978-1-4673-2673-5/12/$31.00 ©2012 IEEE

Technical and Economic Assessment of Distributed Generation to Increase Energy Coverage in Rural

Areas

Miguel A. Velásquez, IEEE Student Member, Camilo Táutiva and Ángela I. Cadena

Abstract— The grid expansion is the most usual alternative to

increase the coverage of distribution utility in rural areas. However, this alternative has several constraints related with its costs, the dispersion of costumers, assets configuration (mostly radial), and reliability, among others. This paper summarizes the main issues concerning to supply the energy demand in rural areas. Technical and economic assessment methods are proposed to determine the best alternative that satisfies energy requirements in specific rural areas. Distributed Generation (DG) is suggested as a competitive option in two cases: islanded and interconnected operation. For each scenario, technical requirements are examined to be met. Similarly, an economic evaluation is performed and finally the results are contrasted.

Index Terms: Energy coverage, distributed generation, grid

expansion, economic assessment, electricity market, energy supply, renewable sources, small hydropower plants, technical assessment.

I. NOMENCLATURE CREG Colombian Energy and Gas Regulatory Commission. PV Solar Photovoltaic. WT Wind Turbine. CHP Combined Heat and Power. SHPP Small Hydro Power Plant. APE Annual energy of the project.

Project energy of year j. n Lifetime of the project. r Discount rate.

Total cost of energy of grid expansion project. Total cost of energy of isolated DG project. Total cost of energy of interconnected DG project.

G Generation cost. T Transmission network usage fee.

Distribution network usage fee for voltage level i. LC Cost of active power losses increment. LLC Cost of transformer´s loss of lifetime. LTACN Long term average cost of network. ACEA Annual equivalent cost of electric assets of the

network. ACT Annual equivalent cost of required terrain for the

This work was supported in part by Codensa S.A. ESP and the Department of Science, Technology and Innovation (Colciencias), under the industry/university cooperative research program: Smart Electric Distribution (SILICE Phase II).

The authors are with the Department of Electrical and Electronic Engineering, Universidad de los Andes, Bogotá, Colombia (e-mails: ma.velasquez107@uniandes.edu.co, c-tautiv@uniandes.edu.co, acadena@uniandes.edu.co).

network. ACNEA Annual equivalent cost of non-electric assets of the

network. AAOM Annual equivalent operating costs. LCOE Levelized cost of energy. TTV Total costs of transformer. i Voltage level of distribution network. , Active power losses with grid expansion, for

distribution level i and year j. , Active power losses without project or with isolated DG, for distribution level i and year j. , Active power losses with interconnected DG, for distribution level i and year j. Losses factor for the distribution utility in distribution level i.

LS Value of savings in active power losses. GLS Gain due to transformer´s lifetime savings. β Factor for transformer lifetime decrease. α Transformer´s loading with grid expansion project. γ Factor for transformer lifetime with base case. λ Transformer´s loading with base case. k Factor for transformer lifetime increase. x Penetration of DG, as percentage of transformer´s

installed capacity.

II. INTRODUCTION URRENTLY, provide electricity in rural areas is a difficult task for the distribution utilities. These areas are

highly dispersed around small villages (which are located far away from the big centers of consumption), and its geographic conditions hinder or bar the expansion of transmission and distribution facilities. Likewise, the system configuration (mostly radial) creates low reliability conditions for costumers. Besides, when the construction of distribution lines is feasible, the project can be unprofitable to public or private investors. Moreover, covering the energy rural demand is not a priority for the network operator due to the low density of customers per area, which implies that the length of the distribution lines can be very large. Nevertheless, there are alternative options to energize these areas, specifically; Distributed Generation (DG) has earned relevance due to the lately coined smart grid concept. It is necessary to perform several analyses to verify that the available technologies of DG fit with the environment conditions, optimize and rationalize the investment, satisfying the technical and

C

operative requirements of the distribution system. Actually, there is no a standardized definition for DG

where the concepts of the authors meet in a definite way. In this paper, the definition introduced by Ackerman et al., in [1] is used: the source of electric energy that is connected directly to the distribution system or in the demand side (i.e., the transmission assets are not involved in the process of electricity transport to the load), with the possibility to operate in island (i.e., isolate of the interconnected system), and usually associated with installed capacities from a few kilowatts up to 10 MW. Is pertinent to emphasize, although previously the DG was composed by several types of generation technologies, nowadays, due to environmental policies and the climate change, the usage of renewable sources of energy is favored.

The implementation of DG has several benefits, among which the literature mentions: the distribution assets lifetime extension due to loading reduction (e.g., in transformers and lines), power losses reduction, voltage profile improvement and enhancement of the reliability indices. These benefits are substantial and will be discussed in detail later in this document. On the other hand, the main barrier of the DG is the high financial cost due to the prices associated with the new generation technologies (e.g., solar photovoltaic). Nevertheless, a key objective of this paper is to propose a new model to assess DG projects, considering the economic benefits of technical externalities when installing DG.

This paper summarizes the main issues concerning to supply the energy demand in rural areas. Technical and economic assessment methods are proposed to determine the best alternative that satisfies energy requirements in specific rural areas. DG is suggested as a competitive option in two cases: islanded and interconnected operation. For each scenario, technical requirements are examined to be met. Similarly, an economic evaluation is performed and finally the results are contrasted.

The remainder of this paper is organized as follows. In section III, the technical assessment is proposed, where the system configuration, the technical criteria and the simulation methodology are described. The economic assessment methodology for each scenario is presented in Section IV. In section V, the study case is described, where the potential of generation and the main characteristics of the test system are detailed. Simulation results and technical analysis are given in section VI. In Section VII, the economic results are shown. Finally, conclusions are drawn and future research is suggested.

III. PROPOSED TECHNICAL ASSESSMENT In this study, one of the key objectives is the comparison of

the main alternatives to increase the energy coverage in rural areas: DG and grid expansion. This section describes the basic configurations to supply a rural load, the technical criteria to be met, and the system´s model and simulations to verify each of the alternatives.

A. System configurations The basic principle of the energy coverage is to satisfy the

unattended system demand and the associated energy requirements as economically as possible, ensuring reasonable reliability and quality levels. In consequence, three basic system configurations (alternatives) are proposed to be analyzed:

- Grid expansion. - Isolated DG. - Interconnected DG.

These alternatives are shown in Fig. 1.

B. Technical criteria The connection of a DG power plant (and in general terms,

any significant element) to the distribution system requires a previous analysis to verify that the operative constraints of the system are met after the connection. For the analysis, the statements included in the IEEE 1547 international standard [2], and Colombian Regulations (CREG 025/1995 [3], CREG 070/1998 [4]), that regulates the interconnection of DG with distribution systems, are taken into account as follows:

⋅ Voltage regulation: at distribution level, the voltage profile must be among 0.9 and 1.1 per unit.

⋅ Security: in normal operation, the overload of elements is forbidden, i.e. the loading must to be lower than 100%. In contingency operation, the transformers and lines at the distribution level may be overloaded by 20%, while the high voltage lines may be overloaded up to 10%.

⋅ Reliability: the deterministic criteria N-1 must met the requirements of quality and security, and ensure the provision of energy to important loads.

⋅ Transient stability: the system is considered stable if after an abnormal dynamic condition in the operation, the behavior of the system is acceptable. Moreover, when the faults are clear and the topology of the system is the same as before the fault occurred, the behavior of the system corresponds to the normal operation conditions.

(a)

(b)

(c)

Fig. 1. Distribution system configurations (alternatives), a) grid expansion, b) isolated DG, c) interconnected DG.

C. Simulation methodology To verify the preceding requirements, the simulation

scheme shown in Fig. 2 is applied to the configurations of Fig. 1. This methodology is based on a previous study for the connection of a Small Hydro Power Plant (SHPP) to a distribution feeder in Colombia, performed by the authors [5].

115 34.5 13.2 115

Fig. 2. Proposed simulation methodology.

IV. PROPOSED ECONOMIC ASSESSMENT As mentioned above, the main barrier for DG is the high

financial cost due to the prices associated with the new generation technologies. Besides, when comparing and choosing between grid expansion and DG projects, the decision factor is the project cost (investment costs plus fixed and variable costs along the project lifetime), and not the final cost of energy. This causes that the comparison among the alternatives is biased. Moreover, DG has several positive externalities, and the grid expansion some negative ones on the network. This work is focused in the internalization of these externalities, the quantification of the associated economic value, and in the proposal of a project comparison methodology based on final Total Cost of Energy (TCE).

In first place, it is necessary to define the total energy that will be demanded by the actual unattended load. Consequently, the equivalent annual value of this energy is found, and then used in the calculation of the monetary value per kWh of every component that will be mentioned later in this section.

· 11 1 1

A. Grid expansion The grid expansion projects are valued with the investment

costs plus fixed and variable operating costs along the project lifetime (i.e. the total costs associated to the acquisition, installation and maintenance of elements required for the grid expansion). In order to simplify the proposed analysis, only line segments will be considered. Nevertheless, the following approach can be applied to any element of the distribution system (e.g., transformers or protective devices). The TCE of grid expansion project is defined as follows:

2

, , · · 8760 · 1· 11 1 · 1 3

· · 21 · 1 21 · 1· 1 4

10808 ,10808 , 5

· 1 6

Equation (3) is related to the increase of active power

losses and its associated cost. When installing new load points to the interconnected system, the power flow in the lines rises, and consequently the losses. Equation (4) defines the cost of reduce the lifetime of a transformer. Expanding the length of a distribution feeder to cover new demand requirements, increases the loading of the transformer associated with the feeder; consequently, the lifetime of the transformer may be reduced. Equation (5) represents the factor by which the lifetime of the transformer is reduced due to its loading, this approach is based on a review of [6]. Equation (6) represents the long term average cost of the grid assets expansion.

B. Isolated DG The DG projects are valued considering the capital costs

plus fixed and variable operating costs of the power plant; and the cost associated with the required distribution network for the DG connection. The following approach also takes into account the distribution network usage fee. In this case, there are no technical externalities to be considered; however, there are social and environmental externalities that will not be included because are outside of the scope of this paper. The TCE of isolated DG project is defined as follows:

7

component of (7) is calculated in the same way as (6); however, is pertinent to emphasize that the network required for DG connection to the new load, could be different of the one required for grid expansion.

C. Interconnected DG The interconnected DG projects are valued in the same way

as the previous case. Nevertheless, in this case there are technical externalities to be considered. The TCE of interconnected DG project is defined as follows:

8

, , · · 8760 · 1· 11 1 · 1 9

· · 21 1 21 · 1· 1 10

k 6 10 1 10 5.1 10 9.3 10 1 ,7 10 2.4 10 1.7 10 0.15 1 ,4 10 3 10 8.9 10 9.3 10 1 ,7 10 1.2 10 6.3 10 0.35 1 , 11

Equation (9) is related to the decrease of active power

losses and its associated monetary value. When installing DG within the grid, the power flow in the distribution system falls and consequently the losses as well. On the other hand, there may be a scenario in which the active power losses increase; this feasible scenario is implicit in (9). Equation (10) defines the monetary savings of increase the lifetime of a transformer. Interconnected DG discharges the transformer associated with the connection feeder, increasing the lifetime of that element. Equation (11) represents the factor by which the lifetime of the transformer is increased [7].

V. CASE STUDY

The previous methodology is tested on a 13.2 kV rural distribution system belonging to Codensa S.A. ESP, Colombian utility. This distribution feeder has 579 line segments, 200 km of length, and a total demand of 412 kW, as Shown in Fig. 3. The unattended rural demand is equivalent to 193kW and is located faraway of the circuit tails as shown in Table I. The substation associated to the feeder has one transformer with 20% of loading, and 34.5kV/13.2kV transformation ratio. The distribution system was modeled with information provided by the utility (line parameters, load demands, and segment lengths). The rural feeder is linked to the 34.5kV sub-transmission network “La Palma”, a radial circuit composed with five 34.5kV/13.2kV substations and an installed capacity of 50 MW. The sub-transmission network is associated with the transmission system through the 115kV/34.5kV substation “Villeta”, which is connected in a ring system with two 115kV/34.5kV substations: Balsillas and Faca.

TABLE I DISTANCE OF NEW LOAD POINTS TO THE SUPPLY NODE IN EACH

ALTERNATIVE

Case Length (Km) Initial node End node

Grid extension 33 CD 51299 Load

Isolated DG 17 SHPP Load

Interconnected DG 15.15 SHPP CD 51262

The feeder is sited in Yacopi, a township located 160 km to the north of the Colombian capital, Bogota. The main economic activities of this region come from agriculture (sugarcane, corn, cacao and fruits); therefore a small biomass power plant may be feasible. Moreover; Yacopi is very close to the Black river, a river with a large flow of water (83m3/s). Consequently, a small hydroelectric power plant could be installed to provide the requirements of energy. Based on data published in [8], the Black river has 6.2 MW of hydro-energetic potential. On the other hand, the PV and WT potential are not good enough, according to UPME and IDEAM [9]-[10] PV has 4kW/m2 of potential and WT 10W/m2. Taking into account the previous analysis, the SHPP option is used to provide the new energy demand requirements, shown in Table II. For the economic analysis proposed in section IV, it’s necessary to define the Colombian electricity market values (G, T and Di), the distribution system parameters (e.g., transformers loading), among others. These parameters are shown in Table III.

TABLE II LOAD PROFILE OF THE DISTRIBUTION SYSTEM DURING 30 YEARS

Year 1 Year 30 Load demand (kW) 193 442

Energy demand (MWh) 1690.68 3871.92

TABLE III SYSTEM PARAMETERS

Variable Value Source

G $ 112.40 [14]

T $ 21.43 [11]

DII $ 64.65 [11]

DIII $ 49.08 [11]

DIV $ 16.55 [11]

DI $ 99.10 [11]

SHPP LCOE $ 173 [15]

TTV $ 52504838/MVA [16]

α 30% System behavior

λ 26.34% System behavior

x 8.84% System behavior

k 3.6815 System behavior

r 12% Project characteristic

n 30 Project characteristic

VI. TECHNICAL ASSESSMENT RESULTS The distribution system is linked to the Colombian National

Interconnected System (SIN) and the associated Regional Transmission System (STR). The proposed technical assessment of Fig 2. is simulated using the Power Systems Analysis and Engineering NEPLAN software, especially the load flow and transient stability module. This section shows the main technical results obtained in the simulations..,

Fig. 3. 579 line segment rural distribution feeder.

The base case corresponds to the distribution system as usual, i.e., without the new load, or with the isolated DG scenario; the case I stand for the grid expansion scenario, and the case II corresponds to the interconnected DG scenario.

A. Steady state analysis Table IV shows the voltage profile for key nodes and for

each scenario, it can be seen that the scenario with the lowest voltage profile is the associated with grid extension, resulting levels below 95%. Interconnected DG has better voltage profile than grid expansion; as mentioned before, this is one of the technical benefits of DG. Table V shows the loading of key elements in the system for each scenario; the interconnected DG discharges the elements of the system (comparing with grid expansion alternative), principally the transformers. Table VI illustrates one of the key definitions of this paper, the interconnected DG decreases the active power losses, while the grid extension raises them.

B. Transient stability Analysis When connecting new power plants to the system, it is

necessary to verify the stability of the network when an abnormal state of operation occurs. Line and busbar three phase faults with 100ms of duration were simulated at 115 kV, 34.5 kV and 13.2 kV levels. After 100ms the fault is cleared and the system topology returns to normal conditions. Only the more representative results of the dynamic behavior of the system are presented in this paper.

TABLE IV

VOLTAGE PROFILE (%) FOR EACH SCENARIO Base case Case I Case II

115 kV

Balsillas 101 100.99 101

Faca 97.92 97.88 97.92

Villeta 96.51 96.45 96.51

34.5 kV

Caparrapi 96.66 96.16 96.64

Juratena 98.03 97.67 98.02

La Palma 96.55 95.99 96.53

Terrazas 99.95 99.76 99.94

Villeta 100.01 99.83 100

13.2 kV

CD 51262 97.81 95.1 98.18

CD 51299 97.51 93.85 96.49

CD 51536 97.34 93.97 96.61

CD 51538 97.3 93.93 96.56

CD 80270 97.06 93.68 96.32

La Palma 100.79 100.04 100.75

Fig. 4 shows the frequency response of the SHPP with115kV line and busbar faults, and when a three phase fault occurs at the SHPP 13.2 kV busbar; it can be seen that the highest deviation of frequency (about 0.52 Hz) is presented when the fault arises in the SHPP busbar;

nevertheless this is not an issue, according to the Colombian Network Code, deviations of 2.5 Hz are allowed during up to 15 seconds.

TABLE V LOADING (%) OF ELEMENTS FOR EACH SCENARIO

Base case Case I Case II

115 kV Lines Balsillas 25.15 25.35 25.16

Faca 15.28 15.48 15.29

34.5 kV Lines

605 22.72 25.17 22.81

613 24.02 26.62 24.12

630 22.72 25.17 22.81

637 34.56 37.18 34.66

645 22.72 25.17 22.81

Transformers La Palma 30.56 34.73 30

Villeta 39.38 40.79 39.43

TABLE VI ACTIVE POWER LOSSES (KW) BEHAVIOR FOR GRID EXPANSION AND

INTERCONNECTED DG, AT EACH VOLTAGE LEVEL

Voltage level Grid expansion losses increase

Interconnected DG losses decrease

115 kV 7.33 7.03

34.5 kV 36.82 35.4

13.2 kV 31.66 17.34

Total 75.81 59.77

Fig. 4. SHPP frequency (Hz) when three phase faults occur in the system. Fig. 5 presents the voltage response of the SHPP with 115kV line and busbar faults, and when a three phase fault occurs at the SHPP 13.2 kV busbar. When the fault is cleared, the voltage profile of the busbar cannot be lower than 80 percent of the nominal voltage for more than 700ms. According to Fig. 5, the previous regulation is satisfied.

In general terms, the dynamic behavior of the system is more than acceptable; the response of all the electric variables is damped when the fault is cleared.

Fig. 5. SHPP Voltage profile (p.u.) when three phase faults occur in the system.

VII. ECONOMIC ASSESSMENT RESULTS The economic results for each scenario are presented in this

section. In first place, it is necessary to define the annual energy of the project (APE) (1). According to the project load profile of 30 years shown in Table II, the APE of the project is equivalent to 3940 MWh/year. Other essential values to develop the economic analysis are presented in the Table III, with its respective data source.

A. Grid expansion As stated before, in order to simplify, the low voltage

network and other elements to connect the new demand will not be considered. In this case, the required length of lines to connect the new demand is 33 km. The values used to calculate the LTACN, showed in Table VII, are taken from CREG 097/2008. Table VII presents the value of the required line per kilometer; this value is also used to calculate the LTACN component of isolated DG and interconnected DG. Finally, Table VIII presents the TCE of this alternative, considering also the costs of generation, transmission and distribution, the cost of losses, and the cost of transformer loss of life.

TABLE VII

TOTAL COST OF NETWORK PER KILOMETER Component Value (COP)

ACEA $ 5.143.757

ACT $ 0 (not considered)

ACNEA $ 21.089

AAOM $ 122.936

Total $ 5.287.782

59.4

59.6

59.8

60

60.2

60.4

60.6

0 1 2 3 4 5 6 7 8 9 10

Freq

uenc

y (H

z)

Time (s)

115 kV line fault 115 kV node fault

13.2 kV SHPP node fault

0

0.2

0.4

0.6

0.8

1

1.2

0 1 2 3 4 5 6 7 8 9 10

Vol

tage

(p.u

.)

Time (s)

115 kV line fault 115 kV node fault

13.2 kV SHPP node fault

B. Isolated DG In this case, the required length of lines to connect the

SHPP to the new load point is 17 km. The cost of lines per kilometer, as shown in Table VIII, is used to find the isolated DG LTACN. Table IX presents the TCE of this alternative, considering the long term average cost of network, the distribution network usage fee, and the levelized cost of energy of SHPP.

TABLE VIII TOTAL COST OF ENERGY OF GRID EXTENSION PROJECT

Component Value (COP/kWh)

G $ 112.40

T $ 21.43

DI $ 99.10

LC $ 19.58

LLC $ 0.00

LTACN $ 44.29

Total $ 296.80

TABLE IX TOTAL COST OF ENERGY OF ISOLATED DG PROJECT Component Value (COP/kWh)

DI $ 99.10

LTACN $ 22.81

SHPP LCOE $ 173.00

Total $ 294.91

TABLE X TOTAL COST OF ENERGY OF INTERCONNECTED DG PROJECT

Component Value (COP/kWh)

DI $ 99.10

LS 13.67

GLS 0.8

SHPP LCOE 173

LTACN 20.33

Total $ 277.96

C. Interconnected DG The required length of lines to connect the SHPP to the

system is 15.5 km. As the isolated DG case, the cost of lines per kilometer, as presented in Table VII, is used to find the interconnected DG LTACN. The TCE of interconnected DG is shown in Table X. This total cost considers: the long term average cost of network, the distribution network usage fee, the levelized cost of energy of SHPP, the saving associated to active power losses decrease and the value of transformer gain of lifetime.

Table XI presents a comparison among the different alternatives to select the project: the traditional method (i.e., considering investment costs plus fixed and variable costs along the project life); the proposed TCE method; and the TCE plus externalities. From the results obtained, essential conclusions can be drawn: 1) with the traditional method, the

DG installation is not competitive due to the high capital costs of this alternative. 2) With the proposed TCE method, although the DG alternatives are more expensive than the grid expansion, the DG installation is competitive and may arise as the main alternative to provide electricity to rural areas when the grid extension is not feasible. 3) When externalities are considered in the TCE method, the DG alternatives are more profitable than the grid extension. Nevertheless, results may vary depending on the utilized case study.

TABLE XI PROJECTS’ DECISION FACTOR

Traditional method

Total Cost of Energy

TCE plus externalities

Grid extension $44.29 $277.22 $296.80

Isolated DG $173.00 $294.91 $294.91

Interconnected DG $173.00 $292.43 $277.96

VIII. CONCLUSIONS A technical and economic methodology to assess DG as an

option to provide electricity to rural areas, is developed. The proposed model is used to quantify the total cost of energy of different alternatives, and verify that the technical constraints are satisfied. To that, a 579 line segment rural distribution feeder is successfully tested with NEPLAN software; the technical requirements were verified, and the total cost of energy quantified.

The feasibility to provide electricity to rural areas depends on a variety of factors (level of demand, feeder parameters, geographic characteristics, DG potential, etc.), it is necessary to incorporate every item into the proposed methodology. The methodology may be used for planning new DG-enhanced rural feeders, with an objective to satisfy the energy requirements taking into account technical benefits achieved by the addition of distributed generation.

In general terms; the DG and the renewable sources of energy, have high growth rates in terms of installed capacity. The associated costs of this kind of generation are expected to decrease; therefore, the DG may arise as the best option to increase the energy coverage in rural areas; without preclude their use in urban areas due to the smart grid concept.

Grid extension and DG have several externalities, especially of environmental kind, which may be considered in future works. On the other hand, a study realized by Lozada [16] shows a SHPP design of 5 MW in the Black river; in future work could be considered the technical impacts of this installation, and the economic implications when exporting active power upstream in the network.

IX. REFERENCES

[1] T. Ackermann, G. Andersson, L. Söder, “Distributed generation: a definition,” Electric Power Systems Research, Vol. 57, Issue 3, pp.195-204, Apr. 2001.

[2] IEEE Standard for interconnecting Distributed Resources with Electric Power Systems. IEEE Standard 1547-2003, 2003.

[3] CREG Código de redes, CREG Resolution 025/1995, 1995.

[4] CREG Reglamento de distribución de energía eléctrica, CREG Resolution 070/1998, 1998.

[5] A. Cadena, M. Ríos, C. Táutiva, M. Velásquez, C. Silva, C. Rodríguez, “Estudio de Conexión Plantas de Generación Distribuida en el Sistema de Distribución de Codensa S.A ESP,” Universidad de los Andes, Bogotá, Colombia, Dec. 2010.

[6] J. Jardini, H. Schmidt,C. Tahan, C. de Oliveira, S. Ahn, "Distribution transformer loss of life evaluation: a novel approach based on daily load profiles," IEEE Transactions on Power Delivery, vol.15, no.1, pp.361-366, Jan 2000.

[7] S. Agah, H. Abyaneh, “Distribution Transformer Loss-of-Life Reduction by Increasing Penetration of Distributed Generation” IEEE transactions on Power Delivery, vol. 26, no. 2, pp.1128-1136, Apr. 2011.

[8] J. Delgadillo, A. de la Calle, A. García, “Definición de los desarrollos hidroeléctricos menores de 100MW en la cuenca del Río Negro en Cundinamarca: informe final,” Universidad la Gran Colombia, Bogotá, Colombia, 2002.

[9] UPME-IDEAM (2005) Atlas de radiación solar en Colombia, UPME, IDEAM., Bogotá, Colombia. [Online]. Available: http://www.upme.gov.co/Docs/Atlas_Radiacion_Solar/0- Primera _Parte.pdf

[10] UPME-IDEAM (2006) Atlas de viento y energía eólica en Colombia, UPME, IDEAM., Bogotá, Colombia. [Online]. Available: http://www.upme.gov.co/Atlas_Viento.htm

[11] Sistema Único de información SUI (2011), precios reconocidos para Codensa S.A ESP desde 2008 hasta 2011, SUI, Bogotá, Colombia. [Online]. Available: http://reportes.sui.gov.co/fabrica Reportes/frameSet.jsp?idreporte=ele_com_102

[12] G. Pepermans, J. Driesen, D. Haeseldonckx, R. Belmans, W. D’haeseleer, “Distributed generation: definition, benefits and issues,” Energy Policy, Vol. 33, Issue 6 , pp. 787-798, Apr. 2005

[13] W El-Khattam, M.M.A Salama, “Distributed generation technologies, definitions and benefits,” Electric Power Systems Research, Vol. 71, Issue 2, pp. 119-128, Oct. 2004.

[14] UPME, Plan de expansión 2010-2024, pp. 69-79 [Online]. Available: http://www.upme.gov.co/Docs/Plan_Expansion/ 2010/Plan_ Expansion_2010-2024_Definitivo.pdf

[15] Energy Information Administration (EIA), “Estimated Levelized Cost of New Generation Resources”, Annual energy Outlook 2011, DOE/EIA-0383(2010). December 2010.

[16] H. Lozada, A. Cadena, “Diseño de una Pequeña Central Hidroeléctrica Para los Municipios de Yacopi y Nimaima con Posibilidad de Venta a la Red,” Universidad de los Andes, Bogotá, Colombia, Dec. 2011.

Miguel A. Velásquez received his B.Sc. (2011) in Electrical Engineering and a B.Sc. (2011) in Electronic Engineering from the Universidad de los Andes, Bogota, Colombia. He is currently working toward the M.Sc. degree at the Universidad de los Andes, Bogota, Colombia.

His research interests are transmission and distribution systems, distributed and renewable resources, and smart grids.

Camilo Táutiva received his B.Sc. (2003) in Electrical

Engineer from the Universidad Industrial de Santander, Bucaramanga, Colombia, and has a M.Sc. (2006) and a Ph.D. (2012) in Electrical Engineering from the Universidad de los Andes, Bogota, Colombia.

Currently he has a postdoctoral position at Universidad de los Andes, in the Strategic Research Center in Energy. His research interests are electrical and energy planning and regulation, transmission and distribution systems, distributed and renewable resources, and smart grids.

Angela I. Cadena received her B.Sc. (1978) and M.Sc. (1987) in Electrical Engineer from the Universidad de los Andes, Bogota, Colombia, and a Ph.D. degree (2000) in Management Science from HEC, School of Economics and Social Sciences, University of Geneva, Switzerland.

Currently, she is an Associate Professor in the Department of Electrical and Electronic Engineering at Universidad de los Andes. Her research interests are smart grids, energy policy and regulation, climate change and energy-economy-environmental modeling. She was the Head of the Colombian Energy and Mining Planning Unit (UPME) and worked in the Colombian Research and Development Fund (Colciencias).

D