The Electricity Act restructured the electricity sector into separate generation, distribution and transmission sectors. Additionally, there exists a separate market for electricity trading that is undertaken by companies with a trading licence or at power exchanges.
Generation of electricity (including captive generation) is a delicensed activity (other than for hydro projects exceeding the notified capital cost, for which an approval of the CEA is required). Private entities are permitted to set up power stations using any type of fuel or power source (such as coal, gas, wind, solar and biomass) except for nuclear power projects, which may be undertaken only by a government of India entity or a government company (ie, where the government holds a minimum of 51 per cent of the shareholding).
Power generation activities in India are dominated by long-term power offtake purchase agreements. For thermal power projects (coal and gas) and hydro projects, long-term power is procured either through a negotiated route or a competitive bidding route. Under the negotiated route, a distribution company’s power procurement tariff is determined by the relevant electricity regulatory commission, upon considering various factors such as return on equity, interest on loans and working capital, depreciation, operation and maintenance expenses and allowances for any renovation and modernisation. Under the competitive bidding route, the tariff discovered through a competitive bidding process is adopted by the relevant electricity regulatory commission and procurement is governed by standard bid documents including power purchase agreements, which are issued by the Power Ministry. While the statutory option to procure electricity under the negotiated route still exists, the Power Ministry has directed state governments and distribution companies to procure power only under the competitive bidding route (except that negotiated route may be used for hydropower projects until the end of 2022 and waste to energy projects).
Prior to 2013, all tariff-based competitive bidding for thermal power projects was done through standard bidding documents, which provided for two modes for procurement (ie, Case 1 and Case 2). Under Case 1, all project assets and inputs (such as land, fuel, water, etc) and relevant statutory approvals required for the construction and operation of, and the supply of power from, the power station had to be arranged by the power producer, while the same had to be arranged by the distribution licensee in Case 2. While these standard bidding documents provided a comprehensive framework for procurement of electricity, they did not address key concerns such as shortage of fuel availability in the domestic market, indexation of fuel prices to market rates, uncertainty in obtaining key approvals such as environmental clearance, delays in land acquisition and foreign exchange variations.
In order to address the manifold concerns of all stakeholders, in 2013 the Power Ministry issued revised competitive bidding guidelines and standard bidding documents that provided for two modes of bidding and supply of electricity (the Revised Standard Bidding Documents (SBDs)):
- design-build-finance-own-operate model (DBFOO) (on the lines of Case 1); and
- design-build-finance-operate-transfer model (DBFOT) (on the lines of Case 2).
The Revised SBDs prescribe higher normative availability, single-variable bidding, restrictions on usage of fuel procured at subsidised rates from government suppliers, pass-through of variable charges (including cost of fuel) to consumers, detailed construction, operation and maintenance standards, appointment of a mandatory independent engineer for each project and also provision for the cost of imported fuel to be benchmarked at actuals and linked to prevailing prices on international indices.
Following the dismal industry response to the competitive bidding process for allotment of ultra-mega power projects (UMPPs, ie, coal-based projects of at least 4GW capacity) that were proposed on the DBFOT model, and general criticism from developers and lenders with respect to various aspects of the DBFOT model, the Power Ministry issued draft guidelines and standard bidding documents for UMPPs. The draft bidding documents for UMPPs (which are based on domestic captive coal blocks) contemplate a build, own and operate structure where the government provides part of the land for the power plant and the captive coal block on a long-term lease to the selected bidder and the selected bidder is required to build and operate a power plant and sell the power generated under a long-term power purchase agreement with state distribution licensees. The draft proposes that upon expiry of the power purchase agreement term the power generator will cease to have any rights over the coal block but will continue to have leasehold rights over the power plant land. The Power Ministry has not clarified the rationale of this approach and hence this structure appears to be fraught with key bankability issues. A key lender concern is the obligation on the developer to acquire the remaining part of the land (ie, the land required in addition to the part of the land provided by the government) required for setting up the power plant and captive coal block.
In addition to long-term power procurement guidelines, the Power Ministry has introduced guidelines (and revised standard bidding documents) for medium-term power procurement (ie, one year to five years) of electricity from coal, gas or hydro-based power stations on a finance, own and operate basis, and power traders and distribution licensees having back-to-back arrangements with power generators. As per media reports, the Power Ministry is in the process of releasing new norms for medium-term (five to seven years) power purchase agreements with an aim to revive commissioned stressed coal-based plants. Further, the Power Ministry has introduced a pilot scheme for the procurement of aggregate power of 2.5GW for three years from commissioned coal-based generating companies that are not party to a power purchase agreement. The Power Ministry has also issued revised guidelines for the procurement of power on a short-term basis (ie, for a period of more than one day up to one year). The revised guidelines introduce tariff determination through an e-auction with an overall aim of reducing power procurement costs in the short term for distribution licensees. Additionally, the Power Ministry is also in the process of finalising new bidding documents for short-term power procurement (one day to one year).
For renewable energy projects, power is typically procured through contracts entered into with state utilities under specific state policies at a regulator determined feed-in tariff or at a tariff discovered through competitive bidding depending on the state or central policy. All distribution utilities, captive-power users and open-access consumers are mandated to procure a prescribed quantum of electricity generated from renewable energy sources (ie, RPO). The Tariff Policy sets out several measures to promote renewable energy development in the country, including: an increase in the solar RPO to 8 per cent by 2022; procurement of power from renewable energy sources by distribution licensees through competitive bidding; and applicability of RPOs on cogeneration power plants. In order to further the objective of renewable energy development, the relevant electricity regulatory commissions have introduced market-based policy instruments (referred to as renewable energy certificates (REC)), which the renewable energy producers can get if they do not opt for the preferential feed-in tariff offered by distribution utilities. To incentivise distribution licensees to procure renewable energy, all distribution licensees procuring renewable power above their RPOs are also eligible for obtaining RECs. Additionally, the Supreme Court of India (Supreme Court) has also upheld the imposition of RPO on captive power generators and open-access consumers on the ground that there is a need to promote renewable energy. On the other hand, despite electricity regulatory commissions having the authority to enforce RPOs, there is repeated failure by the state distribution utilities to comply with their RPO requirements, and accordingly there is abundant supply of RECs in the market, with few takers. In this regard, penalties for non-compliance with RPOs are proposed to be increased under the Proposed Electricity Act Amendments and the proposed Renewable Energy Act (RE Act). Finally, the Ministry of New and Renewable Energy (MNRE) recently constituted a RPO compliance cell to handle all RPO compliance issues across states and to publish monthly reports on compliance, among other activities.
Captive power plants
Another mode of setting up generation facilities is through captive power plants where the captive power user has to hold a minimum of 26 per cent of the ownership of such power plant and should consume at least 51 per cent of the annual aggregate electricity generated by such a power plant. The Power Ministry, on 22 May 2018, issued draft amendments to the electricity laws governing captive generating plants (which are yet to be notified). The proposed amendments aim at reinforcing the intent of the legislature by ensuring that there is actual ownership in the company developing and operating the captive power project and consuming the electricity generated by the project. To this end, the proposed amendments to the Electricity Rules, 2005 prescribe an ownership stake of at least 26 per cent of the equity share capital with voting rights (excluding equity shares with differential voting rights and preference shares), mandate a maximum of two shareholding pattern changes per year and allow for a variation in consumption in proportion to their ownership shares not exceeding 15 per cent and in case of solar and wind power plants not exceeding 30 per cent. Additionally, the CERC has amended its regulations, to disqualify renewable energy generators (including captive generators) - to the extent of their self-consumption and selling of power on open access while availing promotional wheeling, transmission, cross-subsidy or banking charges - from obtaining the benefit of RECs. The amendment aims to reduce the unsold inventory of RECs, of which a major portion is contributed by captive generators. The CERC was of the view that developers under the third-party model were able to leverage the concessional benefits, while participating under the REC framework, and has therefore amended the regulations in order to prevent developers from doing so. However, the CERC has given renewable energy generators (including captive generators) the option of availing the benefit of RECs three years after they forgo the benefits of concessional transmission or wheeling charges or the banking facility benefits or both.
Transmission of electricity in India is a licensed activity and transmission systems are divided into interstate and intra-state transmission systems. The interstate transmission system is mainly owned and operated by Power Grid Corporation of India Limited, a government of India-owned company, and the intra-state transmission systems are owned and maintained by state transmission utilities.
Transmission projects may be undertaken for developing new transmission systems or for strengthening the existing transmission system (which typically include investments in substations along with transmission lines for augmenting the capacity of the existing transmission system). In a manner similar to generation projects, such projects may be implemented under two modes, namely the negotiated route (where the transmission tariff is determined by the relevant electricity regulatory commission) and the competitive bidding route (where the transmission tariff is discovered through competitive bidding under standard bidding documents). For interstate transmission projects, the Tariff Policy states that while all future interstate transmission projects should ordinarily be developed through competitive bidding, the central government may give an exemption for certain projects that are of strategic importance or technical upgrading and where works are required to be done to cater to an urgent situation on a case-to-case basis. For intra-state transmission projects involving a project cost beyond a certain threshold, which will be determined by the respective SERC, such projects are to be developed only through the competitive bidding route.
At present, the sale and distribution of power to consumers is undertaken under a single licence and once the distribution licence has been issued, the licensee does not require a separate licence for the sale of power. However, the Proposed Electricity Act Amendments provide for segregation of supply and distribution activities by allowing multiple suppliers of electricity to use the distribution network provided by a separate entity, each requiring a separate licence. It is proposed that distribution licensees give up all supply related functions. Furthermore, existing power procurement arrangements of distribution licensees will vest in intermediary companies, which will be specially created for this purpose.
Electricity trading is a distinct recognised activity for which a separate licence is required (except for distribution licensees) from the CERC or a SERC (for interstate and intra-state trading respectively). Trading may involve purchase of electricity from generating stations or distribution licensees for sale to end consumers.
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