Power-sector decarbonisation envisages extensive uptake of variable renewable energy (VRE) technologies. Although VRE output is intermittent, coupling between heat and power sectors via combined heat and power (CHP) plants could provide the requisite flexibility. However, strategic CHP plants could use the link between the two energy sectors to manipulate electricity prices. We use a bi-level model to investigate the incentives for the exercise of such market power. At the upper level, a firm with both heat-only and CHP plants is a Stackelberg leader when determining its heat output and is constrained by power-market operations at the lower level. Such a strategic firm produces more (less) heat from its CHP (heat-only) plant vis-à-vis the social optimum to constrain its power output, thereby boosting the electricity price. Additional market power at the lower level from power-only generation induces the strategic heat producer to reduce distortions to its operations as long as the electricity market is relatively large. In order to attenuate welfare losses from such strategic behaviour, we devise an incentive-based regulatory mechanism consisting of a subsidy to or a tax on CHP heat output. Numerical examples illustrate the properties of our analytical results, which can inform future negotiations over CHP cost allocations between regulators and producers.

Decarbonizing the power mix will require investments in storage and flexibility options to replace the current carbon-intensive supply of reserves. This paper questions whether reserve-capacity markets can serve as a capacity mechanism for flexible technologies. A fundamental model of the day-ahead and reserve markets is used to investigate the evolution of reserve prices with large shares of renewable energy and storage. The model represents the current market design in Continental Europe with a centralized supply and platforms for the exchange of reserves. By becoming the main suppliers of reserve capacity, batteries have a noticeable impact on reserve prices. Their flexibility implies zero opportunity cost most of the time, meaning that the flexibility is not rewarded by the market. These results suggest that reserve-capacity markets cannot provide additional remuneration for flexible technologies and, thus, do not solve the missing-money problem in the context of the energy transition.

We examine carbon-policy design for a power system with energy storage as well as renewable and fossil-fuelled generation. A central-planning solution internalises the environmental externality of carbon emissions and curbs fossil-fuelled generation in proportion to the marginal cost of damage. By contrast, a decentralised solution leads to a bi-level setup: an upper-level welfare-maximising policymaker sets a carbon tax to impose upon lower-level profit-maximising generators. For completely efficient storage, an optimal carbon tax in this bi-level setting renders the first-best outcome. However, with inefficient storage, an infinitesimal increase in the carbon tax induces prices to increase at the same rate. As a result, storage shifts energy to the off-peak period to offset the loss in the value of stored energy. Hence, relative to the marginal cost of damage from emissions under central planning, the optimal carbon tax for the decentralised case is lower and may be nonmonotonic in energy storage’s inefficiency.

Ambitious climate packages promote the integration of variable renewable energy (VRE) and the electrification of the economy. With its ample hydro reservoirs and transmission capacity, the Nordic region is well positioned for this transformation. However, the additional need for flexibility and electrification of industrial processes could give power producers more leverage to exert market power. By using a Nash-Cournot model with a detailed spatio-temporal representation of the Nordic power system, we explore how strategic operations may be affected by (i) increased industrial demand and (ii) matching expansion of onshore-wind power. We find that increased electrification, modelled by industrial demand, diminishes firms' market power but simultaneously leads to a higher average price. Meanwhile, matching industry's electricity demand with onshore-wind capacity restores prices to their baseline level but reintroduces market power. In particular, hydro plants are flexible enough to exploit such a power system's additional industrial demand and VRE's intermittent output to actually increase their payoff from market power.

Decarbonization policies have spurred the adoption of variable renewable energy (VRE) technologies such as wind and solar power. To enable flexible resources and accommodate VRE’s intermittency, electricity markets are shifting toward renewable-aware dispatch based on stochastic optimization. However, strategic firms may exploit such market structures to manipulate prices to their advantage. To complement the extant literature, we compare investment decisions as well as worst-case profits and losses in the context of generation expansion by a strategic firm that uses either risk-averse stochastic programming or robust optimization. The former is a bi-level optimization problem, whereas the latter is a tri-level problem. Our contributions are threefold in addressing policy and methodological challenges. First, we demonstrate that using robust optimization instead of stochastic programming generally leads to investment plans with a higher share of VRE because it serves as a hedge during undesirable realizations with low consumer willingness to pay and high marginal costs for conventional generation. Second, a regret analysis shows that the worst-case profit is significantly reduced if an investor uses expansion decisions from stochastic programming, highlighting the importance of selecting a methodology aligned with the main objective of the investor. The effect is especially pronounced if decisions stem from a social planner, thereby indicating how a conventional, centralized perspective may fail to reflect private incentives for generation expansion in evolving electricity markets. Third, the analysis of strategic behavior necessitates state-of-the-art decomposition techniques such as the constraint generation-based algorithm and the column-and-constraint generation algorithm for the bi- and tri-level problems, respectively.

Policymakers face the challenge of integrating intermittent output from variable renewable energy (VRE). Even in a well-functioning power sector with flexible generation, producers’ incentives may not align with society’ swelfare-maximisation objective. At the same time, political pressure can obstruct policymakers from pricing damage from CO2 emissions according to its social costs. In facilitating decarbonisation, transmission planning will have to adapt to such economic and environmental distortions. Using a Stackelberg model of the Nordic power sector, we find that a first-best transmission-expansion plan involves better resource sharing between zones, which actually reduces the need for some VRE adoption. Next, we allow for departures from perfect competition and identify an extended transmission-expansion plan under market power by nuclear plants. By contrast, temporal arbitrage by hydro reservoirs does not necessitate transmission expansion beyond that of perfect competition because it incentivises sufficient VRE adoption using existing lines. Meanwhile, incomplete CO2 pricing under perfect competition requires a transmission plan that matches hydro-rich zones with sites for VRE adoption. However, since incomplete CO2 pricing leaves fossil-fuelled generation economically viable, it reduces the leverage of strategic producers, thereby catalysing less (more) extensive transmission expansionunder market power by nuclear (hydro) plants.

To achieve the recommendation stated in the chapter title, we propose the following:

Stakeholders can be better engaged in energy efficiency decisions through the use of multicriteria models.

Decision-makers should present trade-offs, such as cost and emissions, and combinations of acceptable solutions to various stakeholders such as the public, housing associations, regulatory agencies, and financial institutions.

Decision-makers should adopt a user-centred approach to energy efficiency measures by encouraging stakeholder dialogues around decision-support tools (e.g. multicriteria modelling) to improve understanding of costs and benefits of measures.

Decision-makers should identify opportunities for consensus building and mindset shifts about the wider benefits of energy efficiency measures by emphasising their social considerations.

Using Social Sciences and Humanities (SSH) perspectives can strengthen Science, Technology, Engineering and Mathematics (STEM) led multicriteria models that visualise trade-offs as well as identify plausible conflicts among stakeholders.

Stochastic adaptive robust optimization is capable of handling short-term uncertainties in demand and variable renewable-energy sources that affect investment in generation and transmission capacity. We build on this setting by considering a multi-year investment horizon for finding the optimal plan for generation and transmission capacity expansion while reducing greenhouse gas emissions. In addition, we incorporate multiple hours in power-system operations to capture hydropower operations and flexibility requirements for utilizing variable renewable-energy sources such as wind and solar power. To improve the computational performance of existing exact methods for this problem, we employ Benders decomposition and solve a mixed-integer quadratic programming problem to avoid computationally expensive big-M linearizations. The results for a realistic case study for the Nordic and Baltic region indicate which investments in transmission, wind power, and flexible generation capacity are required for reducing greenhouse gas emissions. Through out-of-sample experiments, we show that the stochastic adaptive robust model leads to lower expected costs than a stochastic programming model under increasingly stringent environmental considerations.

Climate packages envisage decarbonization of the power system and electrification of the wider economy via variable renewable energy (VRE). These trends facilitate the rise of aggregator-enabled prosumers and engender demand for flexibility. By exploiting conducive geography, e.g., in the Nordic region, hydro reservoirs can mitigate VRE's intermittency. Nevertheless, hydro producers may leverage this increased need for flexibility to exert market power through temporal arbitrage. Using a Nash-Cournot model, we examine how aggregator-enabled prosumers with endogenous loads and VRE capacity interact with other agents to affect market outcomes. Based on Nordic data, we find that hydro producers enhance their market power by shifting their production away from periods in which prosumers are net buyers and "dumping" their output during periods in which prosumers are net sellers. Hence, jurisdictions that rely upon (hydro) storage to integrate VRE from prosumers will need to be wary of incumbent firms' incentives to manipulate prices.

Decarbonisation of the Nordic power sector entails substantial variable renewable energy (VRE) adoption. While Nordic hydropower reservoirs can mitigate VRE output's intermittency, strategic hydro producers may leverage increased flexibility requirements to exert market power. Using a Nash-Cournot model, we find that even the current Nordic power system could yield modest gains from strategic reservoir operations regardless of a prohibition on "spilling" water to increase prices. Instead, strategic hydro producers could shift generation from peak to off-peak seasons. Such temporal arbitrage becomes more attractive under a climate package with a €100/t CO2 price and doubled VRE capacity. Since the package increases generation variability, lowers average prices, and makes fossil-fuelled plants unprofitable, strategic hydro producers face lower opportunity costs in shifting output from peak to off-peak seasons and encounter muted responses from price-taking fossil-fuelled plants. Hence, a climate package that curtails CO2 emissions may also bolster strategic hydro producers' leverage.