Historical Electricity Prices Research Articles

Analysis of Variability in Electric Power Consumption: A Methodology for Setting Time-Differentiated Tariffs

The increasing concern for environmental conservation has spurred government initiatives towards energy efficiency. One of the key research areas in this regard is demand response, particularly focusing on differential pricing initiatives such as Time-of-Use (ToU). Differential tariffs are typically designed based on mathematical or statistical models analyzing historical electricity price and consumption data. This study proposes a methodology for identifying time intervals suitable for implementing ToU energy tariffs, achieved by analyzing electric power demand variability to estimate demand flexibility potential. The methodology transforms consumption data into variation via the coefficient of variation and, then, employs k-means data analysis techniques and the a priori algorithm. Tested with real data from smart meters in the Colombian electrical system, the methodology successfully identified time intervals with potential for establishing ToU tariffs. Additionally, no direct relationship was found between external variables such as socioeconomic level, user type, climate, and consumption variability. Finally, it was observed that user behavior concerning consumption variability could be categorized into two types of days: weekdays and non-working days.

The value of wake steering wind farm flow control in US energy markets

Abstract. Wind farm flow control represents a category of control strategies for achieving wind-plant-level objectives, such as increasing wind plant power production and/or reducing structural loads, by mitigating the impact of wake interactions between wind turbines. Wake steering is a wind farm flow control technology in which specific turbines are misaligned with the wind to deflect their wakes away from downstream turbines, thus increasing overall wind plant power production. In addition to promising results from simulation studies, wake steering has been shown to successfully increase energy production through several recent field trials. However, to better understand the benefits of wind farm flow control strategies such as wake steering, the value of the additional energy to the electrical grid should be evaluated – for example, by considering the price of electricity when the additional energy is produced. In this study, we investigate the potential for wake steering to increase the value of wind plant energy production by combining model predictions of power gains using the FLOw Redirection and Induction in Steady State (FLORIS) engineering wind farm flow control tool with historical electricity price data for 15 existing US wind plants in four different electricity market regions. Specifically, for each wind plant, we use FLORIS to estimate power gains from wake steering for a time series of hourly wind speeds and wind directions spanning the years 2018–2020, obtained from the ERA5 reanalysis dataset. The modeled power gains are then correlated with hourly electricity prices for the nearest transmission node. Through this process we find that wake steering increases annual energy production (AEP) between 0.4 % and 1.7 %, depending on the wind plant, with average increases in potential annual revenue (i.e., annual revenue of production, ARP) 4 % higher than the AEP gains. For most wind plants, ARP gain was found to exceed AEP gain. But the ratio between ARP gain and AEP gain is greater for wind plants in regions with high wind penetration because electricity prices tend to be relatively higher during periods with below-rated wind plant power production, when wake losses occur and wake steering is active; for wind plants in the Southwest Power Pool – the region with the highest wind penetration analyzed (31 %) – the increase in ARP from wake steering is 11 % higher than the AEP gain. Consequently, we expect the value of wake steering, and other types of wind farm flow control, to increase as wind penetration continues to grow.

A TWO STAGE MODEL FOR DAY-AHEAD ELECTRICITY PRICE FORECASTING: INTEGRATING EMPIRICAL MODE DECOMPOSITION AND CATBOOST ALGORITHM

Electricity price forecasting is crucial for the secure and cost-effective operation of electrical power systems. However, the uncertain and volatile nature of electricity prices makes the electricity price forecasting process more challenging. In this study, a two-stage forecasting model was proposed in order to accurately predict day-ahead electricity prices. Historical natural gas prices, electricity load forecasts, and historical electricity price values were used as the forecasting model inputs. The historical electricity and natural gas price data were decomposed in the first stage to extract more deep features. The empirical mode decomposition (EMD) algorithm was employed for the efficient decomposition process. In the second stage, the categorical boosting (CatBoost) algorithm was proposed to forecast day-ahead electricity prices accurately. To validate the effectiveness of the proposed forecasting model, a case study was conducted using the dataset from the Turkish electricity market. The proposed model results were compared with benchmark machine learning algorithms. The results of this study indicated that the proposed model outperformed the benchmark models with the lowest root mean squared error (RMSE), mean absolute error (MAE), mean absolute percentage error (MAPE), and correlation coefficient (R) values of 8.3282%, 5.2210%, 6.9675%, and 86.2256%, respectively.

Data-driven Two-step Day-ahead Electricity Price Forecasting Considering Price Spikes

In the electricity market environment, electricity price forecasting plays an essential role in the decision-making process of a power generation company, especially in developing the optimal bidding strategy for maximizing revenues. Hence, it is necessary for a power generation company to develop an accurate electricity price forecasting algorithm. Given this background, this paper proposes a two-step day-ahead electricity price forecasting algorithm based on the weighted <tex xmlns:mml="http://www.w3.org/1998/Math/MathML" xmlns:xlink="http://www.w3.org/1999/xlink">$K$</tex> -nearest neighborhood (WKNN) method and the Gaussian process regression (GPR) approach. In the first step, several predictors, i.e., operation indicators, are presented and the WKNN method is employed to detect the day-ahead price spike based on these indicators. In the second step, the outputs of the first step are regarded as a new predictor, and it is utilized together with the operation indicators to accurately forecast the electricity price based on the GPR approach. The proposed algorithm is verified by actual market data in Pennsylvania-New Jersey-Maryland Interconnection (PJM), and comparisons between this algorithm and existing ones are also made to demonstrate the effectiveness of the proposed algorithm. Simulation results show that the proposed algorithm can attain accurate price forecasting results even with several price spikes in historical electricity price data.

Hourly electricity price forecast for short-and long-term, using deep neural networks

Abstract Despite the practical importance of accurate long-term electricity price forecast with high resolution - and the significant need for that - only small percentage of the tremendous papers on energy price forecast attempted to target this topic. Its reason can be the high volatility of electricity prices and the hidden – and often unpredictable – relations with its influencing factors. In our research, we performed different experiments to predicate hourly Hungarian electricity prices using deep neural networks, for short-term and long-term, too. During this work, investigations were made to compare the results of different network structures and to determine the effect of some environmental factors (meteorologic data and date/time - beside the historical electricity prices). Our results were promising, mostly for short-term forecasts - especially by using a deep neural network with one ConvLSTM encoder.

An analysis of the competitiveness of hydrogen storage and Li-ion batteries based on price arbitrage in the day-ahead market

Acceleration of the hydrogen economy is being observed on a global scale. It is considered to be a potential solution to the problems with high-carbon energy, industry, and transport systems. The potential of production, cost-competitiveness, and opportunities are currently being investigated to provide insights to policymakers, researchers, and industry. In this context, this study makes a quantitative assessment of the competitiveness of hydrogen storage compared to Li-ion batteries based on price arbitrage in the day-ahead market. Two scenarios that form the boundaries of rational decision-making regarding the charging and discharging of energy storage are considered. The first one assumes the charging and discharging of energy storage facilities over the same hours throughout the entire year. The selection of these hours is based on historical electricity prices. The second scenario assumes charge and discharge during historical daily minimum and maximum prices. The results show that NPV is below zero for both technologies when current values of investment expenditure are assumed. The outcomes of sensitivity analysis indicate that only a substantial reduction of investment expenditure could improve the financial results of the Li-ion batteries (NPV>0). The investigation also shows that even simplified charge and discharge over the same hours allows one to achieve 47% (hydrogen) and 70% (Li-ion batteries) of the maximum operating profit when the perfect foresight of prices is applied. In each case, NPV for Li-ion technology is significantly higher than for hydrogen; for example, for a 1 MWh and 1 MWout storage system, NPV is EUR -4.85 million in the case of hydrogen and with Li-ion NPV is EUR -0.23 million. Consequently, the application of expensive decision support systems in small systems may be unprofitable. The increase in profits may not cover the cost of developing and introducing such a system.

Hourly electricity price forecasting with NARMAX

Electricity price prediction through statistical and machine learning techniques captures market trends and would be a useful tool for energy traders to observe price fluctuations and increase their profits over time. A Nonlinear AutoRegressive Moving Average model with eXogenous inputs (NARMAX) identifies key energy-related factors that influence hourly electricity price through prediction modelling. We propose to use a transparent NARMAX model and analyse Irish Integrated Single Electricity Market (ISEM) data from May 2019 until April 2020 to determine which external factors have a significant impact on the electricity pricing. The experimental results indicate that historical electricity price, demand, and system generation are the most significant factors with historical electricity price being the most weighted factor and the largest Error Reduction Ratio (ERR). A NARMAX model generated using correlated lags was also considered to identify key energy-related lag factors that influence the electricity price. For justification, the significant lag factors are included as inputs in a Seasonal AutoRegressive Integrated Moving Average model with eXogenous input (SARIMAX) to determine if model performance improves with refinement. To conclude, using the NARMAX methodology with energy-related input factors helps to determine the significant factors and results in accurate predictions of electricity price.

Optimal Energy Management of Hydrogen Energy Facility Using Integrated Battery Energy Storage and Solar Photovoltaic Systems

The production of renewable hydrogen using water electrolysis has emerged with the increasing penetration of renewable energy sources. The energy management system (EMS) plays a key role in the production of renewable hydrogen by controlling electrolyzer’s operating point to achieve operational and economical benefits. In this regard, this article introduces the optimal scheduling for an EMS model for a hydrogen production system integrated with a photovoltaic (PV) system and a battery energy storage system (BESS) to satisfy electricity and hydrogen demands of an industrial hydrogen facility. The proposed EMS model aims to minimize the cost of hydrogen (CoH) production by minimizing the system net costs of industrial hydrogen facility while maintaining a reliable system operation. Furthermore, the proposed EMS model enables the application of seasonal hydrogen storage by incorporating the Z-score statistical measure of historical electricity prices, which follows seasonal electricity price trends. This allows the storage of hydrogen during periods of relatively low electricity prices. To demonstrate the validity of this model, it is tested for both intraseasonal and seasonal storage. Four case studies are used to prove the techno-economic benefits of the proposed EMS model. Furthermore, the impact of the electrolyzer’s capacity factor, the size of the hydrogen storage, and the PV share is investigated in terms of their techno-economic benefits to the system.

Improving the economics of fossil-free steelmaking via co-production of methanol

Steelmaking is responsible for 7% of the global net emissions of carbon dioxide and heavily reducing emissions from currently dominating steelmaking processes is difficult and costly. Recently, new steelmaking processes based on the reduction of iron ore with hydrogen (H2) produced via water electrolysis have been suggested. If the electricity input to such processes is fossil-free, near-zero carbon dioxide emissions steelmaking is achievable. However, the high electricity demand of electrolysis is a significant implementation barrier. A H2 storage may alleviate this via allowing a larger share of H2 to be produced at low electricity prices. However, accurately forecasting electricity market dynamics is challenging. This increases the risk of investment in a H2 storage. Here we evaluate a novel methanol-based H2 storage concept for H2-based steelmaking that also allows for the co-production of methanol. During electricity price peaks, the methanol can be reformed to produce H2 for the steelmaking process. During prolonged periods of low electricity prices, excess methanol can be produced and sold off, thus improving the prospects of storage profitability. We use historical electricity prices and a process model to evaluate methanol and fossil-free steel co-production schemes. Methanol co-production is found to have the potential to improve the economics of H2 supply to a fossil-free steelmaking process by up to an average of 0.40 €/kg H2 across considered scenarios, equivalent to a 25.0% reduction in H2 production electricity costs.

Abnormal Detection to Big Data Using Deep Neural Networks

It is difficult to detect the anomalies in big data using traditional methods due to big data has the characteristics of mass and disorder. For the common methods, they divide big data into several small samples, then analyze these divided small samples. However, this manner increases the complexity of segmentation algorithms, moreover, it is difficult to control the risk of data segmentation. To address this, here proposes a neural network approch based on Vapnik risk model. Firstly, the sample data is randomly divided into small data blocks. Then, a neural network learns these divided small sample data blocks. To reduce the risks in the process of data segmentation, the Vapnik risk model is used to supervise data segmentation. Finally, the proposed method is verify on the historical electricity price data of Mountain View, California. The results show that our method is effectiveness.

Evolution of Fundamental Price Determination within Electricity Market Simulations

Electricity prices are the key instrument for coordinating electricity markets. For long-term market analyses, price determination based on fundamental unit commitment simulations is required. Within the European wholesale market, electricity prices result from a market clearing, which finds a welfare-optimal price–quantity tuple considering a coupling of multiple market areas with limited transmission capacity. With increasing exchange capacities in Europe, the precise modeling of the market coupling is required. Many market simulation models use multi-stage approaches with a separation of market coupling and price determination. In this paper, we analyze a new single-stage approach that combines both steps and theoretically and empirically demonstrate its precision by a backtest. For this purpose, we compare a simulated versus a historical electricity price distribution. Moreover, we explain the necessary adjustments for future regulatory developments of the European electricity market regarding flow-based market coupling and propose a concept for the application of future regulatory developments. We demonstrate further developments using a future scenario.

BRIM: An Accurate Electricity Spot Price Prediction Scheme-Based Bidirectional Recurrent Neural Network and Integrated Market

For the benefit from accurate electricity price forecasting, not only can various electricity market stakeholders make proper decisions to gain profit in a competitive environment, but also power system stability can be improved. Nevertheless, because of the high volatility and uncertainty, it is an essential challenge to accurately forecast the electricity price. Considering that recurrent neural networks (RNNs) are suitable for processing time series data, in this paper, we propose a bidirectional long short-term memory (LSTM)-based forecasting model, BRIM, which splits the state neurons of a regular RNN into two parts: the forward states (using the historical electricity price information) are designed for processing the data in positive time direction and backward states (using the future price information available at inter-connected markets) for the data in negative time direction. Moreover, due to the fact that inter-connected power exchange markets show a common trend for other neighboring markets and can provide signaling information for each other, it is sensible to incorporate and exploit the impact of the neighboring markets on forecasting accuracy of electricity price. Specifically, future electricity prices of the interconnected market are utilized both as input features for forward LSTM and backward LSTM. By testing on day-ahead electricity prices in the European Power Exchange (EPEX), the experimental results show the superiority of the proposed method BRIM in enhancing predictive accuracy in comparison with the various benchmarks, and moreover Diebold-Mariano (DM) shows that the forecast accuracy of BRIM is not equal to other forecasting models, and thus indirectly demonstrates that BRIM statistically significantly outperforms other schemes.

Modelling Electricity Price Expectations in a Day-Ahead Market: A Case of Latvia

Abstract The paper aims at modelling the electricity generator’s expectations about price development in the Latvian day-ahead electricity market. Correlation and sensitivity analysis methods are used to identify the key determinants of electricity price expectations. A neural network approach is employed to model electricity price expectations. The research results demonstrate that electricity price expectations depend on the historical electricity prices. The price a day ago is the key determinant of price expectations and the importance of the lagged prices reduces as the time backwards lengthens. Nine models of electricity price expectations are prepared for different natural seasons and types of the day. The forecast accuracy of models varies from high to low, since errors are 7.02 % to 59.23 %. The forecasting power of models for weekends is reduced; therefore, additional determinants of electricity price expectations should be considered in the models and advanced input selection algorithms should be applied in future research. Electricity price expectations affect the generator’s loss through the production decisions, which are made considering the expected (forecasted) prices. The models allow making the production decision at a sufficient level of accuracy.

Valuing year‐to‐go hydrologic forecast improvements for a peaking hydropower system in the Sierra Nevada

AbstractWe assessed the potential value of hydrologic forecasting improvements for a snow‐dominated high‐elevation hydropower system in the Sierra Nevada of California, using a hydropower optimization model. To mimic different forecasting skill levels for inflow time series, rest‐of‐year inflows from regression‐based forecasts were blended in different proportions with representative inflows from a spatially distributed hydrologic model. The statistical approach mimics the simpler, historical forecasting approach that is still widely used. Revenue was calculated using historical electricity prices, with perfect price foresight assumed. With current infrastructure and operations, perfect hydrologic forecasts increased annual hydropower revenue by $0.14 to $1.6 million, with lower values in dry years and higher values in wet years, or about $0.8 million (1.2%) on average, representing overall willingness‐to‐pay for perfect information. A second sensitivity analysis found a wider range of annual revenue gain or loss using different skill levels in snow measurement in the regression‐based forecast, mimicking expected declines in skill as the climate warms and historical snow measurements no longer represent current conditions. The value of perfect forecasts was insensitive to storage capacity for small and large reservoirs, relative to average inflow, and modestly sensitive to storage capacity with medium (current) reservoir storage. The value of forecasts was highly sensitive to powerhouse capacity, particularly for the range of capacities in the northern Sierra Nevada. The approach can be extended to multireservoir, multipurpose systems to help guide investments in forecasting.

Is it More Valuable to Store or Destroy Electricity Surpluses?

A typical strategy for dealing with commodity surpluses is to store them for future sale; in particular, this is true of electricity. However, because electricity prices can be negative, there exists another potential strategy: To buy and dispose of electricity surpluses at negative prices. It is not clear whether the storage strategy or the disposal strategy is more valuable for a merchant who trades electricity in a market. We investigate this question by modeling the problem of managing an electricity storage facility when prices can be negative: By varying the efficiency of the storage facility, our model encompasses both the case when electricity surpluses are stored and the case when they are destroyed. We establish the optimal policy structure of our model, and show that it subsumes the known optimal commodity storage policy structure when commodity prices are strictly positive. Then, using our optimal policy structure, we compare the storage and disposal strategies based on an existing electricity price model calibrated to historical electricity prices. We find that the disposal strategy is even more valuable for a merchant than the storage strategy.

Potential and Limitations for Industrial Demand Side Management

The growing share of variable renewable power such as wind and solar photovoltaic (PV) emphasize the importance of demand side management. In a couple of years consumers have to adapt their consumption more to available generated power in order to maintain grid stability and to reduce their electricity costs. In this study the potential and limitations for demand side management in about 15 different companies in Sweden has been investigated. A brief description of some of the company's production process is given, with focus on electrical consumption. Suggestions on different demand side management possibilities are presented as well as limitations. The suggestions are given for different time horizons, from load shifting between hours, to weeks and years. Potential savings achieved with demand side management have also been evaluated based on historical electricity prices from different countries.

Nonconvex model predictive control for commercial refrigeration

We consider the control of a commercial multi-zone refrigeration system, consisting of several cooling units that share a common compressor, and is used to cool multiple areas or rooms. In each time period we choose cooling capacity to each unit and a common evaporation temperature. The goal is to minimise the total energy cost, using real-time electricity prices, while obeying temperature constraints on the zones. We propose a variation on model predictive control to achieve this goal. When the right variables are used, the dynamics of the system are linear, and the constraints are convex. The cost function, however, is nonconvex due to the temperature dependence of thermodynamic efficiency. To handle this nonconvexity we propose a sequential convex optimisation method, which typically converges in fewer than 5 or so iterations. We employ a fast convex quadratic programming solver to carry out the iterations, which is more than fast enough to run in real time. We demonstrate our method on a realistic model, with a full year simulation and 15-minute time periods, using historical electricity prices and weather data, as well as random variations in thermal load. These simulations show substantial cost savings, on the order of 30%, compared to a standard thermostat-based control system. Perhaps more important, we see that the method exhibits sophisticated response to real-time variations in electricity prices. This demand response is critical to help balance real-time uncertainties in generation capacity associated with large penetration of intermittent renewable energy sources in a future smart grid.

Electricity price modeling and asset valuation: a multi-fuel structural approach

We introduce a new and highly tractable structural model for spot and derivative prices in electricity markets. Using a stochastic model of the bid stack, we translate the demand for power and the prices of generating fuels into electricity spot prices. The stack structure allows for a range of generator efficiencies per fuel type and for the possibility of future changes in the merit order of the fuels. The derived spot price process captures important stylized facts of historical electricity prices, including both spikes and the complex dependence upon its underlying supply and demand drivers. Furthermore, under mild and commonly used assumptions on the distributions of the input factors, we obtain closed-form formulae for electricity forward contracts and for spark and dark spread options. As merit order dynamics and fuel forward prices are embedded into the model, we capture a much richer and more realistic dependence structure than can be achieved by classical reduced-form models. We illustrate these advantages by comparing with Margrabe's formula and a simple cointegration model, and highlight important implications for the valuation of power plants.

Cutting the electric bill for internet-scale systems

Energy expenses are becoming an increasingly important fraction of data center operating costs. At the same time, the energy expense per unit of computation can vary significantly between two different locations. In this paper, we characterize the variation due to fluctuating electricity prices and argue that existing distributed systems should be able to exploit this variation for significant economic gains. Electricity prices exhibit both temporal and geographic variation, due to regional demand differences, transmission inefficiencies, and generation diversity. Starting with historical electricity prices, for twenty nine locations in the US, and network traffic data collected on Akamai's CDN, we use simulation to quantify the possible economic gains for a realistic workload. Our results imply that existing systems may be able to save millions of dollars a year in electricity costs, by being cognizant of locational computation cost differences.