India’s wholesale electricity market is no longer fit for purpose according to Dheer Patel of the Regulatory Assistance Project (RAP). Long term procurement contracts are forcing distribution companies (discoms) to buy expensive energy when cheaper alternatives are readily available. So the Central Electricity Regulatory Commission (CERC) is launching a six-month pilot, starting 1st April, that enables “least-cost dispatch” of all centrally regulated interstate generating stations. The new CERC mechanisms—both proposed and those in the works—are designed to minimise discoms’ power procurement costs, reduce their overall financial losses, improve grid efficiency, and support cost-effective grid integration of renewable energy. Dheer Patel takes a close look at what it means for India.
Over the last couple of decades, Indian policymakers have been implementing a wide range of reforms in the electricity sector with the goal of providing reliable, affordable, and clean power to all citizens. During the last few months, the Central Electricity Regulatory Commission (CERC) has started describing wholesale electricity market reforms through a series of discussion papers. CERC’s proposal—if implemented well—may help improve the overall efficiency of the system by optimising the use of existing supply-side resources (i.e., generation and transmission). The proposed reforms also serve as important steps toward cost-effectively integrating the rapidly growing share of renewable energy into the grid.
Current market design handicaps low-cost generation
India’s current market design has led to significant under-utilisation of cheap resources and over-utililisation of expensive resources, inadvertently creating “stressed assets.” It has also forced a sizeable amount of unnecessary curtailment of renewable energy. Under the status quo, distribution companies, or discoms, procure approximately 87 percent of their energy through long-term contracts and procure the balance through a combination of short-term bilateral transactions and power exchange purchases. Further, most of the discoms self‑schedule the generators with whom they have bilateral contracts.
Under this process, it is possible that a relatively cheap generator who has contracted with one discom may not be running. At the same time, another discom that needs additional power has no way of knowing that this cheap generator is available and will end up using a relatively expensive generator with whom it has a contract. Consequently, the second discom is unnecessarily paying a higher cost for power. The inability to assess all available generation in the country and its marginal cost is a major barrier to minimising the cost of power.
The CERC proposals will minimise discoms’ power procurement costs, reduce their overall financial losses, improve the efficiency of the grid, and support cost-effective grid integration of renewable energy.
CERC has taken a positive step forward in proposing a national electricity market platform that will provide discoms the opportunity to identify and procure cheaper generation outside of their own portfolio. Their proposal envisages a centralised market for day-ahead scheduling and real-time dispatch, subject to constraints such as the physical attributes of generators (i.e., ramp-up and ramp‑down capability) and transmission availability. Additionally, CERC proposes to co-optimise and synchronise ancillary services procurement with day-ahead and real-time markets for effective grid balancing.
Together with a senior CERC staff member working in his individual capacity, RAP co-authored a 2017 study that provides foundational research on adapting centralised economic dispatch for the Indian context. RAP also conducted several workshops covering the key issues underlying the CERC proposal for the benefit of staff from several key power sector institutions such as load dispatch centres, regulatory commissions, discoms, generation companies, consumer advocates, and others.
Since July 2018, CERC has published a series of discussion papers to raise awareness among stakeholders of both concerns with the present market design and the benefits of the proposed market mechanisms. These include discussion papers on the day-ahead market, real-time market, and the ancillary services mechanism. CERC is expected to follow up with additional and necessary market constructs, namely financial transmission rights, location-based marginal prices, and market monitoring and surveillance.
Day-ahead market introduces economic dispatch
The objective of the day-ahead market as stated by CERC is, “meeting the system load by dispatching least-cost generation mix while ensuring that the security of the grid is maintained.” If implemented well, this will minimise the lack of insight into available generation described earlier and provide discoms an opportunity to procure cheaper power outside their portfolio. Generators will be able to sell power to buyers other than those with whom it has a contract. Most importantly, this allows the market to discover the system marginal price that serves as an important input to long-term planning.
The current form of bilateral contract covers both the physical and financial aspects of electricity delivered by a generator to a buyer (e.g., a discom). Because of this, system operators are forced to schedule generators on the basis of bilateral contractual arrangements and not based on lowest cost. Consequently, under the current system, there are instances when cheap generation is available but expensive generation is dispatched.
The CERC proposal does not suggest cancelling existing bilateral contracts or prohibiting new bilateral contracts. Instead, CERC recommends that the bilateral contracts are converted into financial contracts which enable least-cost dispatch to occur as discovered through the centralised market. The existing bilateral contracts will, effectively, serve as a hedge for buyers and sellers against the volatility of the market clearing price and will be settled outside the market, through a mechanism called a “bilateral contract settlement.”
Real-time market introduces gate closure, reduces reliance on deviation settlement mechanism
Presently, most of the real-time imbalances are managed through the deviation settlement mechanism. However, this mechanism is best suited for ensuring grid security rather than balancing the grid in a cost-effective manner. Furthermore, the absence of gate closure and the provision of a “right to recall” allows discoms to request power from generators in their portfolio up to four time-blocks (one hour) before delivery. This breaks the sanctity of the schedules as well as restricts the generators from selling the unrequisitioned surplus in the market.
CERC has proposed a real-time market with double-sided, uniform price auctions that will be operated on an hour-ahead basis. The proposal also introduces the concept of gate closure to ensure that the schedules are firm and cannot be revised once the real-time auction begins. A national market for real-time changes in demand or supply will allow optimisation to take place over a larger balancing area.
CERC has already amended the deviation settlement mechanism regulations to link penalties to the daily average price as discovered in the existing day-ahead energy market instead of the administratively determined penalties used previously. This is meant to discourage both buyers and sellers from relying on the grid to manage their imbalances and encourage them to improve their day-ahead forecasting and planning. The introduction of the real-time market provides buyers and sellers an opportunity to correct any mismatch of demand and supply closer to delivery (i.e., one hour in advance) and depend less on the deviation settlement mechanism.
Ancillary services aligned with day-ahead and real-time markets to balance grid
Today, India’s ancillary services market consists primarily of surplus capacity from generators that are regulated by CERC, and there is limited information available about them in terms of their flexibility characteristics to meet system balancing needs.
The proposed ancillary services mechanism allows the procurement of “slow” tertiary reserves that respond to requests within 15 to 30 minutes. These services will be co-optimised by the power exchanges with the day-ahead and real-time markets. The regulator may extend the ancillary services market to include “fast” tertiary services to be procured in the future.
Proposed markets will reduce costs, integrate more renewable generation
The reforms proposed so far by CERC are not sufficiently comprehensive to ensure full system optimisation, but they are important steps in the right direction. As a next step, CERC has approved a six-month pilot program (starting 1 April 2019) that implements least-cost dispatch of all centrally regulated interstate generating stations. The national system operator, POSOCO, will implement this program using a security-constrained economic dispatch optimisation model. The pilot is expected to reveal the benefits of the various reforms proposed by CERC as well as possible barriers to implementation of the proposed markets (e.g., hardware, software, controls, and communication requirements and institutional capacity). CERC will use the insights from the pilot program and public comments received as part of the regulatory process to refine the final market proposals.
The CERC proposals—both proposed and those in the works (i.e., financial transmission rights and location-based marginal pricing)—will minimise discoms’ power procurement costs, reduce their overall financial losses, improve the efficiency of the grid, and support cost-effective grid integration of renewable energy.
This article is published with permission.