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Flexible Connections

Solutions and Challenges for the Integration of Renewables in South America

Figure 1. Percentage contributions of CO2 emissions in 2008.

Figure 1. Percentage contributions of CO2 emissions in 2008.

South American countries account for a small portion of global greenhouse gas emissions (GHE), as seen in Figure 1, which shows the percentage of worldwide GHE originating in Brazil (1.35%), Argentina (0.64%), Chile (0.24%), and Peru (0.13%). While the low level of GHE is partially due to the relatively low level of economic development of these nations, the main reason is the region’s very clean electricity supply mix, with about 50% of installed capacity coming from hydropower sited in the large rivers crossing the continent. The South American region is also among the most promising lands for the development of nonconventional renewable energy (NCRE), encompassing all renewables except large hydro. The strong and persistent wind flows, availability of suitable sites, and thousands of sunny hours a year provide a significant potential for several types of NCRE. In addition, the region’s hydro reservoirs can easily smooth out production fluctuations of intermittent (wind and solar) or seasonal (biomass) energy sources, thus providing operational flexibility and facilitating their reliable and economic integration.

The participation of NCRE in the region’s energy matrix has been increasing. The most relevant options are small hydroelectric plants (considered as NCRE) and wind, solar, and biomass power plants, especially cogeneration plants using sugar cane bagasse. Load factors of 40–45% for wind power are common in some countries. NCRE turns out to be attractive due to a number of factors that are not strictly related to emissions reduction:

  • From the security-of-supply perspective, NCRE provides the opportunity to diversify the current generation mix, currently heavily based on large hydro -facilities.
  • From an economic perspective, there is a strategic objective of diversifying the generation mix, particularly in countries de-pendent on foreign energy supplies.
  • Finally, from a portfolio management standpoint, the lack of a coherent policy for environmental licensing and strong regulatory actions against reservoirs often lead to delays in the construction of conventional hydro plants, which can affect supply reliability. In contrast, renewable generation is usually spread out over several plants with smaller capacities, which provides a “portfolio” effect and thus a hedge against project delays. Also, NCRE construction time is short (about 18 months) in contrast to at least five years for conventional hydro. This allows flexibility in the entrance of new capacity—a valuable hedge against the region’s load growth uncertainty.

Certain support mechanisms for NCRE have been in place in the South American region for the past ten years, typically in the form of fiscal or tax incentives for renewable development in states or municipalities. At the beginning of the last decade, Brazil and Argentina implemented costly subsidies (similar to the feed-in tariffs in Europe) to foster renewables. Afterwards, with the implementation of long-term auctions for energy contracts to attract new generation beginning in 2004, auctions gained momentum and also started to be used in several countries as the main explicit support scheme for NCRE beginning in 2007. Auctions function as an indirect price discovery mechanism, and they also result in the right amount of investment and reduce risk aversion with long-term contracting. Moreover, auctions provide transparent and efficient outcomes that are unlikely to be challenged in the future as political and institutional scenarios change. This is the case in Brazil and Peru, where renewable auctions complement the regular auctions to attract conventional generation. Argentina and Uruguay have also implemented specific auction processes to attract NCRE. Chile has opted for a compulsory quota scheme placed on the generators (they have to demonstrate that part of the energy contracted is being supplied by NCRE). Explicit support mechanisms used by other countries include solely soft loans, tax credits, fiscal incentives, or specific funds to foster NCRE investment in isolated areas.

Another source of funding for NCRE in the region has been the carbon market associated with the United Nations clean development mechanism (CDM). Most NCRE projects reduce GHE by displacing the use of fossil fuels, allowing those projects to claim and later sell certificates of emission reductions (CERs) to developed countries committed to reducing emissions. Several wind farms, mini hydro, and biomass projects have been registered. Latin American and Caribbean countries have contributed 19.6% of the worldwide total of these types of projects. Brazil follows China and India in the list of countries with the most projects registered in the CDM program, while Chile (second in South America) is in the seventh position worldwide.

There are several regulatory and technical challenges for the successful implementation of a support scheme to deploy NCRE. On the regulatory side, the design of the support mechanism itself is an issue. On the technical side, however, the integration of NCRE into the transmission and distribution grids is by far the most difficult challenge in a region that does not have the type of meshed networks existing in the more fully developed countries of the northern hemisphere. This article describes how the South American countries of Argentina, Brazil, Chile, and Peru are integrating NCRE, including hundreds of small-scale NCRE installations, and how those networks are being planned. Table 1 summarizes some key statistics for each of the countries.

table 1. Country data (2010).

Country (Population, in Millions) Installed Capacity (GW) Energy Demand (TWh) Peak Demand (GW) Electricity Consumption Growth Rate per Year (%)
Brazil (190) 115 454 72 4–5
Argentina (40) 28.7 115.7 20.8 4–5
Peru (29) 6.5 32.3 4.6 7–10
Chile (17) 16 55.2 8.5 4–6

NCRE in Brazil

Figure 2. Evolution of contracted wind power (installed capacity and average contract price).

Figure 2. Evolution of contracted wind power (installed capacity and average contract price).

Brazil does not have any specific energy targets for NCRE. Since 2007, NCRE has been economically encouraged through technology-specific auctions. Reserve energy auctions have been organized by the government to increase the country’s reserve margin. Although NCRE does not fit the profile of “reserve generation,” these auctions have been used to stimulate competition between different projects of the same renewable technology with the government defining the amount to be contracted. In the case of wind, 20-year contracts with special risk management clauses to mitigate wind production uncertainty are offered. Accounting rules to verify a predefined MWh delivery over four years apply to these contracts, and all consumers pay for this energy as a system charge. The government can also determine the type of supply that can participate in the regular auctions carried out by distribution companies to supply the captive load with firm energy contracts. For example, because the participation of coal- and oil-fired plants is forbidden for environmental reasons, some auctions had the candidate offer restricted to renewables, and some auctions stimulated competition between renewables and gas-fired plants. A total of seven specific auctions for NCRE have been conducted since 2007. Figure 2 shows the cumulative contracted capacity of wind projects in the country, which reflects the support mechanism and the resultant lower prices for those resources: some 6 GW of wind were acquired from 2009 to August 2011 through auctions, with an average price of US$78/MWh (load factors of 45%). The most recent auction—organized in December 2011 and not represented in Figure 2—contracted an additional 1 GW of wind with an average price of US$60/MWh.

A significant challenge for Brazil is the regulatory and technical coordination between the hundreds of candidate NCRE projects at the auctions and transmission planning. Basically, NCRE traditionally had two grid connection options: 1) connect directly to the main high-voltage (HV) $230-kV grid, through the closest HV substation or 2) connect directly to the distribution network. Individual connections to the HV grid are always paid for by generators. One major hurdle is the regulatory responsibility for planning, constructing and charging for transmission/distribution grid reinforcements. This complexity is further compounded by the economic bids of new NCRE projects in the auctions needing to account for estimates of the associated transmission charges, and that NCRE are usually spread out into a wide geographic area in a large country such as Brazil.

The Traditional Transmission Planning and Cost Allocation Scheme

The Brazilian HV transmission regulatory framework mixes indicative planning and competition in the process of designing transmission reinforcements and sending the locational signals for the installation of new generation before the each generation auction is conducted. This is done as follows:

  1. Every year, the government planning company (EPE) proposes a network expansion plan for the next five years. This plan is initially submitted to a public hearing and afterwards is assessed and approved by the Ministry of Mines and Energy.
  2. The regulator organizes auctions to procure the construction of the approved transmission reinforcements. Each bidder offers a fixed annual remuneration for the construction and operation of each transmission facility (no congestion revenues are assigned to the transmission lines) and the winner (the lowest bid) receives the requested remuneration when the facility starts -operation.
  3. The total revenue required by the basic grid in a given year is the sum of the fixed remunerations of all transmission facilities in operation in that year. This total revenue is collected from the generators and loads—on a 50-50 basis—through fixed monthly charges, called the transmission use of system tariff (TUST).

The TUST charges, calculated using a long-run marginal cost (LRMC) methodology, serve as economic signals for the siting of generation facilities and loads and are used by candidate generators in their economic evaluations prior to participation in generation contract auctions. Because transmission charges may vary by as much as US$10/MWh depending on plant location, they may promote one type of plant over the other. This means the TUST might be a significant component of the costs to generator owners and, ideally, should be known before the generation auction takes place, for risk management purposes. Since 2008, estimates of TUST charges for every candidate generator in the energy auctions have been precalculated and released for the next ten annual tariff cycles, and they remain fixed (they are updated according to a consumer price index). This mitigates the exposure of the investor to tariff volatility. The demand segment is responsible for the monetary differences between the charges resulting from the precalculated tariffs and the charges that result from the actual tariffs. The actual tariffs are obtained by applying the LRMC pricing scheme after the actual network is known (i.e., after the generation auction takes place).

Distribution companies, rather than an EPE, are responsible for the planning and construction of distribution-level (#138-kV) reinforcements in their concession areas. The connection of generation to the distribution network is done on a first-come, first-serve basis. In contrast to transmission interconnections, however, the resulting connection tariff (the distribution use of system tariff, or TUSD) is known only after the auction occurs. (It will depend on the distribution company’s investments to support all approved connections.) Unlike in the basic bulk transmission grid, costs in the distribution network are not required to follow a predefined allocation pattern among generators and loads. Additionally, the TUSD can vary on a yearly basis, according to new distribution network reinforcements.

NCRE as a Driver for New Planning and Cost Allocation Schemes

What should change in this planning and cost allocation scheme with a higher penetration of location-constrained, smaller-size renewable generation projects? This question arose initially in 2008, when hundreds of candidate biomass and small hydro projects, spread over 200,000 km2 in the country’s midwestern portion, were to participate in a NCRE auction. A challenge for regulators assigning responsibility for planning, constructing, and charging the transmission costs was observed: planning the integration of large-scale renewable energy into the basic grid was a regulatory no-man’s-land. The EPE had no mandate or personnel for planning distribution-level reinforcements, and -distribution company planning teams had insufficient capability to address this matter.

Figure 3. Integration network, indicating SFGs.

Figure 3. Integration network, indicating SFGs.

Because of the urgent need to integrate about 80 NCRE plants, a third connection option based on a cooperative transmission-planning and connection scheme was designed jointly by investors, the regulator, and the Ministry of Mines and Energy. The core of this scheme was the cooperative planning of integration networks to connect the NCRE. These networks became known as SFGs (an acronym for “shared facilities for generators,” i.e., facilities used exclusively by generators but shared by different projects) and were planned with help of a computational model based on mixed-quadratic-integer programming. This model optimally plans and locates an integration network with layers of shared connections (by means of collector and subcollector stations) at different voltage levels. As illustrated in Figure 3, this avoids the need for individual connections to the HV grid for the exclusive use of each generator.

By individually connecting each generator to the transmission network entry point, opportunities for economies of scale would be lost. The concept of SFGs captures such economies of scale while making it simple to allocate the facilities’ costs only to the generators responsible for them (as opposed to what would happen if the facilities were to be considered part of the bulk transmission network). A simple MW-mile scheme was used, through which the yearly charges of each generator were calculated in proportion to the use of each facility.

This scheme results, in several cases, in benefits for the NCRE generator when compared with the alternative of individually connecting to the HV grid and paying the TUST. An auction mechanism, similar to that used in the HV-grid approach, is applied to grant the rights to operate and maintain the SFGs.

Figure 4. Chapadão Substation and the associated SFG and exclusive-use transport facilities, auctioned in 2008.

Figure 4. Chapadão Substation and the associated SFG and exclusive-use transport facilities, auctioned in 2008.

A preliminary integration network was designed, and a preliminary cost allocation was released for the initial set of generators. Next, generators were asked to reconfirm their intention to join the “network construction pool” by depositing financial guarantees (typically US$500/kW). The final network was redesigned for the set of “confirmed” generators, and more accurate cost estimates were provided. Those more accurate estimates were issued by the regulator, Agência Nacional de Energia Elétrica (ANEEL), before the NCRE auction and will be kept constant (at the July 2008 level) until June 2015. In parallel, estimates of TUST (for the bulk transmission network) were also provided to generators; those were to be binding for a period of ten tariff cycles. With this binding information on transport costs, generators could better form their bids in the NCRE auction.

After knowing the results of the generation auction, the final network (including SFGs and any reinforcements to the HV transmission grid) was then designed, and an auction was conducted for construction. This procedure was successfully employed in 2008, resulting in ANEEL carrying out a public auction for the construction of about 2,500 km of 138-kV and 230-kV transmission lines to integrate about 30 NCRE projects. Figure 4 illustrates one set of auctioned transmission facilities.

Learning and Improving: The 2009 NCRE Auction

Figure 5. The 2009 Brazilian NCRE auction: illustrative comparison of numbers of candidate and winning projects.

Figure 5. The 2009 Brazilian NCRE auction: illustrative comparison of numbers of candidate and winning projects.

Due to the large number of candidate projects in the 2009 NCRE auction, it was generally understood there could be considerable differences between the integration network designed prior to the auction and the actual system that would need to be constructed. This is illustrated in Figure 5. There was a recognition that the demand sector could be exposed to a significant monetary burden because transmission charges to generators estimated ex ante could be substantially below the actual system costs. This led to the abandonment of the procedure used in 2008. Modifications were implemented beginning in 2009.

Figure 6. Planning and tendering network facilities for NCRE: a comparison of the 2008 and 2009 procedures.

Figure 6. Planning and tendering network facilities for NCRE: a comparison of the 2008 and 2009 procedures.

In the new process, a preliminary planning process for the HV transmission network and for SFG facilities still takes place, and its outputs are also provided to generators prior to the auction. The generators, however, are provided with nonbinding information on the possible network topology and the location of the collector substation. The information serves as input for estimates developed by generator owners. Figure 6 illustrates the differences between the improved 2009 procedure and the one employed during the 2008 reserve energy auction.

The resulting shared connection facilities were auctioned in 2009 along with facilities of the bulk transmission system, adding up to about 500 km of 230-kV transmission lines and 860 MVA in transformation capacity. The shared facility costs that would be allocated to each generator were specified in the transmission auction directives.

NCRE in Argentina

Figure 7. NCRE potential in Argentina in (a) minihydro, (b) biomass, and (c) wind (source: Secretaría de Energía).

Figure 7. NCRE potential in Argentina in (a) minihydro, (b) biomass, and (c) wind (source: Secretaría de Energía).

The geography of Argentina favors the development of NCRE (see Figure 7). Wind generation is supported by the climate characteristics of the Patagonia region, where wind levels ensure capacity factors greater than 35%. The wet Pampa region (in central and northeastern Argentina), on the other hand, provides significant resources for biomass generation with its important agricultural, cattle-raising, and forestry production. Finally, the Andes region offers great potential for the development of small hydro plants.

The national government is trying to promote NCRE by offering tax relief, through either reduced payment of value-added tax (VAT) or accelerated amortization, along with subsidies for every energy unit produced (in the form of a feed-in tariff of US$3.40/MWh). Legislation has established that in 2016 the share of NCRE in the energy mix must be 8%, and priority is given to projects with important job-creating benefits that use domestic capital.

Since Argentina is organized as a federation, the provinces have the power to establish special conditions to promote NCRE. To date, the Argentine provinces have initiated very diverse activities in the area of renewable energy. While some have issued specific legislation, most have not. The general characteristics of the provincial promotion laws are similar, however. Chubut Province (in Patagonia) has been a pioneer, establishing tax relief for projects subject to a strict local development clause. Only one province has established a minimum NCRE share of the total energy required by the province. The subsidy is financed with provincial funds and revenues from the rate structure design.

For the past two years, investment decisions in NCRE have been effected by means of long-run energy contracts promoted and approved by the government, with the wholesale electricity market administrator (Cammesa) as the final counterparty. This mechanism has allowed Enarsa (a state-owned energy company created in 2004) to play an active role in the power market. Enarsa conducts auctions for specific technologies, and contracts are then signed between the winning generator owners and Enarsa. These contracts guarantee energy purchases and payments, made respectively by Cammesa and Enarsa. Auctions organized by Enarsa bought emergency (diesel) generation in 2007 and large thermal gas-fired power plants in 2009 and 2010.

Figure 8. The main 500-kV transmission system in Argentina.

Figure 8. The main 500-kV transmission system in Argentina.

In May 2009, Enarsa organized an auction specifically to develop renewable technologies, basically wind power (the so-called Electric Generation Program from Renewable Sources, or GENREN). The renewable auction offered a 15-year contract (but a three-year extension is given to mitigate production risk), with the supplied energy valued at the offered price. (In the case of wind energy, the contract is expected to be only “for delivery energy.”) The total candidate supply offer was about 45% greater than demand. As in Brazil, the contracted energy is the expected average value of the energy produced by the plant during the term of the contract. The auction awarded 895 MW of new capacity to be built in two years, of which 755 MW were wind power plants (the remaining 140 MW were distributed among the categories of biomass, geothermal, solar, and plants burning biofuels). There was no significant development of NCRE generation before this program—just a few small experimental projects. The price of the winning wind offers was about US$130/MWh, with capacity factors around 40%.

The development of wind generation faces challenges in connection with the transmission system because:

  • The projects are located in the Patagonia region, more than 1,000 km away from the main load centers in Argentina.
  • The region has historically had a limited transmission capacity to the rest of the national interconnected system.
  • The required investment in new transmission capacity would allow energy to be transported from the new renewable projects, but the cost is an economic barrier because of its magnitude and its associated risk, which is very hard for small generators to economically support.
  • Additional reactive compensation resources are required, as wind generation has limited ability to contribute reactive capacity.
  • Additional control resources are required to mitigate the effect of sudden changes in wind generation output on system voltage.

Transmission Expansion to Favor Development of Low-Cost Generation

The Argentine government has plans for the required expansion of the transmission system. The aim is to reinforce the 500-kV trunk system (Federal Plan I) and the regional systems with lower-voltage transmission facilities (Federal Plan II). Those plans are independent of the conventional long-term planning process of the integrated generation and transmission system in order to minimize the cost of supplying load. Instead, the transmission plan is the result of applying criteria to integrate the different regions in the country, solve local problems, and favor the development of low-cost generation.

In order to aid the development of wind generation created as a result of GENREN, the government has included transmission projects that supplement those in Federal Plan I. They consist of the expansion of the 500-kV Patagonian corridor to the town of Pico Truncado at the southern end of the country (see Figure 8). Studies are being conducted to expand the transmission capacity of this system by means of additional series compensation.

To mitigate the costs of the transmission plan for NCRE -projects, it was established that the cost of these networks would be borne by demand, in proportion to the total contracted energy times the total energy generation based on renewable resources.

From a technical standpoint, the connection of a renewable generator to the system will be authorized only if it complies with requirements similar to those of conventional generation. Such requirements relate to capacity factor, voltage control capabilities (PQ capability curve), tolerance to voltage dips resulting from contingencies, ability to help regulate the system for frequency variations, acceptable flicker and harmonic emission performance, and other operability functions.

The coordinated operation of all the units in the generation plants is often required to provide voltage control. The operation of backup generating units may be required for major changes in wind generation outputs.

NCRE in Peru

Figure 9. Income for NCRE (source: OSINERGMIN).

Figure 9. Income for NCRE (source: OSINERGMIN).

Generation expansion in Peru is strongly encouraged by the state. The government contracts future supply through auctions carried out by the government investment promotion agency and the regulator OSINERGMIN. In order to achieve the state goal of at least 5% of total generation coming from NCRE within the next five years, OSINERGMIN holds special contract auctions for NCRE projects in the Peruvian power market. The NCRE is guaranteed to receive the feed-in tariff offered in the auction for the 20-year term of the contract. The NCRE generators, which have priority dispatch, sell their energy at the price in the spot market. Revenues are supplemented with a bonus (the “prime”) fixed by OSINERGMIN when the marginal cost is lower than the tender price (see Figure 9), which is collected from the consumers.

NCRE projects have a guaranteed annual income, defined as net energy deliveries to the grid (up to awarded energy) times the awarded tariff in the public auction (the blue line in the graph). NCRE projects receive two payments every month, as follows:

  • Energy delivered to the grid is priced at the hourly short run marginal cost of the system. In addition, firm capacity is paid at the regulated capacity price. Both concepts are represented by the yellow bar in Figure 9.
  • OSINERGMIN makes an ex ante estimation of the needed subsidy for a given tariff year and publishes it together with annual bus bar tariffs to comply with the guaranteed annual income requirement (the subsidy is represented by the red bar in Figure 9). The subsidy is paid by demand through a charge added to the transmission toll.

There is an ex post adjustment of the estimated prime (annual settlement).

The differences observed in the graph in Figure 9 between the blue line and the stacked bars are adjusted ex post on an annual basis to compensate generators for the differences between expected and actual figures for spot prices and energy delivered. This adjustment is included in the estimation of the subsidy for the following year.

Generators with distributed generation and/or cogeneration will only pay the incremental cost incurred for the use of distribution networks. In the event of capacity constraints in the transmission and/or distribution systems, NCRE generators have priority to interconnect. NCRE projects are subject to an accelerated depreciation scheme in connection with the income tax, applicable on the machinery, equipment, and civil works required to set up and operate the plant.

To date, OSINERGMIN has carried out two tenders for NCRE projects. The first NCRE auction started in August 2009 and ended in March 2010, to supply up to 1,314 GWh-year with biomass (813 GWh), wind (320 GWh), and solar (181 GWh) technologies and up to 500 MW with small hydro (less than 20 MW each). The result of the 2009 -tender was that 32% of the total was covered by hydro generation and 68% by the remaining technologies. The second tender was carried out in 2011; 108 MW were awarded in solar, biomass, and wind technologies, and 102 MW in hydro.

Transmission Expansion Challenges

The development of NCRE presents challenges to transmission system development. Peru has been experiencing a significant shortage of investment in new transmission capacity over the last few years. This has resulted in severe congestion problems that originated the dispatch of inefficient generation (out-of-merit order) and increased marginal cost differentials between nodes in the grid. In order to avoid these problems, several regulatory modifications have been made to ensure a smooth development of the transmission system and prevent it from hindering economical and reliable service to demand.

The system operator, COES, plans the transmission capacity expansion in Peru consistent with system performance requirements, and the resulting transmission plan must be approved by the national energy ministry. The plan has a ten-year horizon, and the planning criterion is based on determining indicators (congestion hours and cost, supply cost, investment costs, cost of unsupplied energy) for a large group of possible expansion scenarios of generation, demand, and transmission. The selected plan optimizes the operation of the transmission system by considering the variations in the indicators in terms of risk and return. The costs of the resulting transmission improvements are paid by demand.

In its transmission planning, COES must forecast the transmission infrastructure needed to connect and transport the energy produced by NCRE generators in a manner consistent with security requirements. COES will consider the geographical areas with the greatest potential to develop NCRE projects and, specifically, projects with an awarded generation concession and contracts to sell their production.

COES differentiates among the short-term, medium-term, and long-term transmission network expansion requirements identified in planning studies. In the long-term studies, COES considers the typical annual production pattern for NCRE generation. In the short- and medium-term studies, COES also considers the limited reactive contributions characteristic of NCRE generation. By means of technical and economic studies, COES also determines the maximum wind generation capacity that may enter the system without adversely affecting its operation.

The transmission improvements included in the expansion plan are part of the so-called “guaranteed transmission system.” Investment, operating, and maintenance costs are covered by demand, thus mitigating risk for NCRE generators.

NCRE in Chile

Chile has some of the world’s greatest areas for exploiting solar power (in the northern desert) and ocean energy (all along the coastal areas), but these sources are still not competitive with conventional sources. Chile also has significant geothermal potential, a technology that is nearly mature and quite cost-effective, but exploration risks and costs have deterred actual development. As a result, most renewable development has occurred in the form of biomass, small hydro, and large-scale wind projects.

A new regulatory tool to stimulate NCRE development, a quota mechanism, was implemented in 2008 under Law 20.257, which required large electricity suppliers serving final customers to buy a growing share of NCRE coming from new projects (connected after 2007) to meet their new supply contracts. This share is 5% from 2010 to 2014 and later increases by 0.5% a year, moving up to 10% by 2024. Although controversial because of its cost and mechanism, the quota is a milestone that guarantees the development of several hundred megawatts of NCRE in the future. Compliance fines were established at approximately US$27/MWh initially and US$41/MWh for continued failure to meet the NCRE requirement.

Previous regulations had already determined that small NCRE projects could join the spot electricity market and enjoy an exemption of transmission charges for the use of the main transmission system. A total exemption was granted for projects with capacities below 9 MW, and a partial one for those from 9–20 MW. The scheme also allowed these projects to transfer electricity through the distribution network.

Figure 10. The Canela wind park, Chile (used with permission from Endesa).

Figure 10. The Canela wind park, Chile (used with permission from Endesa).

Energy suppliers can choose from available NCRE projects or develop projects themselves, so as to meet the NCRE quota at the minimum cost. Chile’s most economically viable NCRE potential is based on mini hydro run-of-river projects, biomass (and biogas), and wind power. Development of these three technologies complies with the NCRE quota, and in several cases projects have been developed under the Clean Development Mechanism (CDM), providing additional funds from the sale of carbon credits to developed countries. There is still a large potential for biomass projects (often based on forest by-products) and small hydro projects. These technologies have a cost -advantage over wind power projects because wind in central Chile (near the Central Interconnected System, or SIC, to which the Canela wind farm, shown in Figure 10, is connected) is not as prevalent as in the south, where capacity factors can rise above 40%, a level that favors wind power development. The demand in these areas is very small, however, and transmission congestion limits the country’s ability to fully exploit its wind resources.

Since 2008 the wind power industry has expanded development, with interconnections to the main system increasing approximately nine times, from 18 MW to 161 MW. In terms of capacity payments (an important component of Chilean regulation), wind power plants are treated very much like any other conventional power plant. They are paid according to their contribution to supplying the peak load, using loss of load probability (LOLP). For wind parks, however, the contribution is computed using the most adverse yearly wind power series. Therefore payments become smaller as lower-wind years are experienced. Another challenge is how to factor in the size of the failure to meet resource adequacy criteria. (Because NCRE projects tend to be small, they have only a small effect on the system LOLP.)

Traditional Transmission Planning and Cost Allocation

The existing procedure associated with the connection of large generation projects or with general reinforcements to the transmission network can be summarized as follows:

  1. The National Energy Commission (CNE) produces an indicative expansion plan (emphasizing generation expansion) for the power system for the next ten years. This study reflects the view of the regulator and is updated every six months.
  2. CNE coordinates a study to produce a network expansion plan for the bulk transmission system (the main transmission lines of the two interconnected systems) under different scenarios for the future. (A 15-year horizon was examined in the 2010 version). The study is updated every four years and builds on the demand and generation projects in the previous study by CNE (which includes projects under construction and development) and other scenarios proposed by the consultant performing the study. The goal is cost minimization over the time horizon, considering the operational constraints of the dispatch center. A min-max criterion is used to assess risk and vulnerability.
  3. This plan is initially submitted to a public hearing and afterwards is assessed and approved by CNE.
  4. CNE is responsible for organizing auctions to procure the construction of the approved new bulk transmission lines, while reinforcements of existing facilities have to be performed by the transmission operator of those facilities.
  5. Smaller transmission lines required by specific generation projects (for instance, to reach the main grid) are built and financed by the project developer and are often managed by the transmission operator.

This procedure has a quite limited scope (cost minimization), however, and does not follow a robust energy-planning model into which energy security, diversification, local and global emission reduction, competition, access to local renewable resources, and other components of the energy policy may be integrated. Transmission installations in the main grid are paid 80% by generation and 20% by load.

Connecting NCRE Through Traverse Systems

Figure 11. Integration network for distributed mini hydro facilities in Chile.

Figure 11. Integration network for distributed mini hydro facilities in Chile.

Chile’s main transmission network, essentially a longitudinal one running north-south within the country’s shoestring shape, remains far away from several areas with good potential for renewable energy. Historically, the network was optimized to connect large-scale generation in the south with load centers in the north. Many NCRE projects are located at significant distances west or east of the main transmission system, and the difficulty of connecting them to the grid is often a barrier to integration. Sites with large mini hydro and wind power potential, in particular, are often far away from the main system. Although they are exempted from transmission charges associated with the main transmission system, such projects often require construction of a long and costly line to reach the main transmission system, making the project uneconomical or even unfeasible; building such a line could take years, while constructing the wind park only takes 15 months. As in Brazil, the integration of NCRE is being implemented through traverse collector and subcollector stations (see Figure 11).


Feed-in tariffs, quota systems, and auction schemes are all used to stimulate NCRE growth in South America. These methods present common challenges in terms of development, operation, and transmission. Common solutions to these challenges are being developed, and Brazil is leading the way with its rapid incorporation of NCRE.

The existing market, commercial, and regulatory frameworks may present barriers to the timely and cost-effective connection of renewable generation, as they may not be flexible and agile enough to allow for the connection of smaller, dispersed generators with short construction times. This has led to the revision of network tariff arrangements, including the review of network operating and design practices, security standards, access regimes, investment incentives, cost recovery, and rates. The experiences presented in this article illustrate some of the key initiatives and solutions being proposed to address the challenge of unlocking the doorway for renewables. Further concerns need to be addressed, however, with a broader vision that seeks convergence to an efficient, 21st-century, low-carbon energy system through more cooperative development of renewables and the required transmission assets.

For Further Reading

L. A. Barroso, R. Rudnick, F. Sensfuss, and P. Linares, “The green effect,” IEEE Power Energy Mag., vol. 8, no. 5, pp. 22–35, Sept./Oct. 2010.

S. Mocarquer, L. A. Barroso, H. Rudnick, B. Bezerra, and M. V. Pereira, “Balance of power,” IEEE Power Energy Mag., vol. 7, no. 5, pp. 26–35, Sept.–Oct. 2009.

H. Rudnick, L. A. Barroso, S. Mocarquer, and B. Bezerra, “A delicate balance in South America,” IEEE Power Energy Mag., vol. 6, no. 4, pp. 22–35, 2008.

L. A. Barroso, F. Porrua, L. M. Thome, and M. V. Pereira, “Planning for big things in Brazil,” IEEE Power Energy Mag., vol. 5, pp. 54–63, Sept.–Oct. 2007.


Hugh Rudnick is with Pontificia Universidad Católica de Chile, Chile.

Luiz A. Barroso is with PSR, Brazil.

Daniel Llarens is with Mercados Energéticos Consultores, Argentina.

David Watts is with Pontificia Universidad Católica de Chile, Chile.

Rafael Ferreira is with PSR, Brazil.

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