The pulp and paper (P&P) industry is a significant contributor to global energy consumption and CO2 emissions, necessitating effective decarbonization strategies. This work provides the first in-depth evaluation of Molten Carbonate Fuel Cells (MCFCs) as a carbon capture solution in the P&P sector, specifically targeting the Tomlinson recovery boiler. As its CO2 emissions are predominantly biogenic (carbon neutral), their capture enables the achievement of negative emissions. A case study techno-economic analysis for a reference medium-sized pulp mill in a U.S. context. is conducted to compare MCFC-based capture with conventional amine scrubbing (Cansolv). Two distinct configurations are analyzed for MCFC fuel: natural gas, which is considered the standard operation, and syngas, which is produced on-site through the gasification of waste biomass available in the pulp mill. The results indicate that MCFCs offer a dual advantage by enabling carbon capture while generating electricity. The natural gas-based MCFC system demonstrates a levelized cost of CO2 capture (56 $/tCO2) that benefits from revenue generated through electricity sales and an assumed 45 Q tax credit under the Inflation Reduction Act. The Cansolv case using natural gas to provide the energy needed for solvent regeneration has a cost of CO2 capture of $76/tCO2. On the other hand, the biomass-based MCFC configuration faces economic challenges due to the high costs of gasification and methanation, leading to a levelized cost of CO2 capture of 361 $/tCO2. A Cansolv case using biomass-combustion to provide heat for solvent generation is more economical, with a cost of CO2 capture of $135/tCO2.

The chemicals industry accounts for about 5% of global greenhouse gas emissions today and is among the most difficult industries to abate. We model decarbonization pathways for the most energy-intensive segment of the industry, the production of basic chemicals: olefins, aromatics, methanol, ammonia, and chlor-alkali. Unlike most prior pathways studies, we apply a scenario-analysis approach that recognizes the central role of corporate investment decision making for capital-intensive industries, under highly uncertain long-term future investment environments. We vary the average pace of decarbonization capital allocation under plausible alternative future world contexts and construct least-cost decarbonization timelines by modeling abatement projects individually across more than 2,600 production facilities located in four major producing regions. The timeline for deeply decarbonizing production varies by chemical and region and depends importantly on the investment environment context. In a best-of-all environment scenario, to deeply decarbonize production, annual average capital spending for abatement for the next two to three decades will need to be greater than (and in addition to) historical "business-as-usual" capital spending, and cumulative investment in abatement projects would exceed $1 trillion. In futures where key drivers constrain investment appetites, timelines for decarbonizing the industry extend well into the second half of the century.

Carbon emissions accounting with forest-derived biomass energy is more complex than for waste or crop-residue biomass because carbon emissions and uptake occur over more heterogeneous landscapes and longer timeframes. To better understand climate impacts of forest bioenergy use, we develop a comprehensive framework for assessing the dynamic lifecycle greenhouse gas emissions for bioenergy projects using pine pulpwood feedstocks from managed forests in the U.S. South. We apply it in eight different forest basins to determine the carbon payback period and cumulative carbon storage for hypothetical bioenergy projects with 30-year plant operating lives (2030-2060). Variations in local forest types, age class distributions, and traditional wood product market demands result in large differences in carbon payback times between basins. In general, carbon debt repayment is faster for biofuel or bioelectricity projects that employ CCS than those that do not. We find that facilities employing CCS and consuming 3 million green tons of feedstock annually yield carbon payback periods below 10 years if located within pine-dominated coastal plain or gulf coast regions. In a hardwood-dominated basin such as in Virginia, carbon payback is not achieved.

Improved modeling approaches to support decision making are needed to help accelerate the transition to low-carbon energy systems. We offer insights into improving energy transition decision support modeling, drawing on our experience with the Net-Zero America (NZA) project and analogously designed ongoing projects led by researchers in Australia, Brazil, China, India, Republic of Korea, and Poland. The NZA study was impactful because of 1) uniquely high spatial, temporal, sectoral, technological, and socio-economic modeling and visualization using objective, transparent, and scientifically rigorous methods and 2) complementary policy-actionable bridging analyses informed by transparent and unusually extensive engagement with a broad set of stakeholders. The NZA approach established a new standard for high-resolution energy-transition decision support modeling, but further improvements in methods and tools are needed. A foremost need is improving optimization modeling so that it better reflects on-the-ground realities and risks associated with efforts to deploy energy technologies and infrastructure at the scales and pace needed to achieve mid-century net-zero emissions goals.

As the global carbon footprint continues to grow, many countries are implementing carbon emission reduction policies which have incentivized the expansion of low-carbon and renewable technologies. However, the speed and scale of deployment falls short of that needed to meet climate goals. Energy system models serve as key tools for guiding investment decisions and helping policymakers evaluate the effects of various policies on the development of an energy system. This study focuses on the energy system of the United States and builds upon prior work by incorporating more geographic granularity to account for the trade of commodities and addresses transmission congestion through electricity price adjustments. Furthermore, real-world characteristics, such as delays in constructing new liquid fuel production and electricity generation facilities, are integrated using a sequential decision-making approach that better reflects how decisions can be updated as uncertainties unfold. Results demonstrate that stochastic programming combined with sequential decision-making produces energy transition pathways that are robust to multiple uncertain futures. Additionally, considering real-world characteristics significantly impacts the deployment of renewable technologies and the ability to meet carbon emission reduction goals while also reliably meeting demand. These findings highlight the importance of accounting for uncertainty and real-world characteristics to avoid overly optimistic projections in energy system planning.

A global effort is underway to realize long-held visions of a diversified clean hydrogen (H2) economy. In the United States, the Department of Energy has selected seven clean H2 hub proposals into which it plans to invest $7 billion, along with another $1 billion to stimulate demand for the molecules. Coupled with generous production subsidies, these moves are intended to support early-movers to prove business models, initiate the build-out of distribution infrastructure, and catalyze further scale-up efforts. Major public support programs are also underway in Europe, Asia, the Middle East, North Africa, and Australia. Despite this unprecedented level of public funding, there is a growing risk that follow-on commercial adoption could be mostly limited to substitution in existing uses, new entrants will struggle to gain traction, and private capital will remain on the sidelines for emerging applications. Drawing on insights from senior stakeholders from across the clean H2 value chain and investment community, we explain why the long-term prospects for most clean H2 use-cases remain moribund, and show how public support can address the underlying “system-level” gaps that must also be overcome to truly unlock large-scale growth. In particular, there is an opportunity and need for public support to help resolve three underlying issues: (i) clarifying fit with the broader clean energy ecosystem; (ii) bridging “chicken-and-egg” barriers; and (iii) harnessing incumbency without being captured by it.

Bioenergy with carbon capture and storage for power generation (BECCS-power) is a negative emissions technology that could potentially play significant roles in helping achieve climate-change mitigation goals. We evaluate a novel BECCS-power technology utilizing molten carbonate fuel cell-based post-combustion carbon dioxide (CO2) capture (MCFC-CC). We present detailed, internally self-consistent plant-level performance simulation results, techno-economic analyses, and lifecycle greenhouse gas emissions assessment for this technology, with comparisons against conventional monoethanolamine-based post-combustion CO2 capture (MEACC) and biopower without CO2 capture. We additionally carry out grid capacity expansion modeling to 2050 to assess how BECCS-power options might compete with other generators in a case study region (southern region of the Midcontinent Independent System Operator, MISO). This comprehensive work is not only the first rigorous engineering assessments of MCFC for BECCS but also the first techno-economic analyses of MCFC-CC of any type that includes its evaluation in the context of power grid operation. For a biomass input rate of 500 MW thHHV , a MCFC-CC plant generates triple the power and has nearly double the efficiency of a MEA-CC plant (261.5 MWe at 33.5% efficiency vs. 87.2 MWe at 17.4% efficiency). The plants generate comparable levels of negative emissions per tonne of biomass input: 1.3 and 1.5 tCO2, respectively. For a fully-depreciated coal-fired steam-cycle plant repowered for biomass and CO2 capture, the (Nth plant) levelized cost of electricity (LCOE) for MCFC-CC ($113/ MWh) is about half that for MEA-CC owing to a lower estimated unit capital cost ($2,479/kWnet vs. $4,665/ kWnet) and higher efficiency. When 45Q tax credits available under the 2022 Inflation Reduction Act (IRA) are applied, the LCOE of the MCFC-CC is comparable to that of a plant without CO2 capture ($85/MWh). From the capacity expansion modeling, if the southern MISO grid would have a target grid-average carbon emission intensity of 50 kgCO2/MWh or less in 2050, several gigawatts of Bio-MCFC-CC would be economically deployed, and the marginal cost of emissions abatement ($92/tCO2) would be dramatically lower than if it were not a deployment option.

Supporting data for our manuscript Direct Air Capture Integration with Low-Carbon Heat: Process Engineering and Power System Analysis

We present design methods and insights for CO2 capture, transport, and storage systems for clusters of industrial facilities, with a case-study focus on the state of Louisiana. Our analytical framework includes: (1) evaluating the scale and concentration of capturable CO2 emissions at individual facilities for the purpose of estimating the cost of CO2 capture retrofits, (2) a screening method to identify potential CO2 storage sites and estimate their storage capacities, injectivities, and costs; and (3) an approach for cost-minimized design of pipeline infrastructure connecting CO2 capture plants with storage sites that considers land use patterns, existing rights-of-way, demographics, and a variety of social and environmental justice factors. In applying our framework to Louisiana, we estimate up to 50 million tCO2/y of industrial emissions (out of today's total emissions of 130 MtCO2/y) can be captured at under 100 USD/tCO2, and up to 100 MtCO2/y at under 120 USD/tCO2. We identified 98 potential storage sites with estimated aggregate total injectivity between 330 and 730 MtCO2/yr and storage costs ranging from 8 to 17 USD/tCO2. We find dramatic reductions in the aggregate pipeline length and CO2 transport cost per tonne when groups of capture plants share pipeline infrastructure rather than build dedicated single-user pipelines. Smaller facilities (emitting less than 1 MtCO2/y), which account for a quarter of Louisiana's industrial emissions, see the largest transport cost benefits from sharing of infrastructure. Pipeline routes designed to avoid disadvantaged communities (social and environmental justice) so as not to reinforce historical practices of disenfranchisement involve only modestly higher pipeline lengths and costs.

Carbon capture and storage (CCS) has emerged as a promising way for achieving deep decarbonization of China’s steel sector. Large-scale CCS deployment necessitates a comprehensive source-sink matching analysis to offer early engineering guidance. To address this issue, this study conducted a source-sink matching analysis of China’s steel sector, assessing CO2 sources, CO2 storage capacities and costs, and CO2 pipeline layouts under three capture targets. The findings reveal an obvious spatial mismatch between CO2 sources and potential CO2 sinks for China’s steel sector. CO2 sources are mainly situated in eastern China, while main CO2 storage sites are located in western China. The average unit costs of CCS under low (30%), medium (60%), and full capture (90%) targets are 83, 91, and 118 $/t CO2, respectively. In particular, as capture target increases, the CO2 transportation cost will supersede the capture cost and dominate the average CCS unit cost, owing to the construction of longer pipelines. This study recommends prioritizing CCS demonstration with steel plants in regions having suitable CO2 storage basins nearby. Moreover, future investigations should concentrate on on-site experiments of CO2 storage basins and the technology development of offshore carbon storage in China.

A model for estimating CO2 capture retrofit costs at many types of industrial facilities is developed and then applied in a case study exploring alternative designs for capture, transport, and underground storage of CO2 from a cluster of industrial facilities in Southeast Louisiana, USA. The capture cost model is anchored by granular chemical process simulations used to determine capacities of individual equipment components, the capital costs for which are estimated using factoring methods. To generalize the cost model, process simulations are developed for target capture streams having CO2 concentrations of 5, 10, 15, and 94 mol%, and for each concentration, seven different scales of capture plants are modeled. The cost model is then embedded in SimCCS(PRO), a customized version of open-source software for optimizing CO2 pipeline capacities and routings to underground storage sites. For a 22-facility cluster of industrial CO2 sources with collective emissions of 8.1 million tCO(2)/year today, we explore capture, transport and storage (CTS) system designs with varying levels of shared capture and transport infrastructure. When CO2 pipelines are shared rather than dedicated to individual capture facilities, average transport costs can be reduced by up to two-thirds (and aggregate pipeline length by more than this) for the same level of CO2 capture and storage. However, capture costs dominate total CTS costs. Because of this, pooling emission streams from multiple facilities and sharing the scale-economy benefits of larger capture facilities enables more significant reductions in CTS costs per tonne of CO2 stored, even though some of the savings are offset by the added flue gas transport costs. The cost benefits of shared infrastructure are most significant for smaller facilities, i.e., with emissions <0.1 million tCO(2)/year.

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 examined the impacts of the IRA provisions on the costs of producing hydrogen and synthetic liquid fuel made from natural gas, electricity, short-cycle biomass (agricultural residues), and corn-derived ethanol. We determined that, with IRA credits (45V or 45Q) but excluding the incentives provided by other national or state policies, hydrogen produced by electrolysis using carbon-free electricity (green H2) and by natural gas reforming with carbon capture and storage (CCS) (blue H2) is cost-competitive with the carbon-intensive benchmark gray H2, which is produced by steam methane reforming. Biomass-derived H2 with or without CCS is not cost-competitive under the current IRA provisions. However, if the 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 would need to be provided by other national or state policies in order for clean synthetic liquid fuel to be cost-competitive with petroleum-derived liquid fuels. The levelized IRA subsidies per unit of CO2 mitigated for all of the hydrogen and synthetic liquid fuel production pathways, except for electricity-derived synthetic liquid fuel, range from $65-$384/t of CO2. These values are within or below the range of the U.S. federal government's estimates of the social cost of carbon (SCC) in the 2030-2040 time frame.

In recent macro-energy systems modeling studies of net-zero emissions pathways for the United States and elsewhere, fuels made via gasification of sustainably produced biomass coupled with carbon capture and storage (CCS) play critical roles in achieving economy-wide net-zero greenhouse gas emissions because they provide carbon-negative energy carriers. In this study, we develop lifecycle greenhouse gas (GHG) emissions and cost assessments to provide insights into the environmental and economic cost and value of hydrogen (H2), synthetic natural gas (SNG), and Fischer-Tropsch liquid (FTL) fuels made from 1) biomass, coupled with CCS, 2) natural gas, with CCS, and 3) renewably-generated electricity. We find that H2 production pathways are less costly to decarbonize than FTL and SNG pathways that use the same input feedstock and also provide the largest re-ductions in lifecycle GHG emissions per unit of delivered fuel. Sensitivity analyses on the levelized costs of carbon mitigation (LCCM) indicate that capital costs and capacity factors are influential for most of the path-ways. Costs for processes that use natural gas as feedstock are more sensitive to changes in input feedstock in-tensity than other processes. Finally, we find that fuel production pathways starting from biomass and including CCS have the highest carbon mitigation potentials among all feedstock pathways. They also have the lowest production costs beyond certain threshold carbon emission price levels. Our findings help explain the critical role that biomass-based hydrogen production with CCS plays in macro-energy system models of the U.S. transition to net-zero emissions.

The US Department of Energy recently short-listed seven proposals that could become eligible for a total of $7 billion to support the development of clean hydrogen hubs. These are intended to serve as platforms for early-movers to prove business models, initiate the build-out of distribution infrastructure, and serve as building blocks for future scale-up efforts. Despite this unprecedented level of public funding, there is a growing risk that follow-on commercial adoption could be mostly limited to substitution in existing uses and that private capital will continue to stay on the sidelines for other applications. We explain why the long-term prospects for most clean hydrogen use-cases remain uncertain, and how hubs activity must create clarity on three underlying issues: (i) fit with the broader clean energy ecosystem; (ii) bridging “chicken-and-egg” barriers; and (iii) harnessing incumbency without being captured by it.

Using a real-option approach, we study the decision of a private power generator considering investment in a zero-CO2-emissions plant. Specifically, we analyze the investment decision in mutually exclusive technologies under the presence of market uncertainty, for different scenarios and under different policy regimes within each scenario. The scenarios are based on emissions targets, such as net-zero-CO2 emissions by 2050. The policy regimes are based on whether or not the targets are binding. We find that if there are fewer available zero-CO2-technology options there is less hesitation to invest, which potentially leads to earlier investment. We also find that some policies are more effective than others in encouraging investment: incentive payments are somewhat effective, penalties for not reaching zero emissions by a specified future date are more effective; a steadily increasing CO2-emission-allowance price also speeds up investment.

Achieving an economy-wide net-zero emissions goal by mid-century in the United States entails transforming not only the physical energy system, but also the energy workforce. In this study, we develop and demonstrate a labor model, tailored to the context of energy system transitions, and coupled with geospatially-resolved, supply-side energy system activity projections. We find that a net-zero transition supports an annual average of approximately 3 million direct jobs or $200B in wages during the first decade, and approximately 4-8 million direct jobs or $200B-$500B during the 2040s. The modeled supply-side energy workforce represents of 1.5% of the total U.S. labor force in 2020, increasing to 2.5-5% by mid-century. Boom-and-bust cycles arise, with employment and wage losses in declining fossil fuel sectors offset (in aggregate) by increases in low carbon resource sectors. We further estimate training, education, and experience requirements, finding that the diversity of workforce development needs will be similar to historical transitions, but at a much larger scale over a sustained time period. Labor pathways are influenced by policy-mediated factors such as technology selection, pace of infrastructure expansion, infrastructure siting and investment decisions, oil and gas exports, workforce development, labor productivity, and extent of domestic manufacturing. We show that most states have the potential to experience long-term expansion in the supply-side energy workforce, but substantial state-level variation is possible in labor pathways depending on resource availability, siting decisions, and political bargaining.

The journey to carbon neutrality will require trillions of dollars of capital investment over many years. Analytical models based on foresight offer guidance, but an overreliance on them can lead to a myopic focus on a single pathway. Some argue that the solution is to develop higher-resolution models, fed with increasingly granular data. Here, we note that real-time feedback is an important and underappreciated complement to this approach. We discuss how nations and corporations are currently embarking on the energy transition with the equivalent of a high-level map. The ambition is clear, but there is a lack of confidence in the best route. Routing options and conditions are changing rapidly. We outline the features of a navigation app for the energy transition that offers real-time, actionable guidance for the energy transition would be hugely beneficial. The essential function of such an app would be to collect, secure, process, and present data in a way that can support decisions by relevant actors. Such a capability would require three essential elements: route topology awareness with high-resolution details of the benefits and costs of different decarbonization options; data platforms that provide insight into the real-time situation; and trade-off tools that readily convey accurate, up-to-date, and easily-interpretable estimates of switching costs. These elements exist at varying levels of maturity, and improvement and integration is needed to deliver the utility and convenience of a road travel app. This Perspective draws on our collective experience mapping paths to carbon neutrality for the Princeton Net-Zero America study and one of China's largest energy companies (China Energy) to develop the idea of navigation apps for the energy transition. Starting with a resolved accounting of CO2 emissions, we illustrate the importance of accounting for differing motivations and leverage among actors. We discuss the essential features of a navigation app and show how progress in these areas can help address bottlenecks in large-scale clean energy deployment. We conclude with a call for increased collaboration with tech companies to accelerate development of these capabilities.

Continued growth in wind energy penetration increases the demand for operational flexibility on the grid. It is not well-understood if the price formation process in current U.S. electricity markets will appropriately reward the provision of operational flexibility. This study investigates how continued growth in wind penetration impacts conventional marginal pricing efficiency and assesses its ability to remunerate operational flexibility. It also investigates the extent to which alternative marginal pricing schemes that seek to minimize out-of-market payments enhance remuneration of flexibility. Using a custom-built model, we simulate PJM’s hourly electricity market outcomes under conventional and alternative marginal pricing schemes for three wind penetration levels. We find that the increasing demand for operational flexibility increases the frequency and magnitude of unrepresentative price events that suppress energy prices and thus the market’s ability to remunerate flexibility. We find that the alternative of convex-hull pricing, which minimizes out-of-market payments, can largely overcome these issues.