@article{ssembatya_kern_oikonomou_voisin_burleyson_akdemir_2024, title={Dual Impacts of Space Heating Electrification and Climate Change Increase Uncertainties in Peak Load Behavior and Grid Capacity Requirements in Texas}, volume={12}, ISSN={2328-4277 2328-4277}, url={http://dx.doi.org/10.1029/2024EF004443}, DOI={10.1029/2024EF004443}, abstractNote={Abstract Around 60% of households in Texas currently rely on electricity for space heating. As decarbonization efforts increase, non‐electrified households could adopt electric heat pumps, significantly increasing peak (highest) electricity demand in winter. Simultaneously, anthropogenic climate change is expected to increase temperatures, the potential for summer heat waves, and associated electricity demand for cooling. Uncertainty regarding the timing and magnitude of these concurrent changes raises questions about how they will jointly affect the seasonality of peak demand, firm capacity requirements, and grid reliability. This study investigates the net effects of residential space heating electrification and climate change on long‐term demand patterns and load shedding potential, using climate change projections, a predictive load model, and a direct current optimal power flow (DCOPF) model of the Texas grid. Results show that full electrification of residential space heating by replacing existing fossil fuel use with higher efficiency heat pumps could significantly improve reliability under hotter futures. Less efficient heat pumps may result in more severe winter peaking events and increased reliability risks. As heating electrification intensifies, system planners will need to balance the potential for greater resource adequacy risk caused by shifts in seasonal peaking behavior alongside the benefits (improved efficiency and reductions in emissions).}, number={6}, journal={Earth's Future}, publisher={American Geophysical Union (AGU)}, author={Ssembatya, Henry and Kern, Jordan D. and Oikonomou, Konstantinos and Voisin, Nathalie and Burleyson, Casey D. and Akdemir, Kerem Ziya}, year={2024}, month={Jun} }
 @article{singh_quinn_kern_cuppari_characklis_2024, title={Exploring the benefits of integrated energy-water management in reducing economic and environmental tradeoffs}, volume={1}, ISSN={2753-3751}, url={http://dx.doi.org/10.1088/2753-3751/ad713d}, DOI={10.1088/2753-3751/ad713d}, abstractNote={Abstract Integrated water-energy management is crucial for balancing socioeconomic and environmental objectives in multi-reservoir systems. Multipurpose reservoirs support clean energy production, recreation, navigation, and flood protection but also disrupt natural water flows and fish migration. As hydropower’s role evolves with grid decarbonization, managing these tradeoffs becomes increasingly complex. An integrated model combining economic and environmental factors is essential to inform how to adapt hydropower operations effectively to complement decarbonization of the electric grid. However, existing literature lacks such comprehensive models. This study introduces an integrated water-energy optimization model using the Columbia River Basin (CRB) and Mid-Columbia energy market as a case study. The model couples a simulation of operations of 47 CRB reservoirs with a unit commitment/economic dispatch model of the California and West Coast Power system. We employ Direct policy search and a multi-objective evolutionary algorithm to optimize four objectives: maximize economic benefits from energy production, minimize fossil fuel electricity generation, minimize environmental flow violations, and minimize peak flood levels. Our findings reveal that the integrated model discovers superior operational strategies compared to existing rules, with some policies outperforming current operations on all objectives simultaneously. Insights from the optimized policies include strategies for improved coordination of reservoir operations using storage and inflow data, and the strategic timing of water releases to ensure increased hydropower production leads to less fossil fuel dependence and greater revenue. These results highlight the potential of integrated models to enhance the sustainability of hydropower operations amid a transitioning energy landscape.}, number={3}, journal={Environmental Research: Energy}, publisher={IOP Publishing}, author={Singh, Samarth and Quinn, Julianne and Kern, Jordan and Cuppari, Rosa and Characklis, Greg}, year={2024}, month={Sep}, pages={035010} }
 @article{alvear_haas_palma-behnke_peer_medina_kern_2024, title={Green hydrogen exports in New Zealand and Chile can improve electricity supply security if configured as local energy insurance}, volume={304}, ISSN={0360-5442}, url={http://dx.doi.org/10.1016/j.energy.2024.131930}, DOI={10.1016/j.energy.2024.131930}, abstractNote={Extreme weather events, for example, prolonged droughts, are increasingly stressing electricity systems and threatening the achievement of energy transition goals. At the same time, countries such as Chile and New Zealand are developing strategies to export renewable energy through green hydrogen. This paper economically evaluates the use of future green hydrogen exports as strategic storage under the logic of energy insurance, based on the assumption that Chile and New Zealand will adopt a hydrogen economy. Our first contribution is to compare the marginal costs of re-electrified green hydrogen for different scenarios, to the value of lost load in New Zealand and Chile. We then determine the marginal cost of energy produced from green hydrogen based on projected production, transportation, and re-electrification costs for the year 2030. Finally, we estimate the eventual penalties that exporters would incur in the case of breaking their contracts and the overall resulting system costs of using hydrogen for system security. We found that re-electrifying hydrogen can be competitive with conventional technologies at 3 USD/kg. At 1.5 USD/kg, hydrogen is more competitive than fossil fuel-based technologies, for both New Zealand and Chile. Thus, in 2030, it could make economic sense for New Zealand and Chile to use hydrogen as a strategic reserve. The system cost of the proposed insurance scheme in 2030 ranges from 0.53 to 1.76 USD/MWh, which is small compared to total electricity costs. These values can be used for power system expansion and operation planning.}, journal={Energy}, publisher={Elsevier BV}, author={Alvear, Carlos and Haas, Jannik and Palma-Behnke, Rodrigo and Peer, Rebecca and Medina, Juan Pablo and Kern, Jordan D.}, year={2024}, month={Sep}, pages={131930} }
 @article{prieto-miranda_kern_2024, title={High-resolution, open-source modeling of inland flooding impacts on the North Carolina bulk electric power grid}, volume={1}, ISSN={2753-3751}, url={http://dx.doi.org/10.1088/2753-3751/ad3558}, DOI={10.1088/2753-3751/ad3558}, abstractNote={Abstract
               Although damages to local distribution systems from wind and fallen trees are typically responsible for the largest fraction of electricity outages during hurricanes, outages caused by flooding of electrical substations pose a unique risk. Electrical substations are a key component of electric power systems, and in some areas, the loss of a single substation can cause widespread power outages. Before repairing damaged substations, utilities must first allow floodwaters to recede, potentially leaving some customers without power for weeks following storms. As economic losses from flooding continue to increase in the U.S., there has been increasing attention paid to the potential impacts of flooding on power systems. Yet, this attention has mostly been limited to geospatial risk assessments that identify what assets are in the path of flooding. Here, we present the first major attempt to understand how flooding from hurricanes and other extreme precipitation events affects the dynamic behavior of power networks, including losses of demand and generation, and altered power flows through transmission lines. We use North Carolina, hit by major hurricanes in three of the past seven years, as a test case. Using open-source data of grid infrastructure, we develop a high-resolution direct current optimal power flow model that simulates electricity production and generators and power flows through a network consisting of 662 nodes and 790 lines. We then simulate grid operations during the historical (2018) storm Hurricane Florence. Time series of flooding depth at a discrete set of ‘high water’ mark points from the storm are used to spatially interpolate flooding depth across the footprint area of the storms on an hourly basis. Outages of substations and solar farms due to flooding are translated to location-specific losses of demand and solar power production throughout the network. We perform sensitivity analysis to explore grid impacts as a function of the height of sensitive equipment at substations. Results shed light on the potential for localized impacts from flooding to have wider impacts throughout the grid (including in areas not affected by flooding), with performance tracked in terms of transmission line flows/congestion, generation outputs, and customer outages.}, number={1}, journal={Environmental Research: Energy}, publisher={IOP Publishing}, author={Prieto-Miranda, Luis and Kern, Jordan D}, year={2024}, month={Mar}, pages={015005} }
 @article{kern_2024, title={Utilities Are Planning for the Wrong Kind of Hurricane}, journal={Heatmap News}, author={Kern, J.}, year={2024}, month={Oct} }
 @article{akdemir_oikonomou_kern_voisin_ssembatya_qian_2024, title={An open-source framework for balancing computational speed and fidelity in production cost models}, volume={1}, ISSN={2753-3751}, url={http://dx.doi.org/10.1088/2753-3751/ad1751}, DOI={10.1088/2753-3751/ad1751}, abstractNote={Abstract
               Studies of bulk power system operations need to incorporate uncertainty and sensitivity analyses, especially around exposure to weather and climate variability and extremes, but this remains a computational modeling challenge. Commercial production cost models (PCMs) have shorter runtimes, but also important limitations (opacity, license restrictions) that do not fully support stochastic simulation. Open-source PCMs represent a potential solution. They allow for multiple, simultaneous runs in high-performance computing environments and offer flexibility in model parameterization. Yet, developers must balance computational speed (i.e. runtime) with model fidelity (i.e. accuracy). In this paper, we present Grid Operations (GO), a framework for instantiating open-source, scale-adaptive PCMs. GO allows users to search across parameter spaces to identify model versions that appropriately balance computational speed and fidelity based on experimental needs and resource limits. Results provide generalizable insights on how to navigate the fidelity and computational speed tradeoff through parameter selection. We show that models with coarser network topologies can accurately mimic market operations, sometimes better than higher-resolution models. It is thus possible to conduct large simulation experiments that characterize operational risks related to climate and weather extremes while maintaining sufficient model accuracy.}, number={1}, journal={Environmental Research: Energy}, publisher={IOP Publishing}, author={Akdemir, Kerem Ziya and Oikonomou, Konstantinos and Kern, Jordan D and Voisin, Nathalie and Ssembatya, Henry and Qian, Jingwei}, year={2024}, month={Jan}, pages={015003} }
 @article{kern_2023, title={Blackouts experienced during low temps last month are bound to happen again}, journal={The Post and Courier}, author={Kern, J.}, year={2023}, month={Jan} }
 @article{kern_2023, title={Droughts and heat waves could worsen air pollution for vulnerable communities}, journal={L.A.Times}, author={Kern, J.}, year={2023}, month={Mar} }
 @article{akdemir_robertson_oikonomou_kern_voisin_hanif_bhattacharya_2023, title={Opportunities for wave energy in bulk power system operations}, volume={352}, ISSN={["1872-9118"]}, DOI={10.1016/j.apenergy.2023.121845}, abstractNote={Wave energy resources have high, yet largely untapped potential as candidate generation technology. In this paper, we perform a data-driven analysis to characterize the impact of wave energy integration on bulk-scale power systems and market operations. Through data-driven sensitivity studies centered on an optimization-based production cost modeling formulation, our work characterizes the inflection point beyond which wave integration starts impacting power system operations, considering present day transmission infrastructure. Furthermore, our analysis also considers the joint effects of wave energy integration and system-wide transmission expansion. Finally, potential resilience scenarios such as wildfire-driven transmission contingencies and heat wave events are investigated, whereby the contributions of grid-integrated wave energy in alleviating the effects of the resilience events are analyzed. As our demonstration test bed, we consider a reduced-order network topology for the U.S. Western Interconnection with wave energy generation integrated at carefully selected sites across the coastal areas of Washington, Oregon, and northern California. Our results indicate that over a representative year of operations, wave energy integration systematically reduces locational marginal prices (LMPs) of energy and price volatility, especially during periods of high wave resource availability (winter months for the U.S. west coast). Average, maximum, and minimum of hourly LMPs over a typical year of operation was reduced by 2.95, 51.28, and 1.13 $/MWh respectively (over a baseline scenario with no wave energy integration), when the selected network model had a total of 5000 MW wave power installed capacity during the representative year of study. The effects of wave energy integration can remain localized with existing transmission infrastructure (identified to be most pronounced in the Pacific Northwest region in the example we studied). However, with concurrent transmission expansion, the impacts of wave energy integration are likely to have a higher geographical spread. Our results also indicate that wave energy may be able to assist power system operations during resilience events such as major transmission contingencies and heat wave events, although such benefits might be dependent on factors such as proximity of affected area to wave resources, availability of adequate resource potential and adequate transmission capacity.}, journal={APPLIED ENERGY}, author={Akdemir, Kerem Ziya and Robertson, Bryson and Oikonomou, Konstantinos and Kern, Jordan and Voisin, Nathalie and Hanif, Sarmad and Bhattacharya, Saptarshi}, year={2023}, month={Dec} }
 @article{kern_2023, title={Rolling blackouts can protect power grid from serious damage}, journal={CBS 17 WNCN}, author={Kern, J.}, year={2023}, month={Jan} }
 @article{kern_2023, title={Sturdier, more weatherproof. Improvements being made to power grid to prevent prolonged outages}, journal={ABC 11}, author={Kern, J.}, year={2023}, month={Aug} }
 @article{zeighami_kern_yates_weber_bruno_2023, title={U.S. West Coast droughts and heat waves exacerbate pollution inequality and can evade emission control policies}, volume={14}, ISSN={2041-1723}, url={http://dx.doi.org/10.1038/s41467-023-37080-0}, DOI={10.1038/s41467-023-37080-0}, abstractNote={AbstractDroughts reduce hydropower production and heatwaves increase electricity demand, forcing power system operators to rely more on fossil fuel power plants. However, less is known about how droughts and heat waves impact the county level distribution of health damages from power plant emissions. Using California as a case study, we simulate emissions from power plants under a 500-year synthetic weather ensemble. We find that human health damages are highest in hot, dry years. Counties with a majority of people of color and counties with high pollution burden (which are somewhat overlapping) are disproportionately impacted by increased emissions from power plants during droughts and heat waves. Taxing power plant operations based on each plant’s contribution to health damages significantly reduces average exposure. However, emissions taxes do not reduce air pollution damages on the worst polluting days, because supply scarcity (caused by severe heat waves) forces system operators to use every power plant available to avoid causing a blackout.}, number={1}, journal={Nature Communications}, publisher={Springer Science and Business Media LLC}, author={Zeighami, Amir and Kern, Jordan and Yates, Andrew J. and Weber, Paige and Bruno, August A.}, year={2023}, month={Mar} }
 @article{akdemir_kern_lamontagne_2022, title={Assessing risks for New England's wholesale electricity market from wind power losses during extreme winter storms}, volume={251}, ISSN={0360-5442}, url={http://dx.doi.org/10.1016/j.energy.2022.123886}, DOI={10.1016/j.energy.2022.123886}, abstractNote={In the United States, New England faces difficulties from severe winter weather, during which its power grid simultaneously experiences high natural gas prices and electricity demand, leading to spikes in wholesale electricity prices. In recent years, a significant amount of offshore wind power capacity has been planned for the region, and previous studies have suggested the presence of offshore wind could lower emissions and market prices during cold snaps. However, there has been limited consideration of potential wind power losses during extreme winter weather due to excessive wind speeds, which could lead to sudden losses of wind power. This aim of this study is to quantify risks associated with sudden wind power losses during extreme winter weather, especially the potential for these events to cause spikes in the wholesale electricity price. Results suggest that these so-called wind turbine "cut-out" events likely represent a minor risk compared to the loss of wind power due to low wind speeds and sudden drops in wind speeds during summer, when demand for electricity is higher. Overall, the benefits of having offshore wind power during extreme winter weather appear to outweigh the risks associated with relatively rare cut-out events caused by excessive wind speeds.}, journal={Energy}, publisher={Elsevier BV}, author={Akdemir, Kerem Ziya and Kern, Jordan D. and Lamontagne, Jonathan}, year={2022}, month={Jul}, pages={123886} }
 @article{denaro_cuppari_kern_su_characklis_2022, title={Assessing the Bonneville Power Administration’s Financial Vulnerability to Hydrologic Variability}, volume={148}, ISSN={0733-9496 1943-5452}, url={http://dx.doi.org/10.1061/(ASCE)WR.1943-5452.0001590}, DOI={10.1061/(ASCE)WR.1943-5452.0001590}, abstractNote={Hydrologic variability can cause large swings in hydropower generation, inducing significant volatility in power sales. Dry years often result in low revenues that can threaten a hydropower supplier's ability to meet its fixed costs, leading to budget shortfalls, lower credit ratings, higher interest rates, and, ultimately, higher rates. This is particularly true for suppliers in hydropower-dominated regions, such as the Bonneville power administration (BPA). The BPA strategy for managing its hydrologic financial risk is multilayered, involving cash reserves, a line of credit, and tariff adjustments. Yet, compared to its long-term energy contracts and debt service, BPA's risk assessment is conducted on a short-term basis, thereby neglecting medium- and long-term temporal dynamics impacting their financial risk. This paper focuses on (1) evaluating BPA's hydrologic financial risk; and (2) testing the effectiveness of BPA's existing risk management strategy. Results suggest that BPA's financial risk will grow substantially over the next 20 years as its risk management tools become increasingly inadequate, providing cautionary lessons for organizations in similarly hydrodominated systems despite the current use of common risk management tools.}, number={10}, journal={Journal of Water Resources Planning and Management}, publisher={American Society of Civil Engineers (ASCE)}, author={Denaro, Simona and Cuppari, Rosa I. and Kern, Jordan D. and Su, Yufei and Characklis, Gregory W.}, year={2022}, month={Oct} }
 @article{kern_2022, title={Climate change makes West Coast more susceptible to blackouts}, journal={The Hill}, author={Kern, J.}, year={2022}, month={Jan} }
 @article{kern_2022, title={Duke Energy aims to double renewable energy capacity by 2030}, journal={Renewable Energy World}, author={Kern, J.}, year={2022}, month={Feb} }
 @article{kern_2022, title={Extreme Weather is Weakening U.S. Hydropower and Stressing Energy Grids}, journal={TIME Magazine}, author={Kern, J.}, year={2022}, month={Sep} }
 @article{koh_kern_galelli_2022, title={Hard-coupling water and power system models increases the complementarity of renewable energy sources}, volume={321}, ISSN={0306-2619}, url={http://dx.doi.org/10.1016/j.apenergy.2022.119386}, DOI={10.1016/j.apenergy.2022.119386}, abstractNote={The soft (one-way) coupling of water and power system models is the dominant approach for studying the impact of water availability on grid performance. Yet, such approach does not explicitly capture key dynamic interdependencies between the state of the grid and the operational decisions made at the water system level. Here, we address this gap and introduce a novel numerical modelling framework that hard-couples a multi-reservoir system model and a power system model. The framework captures two-way feedback mechanisms and thereby enables operational decisions to be made contingent upon the states of both the water and energy system. We evaluate the framework on a real-world case study based on the Cambodian grid. In light of the country's plan to further decarbonize its grid, we tested the framework on three grid configurations—the as-is grid, and the grid with two different levels of installed solar capacity. Simulation experiments were run with and without feedback, while uncertainty in external forcings was explored through 1,000 stochastic time series of streamflow, solar production, and load. As demonstrated in our results, hard-coupling the water and energy systems reduces operating costs and CO2 emissions while increasing the integration of renewables. Under favourable conditions (large reservoir inflow and low electricity demand), the system experienced a 44% saving in annual operating costs and 53% reduction of CO2 emissions. A spatio-temporal analysis on the reservoir operations and transmission line usage reveals that the timing of the monsoon and interconnections between individual grid components also play significant roles in influencing the system's responses to the hard coupling. Overall, simulation frameworks like this provide a modelling framework for testing management and planning solutions aimed to improve the performance of water-energy systems.}, journal={Applied Energy}, publisher={Elsevier BV}, author={Koh, Rachel and Kern, Jordan and Galelli, Stefano}, year={2022}, month={Sep}, pages={119386} }
 @article{kern_2022, title={How global warming could further mess up electric power on the West Coast}, journal={Jefferson Public Radio}, author={Kern, J.}, year={2022}, month={Jan} }
 @article{kern_2022, title={How the Western drought is pushing the power grid to the brink}, journal={Vox}, author={Kern, J.Vox}, year={2022}, month={Aug} }
 @article{kleiman_characklis_kern_2022, title={Managing weather- and market price-related financial risks in algal biofuel production}, volume={200}, ISSN={0960-1481}, url={http://dx.doi.org/10.1016/j.renene.2022.09.104}, DOI={10.1016/j.renene.2022.09.104}, abstractNote={Large-scale algae production has garnered interest due to its potential as a biofuel feedstock. Previous research assessing the profitability of algae products has been mostly based on values averaged over time, but algae production and resulting financial returns exhibit significant variability due to weather and fluctuations in selling prices for algae-based products. In other sectors, producers often reduce weather- and market price-related financial risk with financial instruments such as insurance, but little research has been performed on the design of insurance products to protect algae producers. This study develops a novel index-based insurance instrument that pays-out during unfavorable weather and market conditions, then explores the instrument's effectiveness, combined with a cash reserve, in reducing revenue stream variability for an algae producer. Results indicate that a biophysically based index-insurance product tailored to the specific financial risks in algae production can reduce variability in net revenues and can do so at a lower cost than relying solely on cash reserves, the most common financial risk management tool. Assessing the performance of index-insurance in algae production is particularly timely given the passage of the 2018 Farm Bill, which newly opens opportunities for the USDA to provide crop insurance to algae producers.}, journal={Renewable Energy}, publisher={Elsevier BV}, author={Kleiman, Rachel M. and Characklis, Gregory W. and Kern, Jordan D.}, year={2022}, month={Nov}, pages={111–124} }
 @article{kern_2022, title={Officials investigate after fire, explosion at Hoover Dam}, journal={AP. News}, author={Kern, J.}, year={2022}, month={Jul} }
 @article{kern_2022, title={Southwest megadrought pushes hydropower to the brink}, journal={E.&E.News EnergyWire}, author={Kern, J.}, year={2022}, month={May} }
 @article{kern_2022, title={West Coast power grid at mercy of climate change — and prices may soar, study finds}, journal={Sun Herald}, author={Kern, J.}, year={2022}, month={Jan} }
 @article{kern_2022, title={What the Western drought reveals about hydropower}, journal={E&E News EnergyWire}, author={Kern, J.}, year={2022}, month={Sep} }
 @article{lucy_kern_2021, title={Analysis of fixed volume swaps for hedging financial risk at large-scale wind projects}, volume={103}, ISSN={["1873-6181"]}, url={http://dx.doi.org/10.1016/j.eneco.2021.105603}, DOI={10.1016/j.eneco.2021.105603}, abstractNote={Large scale wind power projects are increasingly selling power directly into wholesale electricity markets without the benefits of stable (fixed price) off-take agreements. As a result, many wind power producers seek financial hedging contracts to mitigate exposure to price risk. One particular hedging contract - the “fixed volume price swap” - has gained widespread use, but it poses several liabilities for wind power producers that reduce its effectiveness. In this paper, we examine problems associated with fixed volume swaps and explore possibilities for improving their performance. Using a hypothetical wind power project in the Southwest Power Pool (SPP) market as a case study, we first look at how “shape risk” (an imbalance between actual wind power production and hourly production targets specified by contract terms) negatively impacts contract performance and whether this could be remedied through improved contract design. Using a multi-objective optimization algorithm, we find examples of alternative contract parameters (hourly wind power production targets) that are more effective at increasing revenues during low performing months and do so at a lower cost than conventional fixed volume swaps. Then we examine how “basis risk” (a discrepancy in market prices between the “node” where the wind project injects power into the grid, and the regional hub price) can negatively impact contract performance. Overall, our results suggest that wind power producers would be better served hedging substantially lower volumes of wind power production, and in certain months should not be hedging at all. Another key finding is that contract performance improves with modest reductions in basis risk. This indicates that eliminating transmission congestion issues across the grid may not be necessary to improve contract performance.}, journal={ENERGY ECONOMICS}, publisher={Elsevier BV}, author={Lucy, Zachary and Kern, Jordan}, year={2021}, month={Nov} }
 @article{kleiman_characklis_kern_gerlach_2021, title={Characterizing weather-related biophysical and financial risks in algal biofuel production}, volume={294}, ISSN={0306-2619}, url={http://dx.doi.org/10.1016/j.apenergy.2021.116960}, DOI={10.1016/j.apenergy.2021.116960}, abstractNote={Algal biofuels are a renewable liquid fuel with advantages over crop-based biofuels, including higher yield per acre, the ability to recycle production inputs, and the option to create valuable co-products. Previous analyses suggest that algal biofuels could become cost-competitive if technological improvements are achieved. Most previous research, however, does not consider the impact of seasonal and year-to-year uncertainty in weather factors, such as solar irradiance and temperature, on biomass productivity, and those that do are based on limited meteorological records. This study explores the influence of weather uncertainty on biomass growth and biorefinery revenues as well as impacts from market price uncertainty. The performance of a hypothetical algal biorefinery in Vero Beach, Florida is explored by combining stochastic weather generation, biophysical growth modelling, stochastic market price generation, and techno-economic analysis. Results show coefficient of variation values of 8–15% in seasonal revenues for an algae producer, and that the variation in annual revenues was lower than that of corn, soybean, and cotton. In sensitivity analyses, both weather and price fluctuations are found to be significant sources of financial risk. This is the first probabilistic quantification of weather-related production impacts for algae producers, which is relevant given global growth in the algae industry as evidenced by the new eligibility of algae for crop insurance in the US 2018 Farm Bill.}, journal={Applied Energy}, publisher={Elsevier BV}, author={Kleiman, Rachel M. and Characklis, Gregory W. and Kern, Jordan D. and Gerlach, Robin}, year={2021}, month={Jul}, pages={116960} }
 @article{oikonomou_tarroja_kern_voisin_2022, title={Core process representation in power system operational models: Gaps, challenges, and opportunities for multisector dynamics research}, volume={238}, ISSN={["1873-6785"]}, url={http://dx.doi.org/10.1016/j.energy.2021.122049}, DOI={10.1016/j.energy.2021.122049}, abstractNote={Power grid operations increasingly interact with environmental systems and human systems such as transportation, agriculture, the economy, and financial markets. Our objective is to discuss the modelling gaps and opportunities to advance the science for multisector adaptation and tradeoffs. We focus on power system operational models, which typically represent key physical and economic aspects of grid operations over days to a year and assume a fixed power grid infrastructure. Due to computational burden, models are typically customized to reflect regional resource opportunities, data availability, and applications of interest. We conceptualize power system operational models with four core processes: physical grid assets (generation, transmission, loads, and storage), model objectives and purpose, institutions and decision agents, and performance metrics. We taxonomize the representations of these core processes based on a review of 23 existing models. Using science questions around grid and short term uncertainties, long term global change, and multisectoral technological innovation as examples, we report on tradeoffs in process fidelity and tractability that have been adopted by the research community to represent multisectoral interactions in power system operational models. Our recommendations for research directions are model-agnostic, focusing on core processes, their interactions with other human systems, and consider computational tradeoffs.}, journal={ENERGY}, publisher={Elsevier BV}, author={Oikonomou, Konstantinos and Tarroja, Brian and Kern, Jordan and Voisin, Nathalie}, year={2022}, month={Jan} }
 @article{kern_2021, title={Extreme Heat Could Also Mean Power and Water Shortages}, journal={Wired Magazine}, author={Kern, J.}, year={2021}, month={Jul} }
 @article{kern_2021, title={How Our Hydropower System Is Impacting The Drought Gripping The American West}, journal={National Public Radio}, publisher={Gripping The American West}, author={Kern, J.}, year={2021}, month={Jun} }
 @article{kern_2021, title={Hydropower decline adds strain to power grids in drought}, journal={ABC News}, author={Kern, J.}, year={2021}, month={Oct} }
 @article{kern_2021, title={Less water means more gas’: how drought will test California’s stressed power grid}, journal={The Guardian (UK)}, author={Kern, J.}, year={2021}, month={Jun} }
 @article{kern_2021, title={Not Just Wildfire: The Growing Ripple Effects Of More Extreme Heat And Drought}, journal={National Public Radio}, author={Kern, J.}, year={2021}, month={Jul} }
 @article{kern_2021, title={Plummeting reservoir levels could soon force Oroville hydropower offline}, journal={Los Angeles Times}, author={Kern, J.}, year={2021}, month={Jul} }
 @article{su_kern_characklis_2022, title={Retail Load Defection Impacts on a Major Electric Utility's Exposure to Weather Risk}, volume={148}, ISSN={["1943-5452"]}, url={http://dx.doi.org/10.1061/(asce)wr.1943-5452.0001531}, DOI={10.1061/(ASCE)WR.1943-5452.0001531}, abstractNote={Electric power utilities face a wide range of risks that cause financial uncertainty, with potential impacts on prices for customers. Among these, weather variability and retail load defection are perhaps two of the most studied. Whereas weather extremes expose utilities to unpredictable swings in electricity supply and demand, retail load defection, in which customers adopt distributed energy resources or switch to alternative providers, can alter utility business models fundamentally. We showed for the first time that these two phenomena can interact dynamically, with potential negative consequences for electricity ratepayers. We found that retail load defection could alter utilities’ financial exposure to weather risk in a matter of years. Using open-source power system simulation software coupled with a utility financial model, we simulated outcomes for a major hydropower-producing California electric utility under stationary hydrometeorological uncertainty, and under three different load defection scenarios ranging from 0% to 90%. We found that as load defection increases, the utility’s three main businesses (wholesale generation, transmission, and retail distribution) shift in relative importance. As a consequence, the impacts of interannual variability in hydropower production and demand in the utility’s system (a function of streamflow and air temperatures, respectively) become significantly altered. Air temperatures (a proxy for demand) become more predictive of utility financial performance, whereas the utility’s exposure to hydrology is poised to shift in complex ways. Drought will remain a major risk, but extremely wet years (which historically are beneficial to the utility’s significant hydropower holdings) may become damaging due to their association with low market prices. Our results also suggest that load defection could put much more pressure on utilities to make major annual rate adjustments or quickly adapt current strategies for managing weather risk.}, number={3}, journal={JOURNAL OF WATER RESOURCES PLANNING AND MANAGEMENT}, publisher={American Society of Civil Engineers (ASCE)}, author={Su, Yufei and Kern, Jordan and Characklis, Gregory W.}, year={2022}, month={Mar} }
 @article{wessel_kern_voisin_oikonomou_haas_2022, title={Technology Pathways Could Help Drive the U.S. West Coast Grid's Exposure to Hydrometeorological Uncertainty}, volume={10}, ISSN={2328-4277 2328-4277}, url={http://dx.doi.org/10.1029/2021EF002187}, DOI={10.1029/2021EF002187}, abstractNote={AbstractPrevious studies investigating deep decarbonization of bulk electric power systems and wholesale electricity markets have not sufficiently explored how future grid pathways could affect the grid's vulnerability to hydrometeorological uncertainty on multiple timescales. Here, we employ a grid operations model and a large synthetic weather ensemble to “stress test” a range of future grid pathways for the U.S. West Coast developed by ReEDS, a well‐known capacity planning model. Our results show that gradual changes in the underlying capacity mix from 2020 to 2050 can cause significant “re‐ranking” of weather years in terms of annual wholesale electricity prices (with “good” years becoming bad, and vice versa). Nonetheless, we find the highest and lowest ranking price years in terms of average electricity price remain mostly tied to extremes in hydropower availability (streamflow) and load (summer temperatures), with the strongest sensitivities related to drought. Seasonal dynamics seen today involving spring snowmelt and hot, dry summers remain well‐defined out to 2050. In California, future supply shortfalls in our model are concentrated in the evening and occur mostly during periods of high temperature anomalies in late summer months and in late winter; in the Pacific Northwest, supply shortfalls are much more strongly tied to negative streamflow anomalies. Under our more robust sampling of stationary hydrometeorological uncertainty, we also find that the ratio of dis‐patchable thermal (i.e., natural gas) capacity to wind and solar required to ensure grid reliability can differ significantly from values reported by ReEDS.}, number={1}, journal={Earth's Future}, publisher={American Geophysical Union (AGU)}, author={Wessel, Jacob and Kern, Jordan D. and Voisin, Nathalie and Oikonomou, Konstantinos and Haas, Jannik}, year={2022}, month={Jan} }
 @article{hill_kern_rupp_voisin_characklis_2021, title={The Effects of Climate Change on Interregional Electricity Market Dynamics on the U.S. West Coast}, volume={9}, ISSN={2328-4277 2328-4277}, url={http://dx.doi.org/10.1029/2021EF002400}, DOI={10.1029/2021EF002400}, abstractNote={AbstractThe United States (U.S.) West Coast power system is strongly influenced by variability and extremes in air temperatures (which drive electricity demand) and streamflows (which control hydropower availability). As hydroclimate changes across the West Coast, a combination of forces may work in tandem to make its bulk power system more vulnerable to physical reliability issues and market price shocks. In particular, a warmer climate is expected to increase summer cooling (electricity) demands and shift the average timing of peak streamflow (hydropower production) away from summer to the spring and winter, depriving power systems of hydropower when it is needed the most. Here, we investigate how climate change could alter interregional electricity market dynamics on the West Coast, including the potential for hydroclimatic changes in one region (e.g., Pacific Northwest (PNW)) to “spill over” and cause price and reliability risks in another (e.g., California). We find that the most salient hydroclimatic risks for the PNW power system are changes in streamflow, while risks for the California system are driven primarily by changes in summer air temperatures, especially extreme heat events that increase peak system demand. Altered timing and amounts of hydropower production in the PNW do alter summer power deliveries into California but show relatively modest potential to impact prices and reliability there. Instead, our results suggest future extreme heat in California could exert a stronger influence on prices and reliability in the PNW, especially if California continues to rely on its northern neighbor for imported power to meet higher summer demands.}, number={12}, journal={Earth's Future}, publisher={American Geophysical Union (AGU)}, author={Hill, Joy and Kern, Jordan and Rupp, David E. and Voisin, Nathalie and Characklis, Gregory}, year={2021}, month={Dec} }
 @article{kern_2021, title={Water Supply Dropping in Western Reservoirs}, journal={The Weather Channel}, author={Kern, J.}, year={2021}, month={Aug} }
 @article{kern_su_hill_2020, title={A retrospective study of the 2012-2016 California drought and its impacts on the power sector}, volume={15}, ISSN={["1748-9326"]}, url={http://dx.doi.org/10.1088/1748-9326/ab9db1}, DOI={10.1088/1748-9326/ab9db1}, abstractNote={Abstract
               Over the period 2012–2016, the state of California in the United States (U.S.) experienced a drought considered to be one of the worst in state history. Drought’s direct impacts on California’s electric power sector are understood. Extremely low streamflow manifests as reduced hydropower availability, and if drought is also marked by elevated temperatures, these can increase building electricity demands for cooling. Collectively, these impacts force system operators to increase reliance on natural gas power plants, increasing market prices and emissions. However, previous investigations have relied mostly on ex post analysis of observational data to develop estimates of increases in costs and carbon dioxide (CO2) emissions due to the 2012–2016 drought. This has made it difficult to control for confounding variables (e.g. growing renewable energy capacity, volatile natural gas prices) in assessing the drought’s impacts. In this study, we use a power system simulation model to isolate the direct impacts of several hydrometeorological phenomena observed during the 2012–2016 drought on system wide CO2 emissions and wholesale electricity prices in the California market. We find that the impacts of drought conditions on wholesale electricity prices were modest (annual prices increased by $0–3 MWh−1, although much larger within-year increases are also observed). Instead, it was an increase in natural gas prices, punctuated by the 2014 polar vortex event that affected much of the Eastern U.S., which caused wholesale electricity prices to increase during the drought. Costs from the drought were very different for the state’s three investor owned utilities. Overall, we find that increased cooling demands (electricity demand) during the drought may have represented a larger economic cost ($3.8 billion) than lost hydropower generation ($1.9 billion). We also find the potential for renewable energy to mitigate drought-cased increases in CO2 emissions to be negligible, standing in contrast to some previous studies.}, number={9}, journal={ENVIRONMENTAL RESEARCH LETTERS}, publisher={IOP Publishing}, author={Kern, Jordan D. and Su, Yufei and Hill, Joy}, year={2020}, month={Sep} }
 @article{su_kern_denaro_hill_reed_sun_cohen_characklis_2020, title={An open source model for quantifying risks in bulk electric power systems from spatially and temporally correlated hydrometeorological processes}, volume={126}, ISSN={1364-8152}, url={http://dx.doi.org/10.1016/j.envsoft.2020.104667}, DOI={10.1016/j.envsoft.2020.104667}, abstractNote={Variability (and extremes) in streamflow, wind speeds, temperatures, and solar irradiance influence supply and demand for electricity. However, previous research falls short in addressing the risks that joint uncertainties in these processes pose in power systems and wholesale electricity markets. Limiting challenges have included the large areal extents of power systems, high temporal resolutions (hourly or sub-hourly), and the data volumes and computational intensities required. This paper introduces an open source modeling framework for evaluating risks from correlated hydrometeorological processes in electricity markets at decision relevant scales. The framework is able to reproduce historical price dynamics in high profile systems, while also offering unique capabilities for stochastic simulation. Synthetic generation of weather and hydrologic variables is coupled with simulation models of relevant infrastructure (dams, power plants). Our model will allow the role of hydrometeorological uncertainty (including compound extreme events) on electricity market outcomes to be explored using publicly available models.}, journal={Environmental Modelling & Software}, publisher={Elsevier BV}, author={Su, Yufei and Kern, Jordan D. and Denaro, Simona and Hill, Joy and Reed, Patrick and Sun, Yina and Cohen, Jon and Characklis, Gregory W.}, year={2020}, month={Apr}, pages={104667} }
 @article{su_kern_reed_characklis_2020, title={Compound hydrometeorological extremes across multiple timescales drive volatility in California electricity market prices and emissions}, volume={276}, ISSN={0306-2619}, url={http://dx.doi.org/10.1016/j.apenergy.2020.115541}, DOI={10.1016/j.apenergy.2020.115541}, abstractNote={Hydrometeorological conditions influence the operations of bulk electric power systems and wholesale markets for electricity. Streamflow is the “fuel” for hydropower generation, wind speeds and solar irradiance dictate the availability of wind and solar power production, and air temperatures strongly affect heating and cooling demands. Despite growing concern about the vulnerability of power systems to hydrometeorological uncertainty, including “compound” extremes (multiple extremes occurring simultaneously), quantifying baseline probabilistic risks remains difficult even without factoring in climate change. Here, we use newly developed power system simulation software to show how uncertainties in spatially and temporally correlated hydrometeorological processes affect market prices and greenhouse gas emissions in California’s wholesale electricity market. Results highlight the need for large synthetic datasets to access rare, yet plausible system states that have not occurred in the recent historical record. We find that time scale strongly controls which combinations of hydrometeorological variables cause extreme outcomes. Although scarcity caused by low streamflows and high air temperatures has long been considered a primary concern in Western power markets, market prices are more profoundly impacted by weather and streamflow conditions that lead to an overabundance of energy on the grid.}, journal={Applied Energy}, publisher={Elsevier BV}, author={Su, Yufei and Kern, Jordan D. and Reed, Patrick M. and Characklis, Gregory W.}, year={2020}, month={Oct}, pages={115541} }
 @article{kern_2020, title={Decline in hydropower hampered by drought will impact utility costs}, journal={San Jose Mercury News}, author={Kern, J.}, year={2020}, month={Aug} }
 @article{boyle_haas_kern_2021, title={Development of an irradiance-based weather derivative to hedge cloud risk for solar energy systems}, volume={164}, ISSN={0960-1481}, url={http://dx.doi.org/10.1016/j.renene.2020.10.091}, DOI={10.1016/j.renene.2020.10.091}, abstractNote={For large energy consumers transitioning to high shares of solar energy, irradiance variability causes volatility in power generation and energy expenditures. Volatility in an end user's cash flow is harmful to their financial health, especially in abnormally cloudy years. This paper explores the utility of an irradiance-based weather derivative in mitigating cloud weather risk and measures the effectiveness of the developed derivative by applying it to a case study of two Chilean copper mines. Weather derivatives are financial instruments tied to an underlying weather variable that act as an insurance for the contract holder, executing indemnity payments based on an index value. This research develops a contract with a combined index based on monthly sums of irradiance and cloudy day sequencing to mitigate a solar mine's weather risk. The design and evaluation of contracts are based on LEELO, a linear optimization model outputting optimal sizes of solar photovoltaic, battery storage, and power-to-gas systems, as well as the operation of these systems for a given mine's load, irradiance and technology costs. Results indicate contracts are effective in cloudier climates with increasing utility for mines installing solar energy systems until the year 2030. After 2030 batteries begin to become a more cost-effective risk-hedging mechanism as they become more affordable.}, journal={Renewable Energy}, publisher={Elsevier BV}, author={Boyle, Colin F.H. and Haas, Jannik and Kern, Jordan D.}, year={2021}, month={Feb}, pages={1230–1243} }
 @article{chowdhury_kern_dang_galelli_2020, title={PowNet: A Network-Constrained Unit Commitment/Economic Dispatch Model for
                        Large-Scale Power Systems Analysis}, volume={8}, url={http://dx.doi.org/10.5334/jors.302}, DOI={10.5334/jors.302}, abstractNote={PowNet is a free modelling tool for simulating the Unit Commitment/Economic Dispatch of large-scale power systems. PowNet is specifically conceived for systems characterized by the presence of variable renewable resources (e.g., hydropower, solar, and wind), whose penetration on the grid is strongly influenced by climatic variability and constrained by the availability of transmission capacity. To help users effectively capture the nuances of power system dynamics, PowNet is equipped with features that enable accuracy, transferability, and computational efficiency over large spatial and temporal domains. Specifically, the model (i) accounts for the techno-economic constraints of both generating units and transmission networks, (ii) can be easily coupled with models that estimate the status of generating units as a function of the climatic conditions, and (iii) explicitly includes import/export nodes, which are useful in representing cross-border systems. PowNet is implemented in Python and is compatible with any standard optimization solver (e.g., Gurobi, CPLEX). Its functionality is demonstrated on the Cambodian power system. <strong>Funding statement:</strong> This research is supported by Singapore's Ministry of Education (MoE) through the Tier 2 project 'Linking water availability to hydropower supply—an engineering systems approach' (Award No. MOE2017-T2-1-143).}, number={1}, journal={Journal of Open Research Software}, publisher={Ubiquity Press, Ltd.}, author={Chowdhury, A. F. M. Kamal and Kern, Jordan and Dang, Thanh Duc and Galelli, Stefano}, year={2020}, month={Mar}, pages={5} }
 @article{wang_virguez_kern_chen_mei_patino-echeverri_wang_2019, title={Integrating wind, photovoltaic, and large hydropower during the reservoir refilling period}, volume={198}, ISSN={["1879-2227"]}, url={http://dx.doi.org/10.1016/j.enconman.2019.111778}, DOI={10.1016/j.enconman.2019.111778}, abstractNote={Hydropower facilities are an ideal solution to complement the intermittent production of energy from wind and solar photovoltaic facilities in electric power systems. However, adding this task to the multiple diverse duties of a reservoir (e.g., flood mitigation, water supply, and power generation) poses a challenge related to pursuing multiple and sometimes conflicting objectives. This study proposes an approach for integrating hydro, wind, and photovoltaic power during a reservoir’s refill period. Specifically, this approach simultaneously minimizes the fluctuation in the combined power output of these three resources and maximizes their combined power generation while adhering to the target reservoir’s water levels. The proposed approach uses a multiobjective optimization model that prescribes a day-ahead optimal hourly operation for a hydropower facility in terms of spilled water, water stored in the reservoir, and water used for power generation, while meeting a daily target to refill the reservoir. The prescribed scheduling is then used as the input into a model that simulates the actual operations of the power system. This study focuses on a hydro-wind-photovoltaic system located in southwestern China, where the peak power generating capacity of the hydropower facility is ten percent larger than the combined installed capacity of the wind and solar power. The results show that by using the proposed model, the hydropower facility effectively smooths the fluctuations in the combined power output caused by variable wind and photovoltaic power and concurrently meets the reservoir replenishing targets under dry, moderate, or wet hydrologic scenarios. Furthermore, the trade-offs between power generation maximization and power fluctuation reduction were found to depend on two conditions: whether the reservoir is full, and whether the turbine is generating electricity at its maximum capacity. The hydro-wind-photovoltaic integration is more cost-effective when the reservoir is not full and the turbines are not generating electricity at their maximum capacity. When the reservoir is full, hydropower still has the ability to balance the wind and photovoltaic power without curtailment but tends to result in water spillage (22–402 m3/s) and reductions in electricity generation (0.1–11.4 GWh per day). The proposed method for scheduling operations allows hydropower facilities to complement wind and photovoltaic power output, while meeting the target water levels during the refill period.}, journal={ENERGY CONVERSION AND MANAGEMENT}, publisher={Elsevier BV}, author={Wang, Xianxun and Virguez, Edgar and Kern, Jordan and Chen, Lihua and Mei, Yadong and Patino-Echeverri, Dalia and Wang, Hao}, year={2019}, month={Oct} }
 @article{chowdhury_kern_dang_galelli_2019, title={PowNet: a power systems analysis model for large-scale water-energy nexus studies}, url={https://arxiv.org/abs/1909.12529}, DOI={10.48550/arXiv.1909.12529}, abstractNote={PowNet is a free modelling tool for simulating the Unit Commitment / Economic Dispatch of large-scale power systems. PowNet is specifically conceived for applications in the water-energy nexus domain, which investigate the impact of water availability on electricity supply. To this purpose, PowNet is equipped with features that guarantee accuracy, reusability, and computational efficiency over large spatial and temporal domains. Specifically, the model (i) accounts for the techno-economic constraints of both generating units and transmission networks, (ii) can be easily coupled with models that estimate the status of generating units as a function of the climatic conditions, and (iii) explicitly includes import/export nodes, which are often found in cross-border systems. PowNet is implemented in Python and runs with the help of any standard optimization solver (e.g., Gurobi, CPLEX). Its functionality is demonstrated on the Cambodian power system.}, publisher={arXiv}, author={Chowdhury, AFM Kamal and Kern, Jordan and Dang, Thanh Duc and Galelli, Stefano}, year={2019} }
 @article{anindito_haas_olivares_nowak_kern_2019, title={A new solution to mitigate hydropeaking? Batteries versus re-regulation reservoirs}, volume={210}, ISSN={["1879-1786"]}, url={http://dx.doi.org/10.1016/j.jclepro.2018.11.040}, DOI={10.1016/j.jclepro.2018.11.040}, abstractNote={Hydropower plants frequently operate at high output during peak hours and at low output (or even shutoff) during off-peak hours. This scheme, called "hydropeaking", is harmful to downstream ecosystems. Operational constraints (minimum flows, maximum ramps) are frequently used to mitigate the impacts of hydropeaking. However, they reduce the operational flexibility of hydroelectric dams and increase the operational cost of power systems. Another approach to mitigating ecological impacts from hydropeaking is using structural measures, such as re-regulation reservoirs or afterbays. The first contribution of our work is to study the cost-effectiveness of these re-regulation reservoirs in mitigating ecological impacts from subdaily hydropeaking. Our second contribution is assessing energy storage (specifically, batteries) to mitigate the financial impacts of implementing peaking restrictions on dams, which represents the first attempt in the literature. Understanding these mitigation options is relevant for new hydropower dams, as well as for existing ones undergoing relicensing processes. For this, we formulate an hourly mixed-integer linear optimization model to simulate the annual operation of a power system. We then compare the business-as-usual (unconstrained) hydropower operations with ecologically constrained operations. The constrained operation, by limiting hydropower ramping rates, showed to obtain flows close to the natural streamflow regime. As next step, we show how re-regulation reservoirs and batteries can help to achieve these ecological constraints at lower costs. While the former are cost-effective for a very broad range of investment costs, the latter will be cost-effective for hydropeaking mitigation from 2025 onwards, when their capital costs have fallen. If more stringent environmental constraints are imposed, both solutions become significantly more attractive. The same holds for scenarios of more renewable generation (in which the operational flexibility from both alternatives becomes more valuable). After 2030, batteries can match the cost-effectiveness of expensive re-regulation reservoirs. Our findings are valuable for policy and decision makers in energy and ecosystem conservation.}, journal={JOURNAL OF CLEANER PRODUCTION}, publisher={Elsevier BV}, author={Anindito, Yoga and Haas, Jannik and Olivares, Marcelo and Nowak, Wolfgang and Kern, Jordan}, year={2019}, month={Feb}, pages={477–489} }
 @article{kern_gorelick_characklis_macklin_2019, title={Multiobjective Optimal Siting of Algal Biofuel Production with Municipal Wastewater Treatment in Watersheds with Nutrient Trading Markets}, volume={145}, ISSN={["1943-5452"]}, url={http://dx.doi.org/10.1061/(asce)wr.1943-5452.0001018}, DOI={10.1061/(ASCE)WR.1943-5452.0001018}, abstractNote={AbstractUsing municipal wastewater effluent as a feedstock in algae cultivation is a promising approach for increasing the commercial viability of algal biofuel production. However, differences in ...}, number={2}, journal={JOURNAL OF WATER RESOURCES PLANNING AND MANAGEMENT}, publisher={American Society of Civil Engineers (ASCE)}, author={Kern, Jordan D. and Gorelick, David E. and Characklis, Gregory W. and Macklin, Caroline M.}, year={2019}, month={Feb} }
 @article{kern_characklis_2017, title={Evaluating the Financial Vulnerability of a Major Electric Utility in the Southeastern U.S. to Drought under Climate Change and an Evolving Generation Mix}, volume={51}, ISSN={0013-936X 1520-5851}, url={http://dx.doi.org/10.1021/acs.est.6b05460}, DOI={10.1021/acs.est.6b05460}, abstractNote={There is increasing recognition of the vulnerability of electric power systems to drought and the potential for both climate change and a shifting generation mix to alter this vulnerability. Nonetheless, the considerable research in this area has not been synthesized to inform electric utilities with respect to a key factor that influences their decisions about critical infrastructure: financial risk for shareholders. This study addresses this gap in knowledge by developing a systems framework for assessing the financial exposure of utilities to drought, with further consideration of the effects of climate change and a shifting generation mix. We then apply this framework to a major utility in the Southeastern U.S. Results suggest that extreme drought could cause profit shortfalls of more than $100 million if water temperature regulations are strictly enforced. However, even losses of this magnitude would not significantly impact returns for shareholders. This may inadvertently reduce pressure internally at utilities to incorporate drought vulnerability into long-term strategic planning, potentially leaving utilities and their customers at greater risk in the future.}, number={15}, journal={Environmental Science & Technology}, publisher={American Chemical Society (ACS)}, author={Kern, Jordan D. and Characklis, Gregory W.}, year={2017}, month={Jul}, pages={8815–8823} }
 @article{su_kern_characklis_2017, title={The impact of wind power growth and hydrological uncertainty on financial losses from oversupply events in hydropower-dominated systems}, volume={194}, url={http://dx.doi.org/10.1016/j.apenergy.2017.02.067}, DOI={10.1016/j.apenergy.2017.02.067}, abstractNote={The rapid expansion of variable renewable energy (e.g., wind and solar) can make it more difficult to balance electricity supply and demand at a grid-scale. While much attention has focused on the risk of unexpected generation shortfalls, periods of oversupply (when supply is greater than demand) also present challenges that can lead to financial losses for utilities and/or consumers when renewable energy is “curtailed”. A unique form of oversupply occurs in hydro-dominated systems. Although hydropower is thought to offer a highly flexible resource that can complement variable renewable energy, seasonal variability in streamflows and the presence of environmental regulations can create complex oversupply conditions if renewable energy is plentiful. In this study, an integrated hydro-economic model is developed to assess the frequency and severity of financial losses arising from oversupply in the U.S. Pacific Northwest, a hydro-dominated system with rapidly growing wind power generation. Present value losses over 25 years (2016–2040) are evaluated under several future scenarios including increased wind capacity, electricity price uncertainty, and expanded transmission capacity for moving excess electricity to export markets. Results indicate that oversupply losses will increase as a function of installed wind capacity, with the extent of this increase sensitive to future electricity prices. In the case of adding transmission capacity to alleviate oversupply losses, the cost of this infrastructure is substantially more than the associated reduction in losses and is therefore difficult to justify.}, journal={Applied Energy}, publisher={Elsevier BV}, author={Su, Yufei and Kern, Jordan D. and Characklis, Gregory W.}, year={2017}, month={May}, pages={172–183} }
 @article{hise_characklis_kern_gerlach_viamajala_gardner_vadlamani_2016, title={Evaluating the relative impacts of operational and financial factors on the competitiveness of an algal biofuel production facility}, volume={220}, url={http://dx.doi.org/10.1016/j.biortech.2016.08.050}, DOI={10.1016/j.biortech.2016.08.050}, abstractNote={Algal biofuels are becoming more economically competitive due to technological advances and government subsidies offering tax benefits and lower cost financing. These factors are linked, however, as the value of technical advances is affected by modeling assumptions regarding the growth conditions, process design, and financing of the production facility into which novel techniques are incorporated. Two such techniques, related to algal growth and dewatering, are evaluated in representative operating and financing scenarios using an integrated techno-economic model. Results suggest that these techniques can be valuable under specified conditions, but also that investment subsidies influence cost competitive facility design by incentivizing development of more capital intensive facilities (e.g., favoring hydrothermal liquefaction over transesterification-based facilities). Evaluating novel techniques under a variety of operational and financial scenarios highlights the set of site-specific conditions in which technical advances are most valuable, while also demonstrating the influence of subsidies linked to capital intensity.}, journal={Bioresource Technology}, publisher={Elsevier BV}, author={Hise, Adam M. and Characklis, Gregory W. and Kern, Jordan and Gerlach, Robin and Viamajala, Sridhar and Gardner, Robert D. and Vadlamani, Agasteswar}, year={2016}, month={Nov}, pages={271–281} }
 @article{kern_characklis_2017, title={Low natural gas prices and the financial cost of ramp rate restrictions at hydroelectric dams}, volume={61}, url={http://dx.doi.org/10.1016/j.eneco.2016.12.002}, DOI={10.1016/j.eneco.2016.12.002}, abstractNote={Peaking hydroelectric dams that employ variable, stop-start reservoir releases can have adverse impacts on downstream river ecosystems. Efforts to mitigate these impacts have relied predominantly on the use of ramp rate restrictions, which limit the magnitude of hour-to-hour changes in reservoir discharge. Ramp rate restrictions shift hydropower production towards less valuable off-peak hours, imposing a financial penalty on dam owners that is a function of the "spread" (difference) between peak and off-peak electricity prices. This study examines how low natural gas prices in the U.S. have reduced the cost of implementing ramp rate restrictions at dams by narrowing the peak/off-peak price spread. Significantly lower costs of ramp rate restrictions could open new opportunities for improving environmental flows at dams, including the "purchase" of more natural streamflow patterns by downstream stakeholders, a type of arrangement for which there is growing precedent. We also explore the role that uncertainty in the cost of ramp rate restrictions could play in precluding downstream stakeholders from forming these types of agreements with dam owners. Results suggest that financial "collar" contracts could mostly eliminate inter-annual variability in the net cost of restrictions and provide those purchasing more natural flows with greater certainty.}, journal={Energy Economics}, publisher={Elsevier BV}, author={Kern, Jordan D. and Characklis, Gregory W.}, year={2017}, month={Jan}, pages={340–350} }
 @article{kern_hise_characklis_gerlach_viamajala_gardner_2017, title={Using life cycle assessment and techno-economic analysis in a real options framework to inform the design of algal biofuel production facilities}, volume={225}, url={http://dx.doi.org/10.1016/j.biortech.2016.11.116}, DOI={10.1016/j.biortech.2016.11.116}, abstractNote={This study investigates the use of "real options analysis" (ROA) to quantify the value of greater product flexibility at algal biofuel production facilities. A deterministic optimization framework is integrated with a combined life cycle assessment/techno-economic analysis model and subjected to an ensemble of 30-year commodity price trajectories. Profits are maximized for two competing plant configurations: 1) one that sells lipid-extracted algae as animal feed only; and 2) one that can sell lipid-extracted algae as feed or use it to recover nutrients and energy, due to an up-front investment in anaerobic digestion/combined heat and power. Results show that added investment in plant flexibility does not result in an improvement in net present value, because current feed meal prices discourage use of lipid-extracted algae for nutrient and energy recovery. However, this study demonstrates that ROA provides many useful insights regarding plant design that cannot be captured via traditional techno-economic modeling.}, journal={Bioresource Technology}, publisher={Elsevier BV}, author={Kern, Jordan D. and Hise, Adam M. and Characklis, Greg W. and Gerlach, Robin and Viamajala, Sridhar and Gardner, Robert D.}, year={2017}, month={Feb}, pages={418–428} }
 @article{foster_kern_characklis_2015, title={Mitigating hydrologic financial risk in hydropower generation using index-based financial instruments}, volume={10}, url={http://dx.doi.org/10.1016/j.wre.2015.04.001}, DOI={10.1016/j.wre.2015.04.001}, abstractNote={Variability in streamflows can lead to reduced generation from hydropower producers and result in reductions in revenues that can be financially disruptive. This link between hydrologic and financial uncertainties, and the possibility of increased hydrologic variability in the future, suggests that hydropower producers need to begin to consider new strategies and tools for managing these financial risks. This study uses an integrated hydro-economic model of the Roanoke River Basin to characterize the financial risk faced by hydropower generators as a result of hydrologic variability, and develops several index-based financial hedging contracts intended to mitigate this risk. Several different indices are evaluated in terms of their ability to serve as the basis for effective financial contracts. Contract structures are then developed and evaluated using a 100-year simulation that describes hydropower operations in the Roanoke basin. Basis risk, contract pricing, and risk mitigation are investigated for three styles of contracts: insurance, binary, and collar. In all three cases, the contracts are shown to be capable of substantially reducing the risks of very low revenue years for costs that are a small fraction of total annual revenues (1–3%).}, journal={Water Resources and Economics}, publisher={Elsevier BV}, author={Foster, Benjamin T. and Kern, Jordan D. and Characklis, Gregory W.}, year={2015}, month={Apr}, pages={45–67} }
 @article{kern_characklis_foster_2015, title={Natural gas price uncertainty and the cost‐effectiveness of hedging against low hydropower revenues caused by drought}, volume={51}, url={http://dx.doi.org/10.1002/2014wr016533}, DOI={10.1002/2014wr016533}, abstractNote={Abstract Prolonged periods of low reservoir inflows (droughts) significantly reduce a hydropower producer's ability to generate both electricity and revenues. Given the capital intensive nature of the electric power industry, this can impact hydropower producers’ ability to pay down outstanding debt, leading to credit rating downgrades, higher interests rates on new debt, and ultimately, greater infrastructure costs. One potential tool for reducing the financial exposure of hydropower producers to drought is hydrologic index insurance, in particular, contracts structured to payout when streamflows drop below a specified level. An ongoing challenge in developing this type of insurance, however, is minimizing contracts’ “basis risk,” that is, the degree to which contract payouts deviate in timing and/or amount from actual damages experienced by policyholders. In this paper, we show that consideration of year‐to‐year changes in the value of hydropower (i.e., the cost of replacing it with an alternative energy source during droughts) is critical to reducing contract basis risk. In particular, we find that volatility in the price of natural gas, a key driver of peak electricity prices, can significantly degrade the performance of index insurance unless contracts are designed to explicitly consider natural gas prices when determining payouts. Results show that a combined index whose value is derived from both seasonal streamflows and the spot price of natural gas yields contracts that exhibit both lower basis risk and greater effectiveness in terms of reducing financial exposure.}, number={4}, journal={Water Resources Research}, publisher={American Geophysical Union (AGU)}, author={Kern, Jordan D. and Characklis, Gregory W. and Foster, Benjamin T.}, year={2015}, month={Apr}, pages={2412–2427} }
 @article{kern_patino-echeverri_characklis_2014, title={An integrated reservoir-power system model for evaluating the impacts of wind integration on hydropower resources}, volume={71}, url={http://dx.doi.org/10.1016/j.renene.2014.06.014}, DOI={10.1016/j.renene.2014.06.014}, abstractNote={Despite the potential for hydroelectric dams to help address challenges related to the variability and unpredictability of wind energy, at present there are few systems-based wind-hydro studies available in the scientific literature. This work represents an attempt to begin filling this gap through the development of a systems-based modeling framework for analysis of wind power integration and its impacts on hydropower resources. The model, which relies entirely on publicly available information, was developed to assess the effects of wind energy on hydroelectric dams in a power system typical of the Southeastern US (i.e., one in which hydropower makes up <10% of total system capacity). However, the model can easily reflect different power mixes; it can also be used to simulate reservoir releases at self-scheduled (profit maximizing) dams or ones operated in coordination with other generators to minimize total system costs. The modeling framework offers flexibility in setting: the level and geographical distribution of installed wind power capacity; reservoir management rules, and static or dynamic fuel prices for power plants. In addition, the model also includes an hourly 'natural' flow component designed expressly for the purpose of assessing changes in hourly river flow patterns that may occur as a consequence of wind power integration. Validation of the model shows it can accurately reproduce market price dynamics and dam storage and release patterns under current conditions. We also demonstrate the model's capability in assessing the impact of increased wind market penetration on the volumes of reserves and electricity sold by a hydroelectric dam.}, journal={Renewable Energy}, publisher={Elsevier BV}, author={Kern, Jordan D. and Patino-Echeverri, Dalia and Characklis, Gregory W.}, year={2014}, month={Nov}, pages={553–562} }
 @book{kern_2014, title={Analysis of Potential Policy Changes on the Financial Viability of Residential Solar in North Carolina}, institution={UNC Chapel Hill Institute for the Environment}, author={Kern, J.}, year={2014} }
 @article{kern_record. kern_2014, title={Solar: A Sound Investment}, journal={Greensboro News}, author={Kern, J. and Record. Kern, J.}, year={2014}, month={Dec} }
 @article{kern_patino-echeverri_characklis_2014, title={The Impacts of Wind Power Integration on Sub-Daily Variation in River Flows Downstream of Hydroelectric Dams}, volume={48}, url={http://dx.doi.org/10.1021/es405437h}, DOI={10.1021/es405437h}, abstractNote={Due to their operational flexibility, hydroelectric dams are ideal candidates to compensate for the intermittency and unpredictability of wind energy production. However, more coordinated use of wind and hydropower resources may exacerbate the impacts dams have on downstream environmental flows, that is, the timing and magnitude of water flows needed to sustain river ecosystems. In this paper, we examine the effects of increased (i.e., 5%, 15%, and 25%) wind market penetration on prices for electricity and reserves, and assess the potential for altered price dynamics to disrupt reservoir release schedules at a hydroelectric dam and cause more variable and unpredictable hourly flow patterns (measured in terms of the Richards-Baker Flashiness (RBF) index). Results show that the greatest potential for wind energy to impact downstream flows occurs at high (∼25%) wind market penetration, when the dam sells more reserves in order to exploit spikes in real-time electricity prices caused by negative wind forecast errors. Nonetheless, compared to the initial impacts of dam construction (and the dam's subsequent operation as a peaking resource under baseline conditions) the marginal effects of any increased wind market penetration on downstream flows are found to be relatively minor.}, number={16}, journal={Environmental Science & Technology}, publisher={American Chemical Society (ACS)}, author={Kern, Jordan D. and Patino-Echeverri, Dalia and Characklis, Gregory W.}, year={2014}, month={Aug}, pages={9844–9851} }
 @article{kern_characklis_doyle_blumsack_whisnant_2012, title={Influence of Deregulated Electricity Markets on Hydropower Generation and Downstream Flow Regime}, volume={138}, url={http://dx.doi.org/10.1061/(asce)wr.1943-5452.0000183}, DOI={10.1061/(asce)wr.1943-5452.0000183}, abstractNote={The flow regime of rivers is a complex but important measure of environmental quality and one that can be significantly impacted by conventional hydropower generation. While traditional hydropower scheduling creates a periodicity in downstream flows corresponding to seasonal and daily electricity demand patterns, deregulated electricity markets may provide financial incentives to further alter flows, as utilities respond to hourly market dynamics. This study investigates the potential for deregulated markets to impact both a hydropower utility's revenue stream and downstream flow regimes. Six operating scenarios are explored: (1–2) full-market participation (including real-time energy), with and without flow reregulation; (3) day-ahead market only; and (4–6) run-of-river operations (ROR), with and without flood control and flow reregulation. Results suggest that, relative to a day-ahead-only scenario, the scale of any differences in flow regime resulting from full-market participation is relatively small compared to the additional revenue-generating potential of such a strategy. Implementing a run-of-river policy frequently yields "more natural" flow regimes than the day-ahead only scenario; but, in some cases these improvements are modest, and in others the ROR scenarios exacerbate deviation from unregulated flows. Regardless, the effects of implementing an ROR strategy come at a substantial cost in terms of foregone hydropower revenue.}, number={4}, journal={Journal of Water Resources Planning and Management}, publisher={American Society of Civil Engineers (ASCE)}, author={Kern, Jordan D. and Characklis, Gregory W. and Doyle, Martin W. and Blumsack, Seth and Whisnant, Richard B.}, year={2012}, month={Jul}, pages={342–355} }