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We consider the problem of promoting sustainability in production forests wherein a given number of strategic entities are authorized to own or manage concession regions. These entities harvest agricultural commodities and sell them in a market. We study optimal price-shaping in a coupled-activity network game model in which the concession owners (agents) engage in two activities: (a) the sustainable activity of producing a commodity that does not interfere with protected forest resources, and (b) the unsustainable activity of infringing into protected regions to expand their agricultural footprint. We characterize two types of policies in a budget-constrained setting: one that maximally suppresses the aggregate unsustainable activity and another that maximizes social welfare while constraining the aggregate unsustainable activity to remain below a predefined tolerance. Our analysis provides novel insights on the agents' equilibrium effort across the two activities and their influence on others due to intra- and cross-activity network effects. We also identify a measure of node centrality that resembles the Bonacich-Katz centrality and helps us determine pricing incentives that lead to welfare improvement while reducing the aggregate unsustainable activity.

Solving large-scale capacity expansion problems (CEPs) is central to cost-effective decarbonization of regional-scale energy systems. To ensure the intended outcomes of CEPs, modeling uncertainty due to weather-dependent variable renewable energy (VRE) supply and energy demand becomes crucially important. However, the resulting stochastic optimization models are often less computationally tractable than their deterministic counterparts. Here, we propose a learning-assisted approximate solution method to tractably solve two-stage stochastic CEPs. Our method identifies low-cost planning decisions by constructing and solving a sequence of tractable temporally aggregated surrogate problems. We adopt a Bayesian optimization approach to searching the space of time series aggregation hyperparameters and compute approximate solutions that minimize costs on a validation set of supply-demand projections. Importantly, we evaluate solved planning outcomes on a held-out set of test projections. We apply our approach to generation and transmission expansion planning for a joint power-gas system spanning New England. We show that our approach yields an estimated cost savings of up to 3.8% in comparison to benchmark time series aggregation approaches.