Thrust 3: Develop new techno-economic principles

The Goal

To develop, demonstrate, and transfer new principles and tools for addressing three crucial tasks for the T100RE transition:

  1. Coordinating operations and investment;
  2. Harnessing demand-side and distributed energy resource (DER) flexibility; and
  3. Managing queues to connect new variable renewable energy (VRE) projects.
The Theory

VREs and DERs with zero or ambiguous production costs gradually deteriorate the efficiency of current energy and market management practices devised for controllable, centralized fossil-fuel generators with well defined costs. Enabling the 100% renewable energy grid (T100RE) transition requires aligning the techno-economic characteristics of the new resources with power grid management. Technologic challenges concern the ability to harvest the flexibility of a large number of VREs and DERs on operational time scales, and how to “firm up” their output by using their inherent characteristics or exploiting complementarity with demand-side and storage resources.

The Methods

The ability of spot power markets to provide incentives for efficient investment in new resources has been long debated. The public good nature of reliability separates private and public returns on supporting investments. Energy price caps limit the ability of scarcity pricing to reward investments necessary to meet peak demands and enhance power grid resiliency during extreme conditions. Capacity markets have typically not worked well for renewables, and presently do not justify substantial investments in storage required for rapid decarbonization. Modeling suggests that future spot markets will feature more highly volatile and uncertain prices, complicating planning resource investments. Our solution is to develop a hybrid market that includes (1) a long-term forward market that accounts for both resource adequacy and decarbonization goals and (2) energy and ancillary services markets that facilitate efficient power grid operation and must tackle stability issues arising from IBRs (see Thrust 2). A key design issue for hybrid markets, which we will optimize, is carbon border adjustments to manage CO2 emissions in power trade among jurisdictions with inconsistent carbon policies. To prevent carbon leakage, US power grid operators (e.g., CAISO, NYISO) penalize or limit imports from high-carbon sources. There is a need for both economic theory and practical market software for both spot markets and long-term forward markets that encourages cost-effective emissions reductions throughout markets without interfering with the incentives for efficient and reliable planning and operations. We will develop economic theory and empirical methods to evaluate various hybrid market approaches that encourage investment in new VREs and DERs, demand response, and storage needed to support reliability and decarbonization, while considering the extended operating time horizons, energy price variability, and coordinated transmission and distribution decision-making needed to support efficient and flexible participation of storage, demand, and DERs. These enhancements will lead to increasingly large and data-hungry models, which will leverage trustworthy ML and data augmentation frameworks in Thrust 1. These models will be targeted for adoption by industry members of G-PST, FPFM and ESIG, who have important experience in promoting power grid reliability and security.

Identifying and enabling new mechanisms for balancing fluctuations in VRE supply is essential for maintaining reliability of T100RE grids and by extension for supporting societal decarbonization through electrification. Section 1 considers the entire range of flexibility sources; in this section, we focus on exploiting demand-side flexibility, which is central to efficient operations and now exhibits huge opportunities due to increasing adoption of controllable DERs, but whose potential benefits are largely unrealized despite many efforts to promote demand response and retail competition. Repeated failures have been observed globally, and concerns of consumer advocates regarding inequitable distribution of winners and losers hinders progress. This section has two efforts focusing on enabling regulators and operators to accelerate adoption of demand and DER flexibility solutions.

The first effort will draw lessons for regulators and operators on coordination of efforts to encourage demand and DER flexibility across jurisdictions and scales. Consumer-based flexibility, local and regional planning for transport and building decarbonization, and power grid planning increasingly interact, creating uncertainties in roles and responsibilities across scales. While there is emerging research on the optimized design, planning and operation of more locally integrated energy systems, there is a lack of knowledge on the most appropriate regulatory programs to support customer participation. Drawing on socio-technical transition literatures, and extending, this research will investigate the conditions under which policymakers, regulators and grid operators can accelerate the delivery of demand-side flexibility and local integration. Specifically, it will go beyond technological innovation to examine the transformative governance strategies needed to integrate large amounts of consumer flexibility, which is of interest to our Project Affiliates Electric Power Research Institute (EPRI), National Renewable Energy Lab (NREL) and University of Victoria (UV). The research will: carry out policy mapping and analysis of emerging coordination challenges for accessing DER and demand flexibility at, and between, the distribution and transmission levels; conduct an international review with T100RE stakeholders on emerging business models and policy needs for smart flexibility; develop cross country comparators (e.g., UK, US, Australia, Denmark, and Ireland) examining the organizational and institutional factors affecting the T100RE transformation. Outputs will provide policymakers and regulators with learning on the decision support and governance frameworks for demand-side flexibility, including international learning on equity and business models under different regulatory, operator, and consumer protection arrangements.

The second effort, linked to the G-PST’s Tasks Force on DERs, will develop economic programs that incentivize flexibility from DERs (e.g., batteries, often paired “behind the meter” with rooftop PV) and newly electrified loads (e.g., EVs or heat pumps) to match demand with supply; while considering regulatory concerns about consumer protection together with operators’ concerns about reliable performance. State-of-the-art research recognizes the challenges of dynamic pricing and suggests that effective designs will likely include multiple mechanisms with complementary functions such as hedging/insurance programs along with dynamic pricing and novel ancillary services. That research also concludes that recognizing customer heterogeneity in terms of capabilities, socio-economic characteristics, and risk preferences is key for effective design and assessment of programs for motivating demand-side flexibility. Our aim here, overlapping with Project Affiliate Berkeley, is to develop mathematical frameworks that recognize the range of timings for electricity procurement and capture customer diversity in terms of consumer income, price responsiveness, and risk attitudes. Using these frameworks, we will identify designs that strike socially acceptable balances between exposure to real-time price signals and equity concerns, while addressing pressing questions on effective ways to combine programs. Tradeoffs between cost efficiency and distributional equity will be studied for program designs that control exposure to price volatility, such as socially-aware storage dispatch and hedged rates that apply real-time prices only for consumption beyond a minimum level. We will leverage findings from the first research focus in this RD, together with advanced operating models from Thrust 1, to assess how the proposed designs address broader societal concerns.

Transmission expansion planning, especially in an open access environment, has to balance the need for proactive planning and a neutral stance on outcomes. Yet given transmission planning’s long lead times, today’s common myopic approach that responds only to generation requests causes costly bottlenecks and stalled investment, which may endanger full decarbonization of the electric power sector and obstructs society-scale electrification. Today’s management of new resource interconnection requests leads to multi-year delays in approvals and an exaggerated number of such requests, which have caught the attention of policy makers who view them as dramatically slowing the pace of VRE integration. This section will address the inefficiency of present interconnection queue management, observed globally, by working with institutional partners to survey current interconnection policies. One cause of long lead times is that the power grid operator needs to perform large numbers of complex studies that cover many possible future combinations of connected plant.  Working with Thrust 1’s team, we will explore both computational (how to solve interconnection problems faster) and economic solutions (how to prioritize among interconnection requests) to these challenges. We will also propose integrated queue management and anticipatory grid expansion optimization methods, based on Thrust 1’s T100RE power grid models and high-performance algorithms, that will consider the interactions among competing and complementary interconnection requests alike to maximize cost-effective integration of VREs and DERs, while avoiding unnecessarily excessive (and environmentally damaging) grid investments and considering multiple scenarios of future economic, technological, and climate developments.

The Team

Benjamin F. Hobbs

Theodore M. and Kay W. Schad Professor of Environmental Management, Johns Hopkins University

Elina Spyrou

Leverhulme Lecturer in Power System Transformation, Imperial College London

Enrique Mallada

Associate Professor of Electrical and Computer Engineering, Johns Hopkins University

Yury Dvorkin

Associate Professor of Civil and Systems Engineering and Electrical and Computer Engineering, Johns Hopkins University

Karen Palmer

Senior Fellow and Director of Electric Power Program, Resources for the Future

Dallas Burtraw

Darius Gaskins Senior Fellow, Resources for the Future

James Bushnell

Professor of Economics, University of California Davis

Richard Green

Head of Department of Economics and Public Policy, Imperial College London

Mark O’Malley

Leverhulme Professor of Power Systems, Imperial College London

Janusz Bialek

Professor of Power and Energy Systems, Newcastle University

Jess Britton

Research Fellow of Local and Regional Energy Systems, University of Edinburgh

Taj Khandoker

Research Scientist of Energy & Economic Modeling, CSIRO

Reihana Mohideen

Principal Advisor for Social Implications of Technology (Infrastructure and Resilience), University of Melbourne

Luis (Nando) Ochoa

Professor of Smart Grids and Power Systems, University of Melbourne