Distributed Resources Shift Paradigms on Power System Design, Planning, and Operation: An Application of the GAP Model

Power systems have evolved following a century-old paradigm of planning and operating a grid based on large central generation plants connected to load centers through a transmission grid and distribution lines with radial flows. This paradigm is being challenged by the development and diffusion of modular generation and storage technologies. We use a novel approach to assess the sequencing and pacing of centralized, distributed, and off-grid electrification strategies by developing and employing the grid and access planning (GAP) model. GAP is a capacity expansion model to jointly assess operation and investment in utility-scale generation, transmission, distribution, and demand-side resources. This paper conceptually studies the investment and operation decisions for a power system with and without distributed resources. Contrary to the current practice, we find hybrid systems that pair grid connections with distributed energy resources (DERs) are the preferred mode of electricity supply for greenfield expansion under conservative reductions in photovoltaic panel (PV) and energy storage prices. We also find that when distributed PV and storage are employed in power system expansion, there are savings of 15%-20% mostly in capital deferment and reduced diesel use. Results show that enhanced financing mechanisms for DER PV and storage could enable 50%-60% of additional deployment and save 15 /MWh in system costs. These results have important implications to reform current utility business models in developed power systems and to guide the development of electrification strategies in underdeveloped grids

Transmission and interconnection planning in power systems: Contributions to investment under uncertainty and cross-border cost allocation.

<p>Electricity transmission network investments are playing a key role in the integration process of power systems in the European Union. Given the magnitude of investment costs, their irreversibility, and their impact in the overall development of a region, accounting for the role of uncertainties as well as the involvement of multiple parties in the decision process allows for improved and more robust investment decisions. Even though the creation of this internal energy market requires attention to flexibility and strategic decision-making, existing literature and practitioners have not given proper attention to these topics. Using portfolios of real options, we present two stochastic mixed integer linear programming models for transmission network expansion planning. We study the importance of explicitly addressing uncertainties, the option to postpone decisions and other sources of flexibility in the design of transmission networks. In a case study based on the Azores archipelago we show how renewables penetration can increase by introducing contingency planning into the decision process considering generation capacity uncertainty. We also present a two-party Nash-Coase bargaining transmission capacity investment model. We illustrate optimal fair share cost allocation policies with a case study based on the Iberian market. Lastly, we develop a new model that considers both interconnection expansion planning under uncertainty and cross-border cost allocation based on portfolios of real options and Nash-Coase bargaining. The model is illustrated using Iberian transmission and market data.</p

Bringing power and progress to Africa in a financially and environmentally sustainable manner

EXECUTIVE SUMMARY: The future of electricity supply and delivery on the continent of Africa represents one of the thorniest challenges facing professionals in the global energy, economics, finance, environmental, and philanthropic communities. Roughly 600 million people in Africa lack any access to electricity. If this deficiency is not solved, extreme poverty for many Africans is virtually assured for the foreseeable future, as it is widely recognized that economic advancement cannot be achieved in the 21st Century without good electricity supply. Yet, if Africa were to electrify in the same manner pursued in developed economies around the world during the 20th Century, the planet’s global carbon budget would be vastly exceeded, greatly exacerbating the worldwide damages from climate change. Moreover, due to low purchasing power in most African economies and fiscal insolvency of most African utilities, it is unclear exactly how the necessary infrastructure investments can be deployed to bring ample quantities of power – especially zero-carbon power – to all Africans, both those who currently are unconnected to any grid as well as those who are now served by expensive, high-emitting, limited and unreliable electricity supply. With the current population of 1.3 billion people expected to double by 2050, the above-noted challenges associated with the African electricity sector may well get substantially worse than they already are – unless new approaches to infrastructure planning, development, finance and operation can be mobilized and propagated across the continent. This paper presents a summary of the present state and possible futures for the African electricity sector. A synthesis of an ever-growing body of research on electricity in Africa, this paper aims to provide the reader a thorough and balanced context as well as general conclusions and recommendations to better inform and guide decision-making and action. [TRUNCATED]This paper was developed as part of a broader initiative undertaken by the Institute for Sustainable Energy (ISE) at Boston University to explore the future of the global electricity industry. This ISE initiative – a collaboration with the Global Energy Interconnection and Development Cooperation Organization (GEIDCO) of China and the Center for Global Energy Policy within the School of International and Public Affairs at Columbia University – was generously enabled by a grant from Bloomberg Philanthropies. The authors gratefully acknowledge the support and contributions of the above funders and partners in this research

Market and Economic Modelling of the Intelligent Grid: End of Year Report 2009

The overall goal of Project 2 has been to provide a comprehensive understanding of the impacts of distributed energy (DG) on the Australian Electricity System. The research team at the UQ Energy Economics and Management Group (EEMG) has constructed a variety of sophisticated models to analyse the various impacts of significant increases in DG. These models stress that the spatial configuration of the grid really matters - this has tended to be neglected in economic discussions of the costs of DG relative to conventional, centralized power generation. The modelling also makes it clear that efficient storage systems will often be critical in solving transient stability problems on the grid as we move to the greater provision of renewable DG. We show that DG can help to defer of transmission investments in certain conditions. The existing grid structure was constructed with different priorities in mind and we show that its replacement can come at a prohibitive cost unless the capability of the local grid to accommodate DG is assessed very carefully.Distributed Generation. Energy Economics, Electricity Markets, Renewable Energy

An economic evaluation of the potential for distributed energy in Australia

Australia’s Commonwealth Scientific and Industrial Research Organisation (CSIRO) recently completed a major study investigating the value of distributed energy (DE; collectively demand management, energy efficiency and distributed generation) technologies for reducing greenhouse gas emissions from Australia’s energy sector (CSIRO, 2009). This comprehensive report covered potential economic, environmental, technical, social, policy and regulatory impacts that could result from the wide scale adoption of these technologies. In this paper we highlight the economic findings from the study. Partial Equilibrium modeling of the stationary and transport sectors found that Australia could achieve a present value welfare gain of around $130 billion when operating under a 450 ppm carbon reduction trajectory through to 2050. Modeling also suggests that reduced volatility in the spot market could decrease average prices by up to 12% in 2030 and 65% in 2050 by using local resources to better cater for an evolving supply-demand imbalance. Further modeling suggests that even a small amount of distributed generation located within a distribution network has the potential to significantly alter electricity prices by changing the merit order of dispatch in an electricity spot market. Changes to the dispatch relative to a base case can have both positive and negative effects on network losses.Distributed energy; Economic modeling; Carbon price; Electricity markets

Flexibility Value of Distributed Generation in Transmission Expansion Planning

The efficiency of the classic planning methods for solving realistic problems largely relies on an accurate prediction of the future. Nevertheless, the presence of strategic uncertainties in current electricity markets has made prediction and even forecasting essentially futile. The new paradigm of decision-making involves two major deviations from the conventional planning approach. On one hand, the acceptation the fact the future is almost unpredictable. On the other hand, the application of solid risk management techniques turns to be indispensable. In this chapter, a decision-making framework that properly handles strategic uncertainties is proposed and numerically illustrated for solving a realistic transmission expansion planning problem. The key concept proposed in this chapter lies in systematically incorporating flexible options such as large investments postponement and investing in Distributed Generation, in foresight of possible undesired events that strategic uncertainties might unfold. Until now, the consideration of such flexible options has remained largely unexplored. The understanding of the readers is enhanced by means of applying the proposed framework in a numerical mining firm expansion capacity planning problem. The obtained results show that the proposed framework is able to find solutions with noticeably lower involved risks than those resulting from traditional expansion plans.Fil: Vásquez, Paúl. Consejo Nacional de Electricidad; EcuadorFil: Olsina, Fernando Gabriel. Consejo Nacional de Investigaciones Científicas y Técnicas. Centro Científico Tecnológico Conicet - San Juan. Instituto de Energía Eléctrica. Universidad Nacional de San Juan. Facultad de Ingeniería. Instituto de Energía Eléctrica; Argentin

A Nash Approach to Planning Merchant Transmission for Renewable Resource Integration

Major transmission projects are needed to integrate and to deliver renewable energy (RE) resources. Cost recovery is a serious impediment to transmission investment. A negotiation methodology is developed in this study to guide transmission investment for RE integration. Built on Nash bargaining theory, the methodology models a negotiation between an RE generation company and a transmission company for the cost sharing and recovery of a new transmission line permitting delivery of RE to the grid. Findings from a six-bus test case demonstrate the Pareto efficiency of the approach as well as its fairness, in that it is consistent with one commonly used definition of fairness in cooperative games, the Nash cooperative solution. Hence, the approach could potentially be used as a guideline for RE investors. The study also discusses the possibility of using RE subsidies to steer the negotiated solution towards a system-optimal transmission plan that maximizes total net benefits for all market participants. The findings suggest that RE subsidies can be effectively used to achieve system optimality when RE prices are fixed through bilateral contracts but have limited ability to achieve system optimality when RE prices are determined through locational marginal pricing. This limitation needs to be recognized in the design of RE subsidies

Power System Planning in Disparate Systems: Modeling Sustainability and Electricity Access

Electricity goals around the world tend to focus on increasing social benefit through one of two avenues: (1) increasing overall system sustainability or (2) increasing access to electricity. These goals guide the transition of the power system. In pursuit of these goals decision makers will need modeling tools that can inform decisions, in a way that is flexible enough to include a wide range of preferences and goals. It is clear that the future generation mix of the power system will change, but the most sustainable solution, will change based on a country\u27s goals. This dissertation will explore the various options for power grid expansion in disparate electricity systems. We present three essays that focus on evaluating the sustainability of different electricity futures to allow decision makers to understand impacts and trade-offs between various combinations of power generating technologies. The first two essays are focused on evaluating the sustainability of generation mixes for New England. In the first essay we take a multi-model approach, first determining the reliability of the system overall, then evaluating different generation portfolios based on seven sustainability criteria. In the second essay we expand this work by implementing pumped hydro storage into the model. The sustainability of the system with and without storage capabilities is presented and evaluated. The third essay focuses on the UN Sustainable Development Goals, and electricity access in developing countries. Here we present a model that can be used by decision makers in developing countries to determine the best method of grid expansion to meet electricity access goal

A Federal Renewable Electricity Requirement

Rising energy prices and climate change have changed both the economics and politics of electricity. In response, over half the states have enacted "renewable portfolio standards" (RPS) that require utilities to obtain some power from "renewable" generation resources rather than carbon emitting fossil fuels. Reports of state-level success have brought proposals for a national standard. Like several predecessor Congresses, however, the most recent one failed to pass RPS legislation. Before trying one more time, legislators should ask why they favor a policy so politically correct and so economically suspect. Support for a national program largely stems from misleading claims about state-level successes, misunderstandings about how renewables interact with other environmental regulation, and misinformation about the actual benefits renewables create. State RPS programs are largely in disarray, and even the apparently successful ones have had little impact. California's supposedly aggressive program has left it with the same percentage of renewable power as in 1998, and Texas's seemingly impressive wind turbine investments produce only two percent of its electricity. The public may envision solar collectors but wind accounts for almost all of the growth in renewable power, and it largely survives on favorable tax treatment. Wind's intermittency reduces its efficacy in carbon control because it requires extra conventional generation reserves. Computer-generated predictions about a national RPS are generally unreliable, but they show that with or without one the great majority of generation investments for the next several decades will be fossil-fueled. Even without the technological and environmental shortcomings of renewables, the case for a national RPS is economically flawed. Emissions policies are moving toward efficient market-based trading systems and more rational setting of standards. A national RPS clashes with principles of efficient environmental policy because it is a technological requirement that applies to a single industry. Arguments that a national RPS will create jobs, mitigate energy price risks, improve national security and make the United Sates more competitive internationally are in the main restatements of elementary economic fallacies. It is hard to imagine a program that delivers as little in theory as a national RPS, and the experiences of the states indicate that it delivers equally little in practice