• Energy Research

Purpose of Review: This paper focuses on the current possibilities for energy storage systems (ESS) to participate in different power system services. ESS can provide multiple services such as spinning reserve, deferral upgrades, and energy management. However, this versatility of ESS poses a challenge for regulators in designing markets where ESS have prominent roles. We assess recent regulatory proposals in the US and the EU in order to understand their implications for ESS. / Recent Findings: These proposals attempt to improve the current rules for efficient ESS deployment. Nevertheless, they have different approaches to the same problem. We discuss these differences in an attempt to shed light on the regulatory debate about ESS ownership and market design. / Summary: The successful integration of ESS will depend on proper incentives to provide multiple services without hampering the current market structure. New asset definitions could help to define the roles of ESS as either a generation or a transmission asset.

AbstractProsumers adopt distributed energy resources (DER) to cover part of their own consumption and to sell surplus energy. Although individual prosumers are too dispersed to exert operational market power, they may collectively hold a strategic advantage over conventional generation in selecting DER capacity via aggregators. We devise a bilevel model to examine DER capacity sizing by a collective prosumer as a Stackelberg leader in an electricity industry where conventional generation may exert market power in operations. At the upper level, the prosumer chooses DER capacity in anticipation of lower-level operations by conventional generation and DER output. We demonstrate that exertion of market power in operations by conventional generation and the marginal cost of conventional generation affect DER investment by the prosumer in a nonmonotonic manner. Intuitively, in an industry where conventional generation exerts market power in operations similar to a monopoly (MO), the prosumer invests in more DER capacity than under perfectly competitive operations (PC) to take advantage of a high market-clearing price. However, if the marginal cost of conventional generation is high enough, then this intuitive result is reversed as the prosumer adopts more DER capacity under PC than under MO. This is because the high marginal cost of conventional generation prevents the market-clearing price from decreasing, thereby allowing for higher prosumer revenues. Moreover, competition relieves the chokehold on consumption under MO, which further incentivises the prosumer to expand DER capacity to capture market share. We prove the existence of a critical threshold for the marginal cost of conventional generation that leads to this counterintuitive result. Finally, we propose a countervailing regulatory mechanism that yields welfare-enhancing DER investment even in deregulated electricity industries.

Abstract Concerns about climate change have spurred governments to reduce carbon emissions by supporting adoption of renewable energy (RE) technologies. Due to the intermittent and location-specific nature of RE technologies, energy storage has become important because it could be used to smooth out temporal disparities in residual demand. Thus, carbon policy has made storage-enabled RE generation more critical to the power sector, and this enhanced position could be exploited by firms to exert market power. Using an equilibrium model, we examine the implications of policy interventions and technological change on the marginal value of energy storage in a power market with RE and thermal generation. In particular, we specify the market conditions under which RE producers with storage strategically shift deployment of their resource to the off-peak period and outline its implications for the marginal value of RE storage. Moreover, we find that even price-taking RE producers may actually increase off-peak RE production as storage efficiency increases. Consequently, the RE producer's profit decreases with storage efficiency, which conflicts with the social objective of improving storage efficiency. These private and social incentives can be better aligned via a carbon tax, however. Hence, our results may inform the regulatory process governing market design of a power sector with increasing capacities of RE generation and storage.

Abstract Several interconnected power systems worldwide have largely thermal and hydro production along with CO2 cap-and-trade (C&T) systems and variable renewable energy sources (VRES). C&T policies increase VRES generation, and socially optimal storage deployment could integrate VRES output. However, hydro reservoirs may be used strategically due to market power. We investigate these distortions and assess measures for their mitigation via a bottom-up equilibrium model of New York and Quebec. In particular, we find evidence that hydro producers shift water between seasons to manipulate electricity prices even under a net-hydro production constraint. Alternative regulation covering net imports as well as net-hydro production limits such temporal arbitrage but enables firms with both thermal generation and pumped-hydro storage to exercise spatial arbitrage. We demonstrate that these distortions will be exacerbated under more stringent C&T policies because price-taking thermal producers are less able to respond to price signals.

Despite the proven benefits of combined heat and power (CHP) and recently introduced subsidies to support it, CHP adoption has not met its targets. One of the possible reasons for this is risk from uncertain electricity and gas prices. To gain insights into the risk management of a CHP unit, we develop a multi-stage stochastic mean-risk optimisation model for the medium-term management of a distributed generation system with a gas-fired microturbine with heat recovery and a boiler. The model adopts the perspective of a large consumer that procures gas (for on-site generation) and electricity (for consumption) on the spot and futures markets. The consumer's risk aversion is incorporated into the model through the conditional value-at-risk (CVaR) measure. We show that CHP not only decreases the consumer's expected cost and risk exposure by 10% each but also improves expected energy efficiency by 4 percentage points and decreases expected CO2 emissions by 16%. The risk exposure can be further mitigated through the use of financial contracts.

The deployment of small (<1-2 MW) clusters of generators, heat and electrical storage, efficiency investments, and combined heat and power (CHP) applications (particularly involving heat activated cooling) in commercial buildings promises significant benefits but poses many technical and financial challenges, both in system choice and its operation; if successful, such systems may be precursors to widespread microgrid deployment. The presented optimization approach to choosing such systems and their operating schedules uses Berkeley Lab's Distributed Energy Resources Customer Adoption Model [DER-CAM], extended to incorporate electrical storage options. DER-CAM chooses annual energy bill minimizing systems in a fully technology-neutral manner. An illustrative example for a San Francisco hotel is reported. The chosen system includes two engines and an absorption chiller, providing an estimated 11% cost savings and 10% carbon emission reductions, under idealized circumstances.

09.01.13 KB. Ok to add accepted version to Spiral. Elsevier says ok while mandate is not enforced.

Although variable renewable energy (VRE) technologies with zero marginal costs decrease electricity prices, the literature is inconclusive about how the resulting shift in the supply curves impacts price volatility. Because the flexibility to respond to high peak and low off-peak prices is crucial for demand-response applications and may compensate for the losses of conventional generators caused by lower average prices, there is a need to understand how the penetration of VRE affects volatility. In this paper, we build distributed lag models with Danish and German data to estimate the impact of VRE generation on electricity price volatility. We find that in Denmark wind power decreases the daily volatility of prices by flattening the hourly price profile, but in Germany it increases the volatility because it has a stronger impact on off-peak prices. Our analysis suggests that access to flexible generation capacity and wind power generation patterns contribute to these differing impacts. Meanwhile, solar power decreases price volatility in Germany. By contrast, the weekly volatility of prices increases in both areas due to the intermittency of VRE. Thus, policy measures for facilitating the integration of VRE should be tailored to such region-specific patterns.