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DOE OSTI2024

Probabilistic Grid Reliability Analysis with Energy Storage Systems

SAND2025-12025O The Probabilistic Grid Reliability Analysis with Energy Storage Systems (ProGRESS) software tool is an open-source tool for assessing the resource adequacy of the evolving electric power grid integrated with energy storage systems (ESS). This tool uses a simulation engine to create diverse scenarios that test the limits of the modern power grid consisting of a high-volume ESS and variable energy resources (VER). Sandia National Laboratories is a multimission laboratory managed and operated by National Technology & Engineering Solutions of Sandia, LLC, a wholly owned subsidiary of Honeywell International Inc., for the U.S. Department of Energy’s National Nuclear Security Administration under contract DE-NA0003525.

Nguyen, Tu↗

DOE OSTI2026

Guideline for Characterizing and Evaluating a Candidate Project Site for Solar Thermal Applications

This document presents a structured procedure for characterizing and evaluating candidate project sites for concentrating solar power (CSP) and solar heat for industrial processes (SHIP) applications. The objective is to provide project developers, researchers, and other stakeholders with a consistent, technology-agnostic framework for early-stage site assessment, enabling informed decision-making prior to significant investment in project development. Site selection is a critical factor in project success or failure for both CSP and SHIP projects. Key factors such as solar resource availability, land characteristics, environmental and regulatory constraints, infrastructure availability, and community context are determined by the choice of project site and can materially impact project performance, cost, schedule, and overall viability. This procedure is designed to systematically evaluate these factors, identify potential fatal flaws, and prioritize the most favorable candidate sites for further development. The process begins with rapid screening-level evaluation, using publicly available data to assess solar resource, land availability and suitability, zoning and land-use compatibility, and exclusion zones such as protected lands or sensitive habitats. Sites that meet the minimum screening criteria advance to a more detailed characterization. Subsequent sections of this report provide guidance for a next-level assessment of the most important technical and environmental parameters, including: 1) Solar resource quality, variability, and uncertainty using multiyear datasets and, where appropriate, on-site measurement campaigns; 2) Meteorological conditions such as wind, temperature, extreme weather events, and soiling impacts; 3) Land characteristics including slope, shading, and geotechnical conditions; and 4) Environmental and regulatory considerations, including permitting processes, endangered species, cultural resources, and visual impacts. The procedure also addresses infrastructure and integration considerations, including: 1) Grid interconnection requirements for CSP power generation projects; 2) Electrical and operational integration for SHIP facilities; 3) Water availability, quality, and permitting constraints, which are particularly critical for CSP in arid regions; and 4) Site access, construction logistics, and availability of workforce and supporting services. Recognizing the importance of social and economic context, the procedure includes evaluation of community engagement factors, such as stakeholder sentiment, proximity to sensitive visual receptors, workforce development opportunities, and local economic incentives. The outputs of these assessments are synthesized in a cost and risk evaluation, translating site characteristics into expected impacts on capital cost, operating cost, schedule, and technical risk. This is complemented by screening-level performance modeling, including 8760 simulations and long-term projections, to quantify expected energy or thermal output, assess variability thereof, and support comparison between candidate sites. Finally, the procedure provides high-level guidance on a structured go/no-go decision framework, categorizing sites based on identified risks and constraints, and outlining a clear path forward to feasibility studies and front-end engineering design for viable projects. By standardizing the site characterization process across both CSP and SHIP applications, this guideline aims to: 1) Improve consistency and transparency in early-stage project evaluation; 2) Reduce development risk and avoid investment in nonviable project sites; 3) Support collaboration between developers, researchers, and public agencies; and 4) Accelerate successful deployment of concentrating solar technologies for both power generation and industrial process heat.

14 SOLAR ENERGY↗

DOE OSTI2023

Phase 1: Duke Energy Zero Emission Resource Integration Study (ZERIS); Phase 2: Carbon-Free Resource Integration Study for Duke Energy (Final Report)

Phase 1: This statement of work makes up Phase 1 of a larger effort. During this Phase 1 effort, NREL will work with Duke Energy to analyze the impacts of integrating significant amounts of new solar power into the Duke Energy power system under a variety of different penetrations scenarios, with a maximum of ten (10) full scenarios examined. The existing fleet, particularly the nuclear generation, will be considered in the quantitative assessments and discussions. Duke Energy is looking to quantify how much solar generation its system can handle. NREL will work with Duke Energy to quantify solar potential, identify likely integration challenges and possible opportunities for wind, storage, demand side resources and other technologies. Phase 2: This Statement of Work consists of a follow-up effort (Phase 2) to a recently completed Phase 1 modeling effort. During Phase 2, NREL will work closely with Duke Energy to analyze the impacts of integrating significant amounts of variable generation resources (wind and solar) and storage into Duke Energy's system in the Carolinas. The existing fleet, particularly nuclear generation, will be considered in the quantitative assessment and discussions. This Statement of Work also includes an extension to Phase II of the Carbon-Free Resource Integration Study for Duke Energy. In this extension, NREL will work closely with Duke Energy to extend the production cost analysis developed in Phase II to 2018 weather and load data for Duke Energy's territory. This extension leverages the modeling tools and datasets developed as part of Phase II. The analysis will compare results from Phase II (using 2012 weather and load) with 2018 results to assess system operations with increased penetration of renewables and storage. Simplifying assumptions will be made for modeling Duke Energy's neighbors in the production cost model.

14 SOLAR ENERGY↗

DOE OSTI2017

8760-Based Method for Representing Variable Generation Capacity Value in Capacity Expansion Models: Preprint

Capacity expansion models (CEMs) are widely used to evaluate the least-cost portfolio of electricity generators, transmission, and storage needed to reliably serve demand over the evolution of many years or decades. Various CEM formulations are used to evaluate systems ranging in scale from states or utility service territories to national or multi-national systems. CEMs can be computationally complex, and to achieve acceptable solve times, key parameters are often estimated using simplified methods. In this paper, we focus on two of these key parameters associated with the integration of variable generation (VG) resources: capacity value and curtailment. We first discuss common modeling simplifications used in CEMs to estimate capacity value and curtailment, many of which are based on a representative subset of hours that can miss important tail events or which require assumptions about the load and resource distributions that may not match actual distributions. We then present an alternate approach that captures key elements of chronological operation over all hours of the year without the computationally intensive economic dispatch optimization typically employed within more detailed operational models. The updated methodology characterizes the (1) contribution of VG to system capacity during high load and net load hours, (2) the curtailment level of VG, and (3) the potential reductions in curtailments enabled through deployment of storage and more flexible operation of select thermal generators. We apply this alternate methodology to an existing CEM, the Regional Energy Deployment System (ReEDS). Results demonstrate that this alternate approach provides more accurate estimates of capacity value and curtailments by explicitly capturing system interactions across all hours of the year. This approach could be applied more broadly to CEMs at many different scales where hourly resource and load data is available, greatly improving the representation of challenges associate with integration of variable generation resources.

14 SOLAR ENERGY↗

DOE OSTI2016

Capacity Payments in Restructured Markets under Low and High Penetration Levels of Renewable Energy

There is considerable debate about the degree to which restructured markets perform successfully in their use of capacity markets. In providing appropriate incentives for new and existing generation to meet reliability requirements, a variety of capacity market designs have developed across RTOs and ISOs in the United States and internationally. Growing levels of variable renewable energy (VRE) resources arguably create new challenges for capacity market designs, because VREs suppress energy prices while providing relatively little capacity, with these effects increase with VRE penetration. The purpose of this report is threefold. First, we provide a brief outline of the purpose and design of various capacity markets under consideration using variable resource requirement (VRR) demand curves. Second, we discuss some of the main challenges raised in existing literature and a set of interviews that we conducted with market participants, regulators, and observers, including where there substantive differences in opinion. Third, we consider some of the challenges that may be specific to higher penetration levels of VRE. While the well known 'merit order' effect from VRE can be expected to suppress wholesale energy prices and revenue, this may be partly mitigated by increased capacity payments and the greater importance of AS payments for flexible capacity. The potential for greater reliance on capacity markets for generator revenues may amplify any inefficiency and costs associated with capacity price volatility and other suboptimal market design choices. Regulatory intervention to ensure adequate capacity payments and ancillary service revenue may become more prevalent under current market designs as the timescale for market signals shifts increasingly from near term (e.g., day-ahead in wholesale electricity markets) to longer term (annual intervals in capacity markets). Our review and discussion with market participants suggest substantive challenges may remain in implementing capacity markets that provide both adequate operational and investment incentives, particularly under high-VRE scenarios with greater need for flexible capacity.

14 SOLAR ENERGY↗

DOE OSTI2011

Final Scientific/Technical Report for Building Transmission Capacity in the Western Interconnection to Support a Low Carbon Future

The Building Transmission Capacity grant activities focused on educating both policy makers (primarily at Public Utility Commissions) and utilities across the West. Western Grid Group (WGG), the grant recipient, chose three methods to reach these audiences - direct outreach, a website that contains information on policies and strategies to integrate more variable generation resources, and a report - The Best of the West, Policies and Practices to Support Transition to a Lower-Carbon Electric Sector in the Western Interconnection and that highlights what is working in the West. While all avenues for education are effective the Best of the West report is the first west-wide assessment of its kind. The report details incremental changes that are working to integrate variable generation but it also expounds on what fundamental or transformative changes are needed to get to the 20% wind penetration and beyond.

24 POWER TRANSMISSION AND DISTRIBUTION↗

DOE OSTI2015

Role of Smart Grids in Integrating Renewable Energy

This report was prepared for the International Smart Grid Action Network (ISGAN), which periodically publishes briefs and discussion papers on key topics of smart grid development globally. The topic of this report was selected by a multilateral group of national experts participating in ISGAN Annex 4, a working group that aims to produce synthesis insights for decision makers. This report is an update of a 2012 ISGAN Annex 4 report entitled “Smart Grid Contributions to Variable Renewable Resource Integration.” That report and other past publications of ISGAN Annexes can be found at www.iea-isgan.org and at www.cleanenergysolutions.org.

24 POWER TRANSMISSION AND DISTRIBUTION↗

DOE OSTI2014

The RenewElec Project: Variable Renewable Energy and the Power System (Final Report)

Variable energy resources, such as wind power, now produce about 4% of U.S. electricity. They can play a significantly expanded role if the U.S. adopts a systems approach that considers affordability, security and reliability. Reaching a 20-30% renewable portfolio standard goal is possible, but not without changes in the management and regulation of the power system, including accurately assessing and preparing for the operational effects of renewable generation. The RenewElec project will help the nation make the transition to the use of significant amounts of electric generation from variable and intermittent sources of renewable power.

29 ENERGY PLANNING, POLICY, AND ECONOMY↗

DOE OSTI2017

Variable Renewable Energy in Long-Term Planning Models: A Multi-Model Perspective

Long-term capacity expansion models of the U.S. electricity sector have long been used to inform electric sector stakeholders and decision-makers. With the recent surge in variable renewable energy (VRE) generators — primarily wind and solar photovoltaics — the need to appropriately represent VRE generators in these long-term models has increased. VRE generators are especially difficult to represent for a variety of reasons, including their variability, uncertainty, and spatial diversity. This report summarizes the analyses and model experiments that were conducted as part of two workshops on modeling VRE for national-scale capacity expansion models. It discusses the various methods for treating VRE among four modeling teams from the Electric Power Research Institute (EPRI), the U.S. Energy Information Administration (EIA), the U.S. Environmental Protection Agency (EPA), and the National Renewable Energy Laboratory (NREL). The report reviews the findings from the two workshops and emphasizes the areas where there is still need for additional research and development on analysis tools to incorporate VRE into long-term planning and decision-making. This research is intended to inform the energy modeling community on the modeling of variable renewable resources, and is not intended to advocate for or against any particular energy technologies, resources, or policies.

29 ENERGY PLANNING, POLICY, AND ECONOMY↗

DOE OSTI2017

Demonstration of Essential Reliability Services by a 300-MW Solar Photovoltaic Power Plant

The California Independent System Operator (CAISO), First Solar, and the National Renewable Energy Laboratory (NREL) conducted a demonstration project on a large utility-scale photovoltaic (PV) power plant in California to test its ability to provide essential ancillary services to the electric grid. With increasing shares of solar- and wind-generated energy on the electric grid, traditional generation resources equipped with automatic governor control (AGC) and automatic voltage regulation controls -- specifically, fossil thermal -- are being displaced. The deployment of utility-scale, grid-friendly PV power plants that incorporate advanced capabilities to support grid stability and reliability is essential for the large-scale integration of PV generation into the electric power grid, among other technical requirements. A typical PV power plant consists of multiple power electronic inverters and can contribute to grid stability and reliability through sophisticated 'grid-friendly' controls. In this way, PV power plants can be used to mitigate the impact of variability on the grid, a role typically reserved for conventional generators. In August 2016, testing was completed on First Solar's 300-MW PV power plant, and a large amount of test data was produced and analyzed that demonstrates the ability of PV power plants to use grid-friendly controls to provide essential reliability services. These data showed how the development of advanced power controls can enable PV to become a provider of a wide range of grid services, including spinning reserves, load following, voltage support, ramping, frequency response, variability smoothing, and frequency regulation to power quality. Specifically, the tests conducted included various forms of active power control such as AGC and frequency regulation; droop response; and reactive power, voltage, and power factor controls. This project demonstrated that advanced power electronics and solar generation can be controlled to contribute to system-wide reliability. It was shown that the First Solar plant can provide essential reliability services related to different forms of active and reactive power controls, including plant participation in AGC, primary frequency control, ramp rate control, and voltage regulation. For AGC participation in particular, by comparing the PV plant testing results to the typical performance of individual conventional technologies, we showed that regulation accuracy by the PV plant is 24-30 points better than fast gas turbine technologies. The plant's ability to provide volt-ampere reactive control during periods of extremely low power generation was demonstrated as well. The project team developed a pioneering demonstration concept and test plan to show how various types of active and reactive power controls can leverage PV generation's value from being a simple variable energy resource to a resource that provides a wide range of ancillary services. With this project's approach to a holistic demonstration on an actual, large, utility-scale, operational PV power plant and dissemination of the obtained results, the team sought to close some gaps in perspectives that exist among various stakeholders in California and nationwide by providing real test data.

14 SOLAR ENERGY↗

DOE OSTI2017

An Evaluation of Energy Storage Options for Nuclear Power

The dynamics of energy generation, delivery, and consumption in the United States continue to change as new energy sources come online and consumers purchase more energy-intensive devices. The percentage of electricity generation from variable renewable energy sources like wind and solar power has grown year after year. Meanwhile, the evolution of electric vehicles, smart devices, and consumer appliances is changing the way that electricity is used. As a result of these trends, nuclear power plants (NPPs) are being asked to operate more flexibly. Newly constructed, advanced nuclear power plants (A-NPPs) will likely need to adapt their business models with these market shifts in mind. In the future, A-NPPs might operate in an electricity system that values flexibility (e.g. fast ramping) more than stability (e.g. baseload supply). The current fleet of NPPs is struggling to remain economically viable in competitive markets that favor low natural gas prices and renewable energy sources with low marginal costs. Rising construction costs and ambiguous national policies have only added to the challenges facing plant operators. The industry as a whole is in decline, with 19 reactors in the process of being decommissioned and 5 of these plants retiring in the past decade. However, NPPs also provide several performance and environmental benefits by maintaining a high capacity factor and generating almost zero greenhouse gas (GHG) emissions over the life cycle of the plant. As more areas of energy consumption in the United States are electrified, NPPs could potentially replace coal and natural gas as a source of heat and power to help decarbonize the U.S. energy mix. Improving the flexibility of newly constructed A-NPPs to increase revenue through market hedging and reduce costs via stable operation was explored in this analysis. The increasing penetration of variable energy resources could contribute to the uncertainty of electricity demand, which could in turn increase the need for dispatchable electricity generating units. This role is currently filled by inexpensive natural gas combined cycle (NGCC) plants, whereas coal and NPPs have traditionally been called upon to provide baseload power by maintaining a constant power output. As wholesale electricity prices continue to fall due to low natural gas prices and federally subsidized renewable energy, this business model has begun to fail, resulting in incidences of NPPs selling electricity at a loss. Since it has not been economically favorable for NPPs to operate flexibly in this situation in the past, due to their low variable costs compared to fossil fuel power plants, NPPs in the United States were not built with this purpose in mind. Therefore, legacy NPPs have had difficulty adapting to these shifting dynamics due to regulatory and technical constraints, coupled with a lack of meaningful experience. NPPs in France have operated in this manner for years, due to a much higher percentage of baseload generators and a lower percentage of fast-ramping NGCC plants. The integration of energy storage technologies (ESTs) alongside newly constructed A-NPPs will be investigated in this analysis as an alternative method for helping NPPs resolve the economic challenges they currently face. Although the deregulation of energy markets in the United States is responsible for much of the increased competition from natural gas and renewable energy that has negatively impacted NPPs, this process has also led to the creation of ancillary service markets. ESTs can provide many of these services, so an integrated energy storage system could supplement both the reliability of the electricity grid and the economic performance of a NPP by bidding into these markets. However, many technical, financial, and regulatory barriers still prevent ESTs from operating profitably in this space. The purpose of this body of work is to compile a transparent database of metrics for available ESTs and identify barriers to widespread deployment. An analytical selection methodology was also developed to identify favorable technologies for integration with specific NPPs based on information supplied by an interested developer. These tools could help reduce the perceived risk surrounding investment in energy storage systems, which could help both NPPs in need of economic assistance and ESTs in need of further research and development.

22 GENERAL STUDIES OF NUCLEAR REACTORS↗

DOE OSTI2012

Summary of Time Period-Based and Other Approximation Methods for Determining the Capacity Value of Wind and Solar in the United States: September 2010 - February 2012

This paper updates previous work that describes time period-based and other approximation methods for estimating the capacity value of wind power and extends it to include solar power. The paper summarizes various methods presented in utility integrated resource plans, regional transmission organization methodologies, regional stakeholder initiatives, regulatory proceedings, and academic andindustry studies. Time period-based approximation methods typically measure the contribution of a wind or solar plant at the time of system peak--sometimes over a period of months or the average of multiple years.

14 SOLAR ENERGY↗

DOE OSTI2017

Grid-Level Application of Electrical Energy Storage: Example Use Cases in the United States and China

Electrical energy storage (EES) systems are expected to play an increasing role in helping the United States and China-the world's largest economies with the two largest power systems-meet the challenges of integrating more variable renewable resources and enhancing the reliability of power systems by improving the operating capabilities of the electric grid. EES systems are becoming integral components of a resilient and efficient grid through a diverse set of applications that include energy management, load shifting, frequency regulation, grid stabilization, and voltage support.

24 POWER TRANSMISSION AND DISTRIBUTION↗

DOE OSTI2012

Quantifying the Value of Hydropower in the Electric Grid: Final Report

The report summarizes research to Quantify the Value of Hydropower in the Electric Grid. This 3-year DOE study focused on defining value of hydropower assets in a changing electric grid. Methods are described for valuation and planning of pumped storage and conventional hydropower. The project team conducted plant case studies, electric system modeling, market analysis, cost data gathering, and evaluations of operating strategies and constraints. Five other reports detailing these research results are available a project website, www.epri.com/hydrogrid. With increasing deployment of wind and solar renewable generation, many owners, operators, and developers of hydropower have recognized the opportunity to provide more flexibility and ancillary services to the electric grid. To quantify value of services, this study focused on the Western Electric Coordinating Council region. A security-constrained, unit commitment and economic dispatch model was used to quantify the role of hydropower for several future energy scenarios up to 2020. This hourly production simulation considered transmission requirements to deliver energy, including future expansion plans. Both energy and ancillary service values were considered. Addressing specifically the quantification of pumped storage value, no single value stream dominated predicted plant contributions in various energy futures. Modeling confirmed that service value depends greatly on location and on competition with other available grid support resources. In this summary, ten different value streams related to hydropower are described. These fell into three categories; operational improvements, new technologies, and electricity market opportunities. Of these ten, the study was able to quantify a monetary value in six by applying both present day and future scenarios for operating the electric grid. This study confirmed that hydropower resources across the United States contribute significantly to operation of the grid in terms of energy, capacity, and ancillary services. Many potential improvements to existing hydropower plants were found to be cost-effective. Pumped storage is the most likely form of large new hydro asset expansions in the U.S. however, justifying investments in new pumped storage plants remains very challenging with current electricity market economics. Even over a wide range of possible energy futures, up to 2020, no energy future was found to bring quantifiable revenues sufficient to cover estimated costs of plant construction. Value streams not quantified in this study may provide a different cost-benefit balance and an economic tipping point for hydro. Future studies are essential in the quest to quantify the full potential value. Additional research should consider the value of services provided by advanced storage hydropower and pumped storage at smaller time steps for integration of variable renewable resources, and should include all possible value streams such as capacity value and portfolio benefits i.e.; reducing cycling on traditional generation.

13 HYDRO ENERGY↗

DOE OSTI2025

Pavement condition and climatic data in southeast Texas: A dataset for evaluating flood impacts on pavement performance

Effective pavement maintenance is essential for economic stability, optimal network performance, and roadway safety. Achieving this requires thorough evaluation of pavement conditions, including structural integrity, surface roughness, and distress characteristics. Pavement performance indicators play a critical role in influencing vehicle safety and ride quality. Recent advances have emphasized the use of data-driven modeling to anticipate pavement behavior, with the goal of optimizing resource allocation and refining Maintenance and Rehabilitation (M&R) strategies through accurate condition assessment. A foundational requirement for these modeling efforts is the availability of standardized, high-quality datasets that can support robust and reproducible infrastructure analysis. This data article presents a comprehensive dataset assembled to facilitate pavement performance prediction, with a geographic focus on Southeast Texas, particularly the flood-vulnerable area of Beaumont. The dataset encompasses pavement and traffic attributes, meteorological records, flood simulation outputs, ground deformation measurements, and topographic indices, enabling detailed examination of both load-associated and non-load-associated degradation mechanisms. Data preprocessing was performed using ArcGIS Pro, Microsoft Excel, and Python to ensure consistency and usability in data-driven modeling applications, including machine learning workflows. Key contributions of this dataset include its utility in analyzing the climatic and environmental factors affecting pavement conditions, identifying critical predictive features, and enabling in-depth correlation analysis across diverse variables. By filling existing gaps in input variable selection resources, this dataset supports the development of predictive tools for estimating future maintenance demand and enhancing the resilience of pavement networks in flood-impacted areas. The resource highlights the importance of standardized datasets for advancing pavement management practices and provides a robust foundation for ongoing infrastructure performance modeling.

42 ENGINEERING↗

DOE OSTI2019

Variable Grid Method

NETL’s Variable Grid Method (VGM) is a novel approach that leverages GIS capabilities to simultaneously visualize and quantify spatial data trends and underlying data uncertainty. The flexible VGM approach utilizes a range of spatial datasets and uncertainty quantifications, which can be calculated using data related to sample density, sample variance, interpolation error, multiple simulations, etc., to create an integrated visualization of data and uncertainty. The intuitive manner of the VGM helps communicate the relationship between uncertainty and spatial data to effectively guide research, support advanced computation analyses, and helps inform research, management and policy decisions. The VGM approach is being developed into a standalone tool designed to integrate into a variety of research workflows, providing users the capabilities to utilize the VGM for their datasets, analysis, and models in support of their decision making needs. The VGM approach was developed as part of NETL’s Offshore portfolio. It was further matured and utilized in projects associated with both NETL’s Unconventional Resources and Carbon Storage portfolios, and is now being further developed by Varigrid, LLC.

Carbon Storage↗

DOE OSTI2016

Survey of U.S. Ancillary Services Markets

In addition to providing energy to end-consumers, power system operators are also responsible for ensuring system reliability. To this end, power markets maintain an array of ancillary services to ensure that it is always possible to balance the supply and demand for energy in real-time. A subset of these ancillary services are commonly procured through market-based mechanisms: namely, Regulation, Spinning, and Non-spinning Reserves. Regulation Reserves are maintained to respond to supply/demand imbalances over short time frames, typically on the order of several seconds to one minute. Resources that provide Regulation Reserves adjust their generation or load levels in response to automatic generation control (AGC) signals provided by the system operator. Contingency reserves are maintained to provide additional generation capacity in the event that load increases substantially or supply side resources reduce their output or are taken offline. The reserves are typically segmented into two categories, 1) Spinning or Synchronized Reserves that are provided by generation units that are actively generating and have the ability to increase or decrease their output, 2) Non-spinning or Non-synchronized Reserves that are provided by generation resources that are not actively generating, but are able to start up and provide generation within a specified timeframe. Contingency reserves typically have response times on the order of ten to 30 minutes and can also be provided by demand-side resources that are capable of reducing their load. There are seven distinct power markets in the United States, each operated by a Regional Transmission Operator (RTO) or Independent System Operator (ISO) that operates the transmission system in its territory, operates markets for energy and ancillary services, and maintains system reliability. Each power market offers its own set of ancillary services, and precise definitions, requirements, and market mechanisms differ between markets. Despite the differences between markets, both in terms of services offered and system requirements, some broad trends generally apply. Regulation Reserves typically have the highest market prices, followed by Spinning Reserves and Non-spinning Reserves. Prices for Regulation Reserves have been the highest in the PJM market, since it opened in October 2012. This is partially because PJM experienced large price spikes during the period of extreme weather conditions in early 2014. ERCOT has traditionally had the highest prices for Spinning Reserves (called Responsive Reserves in ERCOT), including several periods of sustained high prices between 2010 and 2012. This can be explained in part by the relatively high penetration of variable wind resources and a similarly high requirement relative to peak load. ERCOT has also traditionally had the highest price for Non-spinning Reserves, followed by the NYISO East region. Both have experienced several periods of prolonged high prices since their inception, an occurrence that has not been regularly seen in other markets. In ISO-NE and PJM for example, the market clearing price for Non-spinning Reserves is typically $0/MWh more than 95% of the time. Market volume (in terms of the average amount of capacity of each service that is provided to a system) typically follows the reverse order of prices, as systems maintain the most Non-spinning Reserves capacity followed by Spinning Reserves and Regulation Reserves. PJM generally has the largest market for Regulation Reserves both in terms of capacity. The size of most Regulation Reserves markets in terms of capacity stay relatively constant year-to-year, as this is dictated largely by system requirements. PJM also generally has the largest Spinning Reserves market in terms of capacity. SPP, MISO, ISO-NE and SPP (beginning in 2014) all have Spinning Reserve markets with similar average capacity levels. When combined, the markets for Non-spinning and Operating reserves in ISO-NE have a comparable capacity to the market for Primary Reserves 1 in PJM. SPP, MISO, and CAISO all have smaller markets for their respective Non-spinning Reserves products that are roughly the same size as each other in terms of capacity.

29 ENERGY PLANNING, POLICY, AND ECONOMY↗

DOE OSTI2018

Hydropower Operations in the Colorado River Basin: Institutional Analysis of Opportunities and Constraints

The Colorado River Basin is facing an unprecedented drought. In ongoing drought management efforts, limited attention has been paid to hydropower generation. While some studies do exist on hydropower, they are quantitative in nature and focus on calculating the reduction in megawatts generated at dams in the Basin with declining water availability. These studies simplify the complex process of hydropower generation; water availability is but one factor that impacts hydropower generation. At a more fundamental level, formal institutional arrangements, that is, laws, policies, and rules create the framework within which dams are operated and hydropower is generated. This paper conducts a comparative institutional analysis of water, environment, and energy laws and policies and changes therein to understand the constraints and opportunities faced by hydropower generation in the Colorado River Basin. To tease out the nuances in how institutional arrangements affect dam operations and hydropower generation, the comparative analysis focuses on the two largest and strategically important dams in the Basin: Hoover and Glen Canyon. This paper uses Elinor Ostrom’s Institutional Analysis and Development Framework to analyze laws and policies at three levels: constitutional-choice, collective-choice, and operational levels. Constitutional-choice level laws and policies apply to the entire Basin, whereas collective-choice level and operational level laws and policies are dam specific. Hoover and Glen Canyon Dams face similar biophysical challenges by the virtue of their location in the same river basin. Yet, despite the similarity in the biophysical setting, the analysis in this study finds that the differences in the applicability of constitutional-choice level laws along with the differences in dam specific collective-choice and operational level institutional arrangements produce a distinct set of constraints for hydropower generation at Hoover and Glen Canyon Dams. Even without a drought, water and environmental laws at both the constitutionalchoice and collective-choice levels as well as power contracts constrain hydropower generation and limit the flexibility with which Glen Canyon Dam can be operated. Water and environmental laws also impose specific water release requirements that, at times, require off-peak power generation at Glen Canyon Dam. On the other hand, even with a drought, Hoover Dam faces limited hydropower generation constraints and can operate flexibly. This is because constitutional-choice level laws and dam-specific collective-choice and operational level laws pose limited constraints for flexible daily operations at Hoover. The result is that Hoover Dam can generate hydropower at the same level as it did three decades ago and operate flexibly to provide ancillary services and peaking generation. While water and environmental laws and policies pose constraints for hydropower generation, the analysis in this study further finds that specific historic provisions within energyrelated institutional arrangements and recent changes within power contracts have maintained and even enhanced the value of hydropower to power customers. Historic institutional provisions ensure that hydropower is sold ‘at cost’ making this resource economically competitive with wholesale electricity market rates. Recent power contract modifications have resulted in the amendment of an older resale prohibition clause to expand the flexibility available to power customers in using their capacity and/or energy allocation in RTOs, ISOs, and bulk power markets. This amendment has opened up an opportunity for customers, especially Hoover power customers, to use flexible generation and ancillary services in a market environment. In addition, the extension of power contract duration to the legally maximum term has enhanced the reliability and stability of this resource for customers. In the Colorado River Basin, despite the enduring economic responsibility of power customers—where laws require customers to pay for a large portion of construction and O&M costs whether or not they actually receive hydropower— the persistent threat of a drought-induced water shortage, and constraints imposed by water and environmental laws and policies, power customers continue to invest in this resource as energy-related institutional arrangements and power contract provisions protect the reasons why they value hydropower. Lastly, the analysis in this study finds that the consequences of changes in hydropower generation for energy users, irrigators, and environmental programs in the Basin depend on how specific institutional arrangements tie electricity revenues to irrigation aid and environmental programs, and how the power contracts themselves are set up. Collective-choice level institutional arrangements create a higher level of financial dependency of irrigation aid and environmental programs on electricity revenues in the Upper Basin—the legal subdivision of Colorado River where Glen Canyon Dam is located—compared to the Lower Basin—the legal subdivision of Colorado River where Hoover Dam is located. Therefore, changes in hydropower generation or the way its revenue is collected and used will have far reacting detrimental consequences for the Upper Basin. Likewise, differences in the nature of power contracts for Glen Canyon and Hoover Dams also creates differences in the financial impact incurred by energy users when there is a reduction in hydropower generation. While this study identifies the types of impacts on resource users as a result of specific institutional arrangements, the calculation of extent of impact warrants further attention. Hydropower in the United States is in a unique position today. The strategic importance of this resource for the nation’s electricity sector is rapidly growing even as its contribution to overall electricity generation remains fairly small. This strategic importance, however, is built hydropower’s ability to operate flexibly in order to support the integration of intermittent renewable generating sources and the expansion of electricity markets. As this study shows, such flexibility may not be available at certain plants not due to the lack of water availability but because of institutional constraints. Institutional arrangements may also require dam operators to first consider high priority water uses (such as irrigation or environmental needs), which in turn may limit the ability to generate hydropower when it is most valuable or useful. Engineering and quantitative models, such as production cost models, recognize policy constraints for hydropower operations but often inadequately capture or assume away such constraints in the models. A failure to account for policy constraints in these models runs the risk of inaccurate representation of the operational flexibility and capacity available at specific hydropower plants, which can result in over/underestimation of hydropower’s ability to support the integration of variable renewable resources and address grid reliability concerns. Against this background, this paper and the analysis herein serves as an example of how we can systematically identify institutional constraints (and opportunities) that influence the flexibility in not only generating electricity at specific dams but also using this hydropower once it is generated.

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