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Hydrogen production from water electrolysis, direct air capture (DAC), and synthetic kerosene derived from hydrogen and CO2 (`e-kerosene') are expected to play an important role in global decarbonization efforts. So far, the economics of these nascent technologies hamper their market diffusion. However, a wave of recent policy support in the United States, Europe, China, and elsewhere is anticipated to drive their commercial liftoff and bring their costs down. To this end, we evaluate the potential cost reductions driven by policy-induced scale-up of these emerging technologies through 2030 using an experience curves approach accounting for both local and global learning effects. We then analyze the consequences of projected cost declines on the competitiveness of these nascent technologies compared to conventional fossil alternatives, where applicable, and highlight some of the tradeoffs associated with their expansion. Our findings indicate that enacted policies could lead to substantial capital cost reductions for electrolyzers. Nevertheless, electrolytic hydrogen production at $1-2/kg would still require some form of policy support. Given expected costs and experience curves, it is unlikely that liquid solvent DAC (L-DAC) scale-up will bring removal costs to stated targets of $100/tCO2, though a $200/tCO2 may eventually be within reach. We also underscore the importance of tackling methane leakage for natural gas-powered L-DAC: unmitigated leaks amplify net removal costs, exacerbate the investment requirements to reach targeted costs, and cast doubt on L-DAC's role in the clean energy transition. Lastly, despite reductions in electrolysis and L-DAC costs, e-kerosene remains considerably more expensive than fossil jet fuel. The economics of e-kerosene and the resources required for production raise questions about the fuel's ultimate viability as a decarbonization tool for aviation.

Energy systems models, critical for power sector decision support, incur non-linear memory and runtime penalties when scaling up under typical formulations. Even hardware improvements cannot make large models tractable, requiring omission of detail which affects siting, cost, and emission outputs to an unknown degree. Recent algorithmic innovations have enabled large scale, high resolution modeling. Newly tractable, granular systems can be compared with coarse ones for better understanding of inaccuracies from low resolution. Here we use a state of the art model to quantify the impact of resolution on results salient to policymakers and planners, affording confidence in decision quality. We find more realistic siting in recommendations from high resolution energy systems models, improving emissions, reliability, and price outcomes. Errors are generally stronger from low spatial resolution. When models have low resolution in multiple dimensions, errors are introduced by the coarser of temporal or spatial resolution. We see no diminishing returns in accuracy for several key metrics when increasing resolution. We recommend using computationally efficient techniques to maximize granularity and allocating resolution without leaving any aspect (spatial, temporal, operational) of systems unduly coarse.

As decarbonization agendas mature, macro-energy systems modelling studies have increasingly focused on enhanced decision support methods that move beyond least-cost modelling to improve consideration of additional objectives and tradeoffs. One candidate is Modeling to Generate Alternatives (MGA), which systematically explores new objectives without explicit stakeholder elicitation. Previous literature lacks both a comprehensive review of MGA vector selection methods in large-scale energy system models and comparative testing of their relative efficacies in this setting. To fill this gap, this paper provides a comprehensive review of the MGA literature, identifying at least seven MGA vector selection methodologies and carrying out a systematic evaluation of four: Hop-Skip-Jump, Random Vector, Variable Min/Max, and Modelling All Alternatives. We examine each method's runtime, parallelizability, new solution discovery efficiency, and spatial exploration in lower dimensional (N <= 100) spaces, as well as spatial exploration in a three-zone, 8760-hour capacity expansion model case. Through these tests, we find Random Vector provides the broadest exploration of the near-optimal feasible region and Variable Min/Max provides the most extreme results, while the two tie on computational speed. We thus propose a new Hybrid vector selection approach combining the two methods to take advantage of the strengths of each. Additional analysis is provided on MGA variable selection, in which we demonstrate MGA problems formulated over generation variables fail to retain cost-optimal dispatch and are thus not reflective of real operations of equivalent hypothetical capacity choices. As such, we recommend future studies utilize a parallelized combined vector approach over the set of capacity variables for best results in computational speed and spatial exploration while retaining optimal dispatch.

Long duration energy storage (LDES) may become a critical technology for the decarbonization of the power sector, as current commercially available Li-ion battery storage technologies cannot cost-effectively shift energy to address multi-day or seasonal variability in demand and renewable energy availability. LDES is difficult to model in existing energy system planning models (such as electricity system capacity expansion models), as it is much more dependent on an accurate representation of chronology than other resources. Techniques exist for modeling LDES in these planning models; however, it is not known how spatial and temporal resolution affect the performance of these techniques, creating a research gap. In this study we examine what spatial and temporal resolution is necessarily to accurately capture the full value of LDES, in the context of a continent-scale capacity expansion model. We use the results to draw conclusions and present best practices for modelers seeking to accurately model LDES in a macro-energy systems planning context. Our key findings are: 1) modeling LDES with linked representative periods is crucial to capturing its full value, 2) LDES value is highly sensitive to the cost and availability of other resources, and 3) temporal resolution is more important than spatial resolution for capturing the full value of LDES, although how much temporal resolution is needed will depend on the specific model context., Comment: Working paper

In the coming decades, the United States aims to undergo an energy transition away from fossil fuels and toward a fully decarbonized power grid. There are many pathways that the US could pursue toward this objective, each of which relies on different types of generating technologies to provide clean and reliable electricity. One potential contributor to these pathways is advanced nuclear fission, which encompasses various innovative nuclear reactor designs. However, little is known about how cost-competitive these reactors would be compared to other technologies, or about which aspects of their designs offer the most value to a decarbonized power grid. We employ an electricity system optimization model and a case study of a decarbonized U.S. Eastern Interconnection circa 2050 to generate initial indicators of future economic value for advanced reactors and the sensitivity of future value to various design parameters, the availability of competing technologies, and the underlying policy environment. These results can inform long-term cost targets and guide near-term innovation priorities, investments, and reactor design decisions. We find that advanced reactors should cost \$5.1-\$6.6/W to gain an initial market share (assuming 30 year asset life and 3.5-6.5% real WACC), while those that include thermal storage in their designs can cost up to \$5.5-\$7.0/W (not including cost of storage). Since the marginal value of advanced fission reactors declines as market penetration increases, break-even costs fall around 19% at 100 GW of cumulative capacity and around 40% at 300 GW. Additionally, policies that provide investment tax credits for nuclear energy create the most favorable environment for advanced nuclear fission. Stakeholders and investors should consider these findings when deciding which technologies to consider for decarbonizing the US power grid., Comment: 29 pages, 12 figures, plus appendices. Submitted to Applied Energy

We consider electricity capacity expansion models, which optimize investment and retirement decisions by minimizing both investment and operation costs. In order to provide credible support for planning and policy decisions, these models need to include detailed operations and time-coupling constraints, and allow modeling of discrete planning decisions. Such requirements result in large-scale mixed integer optimization problems that are intractable with off-the-shelf solvers. Hence, practical solution approaches often rely on carefully designed abstraction techniques to find the best compromise between reduced temporal and spatial resolutions and model accuracy. Benders decomposition methods offer scalable approaches to leverage distributed computing resources and enable models with both high resolution and computational performance. Unfortunately, such algorithms are known to suffer from instabilities, resulting in oscillations between extreme planning decisions that slows convergence. In this study, we implement and evaluate several level-set regularization schemes to avoid the selection of extreme planning decisions. Using a large capacity expansion model of the Continental United States with over 70 million variables as a case study, we find that a regularization scheme that selects planning decisions in the interior of the feasible set shows superior performance compared to previously published methods, enabling high-resolution, mixed-integer planning problems with unprecedented computational performance., Comment: This work has been submitted to the IEEE for possible publication. Copyright may be transferred without notice, after which this version may no longer be accessible

As the availability of weather-dependent, zero marginal cost resources such as wind and solar power increases, a variety of flexible electricity loads, or `demand sinks', could be deployed to use intermittently available low-cost electricity to produce valuable outputs. This study provides a general framework to evaluate any potential demand sink technology and understand its viability to be deployed cost-effectively in low-carbon power systems. We use an electricity system optimization model to assess 98 discrete combinations of capital costs and output values that collectively span the range of feasible characteristics of potential demand sink technologies. We find that candidates like hydrogen electrolysis, direct air capture, and flexible electric heating can all achieve significant installed capacity (>10% of system peak load) if lower capital costs are reached in the future. Demand sink technologies significantly increase installed wind and solar capacity while not significantly affecting battery storage, firm generating capacity, or the average cost of electricity.

If goals set under the Paris Agreement are met, the world may hold warming well below 2 C; however, parties are not on track to deliver these commitments, increasing focus on policy implementation to close the gap between ambition and action. Recently, the US government passed its most prominent piece of climate legislation to date, the Inflation Reduction Act of 2022 (IRA), designed to invest in a wide range of programs that, among other provisions, incentivize clean energy and carbon management, encourage electrification and efficiency measures, reduce methane emissions, promote domestic supply chains, and address environmental justice concerns. IRA's scope and complexity make modeling important to understand impacts on emissions and energy systems. We leverage results from nine independent, state-of-the-art models to examine potential implications of key IRA provisions, showing economy wide emissions reductions between 43-48% below 2005 by 2035.

The Inflation Reduction Act (IRA) in the United States provides unprecedented incentives for deploying low-carbon hydrogen and liquid fuels, among other low greenhouse gas (GHG) emissions technologies. To better understand the prospective competitiveness of low-carbon or negative-carbon hydrogen and liquid fuels under the IRA in the early 2030s, we examine the impacts of IRA provisions on costs of producing hydrogen and synthetic liquid fuel made from natural gas, electricity, short-cycle biomass (agricultural residues), and corn-ethanol. With IRA credits (45V or 45Q), but excluding incentives provided by other national or state policies, hydrogen produced by electrolysis using carbon-free electricity (green H2) and natural gas reforming with carbon capture and storage (CCS) (blue H2) are cost-competitive with the carbon-intensive benchmark gray H2 from steam methane reforming. Biomass-derived H2 with or without CCS is not cost-completive under current IRA provisions. However, if IRA allowed biomass gasification with CCS to claim a 45V credit for carbon-neutral H2 and a 45Q credit for negative biogenic-CO2 emissions, this pathway would be less costly than gray H2. The IRA credit for clean fuels (45Z), currently stipulated to end in 2027, would need to be extended, or similar policy support provided by other national or state policies, for clean synthetic liquid fuel to be cost-competitive with petroleum-derived liquid fuels. Levelized IRA subsidies per unit of CO2 mitigated for all hydrogen and synthetic liquid fuel production pathways, except electricity-derived synthetic liquid fuel, range from 65 to 384 $/t CO2, which is within or below the range in U.S. federal government estimates of the Social Cost of Carbon (SCC) in the 2030 to 2040 timeframe.

Expanding transmission capacity is likely a bottleneck that will restrict variable renewable energy (VRE) deployment required to achieve ambitious emission reduction goals. Grid interconnection and inter-regional transmission capacity may be reduced by the optimal sizing of VREs to grid connection or co-location of VRE and battery resources behind the grid interconnection, but neither of these capabilities are commonly captured in macro-energy system models. We thus develop these two new functionalities to explore the substitutability of storage for transmission and VRE resource trade-offs through 2030 in the Western Interconnection of the United States. Our findings indicate that not modeling co-location fails to capture the full substitutability of storage and solar photovoltaic (PV) resources for transmission: co-location can reduce long-distance inter-regional transmission expansion by 12-31% and decrease grid connection capacity and shorter-distance transmission interconnection by 20-25%. We also demonstrate that not modeling colocated storage does not accurately reflect competition between wind and solar PV resources and underestimates the value of energy storage: co-location of VREs and storage favors solar PV (4-5% increase) and lithium-ion battery deployment (1.7-6 times increase), while decreasing wind buildout (0.9-1.6% decline)., Comment: The authors have decided to withdraw this version since they have found multiple inaccuracies in the results with the new model version, updated data, and reformulated cost analysis

Energy systems planning models identify least-cost strategies for expansion and operation of energy systems and provide decision support for investment, planning, regulation, and policy. Most are formulated as linear programming (LP) or mixed integer linear programming (MILP) problems. Despite the relative efficiency and maturity of LP and MILP solvers, large scale problems are often intractable without abstractions that impact quality of results and generalizability of findings. We consider a macro-energy systems planning problem with detailed operations and policy constraints and formulate a computationally efficient Benders decomposition separating investments from operations and decoupling operational timesteps using budgeting variables in the master model. This novel approach enables parallelization of operational subproblems and permits modeling of relevant constraints coupling decisions across time periods (e.g. policy constraints) within a decomposed framework. Runtime scales linearly with temporal resolution; tests demonstrate substantial runtime improvement for all MILP formulations and for some LP formulations depending on problem size relative to analagous monolithic models solved with state-of-the-art commercial solvers. Our algorithm is applicable to planning problems in other domains (e.g. water, transportation networks, production processes) and can solve large-scale problems otherwise intractable. We show that the increased resolution enabled by this algorithm mitigates structural uncertainty, improving recommendation accuracy., Comment: Published in: Anna Jacobson, Filippo Pecci, Nestor Sepulveda, Qingyu Xu, Jesse Jenkins (2023) A Computationally Efficient Benders Decomposition for Energy Systems Planning Problems with Detailed Operations and Time-Coupling Constraints. INFORMS Journal on Optimization 0(0)

Land-use conflicts may constrain the unprecedented rates of renewable energy deployment required to meet the decarbonization goals of the Inflation Reduction Act (IRA). This paper employs geospatially resolved data and a detailed electricity system capacity expansion model to generate 160 affordable, zero-carbon electricity supply portfolios for the American west and evaluates the land use impacts of each portfolio. Less than 4% of all sites suitable for solar development and 17% of all wind sites appear in this set of portfolios. Of these sites, 53% of solar and 85% of wind sites exhibit higher development risk and potential for land use conflict. We thus find that clean electricity goals cannot be achieved in an affordable manner without substantial renewable development on sites with potential for land use conflict. However, this paper identifies significant flexibility across western U.S. states to site renewable energy or alter the composition of the electricity supply portfolio to ameliorate potential conflicts., Comment: 30 pages, 5 figures, 1 table in the main text