电力系统标准译文

Reliability Standards for the Northwest Power System

Abstract

For lack of a better measure, the electric utility industry generally references 95-percent reliability as a “standard” for the Northwest power system, but it is a goal and not an official regulation, requirement or code. As the nation?s electricity industry becomes increasingly competitive, and as our nation becomes increasingly dependent on technology that requires highly reliable electric power, the issue of a regional or national reliability standard looms large. What is an acceptable standard? How would it be created, and what would it address? Should there be one standard or several? Occasional power outages are an inconvenience for some and a disaster for others. Perhaps there is no need for a “standard,” as consumers who need highly reliable power can pay for that privilege by purchasing their own backup generators, and those for whom reliability is less critical might be willing to accept whatever reliability their power supplier provides -- and at a lower cost. This paper explores past efforts to define and assess reliability, and recommends next steps for developing a standard or standards. Separate standards for generation planning, operation and transmission probably are warranted. For operations, a deterministic standard might be crafted around minimum reserve requirements. For generation planning purposes, a probabilistic standard (one that incorporates the frequency, duration and magnitude of customer interruptions) could serve. For transmission, it seems appropriate that an independent Regional Transmission Operator (RTO) would establish a standard, with attention to reducing congestion and rewarding distributed generation when it relieves stress on the system.

Defining the Power System

A power system can be very complex, integrating many different types of generating resources to provide electricity to a number of customers with varying requirements. Each individual component has its own characteristics, including its dependability or reliability. One can imagine the difficulty in trying to evaluate the reliability of such a complex system as a whole. To simplify the task somewhat, power systems are generally broken down into three major components: the generation system, the bulk transmission system and the distribution network. The generation system includes all resources that produce electricity, including oil and gas-fired turbines, coal and nuclear plants, hydroelectric dams, windmills and all other generators. The bulk transmission system includes high voltage transmission lines that connect generators to distribution networks. The distribution networks, made up of all the lower voltage lines, deliver electricity to individual customers.

To our knowledge, no one has attempted to evaluate the reliability of a power system as a whole. Generally, individual utilities assess the reliability of their own distribution networks. This paper focuses on methods to assess the reliability of the generation component of the power system.

Defining Reliability

In general terms, reliability is a measure of how well a system performs its expected function. Another system characteristic that is closely associated with reliability is adequacy. A system is adequate if it has sufficient resources to perform its function. A system can be adequate but unreliable. However, if a system is inadequate, then by most definitions it is also unreliable.

For electrical power systems, these two terms can be defined more specifically. The North American Electric Reliability Council defines power system reliability to be: the degree of performance of the elements of the bulk electric system that results in electricity being delivered to customers within accepted standards and in the amount desired. Reliability may be measured by the frequency, duration and magnitude of adverse effects on the electric supply. Electric system reliability can be addressed by considering two basic and functional aspects of the electric system -- adequacy and security.

Adequacy - The ability of the electric system to supply the aggregate electrical demand and energy requirements of the customers at all times, taking into account scheduled and reasonably expected unscheduled outages of system elements.

Security - The ability of the electric system to withstand sudden disturbances such as electric short circuits or unanticipated loss of system elements.

The NERC definitions of adequacy and security apply to both the generation and transmission systems. Both systems must be able to continue operation after a sudden disturbance -- either a loss of a major transmission line or a major generator. A power system is unreliable if either its transmission or generation systems are inadequate. Unfortunately, analyzing the composite reliability of both systems is very difficult. Because of this difficulty and because in practice the reliability of each system is usually measured separately, the focus of this paper will be on the generation system. However, the Northwest Power Planning Council is also participating in discussions regarding the bulk transmission system and is in favor of establishing a Regional Transmission Operator that will have some control over transmission reliability.

The Northwest Power Planning Council has defined the t erms “reliable” and “adequate” in a slightly different way for the generation system. When the Council discusses reliability, it means the short-term ability of the existing and planned generation system to deliver electricity when needed, including unusually cold periods or times when generators are out of service. In the Council?s March 2000 analysis, it concluded that the generation system was “inadequate” meaning that more resources were needed in order to lower the risk of blackouts to an acceptable level. In that sense, the Council concluded that the power system was also unreliable.

Reserve Requirements

To help ensure a higher likelihood of uninterrupted service, all utilities are required to maintain a certain level of reserve margin. A reserve margin is simply resource capability in excess of the expected peak demand. Reserve resources are called into service when unexpected outages occur. If reserve resources are used more often than expected, it

implies that the power system is inadequate and therefore unreliable.

The WSCC requires reserves equal to 5 percent of load supplied by hydroelectric resources plus 7 percent of load supplied by thermal generation, with spinning reserves not less than one half of the total operating reserve. WSCC is currently reviewing this policy and may change these requirements. Increasing the reserve margin provides a more reliable power system but at a higher cost. Decreasing the reserve margin saves money but could mean higher likelihood of curtailment.

Capacity and Energy

For a power system, planners must also distinguish between capacity and energy shortfalls. The capacity of the system is its ability to deliver power to meet instantaneous demand requirements. The power system must also be able to deliver, on a sustained basis, the average energy requirements of the region. Another way to look at the difference between capacity and energy (especially for a predominantly hydro system) is to consider fuel as opposed to machines. Does the system have enough machines to meet the peak demand? Does the system have enough water and fuel to run the machines when needed? Curtailment of service can occur if the system has insufficient machines or fuel or both. Most power systems in the world plan for capacity needs -- ensuring that enough resources are in place to serve the peak demand. Their ability to meet load is limited by their peak generating capacity, rather than the fuel available for their generating facilities. For these systems, the total generating capability usually far exceeds the average energy requirements.

For systems that incorporate a large share of hydroelectric generation, however, planning is usually done on an energy basis. This is because reservoirs behind the dams generally cannot hold enough water to run each project at full capacity all year long. These systems are considered energy limited and capacity surplus. For the Northwest region, the peaking capacity is about 42,000 megawatts and the average annual energy production is about 21,000 average megawatts.

In a capacity- limited system, no additional amount of fuel will increase service to customers. In an energy- limited hydroelectric system, no additional number of turbines will help. (Although adding other non-hydro generators obviously would improve the situation). To make matters more complicated, quite often the operation of resources is limited by constraints designed to protect air or water quality or to enhance fish survival. How do capacity and energy relate to reliability and adequacy? A system is adequate if it has enough resources and fuel to meet both the peak demand and the annual average energy requirement. A system is reliable if it can deliver power when called upon to do so within acceptable standards, taking into account scheduled and reasonably expected unscheduled outages of system elements. (Systems are generally designed to withstand the loss of a major transmission line or the largest generating resource).

Up to this point, we have defined reliability in qualitative terms. In order to measure reliability, a quantitative definition must be developed. In the following section, several approaches are explored.

Measuring Reliability

There is no single index that is universally used to express the reliability of a power system. Reliability indices can be broadly categorized as either deterministic or probabilistic.

Deterministic indices are calculated with known system parameters and provide a static look at the system. Their advantage is that they can be easily measured; their deficiency is that they are a poor representation of system reliability because they do not take unforeseen events into account very well. Operating reserve margin is an example of a deterministic index.

Probabilistic measures incorporate the dynamic nature of a power system. Statistical methods are used to account for future uncertainties in system components. These indices provide a much better indication of reliability but are more difficult and take more time to calculate.

Probabilistic reliability indices usually include the frequency, duration and magnitude of customer interruptions. Using these three parameters, various indices can be constructed. Reliability assessments are crucial for planning system expansion and other long-term programs (such as demand-side management). They are also critical to system operators in making decisions for short-term and daily operations. Long-term planners have more time to assess the reliability of potential future systems and can therefore use probabilistic indices. System operators on the other hand, require a much quicker assessment of system reliability and are more likely to use deterministic indices. The reserve margin is a good candidate for use by system operators. For system planners, such as the Council, probabilistic measures are a better choice. A discussion of probabilistic indices follows. Probability - (Frequency and Duration)

The Loss of Load Expectation (LOLE) is a reliability index that identifies the likelihood that generation will be insufficient to meet peak demand during a part or all of a year. NERC defines this index as: The expected number of days in the year when the daily peak demand exceeds the available generating capacity. It is obtained by calculating the probability of daily peak demand exceeding the available capacity for each day and adding these probabilities for all the days in the year. The index is referred to as Hourly Loss-of-Load-Expectation if hourly demands are used in the calculations instead of daily peak demands. LOLE also is commonly referred to as Loss-of-Load-Probability (LOLP). Using a Monte Carlo simulation model, a large number of potential futures can be simulated with each element of the system varying randomly based on its known operational characteristics. From the many potential futures, it is easily assessed how many days demand was not satisfied (or reserves were not met). The LOLP is then just the number of days when generation was insufficient divided by the total number of days simulated. If the LOLP is 5 percent that means that demand was not satisfied in 5 percent of the total number of simulated days.

It should be noted that the LOLP can measure hourly, daily, weekly, monthly or seasonal reliability. For example, instead of daily LOLP, seasonal LOLP is easily calculated if that

is a more important parameter for decision -making. The Council recently analyzed the winter-season LOLP for the Northwest power system.

The study concluded that (with some additional storage in Canadian reservoirs) the seasonal LOLP was about 12 percent for the period between December 2001 and March 2002. This means that in 12 out of every 100 winter-seasons analyzed, at least one insufficiency occurred. It is also likely that multiple insufficiencies occurred in some winters. However, the LOLP does not differentiate between single and multiple curtailment seasons.

Magnitude

While the LOLP is an important index in terms of identifying whether a generation system is reliable, it is an incomplete picture. It does not, for example, give us any indication of the size of the problem. The average magnitude of insufficiency is important in the process of planning for corrective measures. This reliability index, namely the Expected Unserved Energy, is defined by NERC below. “The expected amount of energy curtailment per year is due to demand exceeding available capacity. It is usually expressed in megawatt-hours.”

As an example of how such indices may be used for a distribution system, the following is quoted from the Draft Electricity System Study ESSB 6560, Section 8-Electric Service Reliability.

There is no federal or industry standard for these indices. A committee of the Institute of Electrical and Electronic Engineers Inc. (IEEE) has proposed a reliability standard. Specifically, two of the proposed indices were identified by the utilities as useful performance measures. The System Average Interruption Frequency Index or SAIFI, is the average number of interruptions experienced by customers during the year. The System Average Interruption Duration Index or SAIDI, is the average number of minutes of interruption experienced by customers during the year. The proposed standard only counts …sustained interruptions,? which are defined as those la sting five minutes and longer. The SAIFI and SAIDI measure averages for the utility?s distribution system, so it is important to remember that they reveal nothing about extreme values that may be included in the average.

Putting It All Together

A more straightforward method of portraying reliability is simply to evaluate the expected frequency, duration and magnitude of interruptions for a given power system. Given this data, the LOLP and expected unserved energy can easily be calculated. In addition, statistical information regarding the uncertainty in the expected values and extreme conditions is very valuable. For example, displaying the distribution of the duration of interruptions gives us an idea of how long the problem lasts. Are the majority of interruptions short or long? The same can be done with the magnitude. Are we dealing with large interruptions or small ones?

A reliability standard can be developed that includes all of these indices. For example, a

hypothetical standard would be that a system experience no more than one interruption greater than 1,200 megawatts lasting longer than one day over a 20-year period. In the Council?s assessment of reliability, it attempted to incorporate the magnitude into its calculation of the LOLP for the winter of 2001-02. The 12 percent LOLP counted winter seasons when the average seasonal curtailment was greater than 10 megawatts. Because the winter season analyzed was 120 days, the 10 megawatt-season value translates into one 1,200 megawatt-day outage or two 600 megawatt-day outages or one 40 megawatt-month outage, etc. If we were to implement the hypothetical standard mentioned in the second sentence of this paragraph, we would revise the Council?s assessment to include only outages that were greater than 1,200 megawatts lasting longer than one day.

This type of standard may be appropriate for system planners but would do little good for system operators. First of all, evaluating this parameter generally requires a lengthy analysis, certainly not doable on a daily or hourly basis. Secondly, it does not offer operators a good indication of what actions should be taken to alleviate the problem. A more useful standard for operators might be a lower bound on voltage drops or a range of frequency deviations. As soon as these limits are violated, compensatory actions can be taken. Another example is the use of reserve margins as a surrogate for reliability standards. They are easy to establish and monitor but they are arguably conservative and could be costly to maintain. Whatever standard is developed for system operators, it must be quickly accessible to those who control the flow of power.

If separate reliability standards are developed for planners and operators, how are they related? Operation standards are intended to keep the current system up and running (secure). If operation standards are violated by an inordinate amount, it means that the system is likely inadequate and planners have not done their job correctly or their plans have not been implemented or unexpected changes have occurred. Planning standards are intended to provide adequate systems for operators. Planning actions generally require years to implement and are often modified due to unanticipated changes in demand or policies (such as environmental constraints). Operation standards are most often defined under the assumption that the system is adequate.

Reliability and the Market

Historically, reliability standards (whenever they have been established) have been static and universal, that is, constant for all customers within a particular system. New resource (and demand-side) technology and increasing costs force us to examine current standards. In the future, it is more likely that reliability standards will be dynamic in nature and perhaps not even universal. It may be possible for different customers to have (and pay for) different levels of reliability. Even today, certain industries (such as hospitals) buy reserve generators to use in the event of interruption. In a sense, these organizations are paying a premium for higher-than-standard reliability.

The transition from a regulated electricity industry to a free market will further complicate the issue of reliability or make it irrelevant. In a true market condition, where each consumer sees real electricity prices and has real choices among the providers, universal reliability standards do not apply. In this situation, each customer would “pay”

for whatever level of reliability he can afford or wants. In conceptual terms, a “basic” standard would be associated with the general market, and individual consumers who wish to have more or less reliable service could take appropriate actions.

In fact, we do not have a true market condition. It is not even clear whether we can ever achieve a true market situation. We find ourselves in a transition, with some regions more deregulated than others. These regions may even overlap, with some utilities providing service to areas that are deregulated and others that are not. Under the current situation, the issue of reliability standards becomes more complicated. Even if a standard can be developed, how will that standard be enforced? One of the key elements of reliability in a free market is response time. It is yet to be determined whether the “market” will respond quickly enough to provide some of the reliability functions that regulated utilities have in the past. If the market cannot provide the incentives then who can and will?

Resource development will be based on economic projections. A developer will not be willing to invest money unless there is at least a good chance of making a profit. Also, the scope of decisions may be shorter term than in the past. Making a profit in the next year or two seems to be more important than betting on making money in the longer term.

In the shorter term, providing resources to meet unexpected peaking demands will be difficult, particularly in a hydro-based system. A developer is unlikely to invest in a long-term resource that will only operate occasionally, say for a month or two every four years. This is not uncommon for a system like ours in the Northwest, with the bulk of the generation coming from hydroelectric facilities. Also, even if a developer would be willing to take the risk, assuming that the extremely high prices over the short period of need would compensate for the period of in operation, government could step in and cap prices, possibly reducing the incentive to build.

西北电力系统的可靠性标准

摘要

由于缺少更好的措施，95%电力行业普遍引用西北电力系统可靠性的标准作为一个“标准”。但它是一个目标，不是正式的法规，规定或代码。作为全国电力行业竞争日益激烈的技术，作为我们国家变得越来越需要依赖高度可靠的电力，一个地区或国家的可靠性标准的问题越来越大。什么是可接受的标准？它会是怎样创造，会满足什么？应该有一个标准还是几种？偶尔停电是一些不便，对于其他人会是灾难。也许没有任何一个需要“标准”，作为消费者谁需要高度可靠的电源也可以为这一特权支付购买他们自己的备用发电机，那些不太重要的人的可靠性可能会愿意接受任何提供可靠的电力供应商提供的- - 有较低的成本的电力。本文探讨了过去的努力，以确定和评估的可靠性，并建议制定一个标准或标准的下一步骤。发电规划，运行和传输不同的标准可能是必要的。对于行动中，确定的标准可能是按最低储备负荷要求各地制作的。发电规划的目的，是制定一个概率可服务的标准（整合了频率，持续时间和断电级）。对于电力传输，它似乎是适当的，一个独立的区域传输操作员（RTO）在制定一个在注意减少输电挤塞和奖励分布式发电的同时会减轻对系统的影响的标准。电力系统定义

电力系统可能会非常复杂，它整合发电资源，将产生的电力按不同的要求不同的类型提供给客户。每个组件都有它自己的性质，包括它的可靠性和可信赖性的特点。可想而知在试图评估这样一个复杂系统的整体可靠性的困难。为了简化任务，将电力系统一般分为三个主要部分：发电系统，大容量传输系统和销售网络。发电系统使用所有资源发电，包括石油和燃气涡轮机，煤炭和核能电厂，水坝，风车和所有其他发电机。大容量传输系统包括高压输电线路，连接发电机以及分销网络。分销网络，包括所有低电压线路，将电力分配到个人客户。

据我们所知，没有人试图作为一个整体评估电力系统的可靠性。一般来说，个人单位只评估自己的分销网络的可靠性。本文着重评估了电力系统发电部分可靠性方法。

可靠性的定义

总体而言，若一个的系统能够很好执行其预期功能那么是可靠性。另一种系统的特点是密切相关的部分是有很好可靠性。一个系统，如果有足够的资源来执行其功能，那么他是可靠的。一个系统可以容量足够，但不可靠。但是，如果一个系统发电容量是不够的，那么大多数的定义它也是不可靠的。

对电力系统，这两个术语可以更明确的规定。北美电力可靠性委员会电力系统可靠性的定义是：在大容量的电力系统传输到顾客可以达到公认的标准和数量。可靠性，可通过频率，时间长短和对电力供应产生负面影响的大小来衡量。电气系统的可靠性可以解决充分性和安全性两个基本功能方面的问题。

充分性-电力系统在任何考虑到突然地电能损失和计划外停机时候能拥有满足客户的电力需求和能源需求供给的能力，。

安全性- 电力系统的承受能力，如电力系统短路或意外损失等突发性因素的干扰。

电力安全委员会（NERC）将的充足性和安全性的定义同时适用于发电和输电系统。这两种系统都必须在受到突然干扰后能够继续操作，无论是主要输电线路断开或主要发电机停机。如果发电或输电的容量不够，电力系统是不可靠的。不幸的是，同时分析两个系统是非常困难的。由于这种困难，所以在实践中各系统的可靠性通常是分开衡量，本文的重点将放在发电系统。然而，西北电力规划委员会还参与了有关

讨论，并批量建立传输系统在区域输电运营商，这将有对传输的可靠性控制有利。

西北电力规划委员会已定义的术语“可靠”和“适当”在发电系统略有不同的方式。安理会讨论的可靠性，这意味着现有的发电系统能按照计划短期内在需要时提供电力，包括异常寒冷的时期或发电机的突然停机。在委员会2000年3月的分析，得出结论认为，发电系统容量“不够”，这意味着需要更多的资源，以降低停电风险到可接受的水平。在这个意义上说，理事会的结论是，电力系统也不可靠。

备用容量要求

为了帮助确保高质量服务的，所有设施都必须保持一定的备用容量水平。不仅仅是一个备用的在预期在需求满足高峰过剩资源的能力。更在满足系统发生意外时的容量。如果备用容量少于预期电力需要，这意味着电力系统容量是不够的，因此是不可靠的。

西部电网需要储备等于5%的水电资源和7%所提供的热电负荷。目前西部电网正在审查这一政策，可能会改变这些要求。增加备用容量提供了更加可靠的电源系统，但这成本较高。降低备用容量节省了钱，但可能意味着更高事故的可能性。

容量及能源

对于电力系统，规划还必须区分容量和能源短缺。该系统的容量是它不仅能够满足即时电力需求。它还必须能够提供在持续的基础上该地区的平均能源需求。另一种方式来看待容量和能量之间的差别（尤其是占主导地位水电系统）是考虑到能源，而不是发电机。系统是否有足够的发电机来满足高峰用电需求？系统是否有足够的水和燃料满足机器运行的时候需要？如果系统没有足够的发电机或燃料或两者兼而有之可能会减少电力供应。

在世界上大多数电力系统的容量需要有计划- 确保有足够的资源，在电力需求高峰是，他们在负荷高峰期有足够的发电能力，而不是为他们的发电设施有足够可用的能源。对于这些系统，总发电能力通常远远超过了平均能源需求。

对于集成了大份额的水电的电力系统，规划通常是从能源的基础着手。这是因为水库大坝后面一般不能保持足够的水来满负荷运行一年之久。这些系统被认为是能源有限和产能过剩。为西北地区，调峰容量约42,000兆瓦，平均年发电量平均约为21000兆瓦。

在容量有限的系统，无附加燃料来提高客户服务。在能量有限的水电系统，没有额外数量的涡轮机将提供帮助。（虽然存在添加其他非水轮发电机将明显改善的情况）。使问题更复杂的是，旨在保护空气和水质量或提高鱼类生存的目的使能源的使用是有限制的。

如何综合考虑能源相关的可靠性和充足性？一个系统如果有足够的资源和燃料可以满足用户的需求高峰和年平均能源需求那么它是足够的。一个系统如果能提供可靠的电源时要求做在可接受的标准，能够预计到合理调度和计划外停机的系统要素考虑（系统通常能够承受的一个主要输电线路产生的最大损失或最大发电机停机）那么它是可靠的。

至此，我们已定义了在质量上的可靠性。为了衡量的可靠性，定量的定义必须得到发展。在下面的部分，我们几种方法进行了探索。

测量的可靠性

没有单一的指数可以普遍用来表达对电力系统的可靠性。可靠性指标大致可归类为确定性或概率。

确定性指数计算已知的系统参数，并提供一个系统的静态外观。他们的优势是，他们可以很容易地测量，他们的不足之处是，他们表现可靠性较差，因为他们不能很

好考虑到突发事件。操作储备裕量是一个决定性的指标。

概率方法纳入了电力系统的动态特性。统计方法用于计算系统组成部分未来的不确定性。这些指标提供了好得多的可靠性指标，但更困难，需要更多的时间来计算。

概率可靠性指标通常包括频率，时间和断电的严重程度。使用这三个参数，各项指标可以构造。

可靠性评估是规划系统的扩展和其他长期计划（如需求方管理）的关键。他们也在系统运营商在制订短期和日常运作的决定是至关重要的。长期规划有更多的时间来评估潜在的未来系统的可靠性，因此可以使用概率指数。另一方面是系统操作员，需要更快的系统可靠性评估和更容易使用确定性的指标。操作员更容易操作备用量。对于系统规划，如理事会，概率措施是一个更好的选择。一个概率指标需要进行讨论。概率- （频率和持续时间）

期望的负载（LOLE）损失是一个可靠性指标，表明发电机可能不足以应付在部分或一整年需求高峰。北美电力可靠性委员会定义该指数为：预计将在今年高峰时的每日需求超过现有的发电能力天数。它是通过计算，每天高峰期每天超过可用容量需求概率加上所有在年内这些天概率。该指数被称为每小时丢失负载每小时需求预期，如在每日高峰需求，而不是计算中使用。LOLE也就是通常所说的丢失负荷概率（丧失负荷概率）。

使用蒙特卡罗模拟模型，大量潜在的期货可与各不同系统随机在其业务特点的基础上用已知元素模拟。在许多潜在的期货，这是很容易评估需求的天数是如何不满足（或没有得到满足储备）。然后就在丧失负荷概率的天数不足时的天数除以模拟量。如果丧失负荷概率是5个百分点，这意味着，这在的模拟总数的百分之5不满足需求。

应该指出的是，丧失负荷概率可以测量每小时，每天，每周，每月或季节性的可靠性。例如，不是日常丧失负荷概率计算，季节性丧失负荷概率很容易计算，委员会最近分析了西北电力系统的冬季反季节丧失负荷概率。这是一个决策更加重要的参数。

研究结论认为，（有一些在加拿大水库额外存储）2001年12月之间的2002年3月期间季节性丧失负荷概率约为12%。这意味着每100年有12年，至少有一个电力不足发生。这也可能是冬天多发生在一些不足。然而，丧失负荷概率不区分单个和多个季节的削减。

大小

虽然丧失负荷概率是确定发电系统方面是否可靠的重要指标，它是一个不完整的指标。例如，给我们任何指示大小的问题。平均幅度的不足是很重要的纠正措施。这种可靠性指标，即预期缺电，是指由北美电力可靠委员会指定的，定义如下“能源削减量每年预计由需求超过可用容量决定。它通常表示兆瓦小时。“

作为这些指数如何用于通讯系统中使用的例子，下面是从草案中援引电力系统的研究ESSB 6560，第8条电力服务的可靠性。

没有这些指标联邦或行业标准来定义这个指标。电气与电子工程师协会（IEEE）的一个委员会已经试图建立一个可靠性标准。具体来说就是提出两项指标来衡量系统的表现。系统平均停电频率指数或SAIFI，是由客户在这一年经历中断的平均数目。系统平均停电时间指数或停电时间，是由客户在这一年的经历中断分钟的平均数目。拟议的标准只计算的持续中断，'是为那些持续五分钟以上的断电。SAIFI和停电时间的平均值为测量工具的分配制度，所以重要的是要记住他们透露可能在极端值的表现。

把他们放在一起

一个更直接的描绘可靠性评估方法是简单地给定电力系统的预期频率，持续时间和中断的严重程度。鉴于这一数据，丧失负荷概率和预期缺电可以很容易地计算出来。此外，根据有关统计资料，在极端条件下的预期值和不确定性也是非常宝贵的。例如，中断给持续多久时间。大多数的中断是短的还是长的？可以用同样幅度。我们是处理大还是小的中断？

一个可开发的可靠性标准，其中包括所有这些指标。例如，假设标准是一个系统的经验，在20年的时间内没有一个中断超过1200指标。在委员会的可靠性评估下，它试图将其纳入其在丧失负荷概率计算2001-02年度冬季的幅度。在计算冬季时平均有丧失百分之十二的负荷概率，削减了超过10兆瓦更大。由于冬季分析是120天，10兆瓦的季节几点到一个1200兆瓦天停电或两台600兆瓦天停电或40兆瓦月停电等，如果我们要执行标准中提到的本段第二句中的转换价值，我们将修改委员会的评估，包括那些大于1200兆瓦，持续时间超过一天的中断。

这种标准型可用于系统规划，但会做适当的对系统运营商一点好处。首先，评估这个参数通常需要一个漫长的分析，肯定在每天或每小时的基础上是不可行的。其次，它并不为运营商提供一个什么样的行动和应采取减轻问题的好方法。这给运营商更多有用的标准可能是一个较低的电压下降或更小的频率的偏差范围的约束。一旦违反这些标准，就可以采取补偿措施。另一个例子是备用电量作为可靠性标准。他们很容易建立和监测，但他们可以说是保守的，可能是代价高昂的维护。无论标准是系统运营商开发的，它必须迅速接触到那些潮流控制。

如果单独的可靠性标准是发展的规划者和经营者，他们是如何关联的？操作标准是为了保持当前的系统（安全）启动和运行。如果过多违反操作标准，这意味着该系统有可能不足，规划自己的工作做得不正确，或者他们的规划没有得到实施或意外发生了变化。规划标准旨在为运营商提供足够稳定的系统。规划行动通常需要的时间来实施，并经常修改，由于需求的减少或政策（如环境的限制）意料之外的变化。在最常见的操作标准定义的假设下该系统是足够的。

可靠性与市场

从历史上看，可靠性标准（当他们已经建立）已经是静态的和普遍的，即在一个特定系统上的所有客户不断电。新的资源的（和需求方）技术和成本上升迫使我们审视现行标准。在未来，它可能是更可靠的标的准性质将是动态的，甚至不具有普遍性。它可能会针对不同的客户有（和支付）不同级别的可靠性。即使在今天，（如医院）某些行业购买储备发电机在电力中断事件中使用。从某种意义上说，这些组织正在为高于标准的可靠性涨价。

从电力行业监管过渡到自由市场将进一步复杂化的可靠性问题或许使之无关。在真正的市场条件下，每个消费者看到了真正的电力价格和供应商之间的真正选择，通用可靠性标准不适用。在这种情况下，每个客户将“支付”提供各种档次的可靠性或希望他能买得起的可靠性。在概念上，一个“基本”标准将与广大的市场，谁希望有更多的个性化的服务可以采取适当的行动。

事实上，我们没有一个真正的市场条件。我们甚至不清楚是否实现了一个真正的市场情况。我们发现自己在一个过渡阶段这其中一些领域情况更放松管制。这些领域甚至可能重叠，有些公用事业部门提供的缺乏管制的领域服务有些则不提供。在当前形势下，可靠性标准的问题变得更加复杂。即使可以制定一个标准，该标准将如何被执行？可靠性在一个自由市场的关键因素之一是响应时间。这是尚未确定是否“市场”将作出迅速反应，提供足够的在过去有一些的公用事业曾提供的可靠的作用。如果市场不能提供的诱因，然后谁可以呢？

资源开发将基于经济预测。开发者将不会愿意投入资金，除非至少有一个赚钱的好机会。另外，决定的范围可能是短期比过去小。使在未来一两年的利润似乎比作出较长远的利润下注重要。

在短期内，提供资源，以满足意外的高峰需求会很困难特别是在一个水电为基础的系统。发展商不可能投资于只偶尔操作长期的资源，比如说一个月或每四年两次。大量电力来自水电设施对于这样一个系统在我们西北罕见。另外，即使开发商愿意承担风险，在短期内有需要极高的价格将弥补在经营期限内，政府就可以介入，对价格予以限制，可能减少的激励性建设。