“The true voyage of discovery does not lie in seeking new landscapes, but in having new eyes.” (Marcel Proust)
Electricity distribution which was thought to be the last-mile of the electricity supply industry’s value chain until recently is rapidly gaining new importance. It’s now being considered the frontline of this business where most of the action will take place in the future. A consensus is evolving among industry experts that merely improving the efficiency of this system and revenue collection, important as these are, may not be sufficient to confront the vexing challenges this industry faces. Its distribution function will require systemic transformation to effectively deal with the emerging challenges. Some pointers for managing the desired transformation of this function are provided below.
Multiple developments in the world’s energy market have altered the fundamentals of the electricity supply industry (ESI). Small power plants now beat the cost and performance features of large plants. Renewable power generation is proving competitive with conventional technologies. Battery storage technologies coupled with rooftop PV systems are enabling consumers to reduce, and even eliminate, their traditional dependence on the grid. Electric vehicles (EVs) and their charging facilities are also opening up new vistas for their dual role as loads as well as sources of supply. Smart information and communications technologies (ICTs) are unlocking new opportunities for power control and management in the grid.
The above developments—often termed “disruptive forces” by utility analysts—are impacting every part of the ESI. However, the real challenges they pose are to the distribution function as most of these will connect at low and medium voltages. Distribution systems which were designed for most part of this business’ history as passive networks to convey power in one direction only, from central-station generation plants to end users through the transmission grid, cannot handle the stresses that the presence of small and distributed technologies impose on them.
The distribution function consequently needs a thorough transformation to effectively deal with the new technical, managerial, and commercial challenges. We elaborate on each of these aspects below, but not in any specific order, as each aspect is critical and complements the others. We use the term “distributed energy resources (DERs)” to refer to these technologies for their role as new sources of supply, including storage when it’s operated in that mode. Strictly speaking, ICTs are not a DER but an enabler to connect and operate these in the system.
The DERs pose some new and unique technical challenges on the system to which they connect. In addition to the two-way flow of power, their connection with and operation in the system lead to additional issues such as loss of frequency and voltage control capability, risks of back feed to the upstream transmission systems, deterioration of power quality, less understood behavior during system disturbance and faults, and their contribution (or lack of it) to system adequacy, security, stability, and safety. These issues are not too difficult to manage but require careful assessment and planning, proper design, and more than anything, a different regulatory and managerial mindset.
Assessing the potential impacts of the DERs on the system and preventing and protecting it against such stresses requires complex system impact studies and development of suitable counter measures to deal with these impacts. Unfortunately, the expertise and tools required for conducting such assessments and developing the necessary system upgrades are not currently available within the local distribution entities. Planning and design capabilities in the distribution entities will require considerable strengthening and enhancement to equip them with the required capability, expertise, and toolkits.
Distribution Code is the most appropriate document to define the processes, requirements, and standards for planning, developing, connecting, and operating DERs at the distribution level. The Distribution Code of 2005 was a simple extension of (and complement to) the Grid Code that was issued the same year. It was developed, however, to deal with the one-way flow of power in passive networks as we noted earlier. Both these Codes are currently under revision. However, the Distribution Code, in particular, will need special treatment because now it will have to serve active nature of the distribution systems. Moreover, it should be designed as a stand-alone and self-contained document.
Many of the requirements laid down and standards referred in the Distribution Code do not cover the unique characteristics of DERs for their interconnection and subsequent operation and would require updating. To begin with, IEEE Standard 1547-2018 (and the other standards in this family) can be adopted for interconnection of DERs with the local distribution systems. However, many additional requirements and standards will be required to define the requirement for the operation and control of DERs within the distribution systems.
The existing process for seeking connection with the grid (transmission or distribution) by DERs or demand customers needs special care. Any applicant seeking connection of his facility with the grid (DER or otherwise) is required to submit an intention application to the National Transmission and Dispatch Company (NTDC) or the local distribution company (DISCO) first for preliminary screening. On clearance, it’s to be followed by a formal application that the NTDC/DISCO uses to assess the impact of the proposed facility on its system. It also identifies any system upgrades required, due to the proposed facility, that the applicant has to pay for. This process is both cumbersome and reactive, and must change in the future.
The hosting capacity (the ability of the system to accommodate different types and sizes of the DERs without or with some system upgrades) is a function of multiple variables. Hoping the developers of DERs to work out the best site or point in the distribution system for developing their facilities is unrealistic as well as impracticable. The DISCOs will need to plan ahead to identify the scope of DERs in their systems by studying the existing and future power demand in their jurisdictions and the potential of deploying DERs at various points or parts of their system to serve that demand.
Fairly soon the DISCOs may be flooded with the number of applicants seeking new connections. Distribution entities are (or should be) best suited to study and identify the best potential opportunities for deploying and connecting DERs within their networks and the upgrades that may be required. The National Electric Power Regulatory Authority (NEPRA) should mandate DISCOs to conduct such assessments periodically and publish their results on their websites to guide and facilitate potential developers in determining the best option for them to seek connection with the system.
Even better if NEPRA devises a set of clear rules for processing DER connection applications, stipulate time limits for such processing, determining the priority in which the applications are to be processed in case of multiple applications for a specific point or location, and the allocation of costs for any necessary system upgrades. This will add clarity to the whole process, about the costs involved, and the fair and equitable sharing of these costs among existing as well as future applicants. Different approaches have been devised around the world to deal with such issues and NEPRA can select some appropriate scheme for our country easily.
Planning and design sub-functions in Discos will have special roles to play in the deployment of DERs in their system. While integration of DERs in the distribution systems introduces many additional issues, these are not insurmountable. With careful advance planning, proper design, and real-time operation, such issues could be managed quite effectively. The important point is to have a grip on the potential negative impacts of DERs on the system and work with prospective developers to minimize such impacts by selecting the right technology and its interface with the system to prevent or alleviate such stresses as may be practicable.
By virtue of their location in the system, at the source of demand or in its vicinity, the DERs offer significant prospects to avoid capital investments locally and in the system upstream that would be needed otherwise to serve the same demand from the centralized power grid. Identifying these avoidable costs and incorporating these in the planning and decision-making frameworks will need a sea change in the prevailing utility planning and regulatory thinking. This will be perhaps the most difficult transformation required but holds the key to a secure, affordable, and sustainable energy future of the country.
Most planning tools, expertise, and financing have evolved around large and central-station supply-oriented schemes based on conventional technologies. Planning with DERs requires significantly different techniques and skills as the primary resources on which DERs rely are diffused, dispersed, intermittent, and variable and are also location-specific. Their integration in the system requires a careful assessment of resource patterns at a specific site and how well they correlate with the patterns of consumer demand at that site or in its vicinity.
A major part of system planning function, therefore, will need to move from its current central location—under the NTDC—to DISCOs as they are much closer to end users, and thus can better plan for the demand and required supplies within their jurisdictions. In a sense, distribution entities will be planning to function in the future as mini-grids that will be designed to operate as autonomous and independent systems largely but will be tied with the NTDC’s national grid to mutually assist each other to enhance economic, secure, and stable operation of the whole power grid.
As noted earlier, a sea change in the regulatory and managerial mindsets will be required to treat the DERs not as threat to their traditional and comfortable routines or a necessary evil they have to live with. They will need to consider them as partners to their efforts to serve the customers in the country with reliable and economic electric power. They will have to not just encourage, but aggressively seek contributions from DERs.
The management at DISCOs will need to develop appropriate tools and data, information, and knowledge bases and make these freely accessible to customers and investors for assessing the scope and viability of DER schemes for meeting demand for electricity at source and their contribution to the grid. This should also include any technical assistance they might need for making such assessments.
They will need to modernize their existing networks to transform these into an intelligent and smart grid that can facilitate successful integration of DERs and squeeze the most value from these schemes. The modernized grid must be capable of bringing together a host of stakeholders together—developers of DERs and their financiers, other market actors, producers, operators, and end-users—with the aim to optimize resource utilization and operational performance, minimize economic and environmental costs, and maximize system reliability and resilience.
NEPRA will need to provide an enabling regulatory framework to encourage the deployment of DERs, storage technologies, and necessary ICTs in the local distribution systems. This framework should empower the DISCOs to devise innovative pricing and compensation schemes to induce consumers and investors to install these technologies in the distribution systems. It should also enable proper accounting, allocation, and recovery of costs from participating consumers and investors while allowing them a fair compensation for the value they contribute to the grid.
In the absence of a favorable business environment, the DERs will still be ‘connected’ with the grid, but will not be optimally ‘integrated’, raising multiple challenges that a DER-friendly regulatory and managerial approach can help to mitigate effectively and economically. Consumers will lose too because the benefits associated with their newer technologies and schemes may not be realized to full extent. The society on the whole will thus suffer. It’s, therefore, the right time for our leaders and decision-makers to act and lead the nation to a secure, affordable, sustainable energy future.
The writer is a freelance consultant specializing in sustainable energy and power system planning and development. He can be reached via email at: email@example.com.