A country's methods for producing electricity and net trade in fossil fuels are also significant, while industrial structure has little effect at the available level of data disaggregation.

Decarbonizing global steel production requires a fundamental transformation. A sectoral climate club, which goes beyond tariffs and involves deep transnational cooperation, can facilitate this transformation by addressing technical, economic and political uncertainties.

This paper explores the role of hydrogen in helping Canada meet its net-zero emissions goals. On the supply side, we caution against the blanket categorization of production methods by “colours”, and instead encourage a focus on the metrics that matter: cost and lifecycle emissions per kilogram. Hydrogen derived from methane, with sequestered carbon dioxide (i.e. “blue” hydrogen) will likely be the method of choice for some time in western Canada, while hydrogen via electrolysis (i.e. “green”) will likely take off in Québec, spreading to other provinces as clean renewable power costs fall. High levels of sequestration (i.e. 90%+) and upstream methane leakage prevention will be essential for hydrogen to meaningfully contribute to Canada’s net-zero goals. On the demand side, we find while hydrogen can do many things, its highest value will be in areas where alternatives for decarbonization are costly or scarce, such as steel and chemicals production, as well as potentially rail and heavy freight. We take a deeper dive into the potential for hydrogen in the electricity system, both by absorbing excess generation via electrolysis, and providing much needed reliability as a peaking product, enabling higher shares of variable renewable energy. We find that by 2030, hydrogen has the potential to compete with natural gas as a dominant firm power source.

This paper explores the role that hydrogen can play in helping Alberta decarbonize its electricity system. Alberta has an abundance of natural gas resources that can be converted to hydrogen fuel and further used to generate electricity either through a turbine or through a fuel cell. Since Alberta has a significant portion of its current electricity needs supplied by combustion and steam turbines, such turbines can be repurposed to use hydrogen fuels and therefore reduce the amount of stranded assets as the province moves towards lower emissions in the electricity industry. Using hydrogen in the electricity industry can also complement a higher percentage of variable renewable energy resources, like wind and solar, by absorbing excess generation via electrolysis and providing much needed reliability as a peaking product. The carbon price and associated carbon policy in Alberta appears to be a key driver incentivizing hydrogen use in the electricity industry. Our model comparing the marginal costs of natural gas versus hydrogen for electricity production concludes that with the current carbon policy in Alberta and a rising carbon price to $170 per tonne CO2e in 2030, hydrogen has the potential to compete with natural gas as a dominant, \"on-demand\" power source.