Way forward for village power producers Team Up With Large Developers WB

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By 2017-12-18

By Paneetha Ameresekere

Private investors, especially large national and international companies will not be willing to make major investments in mini grids if there is no policy and regulatory clarity as to what
prices they will be allowed to charge and what their post interconnection business options will be, the World Bank (WB) in a recent report said.

Interconnectivity is where privately run mini grids are connected to the Ceylon Electricity Board (CEB).

Without more certainty, private investment in mini grids will be too risky. And the cost of continuing regulatory and policy uncertainty will be the loss of major private investments that could otherwise lead to a significant scale‐up of grid quality electricity in rural communities. In Sri Lanka, legal issues restrict the mini grid's retail sales when the grid arrives. The national utility (CEB) holds a legal monopoly on the right to sell electricity directly to retail customers.

Many large international and national private companies are taking initial steps to develop mini grid projects. International electrical equipment supply companies like Caterpillar, Tesla, Siemens, General Electric, ABB, and others have publicly announced that they intend to enter the mini grid market.

It is still unclear whether they will limit themselves to supplying equipment or they will also take on operational and ownership responsibilities. These companies are building pilot projects with new modular technologies (usually solar PV with some backup or storage system) in a number of developing countries. These large private companies are presumably motivated by the potential to build hundreds of installations using their proprietary technologies. By building at hundreds of modular systems, there will be opportunities for cost reducing economies of scale that were not there among current developers. Unlike present local private entrepreneurs, these new generation companies will have ready access to national and international financial markets. Current mini grid developers almost always used standard existing technologies (mini‐ hydropower and diesel generation). They typically charge customers flat monthly tariffs or postpaid tariffs, relying on basic meters, on‐site meter reading, and in‐person collections. However,

new developers use sophisticated hybrid generating technologies, such as modular solar photovoltaics (PV) combined with batteries and diesel generation and optimized with state‐of‐the‐art control systems. They use prepaid payment systems similar to those used for mobile phones and some solar home system systems in Africa.
'New generation' mini grids also make use of cellular data networks to allow remote monitoring of the generation system, so that engineers can spot problems as they start to emerge and make adjustments or repairs before small problems cascade into larger ones. Some modern mini grid developers make use of sophisticated load dispatch technologies to ensure that priority loads always get electricity by automatically shifting low‐priority loads to times of energy surplus.

Meanwhile, iIsolated micro‐hydropower mini grids were able to get around this CEB restriction by registering as nonprofit Village Electricity Consumer Societies (VECS). The legal interpretation was that VECS do not sell electricity, but rather, self‐supply electricity among dues‐paying members. There is also a legal restriction on wholesale sales of electricity by VECS. In order to interconnect and sell wholesale electricity to the CEB, VECSs must become cooperatives. As VECS they do not have the legal identity to enter into contracts; if they become cooperatives, they can sell to CEB under the standardized power purchase agreement (SPPA) contract.
Few VECSs have pursued this legal option, because of difficulties in obtaining financing and the technical know‐how to support this conversion. Even if a VECS becomes a cooperative, it still needs financing to expand its generation capacity. And since it does not have a history as a small power producer (SPP) selling to the main grid, it would be difficult to obtain loans from commercial banks. Donor programmes that provided grants to VECS are often no longer available.

Joint venture
One plausible alternative would be to form a joint venture (JV) with one of the private developers that has experience selling bulk power to the CEB. The private developer is likely to have easier access to and receive better terms on loans from commercial banks, because it has demonstrated experience in operating larger hydropower‐based facilities. For a VECS (or a successor cooperative), the potential benefit of a JV is that it can access a steady stream of dividends from future bulk power sales. The dividends would provide a regular stream of income that could be used by individual households or the cooperative for projects that benefit the community as a whole. To date no such JVs have been formed in Sri Lanka. The Energy Forum catalyzed the interconnection of three formerly isolated mini grids to the national grid and their conversion to SPPs, working diligently to chart a regulatory and financial path for interconnection. It is unclear whether grid interconnection of formerly isolated mini grids will expand substantially beyond this small number.

CEB
Most VECS were abandoned when the CEB grid reached the villages they served, for several reasons: 1. CEB offered lower (highly subsidized) prices and better service (more hours of service, generally without connection limitations on the size of appliances that could receive service). 2. With a median size of 27 customers, the VECS were too small to survive as commercially viable small power distributors (SPDs). 3. The distribution facilities were not built to meet CEB standards. 4. VECS did not have access to sources of financing that would allow them to finance the cost of interconnection equipment and expansion of their generation capacity. 5. The regulatory requirements to obtain SPP status had been designed for larger generators and were too burdensome for the smaller generators operated by VECS and 6. VECS were widely viewed as a transitional arrangement that could provide a basic level of grid electricity until the CEB arrived with better service at a lower price.

Nonetheless, between 1997 and 2011, VECS built more than 260 individual pico and micro hydropower projects to serve isolated villages. These 'village hydro projects' (VHPs) were small hydropower projects ranging in size from three kW to 55 kW of installed generating capacity and serving 3–80 households. The median system produced 7.5 kW and supplied 27 customers, largely within a two‐kilo metre radius. It is estimated that the VECS created a total of about four MW of installed generating capacity and provided electricity to about 10,000 rural households.In a sample of five VHPs, the unit cost per installed kW of generating capacity ranged from US$1,543 to $2,266 in 2011.

The 260 hydro projects owned and operated by the VECS were the result of two Government of Sri Lanka (GoSL) programmes supported by the WB: Energy Services Delivery (ESD) and Rural Energy for Rural Economic Development (RERED).
The two programmes created credit lines that operated from 1997 to 2012. Loans to the VECS were made by Sri Lankan commercial banks, at more favourable terms because they were supported by WB credit lines. The credit lines were administered by the GoSL, with an interest rate tied to the average weighted deposit rate.
In the absence of these credit lines, it is unlikely that the banks would have been willing to make loans to the VECS, because banks did not have access to other sources of long‐term capital. The credit lines gave the Sri Lankan banks access to a long‐term source of capital specifically targeting the VECS. The Administrative Unit, a group within the Development Finance Corporation of Ceylon (DFCC) Bank, administered the programme. In addition to the credit line, it administered grants from the Global Environment Facility (GEF), channelled subsidies from the GoSL and provided extensive technical assistance to the VECS. A unique feature of the programme was the melding of a community's need for electricity with targeted financial incentives for private sector consultants to assist communities in creating VECS. Selected local consultants received monetary payments if they created VECS that were able to build and operate VHPs.

$ 8,000 payment
Under this programme, a private consultant (called a 'project preparation consultant'), usually an individual or firm with an engineering background, received a payment of $8,000 from the Administrative Unit for each mini grid project. This payment consisted of a down payment of $3,200 upon a review of the technical design, an additional $2,400 upon verification of successful installation and $2,400 after six months of operation. The consultants were required to perform a range of organizational and engineering tasks, which included the following: Identifying viable hydropower sites, engaging with the community, helping form VECS, helping VECS obtain financing, designing, procuring, and installing the project and the necessary distribution facilities, based on guidelines and standards created by the DFCC Bank and financed by the WB's RERED and ESD projects helping the VECS obtain all required statutory approvals and training people in the village to operate and maintain the hydro facility. To ensure that the consultants were competent to perform these tasks, they had to demonstrate a minimum level of knowledge and experience in small hydropower generating projects. In granting registration to applicants, the Administration Unit looked for both engineering and 'social mobilization' skills. Before the two WB projects, various nongovernmental organizations (NGOs), such as the Intermediate Technology Development Group (ITDG, now known as Practical Action) obtained funding from donors such as Rotary International to build micro‐hydropower facilities in a few remote villages. These pioneering projects 'proved the concept'. Building on these experiences, the WB funded ESD programme provided funding and technical assistance to scale up the concept and moved from pure grant funding to semi‐commercial financing. Financing was combined with targeted technical assistance provided by mostly private consultants operating under a performance‐based incentive system. The initial (pre‐ESD) village hydropower projects were 100 per cent financed by grants. Over time projects were able to obtain financing from about 10 local commercial and regional development banks that had access to a WB credit line,

which allowed the banks to offer better terms. The credit line demonstrated that the projects were perceived as being financially viable by commercial banks at least for the period of the loan. For a 10 kW VHP that served 40 households with an overall cost of about $16,900, the typical financing plan for later projects was funded as follows: commercial bank loan: 35 per cent, co‐financing grant from the GEF: 29 per cent, equity from VECS members: 18 per cent and provincial council grant: 18 per cent. The terms of the commercial bank loans are not public because they are in private loan agreements. However, one knowledgeable observer estimated that in 2010 the typical loan had a 16 per cent interest rate and a term of four to five years. This rate was considerably lower than the estimated 48 per cent interest rate that local nonbank lenders were charging rural households at the time. Some of the commercial bank loans were made to the VECS; others were made to individual members of the VECS. The fact that most isolated community‐o

wned mini grids stop making retail sales does not necessarily mean that they will transition to grid‐connected SPPs. In Indonesia, only nine mini grids successful made the transition with the arrival of the main grid; about 150 projects were abandoned. In Sri Lanka, of the more than 250 mini grids that were formerly isolated, only three connected to the main grid as SPPs; more than 100 were abandoned. In both countries, the isolated mini grids were community owned. Whether the outcome would have been different if the mini grids had been privately owned or community owned mini grids had been allowed to create JVs with private companies is not clear. Whether or not a mini grid becomes an SPP seems to be highly dependent on the level of the feed‐in tariff. Selling electricity to the national utility, where it is allowed, often means accepting a low feed‐in tariff (typically the utility's avoided generating cost from very large power plants).

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