The sector is slowly moving from long-term contracts to short-term contracts and spot markets
India’s power sector is currently in a transitional phase, shifting from long-term generation contracts to a greater reliance on short-term contracts and electricity spot markets.
In this transition, policymakers and regulators face some tough questions around contract regulation, spot market design, requirements and incentives for spot market participation, and potential risks in ensuring competitive markets.
According to a recently released report, policymakers and regulators in the United States have also encountered the same problems and grappled with the same issues, which might provide valuable insights for India.
The report has been prepared by the United States Agency for International Development (USAID’s) GTG program, a joint initiative of the Ministry of Power (MoP), National Association of Regulatory Utility Commissioners (NARUC), and Ethree (Energy + Environmental Economics). The report is developed in close collaboration with the Central Electricity Regulatory Commission (CERC), Power System Operation Corporation Limited (POSOCO), and other stakeholders.
According to the report, the transition is occurring in the context of some major changes in India’s electricity industry, which include changes in industry structure; growing interest by distribution companies (DISCOMs) in shorter-term contracts; rapid declines in solar PV projects and wind costs; aggressive national renewable energy targets and renewable purchase obligations; concerns over coal plant utilization; greater flexibility in coal fuel allocation; and ongoing efforts to improve the financial health of DISCOMs.
Citing the examples of California and New York, the report talks about various points in industry structure and regulation that can provide vital insights for the lawmakers in India. In California, most of the generation that takes place is non-utility owned, and the retail sector has been heavily regulated, whereas, in New York, all generation is non-utility owned and the state has a competitive retail market.
As per the report, the federal policy opened California’s electricity industry to independent power producers (IPPs) in the 1980s. By 1990, IPPs with long-term energy and capacity contracts accounted for a large share of California’s generation mix. Market design flaws and other factors led to very high spot market prices for electricity in 2000. In response to California’s electricity crisis, state lawmakers and regulators created a regulatory framework that still governs the electricity sector. This framework includes long-term planning processes for new investment in conventional resources and renewable energy.
New York Case
The report notes that before 1995, New York’s vertically integrated utilities were required to sign long-term contracts with eligible independent power producers through federal and state legislation. From 1996 onwards and up to 2003, the higher power costs prompted the state government to restructure electricity markets, leading to the divestment of generating assets by vertically integrated utilities and the introduction of retail choice. After the creation of a wholesale market in 2004, New York introduced a Renewable Portfolio Standard (RPS) with centralized procurement of long-term contracts for renewables through the New York State Energy Research and Development Authority (NYSERDA).
Insights for India
- In California and New York, long-term bilateral contracts have continued alongside the development of merit order dispatch through spot markets, but in both states, market designs and regulations have evolved to encourage market participants to submit economic bids, rather than self-scheduling.
- California and New York illustrate the diversity of contractual arrangements through which generators and LSEs with long-term contracts can participate and be settled in spot markets.
- California’s experience during the electricity crisis illustrates the risks of overexposure to spot market prices.
- In California, utilities have generally signed 10-year contracts with new generation resources. This 10-year contract duration was agreed to be the minimum duration required to secure bank loans for new projects. In New York, regulated utilities were prevented from signing long-term contracts to limit their exposure to customer migration risk and avoid unduly affecting the retail market.
- In California, balancing needs and generator ramping has increased significantly with growth in solar and wind penetration. Having a well-functioning balancing market that charges and pays renewable energy buyers and sellers a market price for imbalances and pays conventional generators a market price for their increased ramping and cycling costs has been critical for the higher penetration of renewable energy at low cost.
- High average electricity prices, in part as a result of expensive legacy contracts, were a key driver for electricity markets in both California and New York. However, in both states, pre-market contracts have largely been a sunk cost.
- California’s experience highlights the importance of fair and rational tariffs for customers with distributed generation and a vision for how the fixed costs of generation, transmission, and distribution would be allocated in a future scenario.
In the last decade, total installed generation capacity in India increased from 154.7 GW in 2007 to 345.5 GW in 2018, making it the world’s third-largest producer of electricity, falling behind only China and the United States. More than 115 million people have gained access to electricity since 2013, increasing the share of the population with access to electricity from less than 80 percent in 2013 to 86 percent in 2017. These findings were elaborated in a 2018 World Bank report.
Earlier, the CERC had issued regulations for the Power System Development Fund. According to the CERC notification, the fund would be created by credits received from a variety of charges collected, which include congestion charges that are in surplus after the amounts are paid to the eligible regional entities along with interest, if any, according to the Congestion Relief Regulations.