Study On Electricity Market Dynamics, Cycling And Emissions In Decarbonized Scenarios Of The Alberta Electricity Market

This research explored electricity decarbonization through two approaches: simulating scenarios with increased variable renewable energy (VRE) integration using historical market data and employing an energy market simulation model to identify generator fleet mixes that maximize system value. Focusing on Alberta’s electricity market, the study analyzed photovoltaic (PV) energy’s impact on emissions, load and pricing during the province’s transition period from coal to natural gas. Simulations from 2010 to 2019 found that increasing levels of PV capacity (from 15 MW to 3000 MW in a system with an average load of around 9000 MW) significantly reduced greenhouse gas emissions. As the carbon price increased from 15 to 30 Canadian dollars per tonne of carbon dioxide equivalent (CAD/tCO₂e), it significantly impacted the merit order by prioritizing the displacement of higher-emitting sources like coal, enhancing the environmental benefits of PV energy. Consequently, the displacement of coal-fired generation emissions by PV energy rose from 6.1% in 2010 to 10.6% in 2019, while the displacement of natural gas (NG)-fueled generation decreased from 30.2% to 6.9% over the same period. However, inserting modelled PV output into existing market merit orders resulted in steep midday price declines. At low installed capacities, PV plants achieved high market values because their midday production aligned with peak electricity prices. However, as PV capacity increased, oversupply during high solar production hours drove electricity prices down, drastically reducing PV's market value. With 1 GW of installed PV capacity, market value decreased by 30%, 66%, and 78% under low, medium, and high price regimes, respectively. At 3 GW of capacity, the declines were even more pronounced, reaching 51%, 75%, and 95%, respectively. Furthermore, the research explored optimizing PV system orientations (panel’s tilt and azimuth angles) to maximize revenue while addressing aforementioned price cannibalization. Simulations of PV capacities found that, at low capacities, energy-maximizing and revenue-maximizing orientations aligned. At higher PV capacities, revenue-optimal orientations shifted to times of higher-value energy but lower total generation due to intensified price cannibalization. Incorporating carbon credits further aligned revenue and energy-maximizing configurations. Lastly, the effects of carbon pricing on the cycling behavior of fleet mixes with substantial shares of net-zero resources in Alberta by 2035 were studied. The research simulated electricity market operations using commitment and dispatch modeling. Cycling events, such as ramps and startups, were influenced not only by the variability of wind and solar (W&S) energy but also by variable-cost competition between NG-fueled generation without CCS and net-zero resources. Emission costs, driven by the carbon price, introduce a premium that can alter the dispatch order of generators, prioritizing lower-emission resources and reshaping the operational dynamics of the electricity market. Carbon pricing incentivized NG-fueled generation with carbon capture and sequestration (CCS) over NG without CCS, reducing emissions and cycling events. W&S-dominated fleet mixes achieved emissions intensities of 67 kilograms of carbon dioxide equivalent per megawatt-hour (kgCO₂e/MWh), outperforming non-W&S NG-dominated mixes of ~100 kgCO₂e/MWh. Blue hydrogen competed in the merit order against NG without CCS at an estimated carbon price of 170 CAD/tCO₂e, while nuclear facilities would have dispatch priority over thermal units with hydrogen or CCS due to its low variable operating costs. The electricity sector faces uncertainty about how fleet mixes will evolve to reduce emissions, raising concerns among society and stakeholders about costs, revenues, and operational impacts. This dissertation examined key variables, including the effects of PV energy on market prices, how market price dynamics impact PV revenues, and how PV facilities can adapt to changes in fleet composition. It also explored future fleet mixes with net-zero resources, analyzing scenarios with and without W&S and the operation of hydrogen, natural gas with CCS, and nuclear energy. Additionally, it evaluated the impact of carbon pricing on PV revenues and operation patterns of net-zero resources such as dispatch and cycling (ramps and starts). By presenting various net-zero integration scenarios, this research serves as a valuable reference for policymakers and society, aiding informed decision-making in the energy transition.

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