Sustainable electricity pricing for Tanzania

In order to fulfil its aspiration to become a middle-income country, Tanzania is working on improving infrastructure and service delivery in electricity provision, where $40 billion investment is needed in the sector to meet rising demand and widening electrification efforts from 2013 to 2035. This paper considers the institutional arrangements for investment in Tanzaniaâs power sector and surveys the track record (and possible bottlenecks) in funnelling investment to the sector, with special attention given to the gas sector, given the power sectorâs planned reliance upon natural gas as a generation fuel. The paper finds that the financial health of TANESCO is central to all investment vehicles, since it is either directly responsible for investment, or indirectly, as the counter party to the variety of PPAs available with IPPs, EPPs, SPPs, or PPPs. During 2011â13, the financial position of TANESCO was negatively impacted by the increased of its electricity purchases, while the regulated tariff that it charges has not changed. The cost increase is partially attributable to non-favourable hydrology and partially attributable to the depreciation of Tanzanian shilling against the US dollar, in which PPAs are denominated. Detailed study of the tariff setting methodology in place in Tanzania, as evidenced through its latest tariff review, and evaluation of the ratemaking principles used in the tariff approved in 2013 reveals that the core tension within Tanzaniaâs tariff setting methodology is the trade-off between efficiency, sufficiency, and stability principles. The ex-ante assessment of TANESCOâs revenue requirement, a typical incentive-based price cap regulation, is theoretically efficient but not robust: TANESCOâs costs of service are subject to important external uncertainties like hydrology, currency depreciation, and global fuel prices. In order to take revenue sufficiency into account, the regulator needs to periodically adjust tariffs based on ex post fuel costs and inflation rates. This diminishes the regulatorâs ability to maintain tariff stability, which might impact certain classes of customers more than others (lifeline rate customers and domestic industries). The experiences of other nations, namely Bangladesh and Côte dâIvoire, reveal a potential challenge with regard to power and gas co-development: if non-cost reflective gas tariffs are applied as a regulatory decision, then high gas demand that results from that cannot be indefinitely sustained, since investment in gas supply will not follow suite. The case study of Côte dâIvoire also reveals a less obvious opportunity: periods of low electricity demand can be leveraged positively through electricity exports, which can positively influence investor interest