To better understand the role of hydropower in a future electricity grid, the authors managed a three-year study engaging stakeholders from industry, government and research. Ten ways were identified to account for value streams from hydropower and included the implied industry opportunities, as well as likely beneficiaries.
By Thomas Key, Lindsey Rogers, Patrick March, Hoyt Battey and Rajesh Dham
In the U.S., development of new hydropower faces significant challenges. These include limited siting opportunities, large initial capital investment, and diverse value streams that are difficult to quantify in a deregulated electric sector. Methods for electricity production are driven by economics in the resource selection, unit commitment, economic dispatch and selection of reserve resources.
Hydropower must compete with other forms of generation, balancing and demand response. New hydroelectric development has stalled because of the lack of financial incentives to compensate for permitting and construction costs. Wind and solar generation are expected to increase volatility and uncertainty in the electric grid, and hydropower – pumped storage in particular – has the potential to help manage these variable resources. However, it is difficult to capture the value hydroelectric facilities bring to the grid.
The U.S. Department of Energy-funded Quantifying the Value of Hydropower in the Electric Grid project has examined the energy production, services and reliability attributes of hydro. The approach has been to define flexibility and limitations of existing plants, simulate present and future operations in an economic model, analyze the operating constraints and opportunities, develop cost data, and evaluate existing and potential market operations. This analysis focused on the Western Electricity Coordinating Council (WECC) because of the traditional importance of hydropower and the significant growth in wind and solar energy in this region.
This article defines current market structures, assesses the value of this market based on modeling results, and outlines 10 opportunities to increase the value of hydropower. The final report gives more in-depth results and analysis.1
Market structure: Real-time economics
The role and contribution of hydro resources are primarily driven by market structures. There are 10 formal markets for generation resource acquisition in North America. In areas outside markets, referred to as traditional scheduling areas, bilateral transactions are used for resource acquisition. In general, formal markets operate in conjunction with an independent system operator (ISO) or regional transmission organization (RTO). The current market structures are outlined below, with a summary of their potential value.
– Formal markets. ISOs and RTOs manage grid operations and operate the markets through which energy, ancillary services and capacity resources are procured. Participants must have their generation assets tested and approved to meet North American Electric Reliability Corporation (NERC) standards and to demonstrate that they are financially sound. Generator owners, merchant plants, independent power producers (IPPs) and demand side resources bid to provide energy and ancillary services based on financial incentives and profit motive. These do not carry the traditional “obligation to serve” end-use demand in a particular service territory.
– Non-markets. Traditional scheduling areas consist of regulated utilities that maintain their vertically integrated organization, planning and operating models. They are regulated by state public utility authorities and the Federal Energy Regulatory Commission and carry the obligation to serve demand within their territories. Operators schedule energy and power transactions and coordinate operations and system expansion planning to maintain grid reliability following NERC criteria. Entities may engage in bilateral trades with adjacent utilities to meet their obligations.
– Mixed business model. This is characteristic of several NERC regional entities that have market and non-market areas. WECC is an example of a mixed model due to the presence of formal markets, such as the California ISO (CAISO), with the balance governed by a system similar to that in the southeast. The presence of formal markets in WECC presents opportunities for owners whose assets are outside those markets. They are still used to meet load-serving obligation within their balancing areas, but they can bid their assets into other markets. In addition, there are informal bilateral wholesale markets in WECC. This model presents the opportunity for more value streams.
Significance of real-time markets
Economic behavior driven by cost minimization dictates the behavior of participants in market and non-market segments of the industry. Formal electricity markets sharpen the profit incentives of all participants, including those subject to regulation. The role of formal markets is likely to grow in the WECC region.
Hydropower resources across the U.S. contribute significantly to grid reliability in terms of energy, capacity and ancillary services. Hydro plants have been used to provide spinning and non-spinning reserve, replacement reserve, and regulation or load following. Revenues from these services are not fully captured in the current non-market areas due to the lack of markets for ancillary services.
Economic value of hydropower resources
This study used an economic dispatch model called UPLAN to simulate WECC and quantify the existing and potential value of hydropower to the grid. The model looked at energy and ancillary services provided by hydro plants, as well as the effects of adding pumped-storage plants. A separate generation capacity expansion model was used to define the generation mix with different energy futures.
More than 20 scenarios were run to help provide information about the effect of renewables, CO2 prices, natural gas prices and upgraded plants on the overall value to hydropower. These scenarios intend to provide insight into energy dispatch and services a future electricity market structure may need to capture. Complete results can be found in the modeling report.2
Ways to increase hydro’s value
Ten ways to increase or better capture hydro’s value were identified in three categories: operations, technology and markets.
There are three potential operational ways to increase value:
– Identify and implement efficiency improvements by modifying unit operations while respecting river system optimizations and constraints (benefits to plant owner). Analyses were performed on eight plants, including five pumped-storage facilities, to assess performance and sub-optimization under market and non-market conditions.3
Capturing the operations of each plant and its inefficiencies identifies areas with potential to increase value. The performance assessment includes generation improvements based on direct optimization, operation efficiency analyses, and scheduling analyses. It is clear that markets affect plant value. In general, non-market operations of conventional hydroelectric and pumped-storage plants resulted in more efficient performance than the market-based plants.3
– Use hydro to address other generation and load variability, providing flexible resources, reducing wear and tear on the thermal fleet, and increasing the efficiency of other generation (benefits to system operator or vertically integrated utility).
Another potential method to capture value is to provide incentive to address system variability by providing flexible reserves. Scenarios were run with a flat level of reserves (5%), and a scenario was run with increased reserve requirements based on a statistical analysis of the variability of wind and solar over different time scales. The reserve requirements are broken down into three classes: regulation, spinning reserve, and non-spinning and supplemental reserves. Pumped storage was affected most by the increase in reserve requirements (see Figure 1 on page 24), with an increase in revenue of more than 40%.
Modeling clearly shows an increase in overall revenue through the increase in flexible reserves. However, hydroelectric plants have to compete with other generation types to provide this resource.
– Recognize hydro for allowing more generation diversity and options, thus enhancing energy security and maintaining power supply reliability in the face of future uncertainties (benefits to national interest, general public and NERC).
Modeling showed that conventional and pumped-storage hydro are often relied upon to “keep the lights on” in WECC. In addition, pumped storage was used to balance unexpected losses in generation. Although this was not monetized in the study, it was identified as an area where value could be captured.
New hydropower technologies
There are three areas to increase the value of hydro through new technology:
– Expand the effective operating range of units with lower minimum load and higher peak operating capabilities (benefits to plant owner and operator). This requires making changes to increase the capacity. A sensitivity test was run, reducing the minimum load from 70% to 40%. This resulted in a 61% increase in pumped-storage plants’ average income. The energy revenue increases some, but the ancillary services revenue more than doubles.
– Apply adjustable speed drive electronics in pumped-storage units to enable regulation of pumping power requirements, particularly at night (benefits to plant owner and operator). Upgrading a plant with a variable speed drive or installing a plant with new technology can add even greater value than in the previous example. A sensitivity test was run with the variable speed plant characteristics. These changes resulted in an 85% increase in plant income, mostly due to providing ancillary services at night.
– Design pumped-storage plants that minimize environmental impacts, such as low-profile or closed water supply loop, to shorten licensing lead times and the public approval process (benefits to hydro plant developers and general public). This was not monetized as part of the study.
There are four ways to better capture value in the markets:
– Settle energy markets sub-hourly, increasing energy arbitrage opportunities for hydro with grid demand load leveling benefits (benefits everybody). Sub-hourly scheduling provides access and compensation for the flexibility of all generators. Development of forward markets also can benefit hydro resources that must schedule production based on limited energy resources. Developing a system that brings demand response to the market would help reduce power in energy and reserve markets, letting all generators receive competitive energy and ancillary service prices.
The valuation of hydro’s contribution to these components is determined from an hourly-resolution security-constrained unit commitment and economic dispatch model. The production cost simulations represent the movement of load and generation from one hour to the next by assuming average demand and supply across the hour. This means the analysis can represent the value of hydro providing energy, as well as the contribution to the reserve capacity required for providing ancillary services that are needed within the hour. Modeling shows that the existence of hydropower to participate in ancillary services markets, supporting the grid operation, significantly reduced the cost of electricity in WECC.
Conventional hydro accounts for 25% of the energy produced in WECC. Removing hydro from the mix, as a way to value its contribution, was not possible because the electrical laws for real-time delivery of energy to load and for balancing supply and demand could not be solved. A valuation was possible for excluding and including existing hydro in providing ancillary services. Hydro participation in providing ancillary services decreases the overall production costs of electricity in WECC by $1.35 billion, or 6%. Electricity prices were estimated to increase by 5% when hydro does not participate.
Figure 2 on page 25 shows the technologies required to provide ancillary services in the place of hydro and the technologies that provide these services when hydro can participate.
While conventional hydro plants make money from ancillary services, this is just under 3% of overall plant revenue. Also for conventional plants, adding variable generation and thus increasing the system reserve requirements increased total ancillary service revenue by $23 million (on a total revenue of $12.4 million), with an average increase of $1.50/kW. In general, the average conventional hydro plant received revenues of $134 to $230/kW in the base case 2020 before the increased variability.
A significant potential future value stream for pumped-storage plants will be in providing ancillary services in WECC (see Figure 3 on page 26). The ancillary service revenue is a significant portion in each energy future scenario, but in the extreme scenario the pumped-storage plant sees significantly increased revenue from ancillary services.
When looking WECC-wide across all future scenarios, a pumped-storage unit can receive 30% to 50% of its revenues from ancillary services and the remaining from energy arbitrage (see Figure 4 on page 27). In addition, simulation results show that eight of the cases have greater than 40% of 2020 revenues from ancillary services.
– ISOs scheduling hydro to co-optimize energy and ancillary services within a balancing authority (benefits everybody). Allowing ISOs to schedule hydro over multiple hours or days could provide more value by broadening the practice where ISOs co-optimize energy and ancillary scheduling over a single time period to include scheduling energy-limited hydro resources over time periods up to a day or longer. The ISO would know the capabilities, limitations and costs for each plant and could schedule the pumping, generation and ancillary services in a system-wide beneficial way. As the importance and potential income of ancillary services increases, this allows for optimal scheduling and increased profitability. Analysis shows that an example pumped-storage plant could increase profits by 63% to 77% if the ISO optimized scheduling compared with relying on a fixed pumping and generating schedule.4
– Treat pumped storage as a new storage asset class capturing the full value of services and improving the economics in areas with resource constraints (benefits developers, owners and general public). This new asset class, recommended by the National Hydropower Association, would allow storage to be compensated for supporting the grid during low- and high-demand periods. Included are contracts to allow for procurement of long-term ancillary services in which pumped storage can help mitigate the effects of variable renewable generation. Although this concept could provide increased value by compensating pumped storage for its grid support and functionality, this was not quantified in the study.
– Credit hydro for normally fast regulation response in situations where resource adequacy is a power system reliability issue (benefits developers, owners, NERC and general public). There is a potential value that hydropower could gain from providing dynamic reactive power support, primary frequency response and within-hour deployment services. In this study, this value was not captured in the hourly model. A project has been initiated by DOE, entitled “Modeling and Analysis of the Value of Advanced Pumped Storage Hydropower in the U.S.,” to create modeling tools to evaluate pumped-storage hydro’s contribution on a second and sub-second basis.
The study confirmed that hydropower resources across the U.S. contribute significantly to operation of the grid in terms of energy, capacity and ancillary services. Many potential improvements to existing hydro facilities were found to be cost-effective. In this study, consideration for building new hydro facilities was limited to pumped storage opportunities in the western U.S. A key characteristic related to valuing these new facilities is the multiple stakeholders who must share the benefits. Pumped storage remains the most likely form for large-scale electric energy storage.
The general conclusion is that more work needs to be done to quantify the full value stream of hydropower resources. Modeling on shorter time scales may be beneficial to capture value on a within-hour basis. Additionally, work needs to be done to better understand hydro’s role in supporting a reliable grid and preparing the power system for an uncertain energy market future. Ultimately, hydropower will have to compete efficiently and effectively with other generation resources, demand response, and better forecasting to capture value.
1Quantifying the Value of Hydropower in the Electric Grid: Final Report, 1023144, EPRI, Palo Alto, Calif., 2012.
2Quantifying the Value of Hydropower in the Electric Grid: Modeling Results for Future Scenarios, 1023141, EPRI, Palo Alto, Calif., 2012.
3March, P.A., P. Wolff, and T. Key, “Effects of Electricity Markets on Suboptimization of Pumped Storage Hydroelectric Plants,” Proceedings of HydroVision International 2012, PennWell Corporation, Tulsa, Okla., 2012.
4Kirby, B., “Co-optimizing Energy and Ancillary Services from Energy Limited Hydro and Pumped Storage Plants,” Proceedings of HydroVision International 2012, PennWell Corporation, Tulsa, Okla., 2012.
Tom Key is technical executive for power delivery and utilization and Lindsey Rogers is project engineer for power delivery and utilization with the Electric Power Research Institute. Patrick March is president and principal consultant with Hydro Performance Processes Inc. Hoyt Battey is water power market acceleration and deployment team lead and Rajesh Dham is water power team lead for the U. S. Department of Energy’s Wind and Water Power Program. The work discussed in this article is sponsored by DOE and the hydropower industry under DOE‐EE00002666.