To maintain a precise balance between demand and supply, electric utilities are obliged to keep sufficient generation capacity in their systems, called “resource adequacy”. It’s necessary to deal with three types of uncertainties: uncertainty in forecast demand, unexpected outages of generation plants, and abnormal weather—all of a random nature, predictable to some extent but not entirely. Utilities try to maintain extra generation capacity in their system on top of the expected peak demand commonly termed as “reserve margin”.
How much generation capacity will be adequate for a system is a question of how much reliability we want in our supply, essentially a trade-off between the cost of reliability and its value to consumers. The optimum reserve margin for a system depends on multiple factors and varies from one system to another. Generally, 15 to 20 percent is considered reasonable for most systems, though by re-configuring supply portfolios, good utilities can reduce it to as low as 10 percent. It’s, however, a deterministic standard (a “rule of thumb”) and also an average value. Due to the “lumpy” nature of generation investments, its actual value can vary around this average.
To handle randomness in supply, demand, and weather, planners use a variety of techniques to assess the adequacy of different candidate generation portfolios. One such technique is to restrict the risk of supply failure to meet demand below a set target, in terms of “loss of load expectation (LOLE)” in a given period, for instance, “one-hour-in-a-year. This means that future generation in the system will be adequate to serve forecast demand for all hours in the year, but one. Another name for this metric is “loss of load probability (LOLP)“. The above target in terms of LOLP will be roughly 0.01 percent. The uncertainty in demand forecasts and weather is generally ignored in generation optimization studies.
For the vertically-integrated electric utility, the generation costs are usually lumped with T&D, metering and billing, and servicing costs to derive a system-wide total cost which is used to set tariffs for different categories of consumers. The cost of maintaining reserve margin in the system is embedded in such tariffs. Thus, every customer bears this cost, as a necessary evil, irrespective of his contribution to this cost or the value he derives from his supply. Historically, utilities have been managing this requirement amicably through regulated tariffs.
The above situation changes when the industry is unbundled and deregulated. A serious question now arises about the provision and compensation of this reserve. It’s because not all generators are created equal, in their capital costs, production costs, and design and performance features. Some plants like nuclear and coal-fired are designed to serve round-the-clock base-load duties for their high capacity but low operating costs, not amenable to frequent duty cycling. On the other extreme, we have quick-start and fast-response combustion turbines with low capital but high operating costs, designed solely for infrequent peak load duties. And, then there are a host of other plants that fall in between, both in terms of cost and performance.
Two additional aspects of this issue are worth noting. First, the above reliability is at the aggregate level. The reliability that consumers finally receive depends to some extent on the above target but involves additional factors that relate more to design, configuration, and operation of the T&D systems and their robustness against adverse weather. Second, the above reliability is built into the grid and delivered to customers irrespective of the actual value they assign to it. This has been true for much of this industry’s history but is beginning to change lately with the advent of smart sensors and devices that can channel and control the flow of electricity through the grid.
To maintain generation adequacy in the local system, NEPRA prescribes an LOLP target of one percent per year (or 88 hours per year) for the NTDC for its long-term planning. This target is specified in clause PC4.1 of NEPRA Grid Code 2005. No further details are available, either in the Grid Code or elsewhere, as to how it was fixed, and whether it was set purely on technical grounds or with some consideration to its financial implications.
The actual reserve margin in the NTDC system last year was 59 percent. According to NTDC’s latest draft Indicative Generation Capacity Expansion Plan (“IGCEP2030”), the new capacity requirements to maintain sufficient generation adequacy in its system are envisaged to be over 53 GW by 2030 against a base-case demand forecast of 34.37 GW (reflecting a reserve margin of 55 percent), requiring USD 32 billion of new investment. Assuming that typically 60 percent of investment goes to generation and 40 percent to T&D, the total new investment needs in the country can easily top USD 50 to 55 billion by 2030.
The above capacity and the associated investment needs are huge and should be a cause of serious concern for our leaders. We must explore every option and avail every opportunity to minimize future capacity needs without compromising our country’s aspirations for development and consumers’ capacity to pay. Our assumptions that go into future planning need a serious revisit and our criteria for resource adequacy need critical review, making it essential for us to configure our future generation portfolio that is least taxing on the nation’s meager financial resources, is robust against disruptive market forces, and yet is flexible to permit adoption as the future unfolds with minimal risk of leaving the invested capital stranded.
Below, we focus on only three aspects the above issue. First, we examine the suitability of the present reliability criteria as the basis for resource planning to see if some other criteria can serve our needs better. Second, we explore how objectively the present criteria or the other one can reflect the costs and benefits of reliability. Third, we offer a few suggestions that our policy-makers can use to assess the full range of technical and financial implications of resource adequacy plans and take decisions that best serve our socioeconomic interests.
Capacity-based reliability criteria, either “loss of load” or “reserve margin”, are a legacy of the past when economy of scale ruled the monopolistic electricity business. Most demand was served by central-station generation via a complex inter-tied T&D grid. Utility managers actually had a propensity to go for capital-intensive larger plants since that meant lower costs in generation and higher return on their asset bases. Reserve capacity was the only economic choice to deal with uncertainties in demand, weather and generation availability. Storage of electricity was either not possible or very expensive and technologies for controlling power flows in the grid or for consumer demand did not exist.
With the advent of competitive small generators, smart grid technologies, and electronic sensors and control devices, multiple options have emerged and are being used successfully around the world to deal with the possibility and actual events of supply failure quite effectively and at a fraction of the cost of maintaining reserve generation upstream which is called upon only a few hours in the year to deal with peak demands.
In this changed world, capacity-based reliability criteria have lost the charm they once enjoyed. Energy-based criteria such as “loss of energy expectation (LOEE)” or its equivalent “loss of energy probability (LOEP)” or “expected un-served energy (EUE)” offer a much better and more realistic basis to explore the chances of not serving consumers’ energy demand and plan and configure power supply and delivery facilities to prevent such losses from exceeding beyond specified limits. Consumers’ energy demand is also easier to forecast than their peak demand and is less affected by unexpected demand determinants. It will be better for our planners to switch from capacity-based reliability criteria for future capacity expansion planning to energy-based or a composite capacity-cum-energy criteria.
Considering physical reliability criteria exclusively and ignoring the costs of maintaining generation reserves and its value to consumers requires serious revisiting. It might have been difficult in the past to assess its scope or serve electricity at different reliability levels to consumers distinguished by their preferences, but not anymore. Technologies now exist to enable suppliers to discriminate among consumer categories in accordance with their reliability preferences to match its cost with their willing to pay. Except a few industrial processes, for most other consumers, local solutions can be easily used to match their reliability needs at a fraction of the cost of maintaining unnecessary generation reserves.
Pakistan is all set to move to a competitive wholesale electricity market. It’s important to gain insights into how the costs of providing reliability in supply are linked with dynamics of generation, demand patterns and uncertainties, and adverse weather. It is also critical to have a realistic knowledge about the value consumers place on the reliability of their supply. As we progress to more competition in generation, we will need to separate capacity provision issues from energy trade and their respective pricing. In the absence of a clear understanding and a fair compensation scheme, investors will be reluctant to invest in generating capacity as reserve. This could easily lead the country to a crisis similar to one that California faced during 2000-2001.
Three emerging developments will further convolute the resource adequacy issues. Cost-competitive renewable technologies are making rapid inroads into the power grids. EVs are also quickly replacing conventional means of transportation. Spurred by high demand in EVs, battery storage technologies are also experiencing rapid progress in their capacity, performance, and costs. Collectively, all three pose new challenges to the traditional ways of supplying electricity to consumers, but are opening up new opportunities also.
Renewables hold a great promise in serving our electricity demands economically and sustainably, but do not contribute to firm system capacity as conventional plants do. The same is true for EVs which while pose new challenges to the grid also hold great promise in improving utilization of generation capacity in the grid. Utility-scale storage at reasonable costs opens new opportunities for us to obviate the need for building and keeping peaking plants at substantial and unaffordable carrying costs.
Resource adequacy issues have thus acquired a new and unprecedented importance. The basic concept of reliability which is at the core of resource adequacy issues requires critical review. How the costs of building this reliability can be balanced with the economic value that consumers derive from it makes it imperative that we understand the complexities of demand and supply. The generation planning tools at present take a somewhat simplistic view of the issue and focus on generation availabilities only while overlooking the uncertainties is demand and weather forecasts. There is a compelling need to separate reliability evaluation from the current optimization exercises to model the full range of uncertainties in all the variables that affect the reliability of service to consumers and how is it linked with the value they place on it.
NEPRA generally holds public hearings to address stakeholder concerns on the proposed long-term plans by NTDC. This is a good exercise in theory but is meaningless if the stakeholders and the most important among them, the consumers, are not technically trained to understand the complexities of such plans which ultimately reflect in their tariffs.
It’s important for NEPRA to commission independent reliability evaluation studies to understand the costs of building the requisite reliability in the grid, how these costs fare against its value to consumers, and what is the most economically-efficient and equitable means of building and providing reliability to them? The results of these studies will help the Authority a great deal in taking informed decisions on such technically complex issues and in striking a balance between the interests of suppliers of electricity and its consumers.