Investment options and least cost planning in the electricity sector in India

Abstract

Today, the notion that all of the electricity sector is a natural monopoly, and as such is best organized as a regulated monopoly is no longer valid. Developments in contracting in regulation methods, in information technology, especially in ease of measurement and online monitoring, and in unbundling make possible varying market structures. Thus ‘markets’ have been crafted in electricity generation. In the Indian scenario the hesitant transition from a completely regulated and government owned ‘cost plus‘ structure to a more pluralistic structure that includes the possibility of markets, throws up major challenges to planners and regulators. Currently, independent power projects (IPPs) have been able to negotiate ‘take or pay’ contract ‘embodied’ in power purchase agreements (PPAs) for long periods, that have significantly shifted risks on to the State Electricity Boards (SEBs) with whom they have contracted. These PPAs and the entire transition process adopted have given rise to the following questions and debates: • How do these PPAs compare with a possible competitive market that could have been constructed? Thus, what should be the necessary terms and conditions in the future agreements, or in regulations such as to ensure that contracts do not impose costs greater than long run marginal cost. • Some have argued for the need for a take or pay contracts in the present scenario of policy and regulatory uncertainty where private parties would be reluctant to invest otherwise. There is a need to analyses the impact of the policy of ‘guaranteed off take’ on the cost of electricity supplied to the consumer. • Policy has also attempted to actively promote foreign investment in the sector. The foreign exchange outflow in order to service the investment payment obligations as contracted through these PPAs are known to further aggravate the financial burden on the consumer and the buying entity, typically the State Electricity Boards. There is a need to assess these costs systematically. • Similarly, private finance in the current situation of policy and regulatory uncertainty has come at a very high cost. When the private project is also foreign financed and owned, these costs go up not only due to the ‘perceived country risk’, but also because of the interlocking of the markets for technology and= equipment and that of finance. Such costs need to be assessed and estimated. • Similarly, there are significant differences between using domestically available resources such as coal, and imported fuels such as gas and oil, especially because the country is foreign exchange constrained. The effect of such constraints on optimal capacity addition to the sector needs to be understood to arrive at any sort of fuel I technology preference. The policies adopted by the sector in the nineties have been subject to much controversy and debate. The study aims to examine the impact of the PPAs and some of the policies with reference to the above observations with the help of a model. The need for models stems from the complexity of the problem. The varying load curve, long life of assets, significant tradeoff between fixed and variable costs, differences in cost structures allowed to generators (IPPs being allowed depreciation over 10 years whereas ‘public’ plants are allowed lower rates of depreciation), discreteness of capacity addition all interact to make the problem complex. An optimization model is developed and used to answer the questions and issues raised above. Various scenarios are generated. (i) Under the condition of no constraint; (ii) when a public budget constraint is introduced; (m) when a foreign exchange constraint is introduced; (iv) the CEA cleared projects for the 9"‘. 10"‘and 11"‘Plans are assumed to be commissioned within the next 10 years; (v) where the policy of ‘guaranteed off take’ is introduced. For each of these situations/constraints. the least cost investments necessary, and what is the generation nix at the different loads is generated as the solution of a linear optimization model. • The solution then gives the costs over other possible situations/constraints • Its impact on the tariff and hence on the consumers and the SEBs is also estimated. The tool used to develop this model is GAMS, which has already been widely used for planning purposes in the electricity sector. However, the foremost reason for using this tool is its availability, easy access and flexibility. The results of the model just confirm many of the criticisms made against the current policy and especially the IPP policy. Its principal contribution is to allow quantification of the costs imposed by improper policy. The lowest cost optimal solution is achieved through investment in public plants. As budget constraints are imposed, investments in higher cost private IPPs are forced. However the highest cost scenario is where CEA cleared IPPs are all commissioned and are guaranteed 80 per cent off take. Besides, the peak demand remains unmet in some years as the constrained financial resources are utilized in financing the high cost investments of the early years. Moreover given the foreign exchange constraint, the guaranteed off take would be difficult to achieve if the CEA cleared IPPs are all commissioned as per plan. In case the resource constraint is relaxed, the additional cost of the off take policy is not in-substantial. Some other salient observations are: (i) the peak electricity demand is ideally met through combined cycle plants or open cycle plants, besides hydro; (ii) thermal and nuclear plants are operated to meet the base load; (m) in the unconstrained situation low capital cost open cycle plants are a preferred choice over hide, though operating costs are much higher; (iv) the results are much more sensitive to the operating than the servicing costs.