Common simplifications used in transmission valuation studies may lead to inaccurate estimates of the economic value of transmission. Using a case study of the Southeast U.S., this study examined the incremental effects of including more realistic detail in transmission value analysis in five areas: (1) generator heat rates, (2) daily natural gas prices, (3) load forecast error, (4) correlation between generator outages and temperature, and (5) inter-annual weather and natural gas fuel prices. The study found that including more detail in these five areas had a significant impact on marginal transmission value, increasing it by 44% in a typical year (2023), but increasing it by greater than 200% when comparing a higher value year (2022) without simplifications to the typical year (2023) with simplifications. The study found that each of the five areas impacted value in certain year and region combinations, indicating that all areas were important to consider rather than only a subset of the areas studied. The top 20 to 100 hours accounted for an outsized portion of total value gain of including the realistic details, but the next 1900 hours also provided an important value boost. The mix of impacts across regions, years, and hours within a year, illustrates the complexity of transmission valuation and the importance of accounting for the full range of real-world conditions during model simulation.

Interregional electricity trade in the United States reduces total energy costs, but falls short of maximizing the economic potential of existing transmission infrastructure. This analysis of thirty-two U.S. electricity system interfaces crossing grid or market seams finds an average achieved cost savings of at least $1,226 million per year. This positive impact is offset by an average annual cost of uneconomic interchange of $551 million. Additional value of at least $238 million per year could be enabled by increasing utilization. Notably, uneconomic flows and low utilization rates can persist even when the price spread between regions is large. These conclusions are derived from historical (2014-2023) data on the magnitude and direction of interregional price spreads, the magnitude and direction of net energy transfers, and how these variables coincide, but do not account for all system constraints. These findings motivate the development and deployment of solutions that improve interregional transmission operations, in parallel with robust transmission infrastructure planning.JEL Classification: Q40 Energy: General

Abstract Because of their capital-intensive operation, wind energy systems that are competitive in terms of the cost of the energy that they produce lead to risk-reward trade-offs that make their business cases less favorable than those of conventional energy generation technologies. However, wind energy systems tend to be designed to maximize energy production or minimize cost of energy rather than to maximize their business cases. In this work, we attempt to exploit designs specifically tailored to business cases. We develop a novel framework for analyzing energy systems that ties their design variables to monthly operating incomes using simple models and historical hourly market and resource data. Using this approach, we demonstrate that for a wind site with abundant wind resource in the California Independent System Operator market, we can control the trade-off between mean and 5th percentile monthly returns by choosing the specific power of the turbine at a fixed modeled initial capital cost. Our framework gives a measure of the risk-reward spectrum of energy generation assets that could be built at a given site with respect to the sub-annual resource/market variation.

This paper analyzes the impacts of improved day-ahead solar forecasts on costs and dispatch in the solar-rich Southeast U.S. It uses an optimized high-solar, high-storage resource portfolio in which solar generation capacity accounts for 45% of total installed capacity (34%-36% of generation) and energy storage capacity (43 GW) is equivalent to 33% of peak demand. In a base scenario, improved day-ahead solar forecasts reduce production costs by $87 million per year ($0.13 per MWh load, 2023$). This level of savings is within the range or lower than earlier studies of solar forecast improvements at lower levels of solar generation (< 25% of total generation). In this study, solar expansion was accompanied by two important sources of flexibility for managing solar forecast error: energy storage and day-ahead solar curtailment. The analysis finds that regional coordination complements day-ahead solar forecast improvements while natural gas commitment flexibility is a substitute for forecast improvements, as the improved solar forecast leads to sub-optimal commitment of thermal units. Day-ahead solar forecast improvements reduce reserves required to manage forecast error by 30%. Fewer reserves to manage large, infrequent solar forecast errors could be an important benefit of improved solar forecasts.

Abstract There is growing interest in leveraging interregional transmission as a resource adequacy asset as the U.S. electric grid faces challenges from extreme weather, load growth, and a changing generation mix. However, empirical evidence of how transmission functions during periods of system stress remains limited. This paper addresses that gap by analyzing nine years of historical peak demand patterns and interregional power flows across 18 continental U.S. transmission planning regions from 2016-2024. We identify resource adequacy-critical periods based on peak net load and assess when regions experience these peaks at simultaneous or opposite times. We then analyze actual power flows during these high-stress periods to evaluate how effectively interregional transmission was used to support stressed regions. Our results show substantial geographic variation in the theoretical potential for transmission to provide resource adequacy support. Furthermore, realization of this potential is often poor: approximately half of examined region pairs show transmission flows that support the high-need region 50-60% of the time during non-coincident peaks, barely better than random. Several pairs exhibit counter-supportive flow patterns, and benefits are often asymmetric between neighboring regions. These findings suggest that operational, market, institutional, or other barriers are constraining the reliability value of interregional transmission.

Electric transmission infrastructure plays a vital role during extreme weather and supply disruptions and can enable low-cost electricity systems. This paper contributes to a more complete understanding of the value and cost-effectiveness of transmission, as well as barriers to its development. By studying wholesale energy market prices in the United States between 2012 and 2022, we find that additional transfer capacity between regions would have been especially valuable, with a median value of $116 million per GW per year. This capacity would often have provided balanced benefits to each region. The market value of transmission was highly influenced by a small fraction of time: 5% of hours typically captured at least 45% of the total value. These peak periods were primarily driven by unforeseen changes in conditions within one day of operations. Annualized transmission infrastructure cost estimates were lower than the average market value for most locations, including all links crossing regional seams, where the value-to-cost ratio was often greater than 4. This suggests that there are barriers to developing valuable grid infrastructure. These results complement forward-looking modeling studies and support efforts to improve modeling practices.

Wind farm flow control represents a category of control strategies for achieving wind-plant-level objectives, such as increasing wind plant power production and/or reducing structural loads, by mitigating the impact of wake interactions between wind turbines. Wake steering is a wind farm flow control technology in which specific turbines are misaligned with the wind to deflect their wakes away from downstream turbines, thus increasing overall wind plant power production. In addition to promising results from simulation studies, wake steering has been shown to successfully increase energy production through several recent field trials. However, to better understand the benefits of wind farm flow control strategies such as wake steering, the value of the additional energy to the electrical grid should be evaluated – for example, by considering the price of electricity when the additional energy is produced. In this study, we investigate the potential for wake steering to increase the value of wind plant energy production by combining model predictions of power gains using the FLOw Redirection and Induction in Steady State (FLORIS) engineering wind farm flow control tool with historical electricity price data for 15 existing US wind plants in four different electricity market regions. Specifically, for each wind plant, we use FLORIS to estimate power gains from wake steering for a time series of hourly wind speeds and wind directions spanning the years 2018–2020, obtained from the ERA5 reanalysis dataset. The modeled power gains are then correlated with hourly electricity prices for the nearest transmission node. Through this process we find that wake steering increases annual energy production (AEP) between 0.4 % and 1.7 %, depending on the wind plant, with average increases in potential annual revenue (i.e., annual revenue of production, ARP) 4 % higher than the AEP gains. For most wind plants, ARP gain was found to exceed AEP gain. But the ratio between ARP gain and AEP gain is greater for wind plants in regions with high wind penetration because electricity prices tend to be relatively higher during periods with below-rated wind plant power production, when wake losses occur and wake steering is active; for wind plants in the Southwest Power Pool – the region with the highest wind penetration analyzed (31 %) – the increase in ARP from wake steering is 11 % higher than the AEP gain. Consequently, we expect the value of wake steering, and other types of wind farm flow control, to increase as wind penetration continues to grow.

Examining coupled renewable-battery power plants ("hybrids") in congested areas provides insights into a future of increased wind and solar penetration. Our study focuses on two types of congested regions, Variable Renewable Energy (VRE)-rich Areas and Load Centers, and explores likely plant configuration choices for developers and transmission network planners. This paper examines how hybrid value, comprising energy and capacity value, varies by plant configuration and congested region type considering factors such as storage duration, battery degradation, and ability to charge from the grid. We select plant locations from across the seven main U.S. independent system operators (ISOs). Hybrid value for each configuration is computed based on profit- maximizing plant operation given perfect foresight, according to observed wholesale power market real time prices from 2018 to 2021. In VRE-rich Areas, the median increase in energy value from extending storage duration from one to 4 h is 29.4 % for solar and 26.8 % for wind, assuming low battery degradation costs and storage sized to 100% of the plant's nameplate generation capacity. Increasing storage duration beyond 4 h does not substantially increase its value from energy markets, even in VRE-rich Areas. We find that solar hybrids reach a 90 % capacity credit with 4 h of storage, while wind hybrids require 8 h of storage, based on the capacity factor of each hybrid during the top 100 net load hours.

Wind and solar generation reduce electric sector pollutant emissions and associated climate-related damages and air quality-related health damages. Here, we assess these emission reductions, focusing on carbon dioxide (CO2), sulfur dioxide (SO2), and nitrogen oxides (NOx), and incorporate recent estimates of global warming costs and pollution health costs to estimate the dollar value of the associated climate and air quality benefits. From 2019 through 2022, wind and solar generation in the United States provided $249 billion of climate and air quality benefits based on central estimates. In 2022, the normalized benefits were $143/MWh and $100/MWh for wind and solar, respectively, or $36/MWh and $17/MWh when only including air quality benefits. Combined, wind and solar generation led to 1,200 to 1,600 fewer premature mortalities in 2022 (based on a 5th–95th percentile range). Our approach is based on simple, publicly available data, and it includes a sophisticated treatment of uncertainty.