Unlocking Potential for Low-Carbon Hydrogen Production from U.S. Natural Gas Resources.

Hydrogen will potentially play a key role while transitioning to a net-zero economy. This study addresses resource, environmental, economic, policy, and societal issues related to low-carbon hydrogen production by steam methane reforming with carbon capture and storage in Wyoming and other natural-gas-rich states. For low-carbon hydrogen produced from natural gas and electricity supplies and which stores CO2 in saline reservoirs in Wyoming, the levelized cost of hydrogen (LCOH) ranges from $1.62-2.00/kg H2, and the life cycle emissions range from 3.85-5.74 kg CO2-eq/kg H2. If claimed, the 45Q tax credit decreases the LCOH by 19%. Although the supplies of renewable natural gas feedstock and zero- or low-carbon electricity can lower the carbon footprint to make hydrogen projects qualified for the 45V tax credit, the 45Q tax credit is still a stronger economic incentive. To reduce the supply cost, a hydrogen cluster can be developed in the state by leveraging the colocation and coavailability of multiple natural resources and transport infrastructure. Developing a hydrogen cluster can directly create several thousand construction jobs and several hundred permanent jobs in Wyoming. Low-carbon hydrogen production can also be scaled up in other states across the nation.

Technological evolution of large-scale blue hydrogen production toward the U.S. Hydrogen Energy Earthshot.

Hydrogen potentially has a crucial role in the U.S. transition to a net-zero emissions economy. Learning from large-scale hydrogen projects will boost technological evolution and innovation toward the U.S. Hydrogen Energy Earthshot. We apply experience curves to estimate the evolving costs of blue hydrogen production and to further examine the economic effect on technological evolution of the Inflation Reduction Act's tax credits for carbon sequestration and clean hydrogen. Learning-by-doing alone can decrease the production cost of blue hydrogen. Without tax incentives, however, it is hard for blue hydrogen production to reach the cost target of $1/kg H2. Here we show that the breakeven cumulative production capacity required for gas-based blue hydrogen to reach the $1/kg H2 target highly depends on tax credit, natural gas price, inflation rate, and learning rates. We make recommendations for hydrogen hub development and for accelerating technological progress toward the Hydrogen Energy Earthshot.

P300 reduces TUBB4B expression to facilitate the biological process of migration and invasion of non-small cell lung cancer cells.

This article explored the mechanism of E1A binding protein p300 (P300) and beta-tubulin 4B isotype-encoding gene (TUBB4B) in regulating the migration and invasion of non-small cell lung cancer (NSCLC) cells. TUBB4B and P300 expression in NSCLC tissues and cells was monitored by real-time quantitative reverse transcription-polymerase chain reaction (qRT-PCR) and Western blot. TUBB4B function on NSCLC cell migration, invasion and epithelial-mesenchymal transition (EMT) was monitored by wound healing assay, Transwell experiment and Western blot. The regulation of P300 on TUBB4B was monitored by qRT-PCR and Western blot. Mechanism of P300 and TUBB4B in regulating NSCLC cell migration and invasion was explored by rescue experiment. A xenograft tumor model was established by using nude mouse. As a result, low TUBB4B expression and high P300 expression was discovered in NSCLC tissues and cells. TUBB4B and P300 expression showed a negative correlation in NSCLC tissues. Lower TUBB4B but higher P300 was observed in tumor tissues of NSCLC patients with metastasis. TUBB4B overexpression suppressed NSCLC cell migration, invasion and EMT. TUBB4B silencing had opposite results. P300 overexpression inhibited TUBB4B expression, and P300 silencing facilitated TUBB4B overexpression in NSCLC cells. TUBB4B overexpression counteracted the promotion of P300 overexpression on NSCLC cell invasion and migration. TUBB4B silencing abrogated the inhibition of P300 knockdown on NSCLC cell invasion and migration. TUBB4B overexpression suppressed NSCLC cell in vivo growth. Thus, TUBB4B could be reduced by P300 in NSCLC. It exerted suppression role on NSCLC cell migration, invasion and EMT. TUBB4B may be a novel target for NSCLC treatment.

Understanding the complexity of existing fossil fuel power plant decarbonization.

Growing national decarbonization commitments require rapid and deep reductions of carbon dioxide emissions from existing fossil-fuel power plants. Although retrofitting existing plants with carbon capture and storage or biomass has been discussed extensively, yet such options have failed to provide evident emission reductions at a global scale so far. Assessments of decarbonization technologies tend to focus on one specific option but omit its interactions with competing technologies and related sectors (e.g., water, food, and land use). Energy system models could mimic such inter-technological and inter-sectoral competition but often aggregate plant-level parameters without validation, as well as fleet-level inputs with large variability and uncertainty. To enhance the accuracy and reliability of top-down optimization models, bottom-up plant-level experience accumulation is of vital importance. Identifying sweet spots for plant-level pilot projects, overcoming the technical, financial, and social obstacles of early large-scale demonstration projects, incorporating equity into the transition, propagating the plant-level potential to generate fleet-level impacts represent some key complexity of existing fossil-fuel power plant decarbonization challenges that imposes the need for a serious re-evaluation of existing fossil fuel power plant abatement in energy transition.

Fossil-Fuel Options for Power Sector Net-Zero Emissions with Sequestration Tax Credits.

Three of the main challenges in achieving rapid decarbonization of the electric power sector in the near term are getting to net-zero while maintaining grid reliability and minimizing cost. In this policy analysis, we evaluate the performance of a variety of generation strategies using this "triple objective" including nuclear, renewables with different energy storage options, and carbon-emitting generation with carbon capture and storage (CCS) and direct air capture and storage (DACS) technologies. Given the current U.S. tax credits for carbon sequestration under Section 45Q of the Internal Revenue Code, we find that two options: (1) cofiring bioenergy in existing coal-fired assets equipped with CCS, and (2) coupling existing natural gas combined-cycle plants equipped with CCS and DACS, robustly dominate other generation strategies across many assumptions and uncertainties. As a result, capacity-expansion modelers, planners, and policymakers should consider such combinations of carbon-constrained fossil-fuel and negative emissions technologies, together with modifications of the current national incentives, when designing the pathways to a carbon-free economy.

Policy-Driven Potential for Deploying Carbon Capture and Sequestration in a Fossil-Rich Power Sector.

In 2020, the Wyoming Legislature enacted House Bill No. 0200 (HB0200), which requires utilities to generate a percentage of dispatchable and reliable low-carbon electricity by 2030. This state requirement must take into consideration "any potentially expiring federal tax credits", such as the federal Section 45Q tax credit. This study aims to examine the potential role of economic and policy incentives that facilitate carbon capture and sequestration (CCS) deployment. A unit-level retrofit analysis shows that deploying CCS at existing coal-fired power plants in Wyoming to meet the HB0200 emission limit would decrease the net efficiency by 29% and increase the levelized cost of electricity by 237% on the fleet average. The CO2 avoidance cost varies by unit from $65/t to 201/t, which reveals economic challenges for CCS retrofits. However, the current tax credit of $50 per metric ton of CO2 for saline-reservoir storage can lower the avoidance cost by 47% on the fleet average. The proposed enhancement of the tax credit to $85/t would offset the added cost for CCS deployment for a total capacity of 3.4 GW. Joint policy and economic incentives can encourage fossil fuel abatement to play a firm role in energy transition.

Climate-Induced Tradeoffs in Planning and Operating Costs of a Regional Electricity System.

Electricity grid planners design the system to supply electricity to end-users reliably and affordably. Climate change threatens both objectives through potentially compounding supply- and demand-side climate-induced impacts. Uncertainty surrounds each of these future potential impacts. Given long planning horizons, system planners must weigh investment costs against operational costs under this uncertainty. Here, we developed a comprehensive and coherent integrated modeling framework combining physically based models with cost-minimizing optimization models in the power system. We applied this modeling framework to analyze potential tradeoffs in planning and operating costs in the power grid due to climate change in the Southeast U.S. in 2050. We find that planning decisions that do not account for climate-induced impacts would result in a substantial increase in social costs associated with loss of load. These social costs are a result of under-investment in new capacity and capacity deratings of thermal generators when we included climate change impacts in the operation stage. These results highlight the importance of including climate change effects in the planning process.

Effects of Climate Change on Capacity Expansion Decisions of an Electricity Generation Fleet in the Southeast U.S.

The electric power sector in the United States faces many challenges related to climate change. On the demand side, climate change could shift demand patterns due to increased air temperatures. On the supply side, climate change could lead to deratings of thermal units due to changes in air temperature, water temperature, and water availability. Past studies have typically analyzed these risks separately. Here, we developed an integrated, multimodel framework to analyze how compounding risks of climate-change impacts on demand and supply affect long-term planning decisions in the power system. In the southeast U.S., we found that compounding climate-change impacts could result in a 35% increase in installed capacity by 2050 relative to the reference case. Participation of renewables, particularly solar, in the fleet increased, driven mostly by the expected increase in summertime peak demand. Such capacity requirements would increase investment costs by approximately 31 billion (USD 2015) over the next 30 years, compared to the reference case. These changes in investment decisions align with carbon emission mitigation strategies, highlighting how adaptation and mitigation strategies can converge.

Advanced Membranes and Learning Scale Required for Cost-Effective Post-combustion Carbon Capture.

This study offers an integrated vision for advanced membrane technology for post-combustion carbon capture. To inform development of new-generation materials, a plant-level techno-economic analysis is performed to explore major membrane property targets required for cost-effective CO2 capture. To be competitive with amine-based nth-of-a-kind (NOAK) technology or meet a more ambitious cost target for 90% CO2 capture, advanced membranes should have a higher CO2 permeance than 2,250 GPU and a higher CO2/N2 selectivity than 30 if their installed prices are higher than $50/m2. To assess learning experience required for advanced technology using such high-performance membranes toward commercialization, a hybrid approach that combines learning curves with the techno-economic analysis is applied to project the cumulative installed capacity necessary for the evolution from first-of-a-kind to NOAK systems. The estimated learning scale for advanced membrane technology is more than 10 GW, depending on multiple factors. Implications for research, development, and policy are discussed.

Systems Analysis of Physical Absorption of CO2 in Ionic Liquids for Pre-Combustion Carbon Capture.

This study develops an integrated technical and economic modeling framework to investigate the feasibility of ionic liquids (ILs) for precombustion carbon capture. The IL 1-hexyl-3-methylimidazolium bis(trifluoromethylsulfonyl)imide is modeled as a potential physical solvent for CO2 capture at integrated gasification combined cycle (IGCC) power plants. The analysis reveals that the energy penalty of the IL-based capture system comes mainly from the process and product streams compression and solvent pumping, while the major capital cost components are the compressors and absorbers. On the basis of the plant-level analysis, the cost of CO2 avoided by the IL-based capture and storage system is estimated to be $63 per tonne of CO2. Technical and economic comparisons between IL- and Selexol-based capture systems at the plant level show that an IL-based system could be a feasible option for CO2 capture. Improving the CO2 solubility of ILs can simplify the capture process configuration and lower the process energy and cost penalties to further enhance the viability of this technology.

The Economic Merits of Flexible Carbon Capture and Sequestration as a Compliance Strategy with the Clean Power Plan.

Carbon capture and sequestration (CCS) may be a key technology for achieving large CO2 emission reductions. Relative to "normal" CCS, "flexible" CCS retrofits include solvent storage that allows the generator to temporarily reduce the CCS parasitic load and increase the generator's net efficiency, capacity, and ramp rate. Due to this flexibility, flexible CCS generators provide system benefits that normal CCS generators do not, which could make flexible CCS an economic CO2 emission reduction strategy. Here, we estimate the system-level cost effectiveness of reducing CO2 emissions with flexible CCS compared to redispatching (i.e., substituting gas- for coal-fired electricity generation), wind, and normal CCS under the Clean Power Plan (CPP) and a hypothetical more stringent CO2 emission reduction target ("stronger CPP"). Using a unit commitment and economic dispatch model, we find flexible CCS achieves more cost-effective emission reductions than normal CCS under both reduction targets, indicating that policies that promote CCS should encourage flexible CCS. However, flexible CCS is less cost effective than wind under both reduction targets and less and more cost effective than redispatching under the CPP and stronger CPP, respectively. Thus, CCS will likely be a minor CPP compliance strategy but may play a larger role under a stronger emission reduction target.

Consumptive Water Use from Electricity Generation in the Southwest under Alternative Climate, Technology, and Policy Futures.

This research assesses climate, technological, and policy impacts on consumptive water use from electricity generation in the Southwest over a planning horizon of nearly a century. We employed an integrated modeling framework taking into account feedbacks between climate change, air temperature and humidity, and consequent power plant water requirements. These direct impacts of climate change on water consumption by 2095 differ with technology improvements, cooling systems, and policy constraints, ranging from a 3-7% increase over scenarios that do not incorporate ambient air impacts. Upon additional factors being changed that alter electricity generation, water consumption increases by up to 8% over the reference scenario by 2095. With high penetration of wet recirculating cooling, consumptive water required for low-carbon electricity generation via fossil fuels will likely exacerbate regional water pressure as droughts become more common and population increases. Adaptation strategies to lower water use include the use of advanced cooling technologies and greater dependence on solar and wind. Water consumption may be reduced by 50% in 2095 from the reference, requiring an increase in dry cooling shares to 35-40%. Alternatively, the same reduction could be achieved through photovoltaic and wind power generation constituting 60% of the grid, consistent with an increase of over 250% in technology learning rates.

Viability of Carbon Capture and Sequestration Retrofits for Existing Coal-Fired Power Plants under an Emission Trading Scheme.

Using data on the coal-fired electric generating units (EGUs) in Texas we assess the economic feasibility of retrofitting existing units with carbon capture and sequestration (CCS) in order to comply with the Clean Power Plan's rate-based emission standards under an emission trading scheme. CCS with 90% capture is shown to be more economically attractive for a range of existing units than purchasing emission rate credits (ERCs) from a trading market at an average credit price above $28 per MWh under the final state standard and $35 per MWh under the final national standard. The breakeven ERC trading prices would decrease significantly if the captured CO2 were sold for use in enhanced oil recovery, making CCS retrofits viable at lower trading prices. The combination of ERC trading and CO2 use can greatly reinforce economic incentives and market demands for CCS and hence accelerate large-scale deployment, even under scenarios with high retrofit costs. Comparing the levelized costs of electricity generation between CCS retrofits and new renewable plants under the ERC trading scheme, retrofitting coal-fired EGUs with CCS may be significantly cheaper than new solar plants under some market conditions.