Bidding Areas Research Articles

Performance of the autoregressive integrated moving average model with exogenous variables statistical model on the intraday market for the Denmark-West bidding area

This article aims to investigate whether a statistical model known as Autoregressive Integrated Moving Average with Explanatory Variables can aid better predictability of volume-weighted average electricity prices compared to a commonly used forecasting method. This analysis was conducted for a specific bidding area, the Denmark-West bidding area (DK1). Autoregressive integrated moving average model with exogenous variable's performance was tested on the DK1 intraday market over a two-year period starting from 1 January 2019 until 31 December 2020. An explanatory variable used to support better the accuracy of the forecast is the day-ahead price for a corresponding intraday delivery hour. To ensure the validity of the paper, a well-known forecasting methodology was applied, and the results of the analysis show superior performance over the benchmark forecasting method. The autoregressive integrated moving average model with exogenous variables model developed was found to significantly outperform other commonly used forecasting methods, with an average mean absolute percentage error of 1.5%. The model was able to accurately predict intraday volume-weighted average prices up to 24 h in advance, using only publicly available data on day-ahead prices and historical intraday prices. Energy traders and other market players may find the developed autoregressive integrated moving average model with exogenous variables model to be a useful resource when looking to make more informed decisions in the intraday market.

Limiting imbalance settlement costs from variable renewable energy sources in the Nordics: Internal balancing vs. balancing market participation

Due to the market gate closures in the Nordic energy markets, producers with variable renewable energy (VRE) assets, e.g., PV and wind power plants, must forecast their production prior to delivery, leaving room for significant forecast errors. These forecast errors can lead to imbalances between the contractual market agreements and physical delivery, which have to be financially accounted for through the imbalance settlement. The increasing shares of VREs in the Nordic energy mix and the increasing variability in the price of regulating the imbalances, can lead to potential large revenue losses for the producers.This study investigates how different producer balancing strategies can limit the uncertainty and potential revenue losses in the imbalance settlement. The study focuses on available balancing measures the producers are able to use in the period starting from the last energy market gate closure, i.e., the manual Frequency Restoration Reserve (mFRR, tertiary reserves) balancing market, and throughout the subsequent settlement period. During this settlement period, producers have the option within the Nordic imbalance settlement framework to prevent VRE imbalances by performing internal balancing, i.e., ramping up or down their dispatchable assets which are located in the same bidding area as the VRE assets. However, this study shows both theoretically and quantitatively that such internal balancing is not economically beneficial compared to offering this regulating energy to the mFRR market.

Calm before the storm: Market prices in a power market with an increasing share of wind power

Western Denmark is a separate bidding area in the North-Western European power market, Nord Pool. Wind power now exceeds 50% of production annually in Western Denmark. Hourly market data from 1999 onwards are publicly available from the Danish TSO. In this paper, we analyse these data for 2009–2021. Until the energy crisis began in 2021, the Nordic power market has shown relatively stable prices. While extreme events are moderately increasing, the value factor of wind is stable. Thus, the current infrastructure – flexible power plants, interconnectors and electrification of district heating – and market organisation can manage the amount of wind power installed. In other words: 2009–2021 show a well-functioning market economy of dispatch, operating on top of a planned economy of investment.

The value of forecasts for PV power plants operating in the past, present and future Scandinavian energy markets

When participating in the Scandinavian wholesale energy markets with intermittent PV power, imbalances between market-committed and actual energy generation need to be economically accounted for in the imbalance settlement. The market-committed energy is based on forecasts issued at specific timestamps defined by the market. The economic value of such forecasts can be quantified for the past, present and future energy market regulations by comparing the achieved income using perfect forecasts to the income with imperfect forecasts. Differences between these regulations include changing from 60 min to 15 min market intervals, and from a dual-price to a single-price imbalance settlement structure.PV power production data were modelled from meteorological measurements carried out at 11 locations in each of the Nord Pool bidding areas. Forecasts generated from a smart persistence model and a more sophisticated numerical weather prediction (NWP) model were compared for these locations, and the value of these forecasts was estimated from historical market data for each of the 11 bidding areas. The results show that the estimated income, and income losses, are dependent on the electricity mix of the bidding areas. In addition, the transition from the dual-price to the single-price imbalance settlement structure reduces the value of providing accurate forecasts. Moreover, the added incentive to provide accurate forecasts when settling the markets and imbalances on 15 min instead of 60 min intervals is negligible with the single-price imbalance settlement. Finally, the results show that intraday trading is generally beneficial for PV power plants in Scandinavia.

Uniform purchasing price approach for Vietnam wholesale electricity market: modeling and discussing

In Vietnam, the reform of the electricity sector is an urgent need, unbundled and striking to begin a Competitive Electricity Market. The Vietnam electricity day-ahead market model is implemented based on the gross pool model with specific market rules and network constraints. Today, the Vietnam electricity market is operating at the Vietnam Wholesale Electricity Market step but is not yet completed. Due to the long shape of Vietnam territory, an implicit cross-compensation mechanism is applied to create a balance between customers leading to an obstruction to allowing multi-buyers in the electricity market. Therefore, the main aim of this paper is based on the official documents to propose the current mathematical model of the Vietnam electricity day-ahead market using a Mixed Integer Linear Problem, called the Single Buyer Day-Ahead Market model. Then, the Multi Buyer Day-Ahead Market model is implemented to allow multi-buyers to trade in the market. The idea of purchasing uniform prices for multi-buyers using in Italy could be also introduced in the Integrated European Electricity Market in case of large price variations between countries as a mechanism to uniformize the price of energy in Europe for consumers. In this paper, purchasing uniform prices is proposed to provide an explicit cross-compensation mechanism for Vietnam. Eventually, the proposed models are evaluated with four scenarios in two years representing typical days in Vietnam. The results confirm that, on one hand, the proposed market-clearing models can be applied in a real application for any expansion of the market, i.e. the number of suppliers, demands, and bidding areas; on the other hand, the purchasing uniform prices provide an explicit cross-compensation between bidding areas helping to enhance the fairness and the transparency of the market.

Aberdeen, City of Culture?

Aberdeen, City of Culture?

Exploring wind power prognosis data on Nord Pool: the case of Sweden and Denmark

A good understanding of forecast errors is imperative for greater penetration of wind power, as it can facilitate planning and operation tasks. Oftentimes, public data is used for system studies without questioning or verifying its origin. In this study, the authors propose a methodology to verify public data with the example of wind power prognosis published by Nord Pool. They focus on Swedish data and identify a significant bias that increases over the forecast horizon. In order to explore the origin of this bias, they first compare against Danish forecast and then describe the underlying structure behind the submission processes of this data. Based on the balance settlement structure, they reveal that Swedish ‘wind power prognoses’ on Nord Pool are in fact rather wind production plans than technical forecasts. They conclude with the recommendation for improved communication and transparency with respect to the terminology of public data on Nord Pool. They stress the importance for the research community to check publicly available input data before further use. Furthermore, the root-mean-square error and the spatio-temporal correlation between the errors in the bidding areas at different horizons are presented. Even with this compromised data, a stronger correlation is identified in neighbouring areas.

Forward risk premia in long-term transmission rights: The case of electricity price area differentials (EPAD) in the Nordic electricity market

Hedging behaviour among players in derivatives markets have long been explained by forward risk premia. We provide new empirical evidence from the Nordic electricity market and explore the forward risk premia dynamics on power derivative contracts called electricity price area differentials (EPAD). This contract is critical for the market, but its efficiency has been questioned. The study investigates the significance, direction, and magnitude of forward risk premia in individual bidding areas and contract maturities during the period 2001–2013. We test the hypothesis of a negative relationship between forward risk premia and time-to-maturity, for which we find only partial support.

Hedging local volume risk using forward markets: Nordic case

With focus on the Nordic electricity market, this paper develops hedging strategies for an electricity distributor who manages price and volume risk from fixed price agreements on stochastic electricity load. Whereas the distributor trades in the spot market at area prices, the financial contracts used for hedging are settled against the system price. Area and system prices are correlated with electricity load, as are price differences. In practice, however, this is often disregarded. Here, we develop a joint model for the area price, the system price and the load, accounting for correlations, and we suggest various strategies for hedging in the presence of local volume risk. We benchmark against a strategy that ignores correlation and hedges at expected load, as is common practice in the industry. Using data from 2013 and 2014 for two Danish bidding areas, we show that our best hedging strategy reduces gross loss by 5.8% and 13.6% and increases gross profit by 3.8% and 9.5%, respectively. Although this is partly due to the inclusion of correlation, we show that performance improvement is mainly driven by the choice of risk measure.

Acquisition Procedure for Petroleum and Natural Gas (PNG) Rights in Alberta, Canada

Around 81% of Petroleum and Natural Gas rights (PNG rights) could be leased for development through public bidding process in Alberta, Canada and huge capital is not necessary after bidding because there are no mandatory exploration or drilling during leasing period. Based on 2016 bidding results, total bidding amount, total bidding area and average bidding price per area have been dropped 77~96% compared to those of 2011 because of the tight budget of oil and gas companies for acquiring or maintaining PNG Rights. In this study, the process and technical evaluation to acquire high potential but under-valued PNG Rights with low oil price environment was presented. Also, the developed PNG Rights projects and guideline for project development was described. Finally, two PNG Right projects located in the Carrot Creek (Cardium formation) and the Crossfield area (Cardium, Viking formation) in Alberta were introduced to demonstrate the procedure for PNG Rights acquisition.

On Long-Term Transmission Rights in the Nordic Electricity Markets

In vein with the new energy market rules drafted in the EU this paper presents and discusses two contract types for hedging the risks connected to long-term transmission rights, the financial transmission right (FTR) and the electricity price area differentials (EPAD) that are used in the Nordic electricity markets. The possibility to replicate the FTR contracts with a combination of EPAD contracts is presented and discussed. Based on historical evidence and empirical analysis of ten Nordic interconnectors and twenty bidding areas, we investigate the pricing accuracy of the replicated FTR contracts by quantifying ex-post forward risk premia. The results show that the majority of the studied FTR contain a negative risk premium, especially the monthly and the quarterly contracts. Reverse flow (unnatural) pricing was identified for two interconnectors. From a theoretical policy point of view the results imply that it may be possible to continue with the EPAD-based system by using EPAD Combos in the Nordic countries, even if FTR contracts would prevail elsewhere in the EU. In practice the pricing of bi-directional EPAD contracts is more complex and may not always be very efficient. The efficiency of the EPAD market structure should be discussed from various points of view before accepting their status quo as a replacement for FTRs in the Nordic electricity markets.

Two price zones for the German electricity market — Market implications and distributional effects

We discuss the implications of two price zones (i.e., one northern and one southern bidding area) on the German electricity market. In the northern zone, continuous increases in capacity with low variable costs cause large regional supply surpluses in the market dispatch, while in the southern zone conventional capacity decreases. As the spatial imbalance of supply and load is increasing, the current single bidding area more often results in technically infeasible market results, requiring curative congestion management measures.There is an ongoing discussion about the potential effects of introducing bidding zones in Germany. This paper applies an electricity sector model with network representation to analyze the system implications and the distributional effects of two bidding zones in the German electricity system in 2012 and 2015. Results show a modest decrease in cross-zonal re-dispatch levels, particularly in 2015. However, overall network congestion and re-dispatch levels increase in 2015 and also remain on a high level for two bidding zones. Results are very sensitive to more than two bidding zones and additional line investments, illustrating the challenge to define stable price zones in a dynamic setting. With two bidding areas, prices in the model results increase in the southern zone and decrease in the northern zone. The average price deviation grows from 0.4EUR/MWh in 2012 to 1.7EUR/MWh in 2015, with absolute values being significantly higher in hours when price differences occur. Stakeholders within zones are exposed to the price deviations to a different extent. Distributional effects are surprisingly small compared to the wholesale price or different network charges.

It is windy in Denmark: Does market integration suffer?

Some benefits of spot electricity markets integration include the optimization of renewable power, increasing transmission grid security and the decreasing need for internal generation reserves. The high penetration of wind power is known to have a clear influence on price convergence between electricity markets joined by market splitting. However, in multiple interconnected markets, cross-border flows can also play a role in the market splitting behaviour. Denmark, with a high penetration of wind power, is clearly the ideal case study. This paper aims to assess the influence of high penetration of wind power on the market splitting behaviour between West and East Denmark, taking into account cross-border electricity flows. This is modelled through logit and non-parametric models, estimating the probability of market splitting occurrence between both Danish bidding areas. Market splitting probability is found to be sensitive to wind power, nevertheless with distinct behaviour according to interconnection congestion configuration. The highest availability of wind power in West Denmark, which can reach a generation share of 1.5 times the demand, requires strong cross-border interconnections to allow the export of the excess generation. Policies governing a joint assessment of the requirements for additional interconnection and wind power expansion plans, should be developed.

Market splitting in Germany – New evidence from a three-stage numerical model of Europe

With the sharp increase in redispatch measures seen during recent years, the importance of an efficient congestion management has increased, particularly in Germany. As the current market design, with a single bidding area, ignores the physical constraints of the transmission grid, there is an ongoing discussion about introducing price zones. Against this background, we develop a three-stage approach to model redispatch and market splitting for Germany while considering interactions with interconnected countries. We identify an increasing spatial imbalance between generation and load and delays in grid extension as being the main drivers for the increase of modeled redispatch volumes from 2012 to 2020. We show that market splitting reduces imminent congestion although results are sensitive to the zonal delimitation and corresponding net transfer capacities. The overall welfare effect is negligible, but price differences between the bidding areas investigated, i.e. one Northern and Southern price zone, result in considerable distributional effects. While consumers in Northern Germany would benefit – producer rents and in particular the value of wind energy would decrease – the opposite is true for Southern Germany. We conclude that market splitting constitutes a solution to reduce redispatch measures as long as transmission grid expansion is further delayed.

A Nodal Pricing Model for the Nordic Electricity Market

In the Nordic day-ahead electricity market zonal pricing or market splitting is used for relieving congestion between a predetermined set of bidding areas. This congestion management method represents an aggregation of individual connection points into bidding areas, and flows from the actual electricity network are only partly represented in the market clearing. Because of several strained situations in the power system during 2009 and 2010, changes in the congestion management method have been considered by the Norwegian regulator. In this paper we discuss nodal pricing in the Nordic power market, and compare it to optimal and simplified zonal pricing, the latter being used in today’s market. A model of the Nordic electricity market is presented together with a discussion of the calibration of actual market data for four hourly case studies with different load and import/exports to the Nordic area. The market clearing optimization model incorporates thermal and security flow constraints. We analyze the effects on prices and grid constraints and quantify the benefits and inefficiencies of the different methods. We find that the price changes with nodal pricing may not be dramatic, although in cases where intra-zonal constraints are badly represented by the aggregate transfer capacities in the simplified zonal model the nodal prices may be considerably higher on average and vary more than the simplified zonal prices. On the other hand nodal prices may vary less than the simplified zonal prices if aggregate transfer capacities are set too tightly. Allowing for more prices in the Nordic power market would make dealing with capacity limits easier and more transparent.

CMS finalizes durable medical equipment fee schedule

CMS announced an adjusted fee schedule for durable medical equipment (DME) sold outside of competitive bidding areas (CBA) in its End-Stage Renal Disease and Durable Medical Equipment Final Rule for 2015. CMS announced an adjusted fee schedule for durable medical equipment (DME) sold outside of competitive bidding areas (CBA) in its End-Stage Renal Disease and Durable Medical Equipment Final Rule for 2015. According to Jillanne Schulte, JD, APhA Director of Regulatory Affairs, the new fee schedule mostly affects rural pharmacists who are not in a CBA. “Overall, it doesn’t really change the major parameters of the DME program,” she said. Essentially, there will be a different methodology for determining what the prices are going to be for areas where there isn’t a competitive bidding program in place, like rural areas. The adjustment, which goes into effect January 1, 2016, is based on a national ceiling of 110% of the average of regional competitive bidding prices and a floor of 90% of those prices. In most cases, even with the higher 110% upper limit, this will result in cuts to reimbursement to rural pharmacies for these supplies.“It’s another option for patients in rural areas, but it will almost certainly decrease payments to rural pharmacists.” “It’s another option for patients who live in rural areas who don’t have the competitive bidding programs, but it will almost certainly decrease payments to rural pharmacists who have not previously been as heavily impacted by the CBP,” said Schulte. Also noteworthy in the final rule are changes to the quality incentive program (QIP) going into effect for endstage renal disease programs. Providers will be paid based on different quality reporting measures that deal with dialysis adequacy, patient care experience, and readmissions, among other things. Dialysis facilities that fail to meet QIP metrics will face reduced payments. However, the program won’t be fully implemented until 2017 and 2018. “They want to give people time to adjust,” said Schulte. She said it’s still unclear if pharmacists will be on the hook to report under the new QIP requirements.

Efficiency of Contracts for Differences (CfDs) in the Nordic Electricity Market

This paper presents new and updated evidence on the efficiency of the EPAD contracts in the Nordic financial electricity market, based on a long sample of 14 years, from 2000 to 2013 inclusive. The Electricity Price Area Differentials (EPADs) are used to hedge against price differences between a bidding area and the Nordic system price. The aim of this paper is twofold. First, we estimate the magnitude and significance of ex-post risk premia in EPAD products (season, month, quarter, year) with delivery in 2000-2013. Further, we estimate the relationship between spot and futures prices by vector autoregression (VAR) model. By observing Granger causalities, adjustments to price shocks, and decomposing variance, we aim to shed light on the EPADs’ efficiency. Second, we elaborate on some determinants of risk premia and test the roles of time-to-maturity and open interest on risk premia. We additionally consider, for the Nordic system an essential energy source, the role of water availability in the hydro reservoirs on explaining local area price spreads. We support and reject some of the earlier findings about the limited efficiency of the EPADs and bring new empirical evidence on the drivers behind the regional price dynamics.

European Electricity Market Integration With Mixed Market Designs—Part II: Solution Algorithm and Case Studies

This paper presents the solution algorithm and test results of the market-splitting approach, proposed in the first part of this two-paper series, for the clearing of the forthcoming Internal Electricity Market. The market-splitting approach is implemented in a Europe-wide level, indicatively defining three power pools and 22 power exchanges, comprising 42 bidding areas in total, with each local/national market respecting the standard market regulatory framework of power pools and power exchanges (PXs). The performance and computational requirements of this implementation is presented; the model is tested in terms of problem solvability to its limits, considering a day-ahead market clearing time threshold equal to one hour. The results demonstrate that a viable solution to the clearing of the Internal Electricity Market can be attained with the current state-of-the-art of computers' processing power. Further discussion is made concerning the viability of the proposed approach and other harmonization issues that should be considered for successful market integration.

Area price and demand response in a market with 25% wind power

Denmark, east and west of the Great Belt are bidding areas with separate hourly area prices for the Nord Pool power exchange, covering four Nordic countries and parts of Germany. The share of wind power has now increased to 25% on an annual basis in western Denmark. This has a significant impact not only on the electricity wholesale prices, but also on the development of the market. Hourly market data are available from the website of Danish TSO from 1999. In this paper these data are analysed for the period 2004–2010. Electricity generators and customers may respond to hourly price variations, which can improve market efficiency, and a welfare gain is obtained. An important limitation for demand response is events of several consecutive hours with extreme values. The analysis in this paper is a summary and update of some of the issues covered by the EU RESPOND project. It shows that extreme events were few, and the current infrastructure and market organisation have been able to handle the amount of wind power installed so far. This recommends that geographical bidding area for the wholesale electricity market reflects external transmission constraints caused by wind power.

A fast market splitting matching method for the spot electric power market

AbstractA fast, innovative matching method for the spot power market, considering network constraints, has been developed. In this method, buy and sell order bids are respectively divided into the aggregated volume of several band prices. Then, the aggregated volume and the center of each band price are used to calculate an index band clearing price, which contains the real clearing price. The division and calculation process is iterated until the band price is less than the tick size of the bidding price. This method is applied to a real problem in the Japan power market, with 9 bidding areas, 10 area‐connecting lines, and 9000 orders (volume/price pairs). Numerical simulation results show that the new method is ten times faster than conventional linear programming, demonstrating the effectiveness of this method. © 2008 Wiley Periodicals, Inc. Electr Eng Jpn, 165(4): 21–29, 2008; Published online in Wiley InterScience (www.interscience.wiley.com). DOI 10.1002/eej.20694