Against this backdrop, recent developments have made it reasonably clear that state government- owned discoms could be subjected to insolvency proceedings under the IBC. On September 17, 2021, the Madras High Court admitted a writ petition challenging the jurisdiction of the National Company Law Tribunal (NCLT) under section 9 of the IBC to entertain an insolvency proceeding against the petitioner, the Tamil Nadu Generation and Distribution Company (TANGEDCO).^[5] TANGEDCO is a state government-owned discom, that is a ‘government company’ under section 2(45) of the Companies Act, 2013. In relation to this matter, the Union Ministry of Power wrote a letter to the Secretary, Department of Legal Affairs on November 8, 2021, clarifying that insolvency proceedings could indeed be initiated against a ‘government company’.^[6] On the same day, the Madras High Court dismissed TANGEDCO’s writ petition. The court’s reasoning was two-fold. First, the IBC does not provide any exemption to government companies. Consequently, NCLT had jurisdiction to entertain an insolvency proceeding against a government company under the IBC.^[7] Second, section 86(1)(f) of the Electricity Act, 2003 applies only to disputes between distribution licensees and generating companies, not between an operational creditor and a generating company. Therefore, this provision of the Electricity Act, 2003 does not come in the way of triggering insolvency proceeding against discoms under the IBC.^[8] These legal developments are likely to prompt creditors of financially distressed state discoms to trigger IBC proceedings, either seeking resolution or at least, as a legal strategy to settle their dues with a discom bilaterally.^[9] This may put to test the IBC’s ability to handle the most challenging financial distress in the power sector.

The IBC being a general corporate insolvency law was never designed to handle idiosyncratic sectoral issues. Yet, discom resolution raises several such issues. For instance, a discom is a utility that provides an essential service. Continuity of supply of such services to consumers during insolvency resolution is of utmost importance. Even the National Company Law Appellate Tribunal (NCLAT) has acknowledged that initiation of insolvency resolution against a discom ‘may cause problem to the public in general’ and accordingly, encouraged settlement between a discom and the applicant creditor.^[10] Consequently, successful discom resolution under IBC may require additional institutional safeguards to ensure continuity of supply.^[11] Similarly, the tariffs that discoms may charge their consumers are often regulated by the State Electricit/y Regulatory Commission (SERC). There has been much concern that such tariffs are often kept extremely low, even when wholesale electricity prices fluctuate, which in turn impacts the financial viability of discoms. Similar concerns also arise from PPAs. The tariff negotiated in a PPA may subsequently become relatively higher compared to the market rate, increasing the financial burden on a discom. It is therefore not surprising that multiple states including Punjab, Gujarat, Rajasthan, Karnataka and Uttar Pradesh have tried to renegotiate or cancel prior PPAs to aid state-owned discoms. The Andhra Pradesh High Court recently pushed back against this trend, holding that PPAs cannot be renegotiated subsequently.^[12] Successful discom resolutions may therefore have to grapple with the need for tariff changes and the appropriate institutional architecture necessary to alter such tariffs during discom resolution. Addressing such peculiar sectoral concerns may require revisiting the IBC in its application to discoms.

Against this backdrop, this paper aims to identify the idiosyncratic issues that have arisen out of electricity utility resolution by comparing how legal regimes in the USA and the UK approach the problem. The comparative approach that the paper seeks to adopt will be characterised by a functional perspective. It will briefly review the evolution of the electricity sector in these two countries and identify the idiosyncratic legal issues that could potentially arise during electricity utility resolution. Overall, the aim of the paper is to use this comparative approach to inform the discussion on discom resolution through the IBC in India. Hopefully it will trigger a larger policy debate on the subject in future.

USA

Background

From 1929 until 1936, the USA experienced 53 utility holding company bankruptcies involving $1.7 billion in outstanding securities.^[13] For the next half century, no privately owned public utility filed for bankruptcy. This was probably because until mid-1960s, America’s demand for electricity doubled every decade from the turn of the century. Analysts predicted that this growth would continue. To satisfy the demand, utilities turned to nuclear power as a relatively inexpensive, reliable, and pollution- free alternative to oil, coal, and hydroelectric power. In the 1970s, inflation, high-interest rates, and the high cost of crude oil pushed up the operating and construction costs of nuclear power plants far above projected levels. Utility rates rose in response to increased costs compelling customers to conserve electricity. Growth in demand for electricity declined correspondingly. Subsequently, the brush with disaster at a nuclear power plant in Three Mile Island in 1979 heightened public awareness of the risks and intensified governmental scrutiny. Because of all these factors, it was soon realised that many of the utilities’ incomplete nuclear power plants might be too expensive to complete.^[14] It was against this backdrop that allocating the costs of abandoned nuclear plants assumed significance.^[15]

The state commissions had to decide what portion, if any, of abandoned plant costs may be recovered through rates from rate-paying consumers and what portion must be absorbed by the utility and its shareholders. If a state commission denied cost recovery of abandoned nuclear plants by a utility company, and the cost of the plant was excessive in comparison to the utility’s other assets, the utility would be unable to absorb these costs internally. It was in this context that utilities started exploring options under the US Bankruptcy Code from early 1980s.^[16]

In the 21st century, utility bankruptcies have become more common in the USA. A host of regulatory measures and innovations have enabled new generation sources (natural gas, wind and solar) to become cost-competitive with traditional generation sources (nuclear and coal).^[17] The declining prices of new generation sources have already reduced the demand for coal-generated electricity. As the generation segment has become more competitive, several electric utilities have approached bankruptcy courts for relief. For example, FirstEnergy filed for Chapter 11 in 2018 after being dragged down by its failing nuclear and coal plants. At the same time, climate change is intensifying natural disasters, threatening the long-term viability of traditional, vertically integrated electric utilities. For instance, the wild-fire liability faced by PG&E prompted the utility to file for bankruptcy in 2019.^[18]

Idiosyncratic issues

The US Bankruptcy Code has very few special provisions for utility bankruptcies.^[19] Consequently, utility insolvencies have been treated under the same legal provisions as any other financially distressed company. Yet, electricity utility resolution in the USA has raised one idiosyncratic issue – the scope of debtor’s rejection powers under section 365 of the US Bankruptcy Code.

Section 365(a) of the Bankruptcy Code provides that ‘… the trustee, subject to the court’s approval, may assume or reject any executory contract or unexpired lease of the debtor’. In other words, a debtor-in possession has the power to reject any executory contract with the bankruptcy court’s approval. This rejection power is appealing to electric utility debtors who are often burdened by expensive, long- term PPAs because these agreements are challenging to modify or abrogate outside of bankruptcy.^[20] Attempts to reject PPAs under this provision of the US Bankruptcy Code has led to frictions between the bankruptcy court and the Federal Energy Regulatory Commission (FERC).^[21]

The FERC is a creature of the Federal Power Act, 1920. This statute was enacted since the American Congress felt that federal regulation was necessary to protect public interest. The US Supreme Court has noted that the principal purpose of the FPA is the protection of electricity consumers through the ‘orderly development of plentiful supplies of electricity at reasonable prices’.^[22] Although energy contracts are privately negotiated, the contracts must be filed with FERC and certified as ‘just and reasonable’ to be lawful under the FPA. And FERC is vested with the ‘exclusive authority to determine the reasonableness of wholesale [electricity] rates’. FERC’s plenary authority over wholesale energy contracts led to the filed rate doctrine.^[23] The doctrine states that a utility’s right to a reasonable rate under the FPA is the right to the rate which the FERC files or fixes and, except for review of FERC orders, a court cannot provide a right to a different rate. It has been widely recognised that the filed rate doctrine prohibits any collateral attack in the courts on the reasonableness of rates, and that the only forum for such a challenge is the FERC.^[24] Though FERC has exclusive authority to modify filed rate wholesale energy contracts, its power to modify the rates is not limitless. The US Supreme Court has held that the FERC can change a filed rate being charged by an electricity generation company under a contract only when ‘the rate is so low as to adversely affect the public interest – as where it might impair the financial ability of the public utility to continue its service, cast upon other consumers an excessive burden, or be unduly discriminatory’.^[25] Section 206 of the FPA authorises FERC, after hearing, to change filed rates if it determines that they are unjust or unreasonable.

The provisions in these two different statutes – the Bankruptcy Code, 1978 and the Federal Power Act, 1920 – have led to much friction between the bankruptcy court and the FERC in relation to restructuring of electricity utility companies. A brief review of some of the most relevant cases would illustrate the issue better.

For instance, in Mirant Corporation v. Potomac Electricity Power Company,^[26] the corporate debtor (CD) Mirant was in the business of producing and selling energy products and in trade of energy products. Through an asset purchase and sale agreement with Pepco, it acquired most of Pepco’s power purchase agreements (PPAs). However, some of the PPAs required the PPA supplier’s consent for assignment. Mirant and Pepco agreed that for the unassigned PPAs, Pepco will continue purchasing under these PPAs and Mirant would be under an obligation to purchase the same electricity from Pepco. Subsequently, Mirant wanted to reject this agreement using section 365(a) of the Bankruptcy Code. The Bankruptcy Court allowed the rejection on the ground that the energy was no more needed by Mirant to fulfill its obligation to supply. The court held that the FPA would not pre-empt the district court from exercising its jurisdiction under the Bankruptcy Code since the CD’s main justification for rejection of the PPA, in that case, was that it did not need the energy it was purchasing under the PPA to fulfill its own obligations to supply electricity. Such rejection of the contracts would only have an ‘indirect effect’ on the rate.^[27]

In a subsequent decision in re Calpine Corporation, the CD Calpine was in power generation business. It entered into PPAs to supply electricity and raised debt to build power plants. Subsequently, natural gas prices went up. The prices fixed under PPAs were significantly lower. Calpine sought to use section 356(a) to terminate these PPAs. It argued that it was ready to supply the same amount of electricity but at competitive market prices. The court refused termination. The court held that the bankruptcy court’s authority cannot be exercised so as to interfere with the jurisdiction of the FERC, a federal agency, acting in its regulatory capacity.^[28] The court observed that because there is nothing in the Bankruptcy Code that limits FERC’s jurisdiction, Calpine cannot achieve in bankruptcy court what neither it, nor any other party in that case, nor any other federally regulated energy company in the country could do without seeking FERC approval, that is, to cease performance under the rates, terms, and conditions of filed-rate wholesale energy contracts in the hopes of getting a better deal.

Finally, in re First Energy Solutions (2019), First Energy Solutions (FES) was an electricity distributor. It distributed to retail and corporate clients and also supplied to the sport market. For its retail business, it was required to purchase Renewable Energy Credits (RECs). For this, it entered into 8 PPAs. From 2011 onwards, the regulations on RECs were relaxed. RECs became available for cheaper price. FES was also planning to exit the retail segment. The PPAs therefore became burdensome for FES since it did not need RECs at all. It was in this context that FES sought to reject those PPAs using section 365(a). The Court allowed this rejection.^[29] The US Court of Appeals held that when a Chapter 11 debtor moves the bankruptcy court for permission to reject a filed energy contract that is otherwise governed by FERC, via the FPA, the bankruptcy court must consider the public interest and ensure that the equities balance in favor of rejecting the contract, and it must invite FERC to participate and provide an opinion in accordance with the ordinary FPA approach within a reasonable time.^[30]

In a nutshell, section 365(a) of the US Bankruptcy Code has been successfully used by CDs in the USA to reject PPAs only when they are part of a genuine restructuring effort to overcome financial distress. However, courts have refused to allow rejections which were meant merely to renegotiate a better deal for the CD bypassing the jurisdiction of the FERC.

UK

Background

The electricity supply industry was nationalised in England and Wales in 1947. After three decades, the conservative party under Margaret Thatcher started privatising state-owned enterprises. From 1979 to 1992, some 39 companies were privatised, culminating with electricity utilities from 1990 that ended in 1995 with the sale of more modern nuclear plant. The breakup of the nationalised power suppliers into smaller privatised companies immediately increased market competitiveness, with new companies beginning to build their own Combined Cycle Gas Turbine (CCGT) stations from 1992. Major electricity suppliers increased in number from 16 in 1989 before privatisation to 39 in 2019. Major power producers (MPPs) increased in number from 6 in 1989 to 55 in 2019. The market share of smaller suppliers (outside the top nine) rose from 4% in 2010 to 20.4% in 2019, as new and smaller suppliers took market share from the large companies.

The Utilities Act, 2000 introduced new terms in suppliers’ licences to enable Ofgem to revoke them in not less than 24 hours in circumstances where the licensee becomes insolvent. It also empowered Ofgem to appoint a Supplier of Last Resort (SoLR) for all types of customer (domestic and non-domestic) of an electricity supplier. This power was essential to ensure that all failed supplier’s customers have continuity of supply. In December 2001 the gas and electricity supplier Enron Direct Limited failed. Its customers were bought by BGT. In October 2002, TXU Europe’s supply business was sold to Powergen following TXU’s financial difficulties. In June 2003 Maverick Energy Limited (a small non-domestic electricity supplier) went into administrative receivership; its customer contracts were subsequently sold to Atlantic Electricity and Gas Limited.^[31]

It was against this backdrop that the Energy Act 2004 introduced the Energy Supply Company Administration, a special insolvency regime specifically created for companies that supply electricity in England and Wales pursuant to specific supply licences granted by Ofgem. In addition to creating a special administration regime for energy supply companies, there are also restrictions on the use of insolvency processes that would ordinarily be available under the Insolvency Act 1986, such as the ordinary out-of-court administration.

When smaller energy supply companies have gone insolvent, Ofgem used the SoLR mechanism to take over customer accounts. At times, the acquiring companies defaulted on balancing and settlement payments and network and distribution charges, distributing the costs across other market participants. Clearly, this resolution strategy was unsuitable for big energy supply companies. Consequently, the Energy Act, 2011 established a special administration regime for big energy supply companies to serve as a backstop for SoLR mechanism. The purpose is to ensure that if a large electricity supplier is in financial difficulty, arrangements are in place to allow the company to continue operating normally until it is rescued, sold or its customers transferred to other suppliers. The aim has been to reduce risk of contagion in energy markets, maintain market stability and therefore, protect consumers. In 2021, Bulb became the first energy supply company to be admitted to this special administration regime.

Idiosyncratic issues

Unlike the USA, the UK has evolved a special insolvency resolution regime for energy supply companies. A failing energy company is under a legal obligation to notify Ofgem that it is unable to pay its debt as they fall due. Ofgem prefers private trade sale of such a supply company. If trade sale is not achievable, Ofgem has the power to revoke the company’s supply license within 24 hours’ notice and appoint a Supplier of Last Resort (SoLR). If Ofgem cannot appoint a new supplier, it can use the Energy Supply Company Administration, a special administration regime under the Energy Act, 2004/2011. In that case, a special administrator runs the company until its business is restructured, sold, or has its customers transferred to other suppliers.

The SoLR is ideal to handle financial distress of small energy suppliers. The Ofgem asks other competing suppliers if they are willing to be considered as SoLR and the terms on which they would be willing to supply to the consumers of the failed energy supplier. Ofgem also has the power to direct a supplier to act as SoLR. Once SoLR has been identified, Ofgem revokes the license of the failed company and immediately places the supply with SoLR. The failed company is liquidated under general insolvency law.

Unlike SoLR, the Energy Supply Company Administration (ESCA) is meant for larger energy suppliers. This special administration regime alters the ordinary administration process under the Insolvency Act, 1986. It is primarily designed to ensure continuity of service or operation of the electricity supplier. The Secretary of State (or Ofgem with the consent of the Secretary of State) may apply to the court for the special administration order.^[32] No out of court appointment is permitted. The court must be satisfied that the company is or is likely to be unable to pay its debts; or that grounds exist that would entitle the Secretary of State to apply to wind up the company in the public interest.^[33]

The objective of the administration is to secure that energy supplies are continued at the lowest cost which it is reasonably practicable to incur until the company is either rescued as a going concern or, if that is not possible, transferred to another company as a going concern or, if that is not possible, transferred to two or more different companies.^[34] The Administrator runs the company till it is restructured, sold or its customers are transferred to other suppliers. Unlike an ordinary administration, the Secretary of State may provide grants, loans, indemnities or guarantees to enable an energy administrator to finance the supply company’s activities. Approval from Her Majesty’s Treasury is needed for such financial support. Provision is made to recover any government funding from the company or, if it is not able to repay, through a cost recovery mechanism with the cost being borne by the industry.^[35] In 2021, Bulb Energy with 1.7 million customers became the first company to go into ESCA.

CONCLUSION

Discom resolution raises a host of issues under insolvency law. Some relevant idiosyncratic issues that have arisen in this context in the USA and the UK have been identified in this paper. First, the ability to reject a PPA contract under insolvency law is particularly crucial in the Indian context. States like Punjab, Gujarat, Rajasthan, Karnataka and UP have tried to renegotiate or cancel PPAs. Recently, the Andhra Pradhesh High Court pushed back against this trend and reinforced the sanctity of PPAs. In this backdrop, the IBC may provide a workable middle ground to renegotiate burdensome PPAs which may be the cause of financial distress of a discom. In fact, rejection of a PPA was permitted under IBC through a resolution plan in the case of Bhushan Steel.^[36] Additionally, the IBC empowers a resolution professional to amend or modify the contracts which were entered into before the commencement of

the resolution.^[37] This provision has been tested in very few cases till now.^[38] The utility of this provision in modifying PPAs is yet to be tested in India. Second, continuity of service of a discom during resolution is of utmost importance. The UK has developed dedicated legal regimes such as SoLR and the ESCA to ensure continuity of discom services during resolution. One of the most important features of the ESCA is the ability of the Secretary of State to provide grants, loans, indemnities or guarantees to enable an energy administrator to finance the supply company’s activities. The mechanism for recovery of the government funding is also clearly provided for. These are useful features that may be considered in the Indian context. Indian policymakers need to consider if a SoLR or ESCA type of regime for discoms could work in the Indian context. Overall, IBC could potentially offer a viable mechanism for discom resolution if these idiosyncratic issues are specifically addressed within the overarching framework of the law.

Footnote

[1] Kale S.S., Dubash N.K. and Bharvirkar R. (2018), “Introduction: A framework for mapping power, In: Mapping Power: The political economy of electricity in India’s states”, Oxford University Press.

[2] Joesy A., Dixit S., Chitnis A., and Gambhir A. (2018), “Electricity distribution companies in India: Preparing for an uncertain future”, Prayas (Energy Group), Pune.

[3] Ibid

[4] Jaitley A. and Shah A. (2021), “The lowest hanging fruit on the coconut tree: India’s climate transition through the price system in the power sector”, xKDR Forum Working Paper, October.

[5] Madras High Court, Tamil Nadu Generation and Distribution Company v. Union of India, WP No. 19785 of 2021, order dated September 17, 2021.

[6] PTI (2021), “Insolvency proceedings can be initiated against state-owned discoms: Govt”, Business Standard, 12 November..

[7] Madras High Court, Tamil Nadu Generation and Distribution Company v. Union of India, WP No. 19785 of 2021, order dated November 8, 2021.

[8] Ibid

[9] Such settlement has been permitted earlier. NCLAT, Arkay Energy (Rameshwaram) Ltd. v. Tamil Nadu Generationa & Distribution Co. Ltd., Company Appeal (Insol-vency) No. 215 of 2017, order dated August 10, 2018.

[10] NCLAT, Arkay Energy (Rameshwaram) Ltd. v. Tamil Nadu Generationa & Distribution Co. Ltd., Company Appeal (Insolvency) No. 215 of 2017, order dated April 23, 2018.

[11] Datta P. (2021), “Powerless to pay”, Indian Express, 1 December.

[12] High Court of Andhra Pradesh, W.P. No. 11461 of 2021, 15.03.2022.

[13] To redress this situation, the Public Utility Holding Company Act of 1935, reformed utility practices. It limited most holding company operations to single integrat- ed public utility systems and eliminated unnecessary intermediate holding companies. Most importantly, the Act provided separate procedures for the reorganisation of utility holding companies. Robinson, B., In re Blackacre Power and Light: The Bankruptcy of a Public Utility, 50 ALB. L. REV. 641 (1986).

[14] Robinson, B., In re Blackacre Power and Light: The Bankruptcy of a Public Utility, 50 ALB. L. REV. 641 (1986).

[15] This matter fell primarily within the jurisdiction of state utility rate-setting agencies. In general, rates must be low enough to provide service to customers at a reasonable price, yet not so low as to deprive the utility of a ‘fair and reasonable’ rate of return on its investment.

[16] Supra Note 14

[17] After the 1970s energy crisis, the Congress enacted the Public Utility Regulatory Policies Act of 1978 (PURPA) to promote the development of new generating facilities and to conserve the use of fossil fuels. Because the traditional utilities controlled the transmission lines and were reluctant to purchase power from non-tra- ditional facilities, PURPA directed FERC to promulgate rules requiring utilities to purchase electricity from qualifying cogeneration and small power production facil- ities. PURPA disrupted the monopoly market structure by enabling certain non-traditional wholesale sellers, like renewable energy companies, to compel traditional public utilities to purchase their generation capacity and energy. Hirsh M. (2021), “Creatures of Congress Collide: Defending FERC’s Ratemaking Authority in Electric Utility Bankruptcies”, Columbia Business Law Review, Vol. 1:296.

[18] Hirsh M. (2021), “Creatures of Congress Collide: Defending FERC’s Ratemaking Authority in Electric Utility Bankruptcies”, Columbia Business Law Review, Vol. 1:296.

[19] For instance, section 1129(a)(6) which provides that any governmental regulatory commission with jurisdiction, after confirmation of the restructuring plan, over the rates of the debtor, must approve any rate change provided for in the plan, or such rate change must be expressly conditioned on such approval.

[20] Supra Note 18

[21] FERC inherited almost all the responsibilities of Federal Power Commission set up under the FPA. Much of what it didn’t inherit went to the Department of Energy (DoE), but was subsequently delegated from DoE to FERC.

[22] N.A.A.C.P. v. Federal Power Comm’n, 425 U.S. 662, 670 (1976)

[23] Montana-Dakota Utilities v. Northwestern Public Service Co., 341 U.S. 246 (1951)

[24] FERC’s jurisdiction and the filed rate doctrine extends to the terms and conditions of wholesale energy contracts. The filed rate doctrine is not limited to ‘rates’ per se. A change to the duration of a filed rate energy contract, would also come under FERC’s jurisdiction. Because, once filed with FERC, wholesale power contracts become the equivalent of a federal regulation. In re Calpine Corporation, et al, US District Court SDNY, January 27, 2006.

[25] US Supreme Court, FPC v. Sierra Pacific Power Co., 350 U. S. 348, 352-353 (1956).

[26] 378 F.3d 511 (5th Cir. 2004).

[27] Public utility PEPCO, pursuant to deregulation legislation, sold its electric generation facilities and assigned most of its power purchase agreements to Mirant, a power purchaser and provider. Because some of the power purchase agreements contained language that foreclosed PEPCO from assigning them, PEPCO and Mirant entered into a separate agreement (also FERC-regulated), which provided that PEPCO would continue to buy energy under the unassigned agreements and that Mirant would purchase that energy from PEPCO at the filed rates set in those contracts. When Mirant later filed for Chapter 11 bankruptcy, it sought to reject the contracts that bound it to buy the energy from PEPCO. In re Mirant, 378 F.3d 511 (5th Cir. 2004).

[28] Calpine Corporation was a power generator. It had entered into PPAs to supply electricity. It had taken debt to build power plants. However, natural gas price went up. Consequently, Calpine filed for Chapter 11 and asked for cancellation of PPAs since they were burdensome given that electricity prices fixed in the PPAs were sig- nificantly lower than prevailing electricity prices. However, Calpine was ready and willing to supply the same amount of wholesale electric power but at competitive market prices. In re Calpine Corporation, et al, US District Court SDNY, January 27, 2006.

[29] NLRB v. Bildisco & Bildisco , 465 U.S. 513, 518 (1984).

[30] FirstEnergy Solutions (FES) distributed electricity, buying it from its fossil-fuel and nuclear electricity-generating subsidiaries and selling it to retail clients, corporate affiliates, and in the spot market. Since at least 2003, regulations required FES to buy a certain amount of ‘renewable energy credits’ (RECs). But back in 2003, and until at least 2011, three things were very different than they are now: (1) FES’s retail electricity sales were much greater, so its REC requirements were correspondingly greater; (2) the supply of RECs was more limited, so FES was compelled to enter long-term contracts to get enough RECs at an agreeable price; and (3) electricity prices were much higher and were expected to remain high. To ensure a long-term supply of RECs, FES signed eight power purchase agreements (PPAs). Under these PPAs, FES purchased the RECs (and the power, capacity, and ancillary services) from wind- and solar-based generating facilities, such as Duke and Maryland Solar. Also, FES signed three of the PPAs (93 MW of energy) to satisfy a subsidiary’s consent decree with the United States Environmental Protection Agency (USEPA). Subsequently, the government has relaxed the REC requirements. There was also an abundance of RECs available for purchase; and energy and ca- pacity prices became much lower. These market changes rendered the PPAs financially burdensome to FES, which had sold and was in the process of selling its entire retail business and has no commercial or regulatory need for the RECs from these PPAs. In re FirstEnergy Solutions Corp., US Court of Appeals, December 12, 2019.

[31] UK Government (2022), “Competition in the UK Electricity Markets”, Department for Business, Energy and Industrial Strategy.

[32] Section 156, Energy Act, 2004.

[33] Section 157(2), Energy Act, 2004.

[34] Section 95, Energy Act, 2011.

[35] Section 165, Energy Act, 2004.

[36] Section 165, Energy Act, 2004.

[37] Section 20(2)(b), IBC.

[38] For instance, see EIH Limited v. Subodh Kumar Agrawal, IA no. 73 of 2018 in CP(IB) no. 248/7/HDB/2017, NCLT Hyderabad.

This article was originally published in Anusandhaan on 1 May 2024 Written by: Pratik Datta, Associate Director. Click here for original article

Read Less-