碳市场对浙江省发电部门的影响探析

当前全国共有2000多家发电企业纳入了全国碳市场交易,研究碳市场对发电企业碳排放量与经营成本的影响,具有十分重要的意义。本文通过建立DEA-MBP模型,对浙江省发电部门技术效率、环境效率、成本效率和总成本效率进行测算,并分析不同水平碳市场交易价格产生的影子排放和影子成本,进而探析碳市场对浙江省发电部门碳排放量和生产成本的影响。     

基于委托-代理模型的绿色电力市场激励机制

根据发电企业参与绿色电力市场的成本和收益,搭建了政府和发电企业之间的“委托-代理”博弈模型,通过将博弈模型分别在自愿认购市场和配额考核市场下进行求解,研究了在不同绿色电力市场下,政府对发电企业采用的不同激励机制。     

计及动态碳排放对新能源消纳市场的价格研究

通过丰富电力市场交易方式,可有效提高新能源消纳水平。针对现有电力市场无法有效控制碳排放的特点,提出计及动态碳排放的电力市场出清方法,将火电碳排放成本动态传导到电价中,从而使部分发电权向新能源转移。同时,当发生弃能时,对弃能机组引入价格因子替换报价,进行电力市场二次出清,深度促进新能源应发尽发,以激励相容机制平衡发电权转受让方收益。采用改进的IEEE 30节点系统进行仿真验证,提出的电力市场交易机制能有效降低火电机组的碳排放并促进风光消纳,验证了该方法的有效性。     

固定电价政策与固定补贴政策

正固定电价政策即按各类可再生能源发电标准成本,直接明确规定各类可再生能源电力上网价格,电网企业必须按此价格向可再生能源发电企业支付费用。其主要特点是能保证可再生能源发电项目稳定的收益。固定补贴政策(溢价电价机制),既考虑可再生能源发电实际成本情况和价格政策需求,又与电力市场的竞价挂钩,是在电力市场价格基础上给予可再生能     

几种类型发电公司环境成本核算的分析研究

在自由的电力市场条件下，发电厂的环境成本将会被纳入发电成本，成为影响市场竞争力的重要因素。为了比较不同电源的环境成本对电价的影响程度，应用环境经济学理论分别对燃煤发电、天然气发电以及核能发电的环境成本进行了核算和比较。     

基于SQP法的电厂日前合约市场报价策略研究

在电力市场环境下,发电企业为了追求经济效益的最大化,必须在优化机组负荷分配的基础上掌握企业运行成本,并在电力市场上报出具有竞争力的上网电价。针对日前市场的特殊性,并建立了机组经济性曲线拟合的数学模型和基于序列二次规划法(SQP法)的机组负荷优化分配模型,指出了完全成本加成法的报价方法。用算例验证了一个发电企业在4个时段日前市场负荷的耗量成本。     

水电富集区燃煤机组容量补偿机制研究

随着电力市场化改革的逐步推进,水电富集区燃煤机组功能定位的转变引发的成本搁浅问题逐渐显现,亟需配置合理的容量成本回收机制。该文通过对燃煤机组容量补偿机制建设的必要性进行分析,设计了符合四川电力市场特性的燃煤机组容量补偿机制,对容量确定方式、成本核算、补偿方式等进行研究,通过重构电价体系阐述了“容量电价+电量电价”的设计原理,并探讨了新电价体系未来发展方向,可为解决四川及国内具有类似燃煤机组容量成本回收问题的省份提供参考。     

电力市场环境下梯级水电站运行管控仿真研究

针对电力市场环境下梯级水电站运行管控问题,提出基于市场出清价的市场力评估指标,并通过构建双层市场仿真与管控模型对不同管控条件下梯级水电站运行方式进行仿真研究。在下层市场竞价仿真模型中,通过迭代优化算法实现市场仿真运行;在上层市场管控设计模型中,以基数电量为决策变量实现对梯级水电站运行的管控;上下层通过市场力评估指标与基数电量形成耦合关系。最后提出耦合市场仿真运行与多核并行禁忌遗传算法(MPTGA)的求解思路对管控方案进行评价优选。实例分析表明,基于出清电价的市场力评估指标可有效评估市场中梯级水电站跨交易时段所拥有的市场力,利用双层市场仿真与管控模型获得的基数电量方案可实现市场优化管控运行。     

电力市场化对发电企业的影响分析

我国于2015年开始了新一轮电力体制改革,其核心是还原电力商品属性,在发、售电侧引入市场化竞争。新电改后我国电力市场建设已经积累了一定经验并取得了阶段性成果:市场主体范围持续扩大、交易品种日益丰富、交易方式灵活多样、市场规模逐步扩大、电价水平明显下降。但与国外较成熟的电力市场相比,我国电力市场在体系建设、交易规则、价格机制、市场规范运行等方面依然还存在各种问题。对于发电企业而言,电力市场化改革既是机遇也是挑战,但在当前供给侧改革、降低工商业用户电价的形势下,面临的冲击和挑战要更多一些。诸如交易电价降幅明显;市场电量逐步取代计划电量,发用电计划缩减,直接交易份额提高;电力年度长协集中在年前完成,而次年电煤合同价大多尚未落实,市场主体面临较大风险;短期边际成本报价模式未考虑"搁浅"成本,对存量发电企业参与竞争不利;单纯发电的经营模式正在发生改变,而涉足新的业务领域又将面临新的挑战等等。发电企业必须根据市场化改革形势及时调整经营策略,创新管理思路,提升经营管理水平。加强设备可靠性管理,为安全清洁高效生产提供根本保障;严格控制发电成本;发电侧应积极开展售电业务,组建市场营销业务体系;循序渐进地开展市场化交易,为现货市场交易等提前做准备;注重延伸产业链,向综合能源供应和服务商转型发展。     

世界主要地区煤电市场情况

美国煤电比例：42%电力市场结构：三个主要电网以及一批区域电网构成了电力批发市场。各州的电力系统政策有所不同。电价构成：在受监管州,价格由全部成本和原料成本决定,在电力重组的州,价格取市场上的最低价。煤炭供应：所需煤炭全部自给。电价对煤炭的影响：煤炭价格数十年保持稳定,与电价之间的关联性很弱。在部分电力市场重组的州,由于燃气发电装机容量的增加,电价降低,拉低了煤炭价格。     

Using renewables to hedge against future electricity industry uncertainties—An Australian case study

A generation portfolio modelling was employed to assess the expected costs, cost risk and emissions of different generation portfolios in the Australian National Electricity Market (NEM) under highly uncertain gas prices, carbon pricing policy and electricity demand. Outcomes were modelled for 396 possible generation portfolios, each with 10,000 simulations of possible fuel and carbon prices and electricity demands. In 2030, the lowest expected cost generation portfolio includes 60% renewable energy. Increasing the renewable proportion to 75% slightly increased expected cost (by $0.2/MWh), but significantly decreased the standard deviation of cost (representing the cost risk). Increasing the renewable proportion from the present 15% to 75% by 2030 is found to decrease expected wholesale electricity costs by $17/MWh. Fossil-fuel intensive portfolios have substantial cost risk associated with high uncertainty in future gas and carbon prices. Renewables can effectively mitigate cost risk associated with gas and carbon price uncertainty. This is found to be robust to a wide range of carbon pricing assumptions. This modelling suggests that policy mechanisms to promote an increase in renewable generation towards a level of 75% by 2030 would minimise costs to consumers, and mitigate the risk of extreme electricity prices due to uncertain gas and carbon prices.     

The British Model in Britain: Failing slowly

In 1990, Britain reorganised its electricity industry to run on competitive lines. The British reforms are widely regarded as successful and the model used provides the basis for reforms of electricity industries worldwide. The main reason for this perception of success is major reductions in the real price of electricity with no reduction in service quality. This paper examines whether the reputation of the British reforms is justified. It concludes that the reputation is not justified and that serious fundamental problems are beginning to emerge. The central question is: have the British reforms resulted in the creation of efficient wholesale and retail markets? On this criterion, the reforms have failed. The wholesale market is dominated by obscure long-term contracts, privileged access to the market and self-dealing within integrated generator/retailers, leaving the spot markets with minimal liquidity and unreliable prices. The failure to develop an efficient wholesale market places the onus on consumers to impose competitive forces on electricity companies by switching regularly. Small consumers will not do this and they are paying too much for their power. For the future, there is a serious risk that the electricity industry will become a weakly regulated oligopoly with a veneer of competition.     

基于碳交易市场下的电力企业碳减排决策研究

中国CO2排放量巨大,其中电力企业的CO2排放量占全国总排放量的50%以上。在碳交易市场背景下,电力企业需要在拍卖购买碳配额进行减排与自主更新进行减排中作出抉择。基于成本效益法对发电企业的低碳成本进行了综合分析,将通过优化后所减少的CO2排放量作为收益,在碳排放交易市场的背景下将碳减排的经济效益进行量化,并通过与碳排放权交易市场的碳价格进行比较,从而得出火电企业所应作出的最佳决策。如结果所示,在一定条件下,如果企业进行技术更新后可以减排10%、20%、30%的电力生产CO2排放量,则火电企业所作出的碳减排决策分界点的拍卖比例分别为54%、27%与18%。     

How competitive are EU electricity markets? An assessment of ETS Phase II

This paper studies the interactions between electricity and carbon allowance prices in the year-ahead energy markets of France, Germany, United Kingdom and the Nordic countries, during Phase II of the EU ETS. VAR and Granger-causality methods are used to analyze causal interfaces, whereas the volatility of electricity prices is studied with basic and asymmetric AR-GARCH models. Among the main results, the marginal rate at which carbon prices feed into electricity prices is shown to be ca. 135% in the EEX and Nord Pool markets, where electricity and carbon prices display bidirectional causality, and 109% in the UK. Therefore, generators in these markets internalized the cost of freely allotted emission allowances into their electricity prices considerably more than the proportionate increase in costs justified by effective carbon intensity. Moreover, electricity prices in France are found to Granger-cause the carbon price. This study also shows how European electricity prices are deeply linked to coal prices among other factors, both in terms of levels and volatility, regardless of the underlying fuel mix, and that coal was marginally more profitable than gas for electricity generation. EU policies aimed at increasing the carbon price are likely to be crucial in limiting the externalities involved in the transition to a low-carbon system.     

Government procurement of peak capacity in the New Zealand electricity market

This paper analyzes the impact of government procurement of reserve electricity generation capacity on the long-run equilibrium in the electricity market. The approach here is to model the electricity market in a context where the supply companies have market power. The model is then used to analyze the impact of government direct supply of peak capacity on the market. We find that the firms build less peak-generation capacity when the government procures peak generating capacity. The long-run equilibrium with N firms and government capacity of K_G results in an increase of total peak generation capacity of K_G/(N+1) compared to the long-run equilibrium with no government capacity. Supply disruptions of baseline capacity during the peak time period are also considered. It is found that peak prices do not go up any further with (anticipated) supply disruptions. Instead the entire cost of the extra peakers is borne by customers on traditional meters and off-peak customers who face real-time pricing.     

Assessing the value of wind generation in future carbon constrained electricity industries

This paper employs a novel Monte-Carlo based generation portfolio assessment tool to explore the implications of increasing wind penetration and carbon prices within future electricity generation portfolios under considerable uncertainty. This tool combines optimal generation mix techniques with Monte Carlo simulation and portfolio analysis methods to determine expected overall generation costs, associated cost uncertainty and expected CO₂ emissions for different possible generation portfolios. A case study of an electricity industry with coal, Combined Cycle Gas Turbines (CCGT), Open Cycle Gas Turbines (OCGT) and wind generation options that faces uncertain future fossil-fuel prices, carbon pricing, electricity demand and plant construction costs is presented to illustrate some of the key issues associated with growing wind penetrations. The case study uses half-hourly demand and wind generation data from South Eastern Australia, and regional estimates of new-build plant costs and characteristics. Results suggest that although wind generation generally increases overall industry costs, it reduces associated cost uncertainties and CO₂ emissions. However, there are some cases in which wind generation can reduce the overall costs of generation portfolios. The extent to which wind penetration affects industry expected costs and uncertainties depends on the level of carbon price and the conventional technology mix in the portfolios.     

Optimal generation and reserve dispatch in a multi-area competitive market using a hybrid direct search method

With restructuring of the power industry, competitive bidding for energy and ancillary services are increasingly recognized as an important part of electricity markets. It is desirable to optimize not only the generator’s bid prices for energy and for providing minimized ancillary services but also the transmission congestion costs. In this paper, a hybrid approach of combining sequential dispatch with a direct search method is developed to deal with the multi-product and multi-area electricity market dispatch problem. The hybrid direct search method (HDSM) incorporates sequential dispatch into the direct search method to facilitate economic sharing of generation and reserve across areas and to minimize the total market cost in a multi-area competitive electricity market. The effects of tie line congestion and area spinning reserve requirement are also consistently reflected in the marginal price in each area. Numerical experiments are included to understand the various constraints in the market cost analysis and to provide valuable information for market participants in a pool oriented electricity market.     

Measuring competitiveness of the EPEX spot market for electricity

The issue of market concentration in electricity markets and resulting possible anti-competitive behavior of producers is a much discussed topic in many countries. We investigate the day-ahead market for electricity at the EPEX, the largest central European market for electricity. To analyze whether generating companies use their market power to influence prices, we use a conjectural variations approach as well as a direct approach to construct marginal costs of electricity production. Given the available data, we cannot reject the hypothesis that there was no systematic abuse of market power by the suppliers of electricity on the EPEX day-ahead spot market for the years 2007–2010. These results are essentially robust when restricting the sample to high load hours, which are generally considered to be the most prone to market manipulation.     

Potential impact of (CET) carbon emissions trading on China’s power sector: A perspective from different allowance allocation options

In Copenhagen climate conference China government promised that China would cut down carbon intensity 40–45% from 2005 by 2020. CET (carbon emissions trading) is an effective tool to reduce emissions. But because CET is not fully implemented in China up to now, how to design it and its potential impact are unknown to us. This paper studies the potential impact of introduction of CET on China’s power sector and discusses the impact of different allocation options of allowances. Agent-based modeling is one appealing new methodology that has the potential to overcome some shortcomings of traditional methods. We establish an agent-based model, CETICEM (CET Introduced China Electricity Market), of introduction of CET to China. In CETICEM, six types of agents and two markets are modeled. We find that: (1) CET internalizes environment cost; increases the average electricity price by 12%; and transfers carbon price volatility to the electricity market, increasing electricity price volatility by 4%. (2) CET influences the relative cost of different power generation technologies through the carbon price, significantly increasing the proportion of environmentally friendly technologies; expensive solar power generation in particular develops significantly, with final proportion increasing by 14%. (3) Emission-based allocation brings about both higher electricity and carbon prices than by output-based allocation which encourages producers to be environmentally friendly. Therefore, output-based allocation would be more conducive to reducing emissions in the Chinese power sector.     

Pricing of electricity in China

In China, the State Power Corporation (SPC) was the dominant producer and supplier of electric power. Our price estimation results based on published data of the SPC indicate that short run cost factors, like fuel costs and investment expenditure, were more important in the price determination process. Although the power purchase prices paid by the SPC to independent power producers (IPPs) have already covered capital costs, capital costs of generation and transmission assets owned by the SPC were ignored in the process. Our studies indicate that electricity prices in China were highly subsidized and below the average total costs of generation and transmission.