MIDEPLAN’s project assessment methodology

As has already been mentioned, the PER was a centrepiece in a broader rural infrastructure investment programme established during President Frei’s administration. The rationale behind those programmes was the extension of service provision at a residential level. For that reason, most of the technical support and dedicated funding was targeted at the provision of basic services to rural households and complemented services in schools, health clinics and community centres. Productive activities were not considered as a priority at that point but as the secondary result of basic infrastructure provision (McAllister and Waddle, 2007, IEA, 2009a).

Figure 4-3: Share of technology source in Rural Electrification in Chile (2002-2012) Source: author’s compilation of data from Ministry of Energy (2010) and GEF (2011a)

A crucial feature of all rural infrastructure programmes (including PER) was the provision of investment subsidies through the National Fund for Regional Development (FNDR). As rural electrification was considered the backbone of much rural investment, in 1996 a dedicated budgetary line within FNDR (called ‘FNDR-ER’, following the Spanish acronym for Rural Electrification ‘ER’) was created specifically to subsidise rural electrification projects. Funds flowed from the Treasury, through the administration of SUBDERE, to the Regional Governments, whose Regional Council boards had autonomous powers of deliberation and allocation. All projects applying for FNDR funding must be assessed (and approved) in terms of the project assessment methodology developed by MIDEPLAN. This assessment is based on a Cost-Benefit Analysis (CBA) which is undertaken to evaluate both wide (social) net benefits and financial (private) benefits.

Following strict assessment procedures and defined parameters, the tool allows the calculation of a maximum level of subsidy.

The rationale behind subsidised rural infrastructure programmes lies at the heart of the neo-liberal state. The limits to free market resource allocation are defined by the forces of the market, in this case private distribution companies seeking to maximise profits, something which in practice defines the what, the how and the to whom in the provision of a public service. In other words, distribution utilities devised strategic investment plans consistent with sectoral regulations and designed series of rural electrification projects in accordance with their own decisions about quality of service, technological choices and geographical distribution. As distant and dispersed rural electrification projects have never been an attractive business, with the implementation of the PER the state assumed its constitutional subsidiary role, which assigns the responsibility to governmental institutions to fulfil a societal need only when the market is unable to do so in an appropriate way. In other words, the state remains involved in public service provision only in those areas in which demand cannot be met through the market, i.e.

through the initiative of private actors. State entrepreneurial action is limited by constitutional rule, which protects private property and private entrepreneurial initiative.

Within this context PER policy design included a detailed procedure for the assessment of infrastructure provision projects subject to financial support from public funds. For this, the major tool has been MIDEPLAN’s methodology. In the case of rural electrification the methodology guides project design and assessment processes. For a project to receive a FNDR subsidy, two conditions must be met. Firstly, the project’s

economic benefits over a given lifespan have to exceed the project’s total costs²⁷. Secondly, financial benefits (i.e. those benefits accruing to the distribution company as a cash flow of electricity sales) must be less than total investment and operating costs during the same project’s lifespan. Whenever the two conditions are met, a subsidy is set in order to reach a break-even point. The maximum subsidy can therefore cover only the capital cost of infrastructure and never operating costs. If, on the contrary, financial benefits are higher than costs, a sufficiently positive net present value (NPV) and an attractive internal rate of return (IRR) should persuade private utilities to embark on the project on their own.

Economic benefits (also referred to as social benefits) are valued by means of a theoretical demand curve which is estimated from two points (baseline and projected energy consumption and prices). In the baseline case, consumption and expenditure are taken from census data (for most grid extension projects) and surveys of beneficiaries (mainly in the case of RET-based off-grid projects). Typical values of baseline demand for non-electrified communities are 3-5 kWh/month equivalent per household (mainly candles, kerosene or carbide lamps and batteries) at a market price of about US$5-10/month. Projected demand varies with region and socio-economic stratum, but typical values for grid extension and mini-grid projects are about 25-30 kWh/month and 10-15kWh/month for RET-stand alone off-grid electrification²⁸. Electricity prices are defined by regulated distribution tariffs in the case of grid extension and, for most off-grid projects, tariffs are piecemeal, although there is a trend to estimate cost recovery tariffs. Net benefits are calculated by annualising investment cost (on year zero) and operating costs, estimated economic benefits and revenues from electricity sales. NPV is calculated over the project lifespan (30 years for grid extension and 10 for RET-based electrification)²⁹ at a discount rate set by MIDEPLAN (between 12% and 8% during PER implementation).

Financial benefits (also referred to as private benefits) are valued at market prices and calculated as a traditional financial cash flow of investment cost, annual operating cost,

27 These economic benefits include direct returns/income from electricity sales and other external benefits such as increased welfare as a result of better quality of service (i.e. higher energy consumption at lower prices than in a baseline scenario) and extended productive time or study hours.

28 Values taken from Project Designs and official PV project submissions to FNDR.

29 RET projects have a lifespan of more than 10 years, but the methodology uses this very limited period due to the technological uncertainty of RET projects. This represents in fact a counter protection measure for RETs compared to the long period in which conventional technologies can recover investments (30 years).

depreciation, interest payments and revenues from electricity sales. As the NPV in this case must be negative, the maximum subsidy to be considered is the portion of the capital investment that turns the financial cash flow (NPV) positive discounted at the

‘social’ rate defined by MIDEPLAN. This methodology is very efficient in supporting projects that are viable for the country and attractive for private distribution companies (when subsidies are provided).

Although the methodology was designed particularly for grid extension projects (in which case most of the variables and parameters could be estimated from previous experience in grid extension projects), the same methodology has been applied to off-grid RET projects. In such circumstances, certain assumptions are made, such as future electricity tariffs, unknown maintenance costs and other baseline parameters, which increase private investors’ perception of risk. Furthermore, the seminal PER policy paper (1994) and its subsequent versions have made explicit that where possible grid extension is to be sought: off-grid RET projects are to be considered as a last resort alternative in rural electrification, even if the per user cost of grid-based projects is higher than alternative sources (Covarrubias et al., 2005, MIDEPLAN, 2007).

A substantial step towards regime stabilisation was taken in 2007 when the broadly accepted MIDEPLAN methodology (CBA) was radically changed (MIDEPLAN, 2007). This was a response to recognition that the most pressing electrification targets were not being achieved due to i) the higher cost of grid extension to extremely remote rural areas and ii) the increasingly reduced capacity of centralised and decentralised institutional actors to negotiate and incentivise distribution companies to implement projects. This change removed the requisite of carrying out Cost Benefit Analysis (CBA) for the remaining non-electrified rural households. It was decided instead that least cost grid extension options should be sought and projects should be assessed according to a Cost Effectiveness approach. To that end, a reference cost cap per household was established (which varied according to region), increasing historical electrification costs so projects would become attractive to distribution companies, no matter how economically viable they were (given the high subsidies these would receive). Off-grid RET electrification continued its modest progress in those areas included in the national project portfolio (which is described further in next section). This change of methodology implied that many grid extension projects that otherwise could have been considered for RET electrification became open to subsidies and hence finally executed, at an even higher cost than the off-grid RET alternative.

4.6 In Search of Alternative Solutions: the Emergence of Off-Grid Rural