PRESENTATION ON LOAD FORECAST FOR BIHAR - … ON LOAD FORECAST FOR BIHAR JUNE 4, 2009 ICRA Management Consulting Services Limited © IMaCS 2008 Printed on 18-Mar-11 Background Asian

© IMaCS 2008Printed on 18-Mar-11

June 3, 2009

PRESENTATION ON

LOAD FORECAST FOR BIHAR

JUNE 4, 2009

ICRA Management Consulting Services Limited


Background

Asian Development Bank (ADB) is extending financial assistance to

Government of Bihar for development of power sector in Bihar

As first stage of the assistance, ADB has funded the technical assistance for

developing Power Sector Master Plan for Bihar comprising Load Forecasting,

Generation Plan and Transmission Plan

SNC-Lavalin International Inc. and ICRA Management Consulting Services

Limited (IMaCS) consortium has been mandated for developing the master plan


Objective

•Present the approach, methodology and assumptions used for the

load forecast

•

Share results of the exercise


Contents

Key Issues in Load Forecasting

Approach and Methodology

Key Assumptions

Derivation

Final Results


Key issues

Issue-1: Estimation of Unconstrained Demand

Large scale load shedding due to inadequate generation capacity and

related transmission and distribution system

Non availability of reliable data on the historical load shedding-

quantum and pattern

There is need for appropriate empirical assumptions to arrive atunconstrained sales


Key issues...

Issue-2: High Level of Unmetered Sales

Owing to very high number of unmetered sales, it is challenging to estimate actual power consumption, especially for the categories such as Domestic

and Irrigation

Category Unmetered connections Assessed Consumption (MU)Domestic-Kutir Jyoti 2,70,000 58.3Domestic-Rural 4,90,000 235.2Non Domestic-Rural 14,500 6.96Irrigation 58,030 1,282Street lighting 503 24Total 8,33,033 1,606.46Total No. of connections/Sale 1,730,904 4,224Unmetered connection/Sale (% of total) 48% 38%


Issue-3: Transmission and Distribution (T&D) Losses

Current T&D losses just the difference between system input and

billed sales

High probability of errors in the estimated T&D losses and actual T&D

losses due to high percentage of assessed (unmetered) sales

Non availability of break-up between technical and commercial losses

•Owning to non availability of break-up of T&D losses, setting up target reduction for future would need estimates

Key issues...

•Non availability of break-up between technical and commercial losses would reduce the demand forecast to some extent, as large percentage of

commercial losses is generally converted in to additional sale


Issue-4: Availability and Reliability of Other Historical Data

Key issues (Contd.)

Load shedding data is based on estimates for the few circles and is

available for only FY09

Consumer category wise data is not available before FY03

Consumer category wise sales data for each distribution circle has been

derived from the revenue earned in the respective circle


Contents



Key Assumptions

Derivation

Final Results


Possible Load Forecasting Approaches

1. Extrapolation/ Trend Approach

2. Econometric Approach

3. End Use Approach


Possible Load Forecasting Approaches (Contd.)

1. Extrapolation/ Trend Approach

Based on the assumption that future growth will be a continuation of

past growth

Can use the methods such as:

Compound growth rates

Fitting of mathematical growth curves

Graphs with linear and logarithmic plots

Simple and easy to use

History may not be correct reflection of the future

This method has relative advantage as the data availability in BSEB is limited



2. Econometric Approach Combines economic theory and statistical techniques for developing

electricity demand forecast Establishes relationships between electricity consumption and

economic variables like GDP, Income, Population, No. of Households etc.

An Improvement to the trend approach. Can objectively evaluate impact of policy decisions on the electricity consumption.

Requires consistent set of information over a reasonable long duration (~15 years)

Due to constraints in data availability, this approach of forecasting is not appropriate for BSEB. However, economic variables can be used to justify

future growth rate in certain consumer categories



3. End-Use Approach Based on the consumption pattern and growth in the end users Considers:

Specific consumption Degree of saturation Number of customers Growth in the above mentioned factors

Used primarily in Domestic, Commercial and Industrial consumer category forecast

Requires extensive data

Owing to need of extensive data, the approach is suitable for forecasting the energy sales for limited category of consumers of BSEB


Selected Approach

Load Forecast Categories

Group-I Group-II Group-III

•Non-Domestic•Public Lighting•LT-Industry•HT-Industry•Railway Traction•Public Water Works

•Domestic•Domestic •Irrigation •Irrigation

Trend/ Adjusted Trend

Partial End Use Method

End Use

•Partial End Use Method (PEUM) is a combination of Trend and End-Use approach

•Partial End Use Method (PEUM) is a combination of Trend and End-Use approach


Methodology

Collection of constrained sales data

Non Irrigation Irrigation

Estimation of unconstrained sales

Forecast of Sales based on Trend/Adjusted Trend

Forecast of T&D Losses

Forecast of System Energy Input

Estimate of USLF

Forecast of Peak Load

Forecast of sales based on rural electrification, authorization of connections and release of new

connections


Data Sources


Contents



Key Assumptions

Derivation

Final Results


Unconstrained Sales


Current and Required Hours of Supply


Historical Supply Deficit

Consumer Category/FY 2002 2003 2004 2005 2006 2007 2008Domestic 57% 56% 55% 54% 53% 52% 51%Commercial 15% 13% 10% 8% 6% 4% 2%Public Lighting 54% 52% 50% 48% 46% 44% 42%Irrigation 56% 54% 52% 50% 48% 46% 44%Public Water Works 0% 0% 0% 0% 0% 0% 0%Industrial L.T. 41% 40% 39% 38% 36% 35% 34%Industrial H.T. 2% 2% 2% 2% 2% 2% 2%Railway 0% 0% 0% 0% 0% 0% 0%

Huge deficit in supply in all categories barring PWW and Railways where the supply is maintained due to mandatory nature of those loads


Estimated Historical Unconstrained Sales

Sales in MU/ FY 2002 2003 2004 2005 2006 2007 2008Domestic 2486 2528 2526 2535 2782 3027 3472Commercial 320 311 314 311 334 323 380Public Lighting 48 55 44 46 37 45 41Irrigation 2502 2049 2331 2259 1704 1309 1172Public Water Works 199 173 172 176 178 164 151Industrial L.T. 257 216 192 176 177 172 212Industrial H.T. 664 645 599 627 688 778 985Railway 246 256 309 342 359 384 385Total 6722 6233 6487 6472 6259 6202 6798

There is no significant growth in unconstrained sales in any consumer category excepting “Domestic” during last 7 years


Unconstrained System Load Factor (USLF)


Unconstrained System Load Factor (USLF)

FY

Restricted Load Factor

(%)

Estimated Unrestricted Load

Factor (%)2002 67.9% 75.9%2003 49.1% 66.5%2004 85.5% 89.0%2005 73.2% 83.9%2006 70.2% 69.1%2007 78.0% 68.7%2008 73.4% 55.5%

Average 74.21% 69.81%

FY Estimated Unconstrained load factor 2009 67.5%2010 66.0%2011 64.3%2012 63.0%2013 63.7%2014 64.3%2015 65.0%2016 65.7%2017 66.3%2018 67.0%

Historical Projection

USLF projection based upon 17th EPS and expected change in load profile


T&D Losses


Transmission and Distribution (T&D) Losses


Transmission and Distribution (T&D) Losses

FY T&D Losses (%)

2002 50.8%

2003 36.8%2004 34.5%

2005 36.2%

2006 39.6%

2007 46.4%

2008 41.7%

FYT&D Loss Reduction

Effective T&D Losses

2009 3.7% 38.0%2010 3.0% 35.0%2011 3.0% 32.0%2012 3.0% 29.0%2013 2.0% 27.0%2014 2.0% 25.0%2015 2.0% 23.0%2016 2.0% 21.0%2017 1.0% 20.0%2018 1.0% 19.0%

Projection of T&D loss reduction upto FY12 are based on the targets set by BERC and beyond that based on achievability and experience in other states

Historical Projection


Gross Domestic Product


Gross Domestic Product (GDP)

FY 2001 2002 2003 2004 2005 2006 2007 2008 CAGR- 3 Yrs

CAGR- 5 Yrs

Primary GDP 34% -19% 23% -16% 13% -11% 24% -10% 5.5% 3.1%Agriculture and allied 37% -22% 27% -18% 15% -13% 28% -12% 5.6% 3.1%

Mining & Quarrying 41% 82% -72% -18% -21% 71% -14% 0% -7.5% 3.5%

Secondary GDP -2% -4% 11% -2% 13% 40% 19% 5% 11.7% 18.5%Tertiary GDP 9% 6% 5% 2% 10% 3% 18% 4% 11.1% 8.8%Total GDP 16% -5% 12% -5% 11% 3% 20% 0% 9.6% 8.3%

Growth rate of Bihar’s GDP has been more than 9.6% during last three years due to development initiatives by the state government and overall growth in

the Indian economy

Bihar’s Historical GDP



FY 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

GDP Growth 6.5% 6.0% 7.0% 8.0% 8.0% 8.0% 8.0% 8.0% 8.0% 8.0%

FY 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018Base 7.5% 8.0% 9.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0%

Optimistic 10.5% 11.0% 12.0% 13.0% 13.0% 13.0% 13.0% 13.0% 13.0% 13.0%

Projection of Growth in Indian GDP

Projection of Growth in Bihar’s GDP

Considering under-development in last two decades and immense potential for growth in the coming years and initiatives by the statement government, the growth rate of Bihar’s GDP has been considered 1-2% point higher than the Indian GDP growth rate. In optimistic case, the growth rate is 3% point

higher than the Base Case.



GDP 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

Base 7.5% 8.0% 9.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0%

Primary 3.0% 4.0% 4.0% 4.0% 3.5% 3.5% 3.5% 3.5% 3.5% 3.5%

Secondary 7.8% 7.0% 9.2% 11.2% 11.3% 10.6% 9.9% 9.3% 8.7% 8.1%

Tertiary 9.5% 10.0% 11.0% 12.0% 12.0% 12.0% 12.0% 12.0% 12.0% 12.0%

Optimistic 10.5% 11.0% 12.0% 13.0% 13.0% 13.0% 13.0% 13.0% 13.0% 13.0%

Primary 6.0% 7.0% 7.0% 7.0% 6.5% 6.5% 6.5% 6.5% 6.5% 6.5%

Secondary 14.4% 13.7% 15.9% 17.7% 17.7% 17.1% 16.5% 16.0% 15.5% 15.2%

Tertiary 11.5% 12.0% 13.0% 14.0% 14.0% 14.0% 14.0% 14.0% 14.0% 14.0%

Growth rate in Tertiary Segment is expected to remain highest in Bihar in line with the trends in Indian economy. In optimistic case, the growth rates in Secondary and Tertiary sectors are considered 2-6% higher than that in

the Base Case.

Projection of Break-up of Bihar’s GDP growth in Main Segments



FY 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018Base 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%Primary 25.5% 24.6% 23.4% 22.2% 20.8% 19.6% 18.5% 17.4% 16.3% 15.4%Secondary 15.8% 15.6% 15.7% 15.8% 16.0% 16.1% 16.1% 16.0% 15.8% 15.6%Tertiary 58.7% 59.8% 60.9% 62.0% 63.1% 64.3% 65.4% 66.6% 67.8% 69.1%Optimistic 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%Primary 25.5% 24.6% 23.5% 22.3% 21.0% 19.8% 18.6% 17.6% 16.6% 15.6%Secondary 16.3% 16.7% 17.3% 18.0% 18.8% 19.4% 20.0% 20.6% 21.0% 21.4%Tertiary 58.2% 58.7% 59.2% 59.7% 60.3% 60.8% 61.3% 61.9% 62.4% 63.0%

Projection of Break-up of Bihar’s GDP in Main Segments

The share of Tertiary and Secondary segments is likely to increase faster than Primary segment due to high growth rate in these segments


Population


Population

FY 2000 2001 2002 2003 2004 2005 2006 2007 CAGR-1 Yr.

CAGR-5Yrs.

Population (‘000)

79,630 81,873 84,386 85,568 87,131 88,662 90,162 91,631 1.63% 1.73%

Population 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018Base 1.63% 1.60% 1.57% 1.54% 1.51% 1.48% 1.45% 1.42% 1.39% 1.36%Optimistic 1.73% 1.70% 1.67% 1.64% 1.61% 1.58% 1.55% 1.52% 1.49% 1.46%

Historical Trends in Population

Projections

Due to various measures by the government and heightening awareness levels, the population growth rate is going to witness decreasing trends in

future. Accordingly, in the Base Case the growth rate is decreasing by 0.03% each year. Optimistic Case considers higher growth rate in the first year

with same decreasing trend


Contents



Key Assumptions

Derivation

Final Results


Domestic

Assumptions: Growth in No. of consumers Base Case : 7.5% Optimistic Case: 10.5%

Growth in Specific consumption: Base Case: Equals to growth in per capita income Optimistic case: 3% point higher than base case

Electrification of unelectrified villages Base Case: 5 Years Optimistic Case: 3 Years

Household electrified under village electrification: Number of households electrified per village : 40 Connected load per consumer : 200 Watts Connected Load Factor: 50% Growth in Specific Consumption: 2% lesser than other

domestic consumers

Historical Analysis 3 year CAGR in

unconstrained sales : 11.73%

3 year CAGR in number of consumers: 8.01%

3 year CAGR in Specific Consumption (kWh/Consumer/Annum) : 3.45%

FY 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

Base Case 13.7% 16.4% 17.1% 17.9% 17.6% 17.4% 15.9% 16.0% 16.1% 16.2%

Optimistic Case 20.2% 24.2% 24.5% 25.0% 22.2% 22.3% 22.4% 22.5% 22.6% 22.7%


Industrial HT

Assumptions: Sustained industrialization initiatives by the state government Base Case : Based on historical 5 year CAGR i.e 13.2% up to FY 2012

and 3% points higher beyond assuming higher available supply Optimistic Case: 3% points higher than base case

Historical Analysis 5 year CAGR in unconstrained Sales: 13.2% 3 year CAGR in unconstrained sales : 19.6%

FY 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018Base Case 13.2% 13.2% 13.2% 13.2% 16.2% 16.2% 16.2% 16.2% 16.2% 16.2%Optimistic Case 16.2% 16.2% 16.2% 16.2% 19.2% 19.2% 19.2% 19.2% 19.2% 19.2%


Railway Traction

Assumptions: Initiatives taken by Ministry of Railways in expanding the traction network and

the expected Bihar Economic growth Base Case : Expected to grow in tandem with tertiary GDP Optimistic Case: 3% points higher than base case

Historical Analysis 5 year CAGR in unconstrained Sales: 5.6% 3 year CAGR in unconstrained sales : 3.6% Historical growth is very limited



Non-Domestic

Assumptions: Growth in unconstrained sales (CAGR) Base Case : based on historical 3 year growth rate Optimistic Case: 3% points higher than base case

Historical Analysis 5 year CAGR in unconstrained Sales: 4.9% 3 year CAGR in unconstrained sales : 6.6% No clear trend in year to year growth in the sector is observed



Industrial -LT

Assumptions: Sustained industrialization initiatives by the state government Base Case : based on historical 3 year CAGR Optimistic Case: 3% points higher than base case

Historical Analysis 5 year CAGR in unconstrained Sales: 2.5% 3 year CAGR in unconstrained sales : 9.4% No clear trend in year to year growth in the sector is observed

FY 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018Base 9.4% 9.4% 9.4% 9.4% 9.4% 9.4% 9.4% 9.4% 9.4% 9.4%Optimistic 12.4% 12.4% 12.4% 12.4% 12.4% 12.4% 12.4% 12.4% 12.4% 12.4%


Public Lighting

Assumptions: Sustained initiatives by the state government in rural electrification programs

and strengthening of sub-transmission and distribution system Base Case : Based on historical 3 year CAGR Optimistic Case: 3% points higher than base case

Historical Analysis 5 year CAGR in unconstrained Sales: -1.9% 3 year CAGR in unconstrained sales : 5.7% No clear trend in year to year growth in the sector is observed



Public Water Works

Assumptions: Higher degree of correlation between increase in population and water

consumption Growth in unconstrained sales expected: Base Case : At the rate of growth in population Optimistic Case: 3% points higher than base case

Historical Analysis 5 year CAGR in unconstrained Sales: -3.3% 3 year CAGR in unconstrained sales : -8.0% No clear trend in year to year growth in the sector is observed



Irrigation

Assumptions Regularization of unauthorized connections Base Case: within 7 years Optimistic Case: within 5 years

Rural electrification 100% electrification Base Case: within 5 year period Optimistic case: within 3 year period

Average connections per village: 2.27 Average connected load per consumer: based on

historical data New connections Base Case: 1,000 connections per year up to FY

2014 and 2,000 per year beyond FY 2014 Optimistic Case: 2,000 connections per year up to FY

2012 and 4,000 per year beyond FY 2012 Average connected load per consumer: based on

historical data Average hours of supply : 12

Historical Analysis Unauthorized

connections: 1,18,761 Unauthorized

Connected Load: 2,62,353 KW

Villages unelectrified: 11,480


Contents



Key Assumptions

Derivation

Final Results


Load Forecast


Forecast Results: Base Case

MU/FY 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018Domestic 3,948 4,596 5,382 6,343 7,461 8,760 10,156 11,785 13,683 15,898Commercial 405 432 460 490 523 557 594 633 675 720Public Lighting 43 46 48 51 54 57 60 64 67 71Irrigation 1,190 1,473 1,755 2,038 2,320 2,603 2,805 3,007 3,045 3,083

PWW 153 156 158 161 163 166 168 170 173 175Industrial L.T. 232 254 277 303 332 363 397 435 476 520Industrial H.T. 1,115 1,262 1,429 1,618 1,880 2,185 2,539 2,951 3,429 3,985Railway 421 463 514 576 645 723 810 907 1,015 1,137Total Sales 7,508 8,681 10,025 11,581 13,378 15,413 17,530 19,951 22,564 25,590T&D Loss (%) 38.0% 35.0% 32.0% 29.0% 27.0% 25.0% 23.0% 21.0% 20.0% 19.0%System Input 12,110 13,355 14,742 16,311 18,327 20,551 22,766 25,255 28,204 31,592USLF (%) 67.5% 66.0% 64.3% 63.0% 63.7% 64.3% 65.0% 65.7% 66.3% 67.0%

Peak Load (MW) 2,048 2,310 2,617 2,956 3,286 3,647 3,998 4,390 4,854 5,383

Energy Sales CAGR~ 15%Peak Load CAGR ~11%


Forecast Results: Optimistic Case

MU/FY 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018Domestic 4,174 5,185 6,456 8,070 9,861 12,062 14,767 18,096 22,194 27,241Commercial 416 456 500 548 601 658 721 791 867 950Public Lighting 45 48 53 57 62 68 73 80 87 94Irrigation 1,190 1,624 2,057 2,490 2,796 3,102 3,178 3,254 3,330 3,406PWW 154 156 159 161 164 167 169 172 174 177Industrial L.T. 238 268 301 338 380 427 480 540 607 682Industrial H.T. 1,144 1,330 1,545 1,796 2,141 2,553 3,043 3,628 4,325 5,156Railway 433 489 558 641 738 848 975 1,122 1,290 1,483Total Sales 7,794 9,556 11,629 14,103 16,743 19,884 23,408 27,682 32,873 39,189T&D Loss (%) 38.0% 35.0% 32.0% 29.0% 27.0% 25.0% 23.0% 21.0% 20.0% 19.0%

System Input 12,571 14,701 17,101 19,863 22,935 26,512 30,400 35,040 41,091 48,381USLF (%) 67.5% 66.0% 64.3% 63.0% 63.7% 64.3% 65.0% 65.7% 66.3% 67.0%

Peak Load (MW) 2,126 2,543 3,036 3,599 4,113 4,705 5,339 6,092 7,072 8,243

Energy Sales CAGR~ 20%Peak Load CAGR ~16%


Category Wise CAGR


Comparison with CEA’s 17th EPS Forecast


Thank You

ADB TA No. 7073 – INDIA: Developing the Power System Master Plan for Bihar

Training in Power System PlanningTraining in Power System Planning

Workshop # 1

Power System Planning

Patna, BiharJune 2009

2

Session 1: Overview of Power System Planning• Load Forecast• Generation Planning• Transmission Planning• Distribution Planning• Economic/Financial Evaluation

Session 2: Generation Planning• Approach and Methodology• Planning Models and Techniques• Generation Planning for Bihar

Agenda

3

Session 1:

Overview of Power System Planning

4


• Long Term> National system

> 15-25 year time frame

> Development of overall strategies

• Medium Term> Regional/local systems


> Pre-feasibility evaluation of alternatives associated with specific projects

• Short Term> Regional/local systems


> Feasibility & design of specific projects

5

Power System Master Plan (PSMP)

• Define the long term development strategy

• Identify the short & medium term objectives that are consistent with the long term strategy

• Identify alternative projects

6

Elements of the PSMP

• Establish a database of the existing demand

• establish a coherent database of the existing system

& Supply options available

• Load forecast

• Assessment of supply options

• Generation expansion scenarios

• Transmission & distribution expansion scenarios

• Economic evaluation of alternative plans

• Financial analysis of optimum plan

7

Overview of the Planning Process

PLANNING BASIS

LOAD DATA

EXISTING DOCUMENTS

GENERATION DATA

TRANSMISSION DATA

RESOURCE DATA

PLANNING CRITERIA

DISTRIBUTIONDATA

LOAD FORECAST

SUPPLY OPTIONS

GENERATION/TRANSMISSION DEVELOPMENT SCENARIOS

OPTIMIZATION OF DEVELOPMENT SCENARIOS

ECONOMIC EVALUATION (FINANCIAL CONSTRAINTS)

SENSITIVITY STUDIES

SELECTED SCENARIO(S)

DISTRIBUTION INVESTMENT PLANNING

INVESTMENT PLAN

FINANCIAL ANALYSIS/TARIFFS

8

Agenda

Session 1: Electrical Power Planning Overview

• Load Forecast• Generation Planning• Transmission Planning• Distribution Planning• Economic/Financial Evaluation


9

Load Forecasting

• Starting point for system planning

• Basis for investment decisions

• Range of forecasts to deal with future uncertainties

• 15 - 25 year forecast period used to develop long term strategy

• Short term (5 year) forecast critical to timing of next major plant

10

Agenda

Session 1: Electrical Power Planning Overview• Load Forecast

• Generation Planning• Transmission Planning• Distribution Planning• Economic/Financial Evaluation


11

Generation Supply Options

• Hydro

• Conventional Thermal (Coal, Oil, Gas, Other)

• Combined Cycle

• Nuclear

• Gas Turbines

• Diesel

• Imports

• Geothermal, Wind, Solar, Biomass

12

Comparative Unit Costs

406080

100120140160180200

10 15 20 25 30 35 40 45 50 55 60 65 70 75 80

CAPACITY FACTOR (%)

UN

IT C

OST

(per

kW

h)

THERMAL-COALTHERMAL-OILNUCLEARCOMBINED CYCLEGAS TURBINEDIESEL

13

Generation Expansion Planning ModelLOAD SHAPE LOAD ANNUAL

DATA MODEL LOAD

HYDRO EXISTING/PLANNEDSCHEDULER HYDRO

EXISTING/PLANNEDTHERMAL

LOLP ADDITIONS IMPORTS

NEW UNITS

GENERATIONPLAN

PRODUCTION INVESTMENTCOSTING COSTING

ECONOMICEVALUATION

14

Agenda

Session 1: Electrical Power Planning Overview• Load Forecast• Generation Planning

• Transmission Planning• Distribution Planning• Economic/Financial Evaluation


15

Transmission Planning Methodology

HORIZON YEAR

INTEGRATION OF REMOTE PLANTS/SYSTEMS

VOLTAGE/CONDUCTOR SELECTION

NO.OF CIRCUITS

DEVELOP ALTERNATIVE SCHEMES IDENTIFY REQUIREMENTS

ANALYSIS OF ALTERNATIVE SCHEMES FEASIBILITY/COST

TIMING OF NEW FACILITIES INTERMEDIATE YEARS

TRANSMISSION EXPANSION PLAN

16

Development of Alternative Schemes

• Identification of generation & load centres

• Generation/load balances between zones/regions

• Existing facilities

• Alternative transmission routes

• Alternative voltages

• Alternative transmission types

17

Types of Analysis

• Load Flow

• Short-Circuit

• Stability

• Reliability

• Preliminary Design & Costing

18

Agenda

Session 1: Electrical Power Planning Overview• Load Forecast• Generation Planning• Transmission Planning

• Distribution Planning• Economic/Financial Evaluation


19

Parametric Analysis (Long Term)

• Correlate historic load, load density & costs

• Develop zonal/regional distribution requirements using zonal/regional load forecasts

• Impact of special programmes

> Electrification

> Loss reduction

• Develop investment requirements

20

Agenda

Session 1: Electrical Power Planning Overview• Load Forecast• Generation Planning• Transmission Planning• Distribution Planning

• Economic/Financial Evaluation


21

Why do We Need Economic Analysis?

• The main purpose is to help design and select projects that contribute to the welfare of a country/region by improving investment efficiency and productivity through resource optimisation

• Investment decisions have long-term consequences. Understanding the possible economic impact of the decisions is critical to future economic development/growth.

• Economic analysis is most useful when used early in the project cycle, to catch bad projects and bad project components

22

Fundamentals of Economic/Financial Analysis

Time Value of Money and Discounting> Future Value FV = PV x ( 1 + i ) n

> Present Value PV = FV / ( 1 + i ) n

> Discounting and Discounted Cash Flow

FVFV11 FVFV22 FVFVnn

00 nn2211

PVPV

1 / (1 + i )1 / (1 + i )

1 / (1 + i ) 1 / (1 + i ) 22

1 / (1 + i ) 1 / (1 + i ) nn

23

Methods for Economic/Financial Evaluation

> Benefit Cost Ratio

Discount of all benefitsDiscount of all costs

> Net Present Value

NPV = Discounted Benefits - Discounted Costs

> Internal Rate of Return for Projects

Discount Rate where Disc. Benefits = Disc. Costs

> Payback Method:Length of time for investment to pay itself back

The first three methods rely on the discounting principle and the time value of money.

B/C Ratio =B/C Ratio =

24

Economic Evaluation for the PSMP

• Equivalent capability for each alternative

> Compliance with planning criteria

• Present-worth/discounted cash flow/constant dollar

> Least-cost development plan

• Project sequencing

25

Relative Investment Costs of the Sectors

Relative Investment CostsDistribution

25%

Generation50%

Transmission10%

Sub-Transmission

15%

26

Financial Analysis for Projects

• Financial Constrains/Covenants

• Project Financial Viability

> Discounted Cash Flow

> Internal Rates of Return (IRR)

> Benefit/Cost Ratios

> Repayment Capablity

• Tariff Studies

27

Risk Assessment and Impact Analysis

Sensitivity Studies on Key Factors:

• Load Growth

• Discount Rate/Weighted Average Cost of Capital (WACC)

• Fuel Costs

• Capital Costs

• In-service Dates

28

Commentaires ?

QUESTIONS ?

29

Session 2:

Generation Planning

30

Agenda

Session 1: Electrical Power Planning Overview• Load Forecast• Generation Planning• Transmission Planning• Distribution Planning• Economic/Financial Evaluation

Session 2: Generation Planning

• Approach and Methodology• Planning Models and Techniques• Generation Planning for Bihar

31

Issues to Generation Planning

> When is new generation required?

> How much is needed?

> What type of generation should be added?

> Provide sufficient energy & capacity

> Represent the optimal addition

32

Tasks of Generation Planner

UNCONSTRAINED LOAD FORECAST

0

2000

4000

6000

8000

10000

12000

14000

16000

2004 2005 2006 20007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2022FINANCIAL YEAR

PEAK

DE

MA

ND

INST

ALLE

D C

APAC

ITY(

MW

)

PEAK LOAD INSTALLED CAPACITY

FUTUREPAST

HOW BEST TO MEET THE LOAD ?

33

General Approach to Generation Planning

Reliability-based Planning

• Adequacy/Security

> Adequacy – Ability to supply power/energy demand taking into account planned/unplanned outages

> Security – Ability to withstand specified sudden disturbances

• Adequacy - Static Reliability

• Security – Dynamic Reliability

34

Reliability Criteria

35

Methodologies - Deterministic Planning

• Easy to understand & formulate

• Easy to implement

• Correlate to system operation practices

• Difficult to determine the impact of particular criteria

• Dependent on the experience of the planner

36

Deterministic Planning - Planning Criteria

Reserve Margin:

> Most Commonly Used

> Reserve Margin = Installed Capacity(MW)Annual Peak Load(MW)

> Dependent on • System Size• Largest Unit Size• Maintenance Programmes

> Hydro Systems - Energy Criteria

37

Deterministic Planning Method

0

1000

2000

3000

4000

5000

0 5 10 15 20 25Years

MW

38

Probabilistic Planning

• Analysis of the generating system & load to determine the level of load that will not be supplied > Energy not served-ens/unserved energy

• Reliability index –> LOLP (loss of load probability)

• Selection of the value of the index

39

Probabilistic Planning - Choice of Reliability Index

• 0.1 DAYS/YEAR: Large systems in industrial countriesWhich set a high value on reliability

• 0.2 DAYS/YEAR: Similar systems where lower reliability isAcceptable (because of the high cost ofElectrical service there is now a trend toAcceptance of lower reliability)

• 1 DAY/YEAR: Medium sized systems in developingCountries providing a reasonableDegree of reliability

• 5 DAYS/YEAR: Systems in developing countries whereConditions do not allow high reliability

40

Optimum Level of Reliability

41

Agenda


Session 2: Generation Planning• Approach and Methodology

• Planning Models & Techniques• Generation Planning for Bihar

42

Planning Models and Techniques - SYPCO

SYPCO SYPCO Advanced Advanced Power Power SYSYstem stem PPlanninglanningand and Production Production COCOsting sting ProgramProgram

43

Step 1 – SYPCO LDC

44

Step 2 – Stacking Peaking and Base Hydro Units

45

Step 3 – Static Optimisation to Determine Base Load and Intermediate Load Additions

46

Step 4 – LOLP Analysis to Determine Peak Capacity Additions

47

Tie Capacity Optimisation

48

Unit Stacking – an example

0

5,000

10,000

15,000

20,000

25,000

30,000

1 10 19 28 37 46 55 64 73 82 91 100

Time (%)

MW

Peak Hydro

ST (HFO)

GT(Gas&Diesel)

Other DE(HFO)

WB DE(HFO)

Existing CC 2(Gas&Diesel)

New CC 3(Gas&Diesel)

Off-peak Hydro


Existing ST (Gas&HFO))

WB CC 1(Gas&Diesel)


Existing CC 1(Gas$Diesel)

WB CC 2 (Gas&HFO)

ST (Coal)

Nuke

Base Hydro

CCDE-17Capcity Factor ~ 45%

CC-142Capcity Factor ~ 87%


49

Agenda


Session 2: Generation Planning• Approach and Methodology• Planning Models & Techniques

• Generation Planning for Bihar

50

Generation Planning for Bihar

• Monthly Peak Demand Met and Required

Monthly Peak Demand (MW)

0

500

1000

1500

2000

2500

Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar

Restricted Unrestricted

51


• Restricted MLDC and Unconstrained MLDC

Montly Load Duration Curve : November-2008

0

500

1000

1500

2000

25001 21 41 61 81 101

121

141

161

181

201

221

241

261

281

301

321

341

361

381

401

421

441

461

481

501

521

541

561

581

601

621

641

661

681

701

Restricted Unrestri cted

52


53


• Existing Units (BSEB)


• Current Share for Bihar from Central Sector

DstailsFarakka STPS

Talchar STPS

Kahalgaon STPS

Tala HPS

Teesta HPS

Chukha HPS

Rangit HPS Totalw.e.f.30.12.2008

Inst. Capapcity MW 394 370 254 260 108 80 21 1487

Energy MU 2450 2653 1090 974 391 554 115 8228

PLF %

FOR %

Aux. Consumption %

Tariff (Paise/kWh) 212 150 291 184 162 159 450


• Future Projects

Name of the Project SectorNumber of Units Capacity Share

Capacity Available to Bihar

Expected COD

MTPS Extension Public 2 195 100% 390 FY 2014 BTPS Extension Public 2 250 100% 500 FY 2014 Nabinagar Power Generation Company JV 3 660 75% 1,485 FY 2014 Buxar Thermal Power Station TBCB 2 660 70% 924

FY 2015 Lakhisarai Thermal Power Station TBCB 2 660 70% 924 Pirpainti Thermal Power Station TBCB 2 660 70% 924

JAS Infrastructure & CapitalMOU signed with IPP 3 660 25% 1,485

Vikas Metal and Power LimitedMOU signed with IPP 1 500 25% 375

Adhunik Power and National ResourcesMOU signed with IPP 1 2,000 25% 1,500

Total Installed Capacity (MW) 11,310 Share (MW) 7,583TBCB: Tariff Based Competitive

56


• Future ProjectsProjects : Approved by SIPB

Name of the ProjectPlant Capacity

(MW) RemarksM/s Subhas Projects and marketing Ltd. 1200

M/s IL&FS, New Delhi, at Motipur Block, Muzaffarpur 500M/s India Power Corporation Ltd., Kolkata 1650

M/s Triton Energy Ltd., Gurgaon 13201400 acres land identified. FR submitted

M/s Krishak Bharti Co-operative Ltd., New Delhi 1320

M/s Cement Manufacturing Company Ltd., Kolkata 500

600 acres land identified. Application submitted for coal block allocation

M/s Essar Power Ltd., Ranchi 1800Total 8290

57


• Future Hydro Projects

Name of the Project AgencyCapacity (MW) Expected COD

Small Hydro BHPC 1.7 Jul 2009

BHPC 8.4 Dec 2009

BHPC 6.4 Dec-2011

BHPC 102 Year 2012-13

Dagmara HEP BHPC 126 12 th Plan

Total Installed Capacity (MW) 244.5

58


• Future Imports

Name of the Project AgencyNumber of Units Capacity Share

Capacity Available to Bihar Expected COD

Barh TPS Stage-I NTPC 3 660 16% 324 June ?Barh TPS Stage-II NTPC 2 660 14% 188 Feb 2012 Nabi Nagar (RLY) TPS NTPC 4 250 6% 58 FY 2014KHSTPS Stage-II NTPC 1 500 19% 96 May 09 North Karanpura TPS NTPC 3 660 6% 127 FY 14Subhansri HES NHPC 4 250 20% to 30% 250 2011-12 Siang Middle HEP NHPC 4 250 15% 150 NLC NLC 4 500 10% 200

UMPP Tilaiya (Jharkhand) 6 660 12.5% 500 1st unit FY 2014

Shell Companies of Orissa (under Orissa Hydro Power Corporation) 8,500 5.88% 500 APGENCO (under Andhra Pradesh Power Development Co. Ltd.) APGENCO 4,400 25% 1,100 Total Installed Capacity (MW) 27,680 Share (MW) 3,493

59


• Planning Criteria

> Reserve margin– Planned largest unit size 660 MW ~ 12% of the projected

peak demand by 2018 under Base Case– >17% or higher?

> LOLP – CEA criterion 1% = 3.65 days/years– This study = ? (5 days/year)

60

Generation Expansion Scenarios for Bihar

• Coal + Hydro• Coal + Hydro + Imports• Coal + Hydro + Export?• Coal + Hydro + Gas ?• Coal + Hydro + Nuclear + PSS for long term

plan• ???

QUESTIONS ?

Commentaires ?

61

Developing Power System Master Plan for Bihar

Workshop # 1 – Generation Planning (Patna, Bihar - June 2009)

ADB TA No. 7073 – INDIA:Developing the Power System Master Plan for Bihar

Training inTraining in GenerationGeneration Planning (SYPCO)Planning (SYPCO)

Day 1

Concept Review

Patna, BiharSeptember 2009

2

Session 1: Overview of Generation Planning• Summary of generation plan for Bihar• Generation planning process and methodology:

• Overall power system planning process• Overview of generation planning process

• Generation planning approach and methodology

• Generation planning model and techniques

Session 2: Engineering Economics• Concepts of engineering economics• Investment costing• Production costing

Agenda

3

Session 1:

Overview of Generation Planning

4

Summary of Generation Plan for Bihar

• ObjectiveDevelopment of Indicative Least Cost Generation Plan byminimising the present worth of the sum of annual costs andoperating and maintenance costs over the planning horizon

• Key Assumptions:• Horizon Period: 10 years (FY 2009 to FY 2018)• Reliability Criterion:

Upto FY 2012:LOLP: 3% (262.8 hours/years)

FY 2012 to FY 2013:LOLP: 2% (175.2 hours/year)

FY 2014 onwards:LOLP: 1% (87.6 hours/year)EUE: 0.15% of system annual energy requirement

• Supply Options:Coal, Hydro, Gas and Imports

5

Generation Planning Scenarios

• Scenario-1: Coal+Hydro• Scenario-2: Coal+Hydro+Import• Scenario-3: Coal+Hydro+CCGT• Scenario-4: Coal+Hydro+Import+Pumped Storage• Scenario-5: Coal+Hydro+Exports

All the scenarios are carried out for two loadforecast scenario, i.e Average Load ForecastScenario and Optimistic Load Forecast Scenario

* For Peak Load requirement GTs are planned except for scenario-4

6

Result Summary Table (Average LoadForecast Scenario)

ScenariosFinancial Year

Total 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018SC-1

MW addition 4,353 0.0 10.0 0.0 6.0 662.01739.0 784.0 99.0 427.0 625.0PW of Total Costs

(Rs. Crores)70,716LOLP 21.0 47.9 70.3 83.8 56.4 0.2 0.1 0.2 0.4 0.3

SC 2MW addition 4,373 0.0 10.0 0.0 455.0 662.01380.0 784.0 0.0 458.0 625.0PW of Total

Costs (Rs.Crores)67,422

LOLP 21.0 47.9 70.3 58.9 13.8 0.1 0.0 0.1 0.2 0.2SC 3

MW addition 4,371 0.0 10.0 0.0 6.0 662.01739.0 784.0 0.0 582.0 588.0PW of Total Costs

(Rs. Crores)72,228LOLP 21.0 47.9 70.3 83.8 56.4 0.2 0.1 0.4 0.2 0.2

SC 4MW addition 4,807 0.0 10.0 0.0 455.0 167.01739.01075.0 458.0 223.0 681.0

PW of Total Costs(Rs. Crores)71,128

LOLP 21.0 47.9 70.3 58.9 56.7 0.2 0.0 0.0 0.1 0.0

7

Result Summary Table (Optimistic LoadForecast Scenario)

ScenariosFinancial Year

Total 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018SC-1

MW addition 7,053 0 10 0 6 761 2624 852 625 1053 1121PW of Total Costs

(Rs. Crores)100,039LOLP 30.4 71.0 89.3 95.5 85.8 0.5 0.5 0.6 0.6 0.8

SC 2MW addition 7,068 0 10 0 455 761 2271 852 625 954 1140PW of Total

Costs (Rs.Crores) 96,525

LOLP 30.4 71.0 89.3 88.4 56.8 0.3 0.2 0.3 0.4 0.6SC 3

MW addition 7,034 0 10 0 6 761 2624 852 625 1009 1146PW of Total Costs

(Rs. Crores)100,944LOLP 30.4 71.0 89.3 95.5 85.8 0.5 0.5 0.6 0.6 0.8

SC 4MW addition 7,450 0 10 0 455 167 2752 753 1172 855 1286

PW of Total Costs(Rs. Crores)100,448

LOLP 30.4 71.0 89.3 88.4 89.9 0.6 0.7 0.1 0.1 0.1

8

Findings and Recommendations

• BSEB immediately needs to bridge the demand-supplygap exists before FY 2014

• Closely monitor the projects planned• Take immediate actions to get necessary approval for

R&M works of existing plants• Monitor R&M works closely to complete the works within

allocated time period once the R&M works start.• Setup Peak Load Plants (GTs or Pumped Storage Plants)

through JV/IPP/ any other mode• Examine the possibility of selling out the power to other

state once the committed/ planned projetcs materailised

9

Findings and Recommendations (cont’d)

• Carry out detail generation planning studies beforeentering into the long-term contract with IPPs

• Plan future capacity addittions based on the requirementand not based on their availability in the market

• Condut detailed financial analysis before finalising PPA orcontract with other parties

10

Concept Review - Power System Planning

• Long Term> National system


> Development of overall strategies

• Medium Term> Regional/local systems


> Pre-feasibility evaluation of alternatives associated with specificprojects

• Short Term> Regional/local systems


> Feasibility & design of specific projects

11

Power System Master Plan (PSMP)

• Define the long term development strategy

• Identify the short & medium term objectives that areconsistent with the long term strategy

• Identify alternative projects

12

Elements of the PSMP

• Establish a database of the existing demand

• establish a coherent database of the existing system

& Supply options available

• Load forecast

• Assessment of supply options

• Generation expansion scenarios

• Transmission & distribution expansion scenarios

• Economic evaluation of alternative plans

• Financial analysis of optimum plan

13

Power System Planning Process

PLANNING BASIS

LOADDATA

EXISTINGDOCUMENTS

GENERATIONDATA

TRANSMISSIONDATA

RESOURCEDATA

PLANNINGCRITERIA

DISTRIBUTIONDATA

LOADFORECAST

SUPPLYOPTIONS

GENERATION/TRANSMISSIONDEVELOPMENT SCENARIOS

OPTIMIZATION OFDEVELOPMENT SCENARIOS

ECONOMIC EVALUATION(FINANCIAL CONSTRAINTS)

SENSITIVITYSTUDIES



INVESTMENT PLAN


14

Preview of Generation Planning

• Issues to generation planning> When is new generation required?

> How much is needed?

> What type of generation should be added?

> Provide sufficient energy & capacity

> Represent the optimal addition

15

Tasks of Generation Planner

UNCONSTRAINED LOAD FORECAST

0

2000

4000

6000

8000

10000

12000

14000

16000

2004 2005 2006 20007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2022FINANCIAL YEAR

PEA

KD

EM

AND

INST

ALL

ED C

APA

CIT

Y(M

W)

PEAK LOAD INSTALLED CAPACITY

FUTUREPAST

HOW BEST TO MEET THELOAD ?

16

Generation Expansion Planning Process

17

Generation Supply Options

• Hydro

• Conventional Thermal (Coal, Oil, Gas, Other)

• Combined Cycle

• Nuclear

• Gas Turbines

• Diesel

• Imports

• Geothermal, Wind, Solar, Biomass

18

Comparative Unit Costs

40

60

80

100

120

140

160

180

200

10 15 20 25 30 35 40 45 50 55 60 65 70 75 80

CAPACITY FACTOR (%)

UN

IT C

OST

(per

kW

h)

THERMAL-COAL

THERMAL-OIL

NUCLEAR

COMBINED CYCLE

GAS TURBINE

DIESEL

19

General Approach to Generation Planning

Reliability-based Planning

• Adequacy/Security

> Adequacy – Ability to supply power/energy demandtaking into account planned/unplanned outages

> Security – Ability to withstand specified suddendisturbances

• Adequacy - Static Reliability

• Security – Dynamic Reliability

20

Reliability Criteria

21

Methodologies - Deterministic Planning

• Easy to understand & formulate

• Easy to implement

• Correlate to system operation practices

• Difficult to determine the impact of particularcriteria

• Dependent on the experience of the planner

22

Deterministic Planning - Planning Criteria

Reserve Margin:

> Most commonly used

> Reserve margin = Installed capacity(MW)Annual peak load(MW)

> Dependent on• System size• Largest unit size• Maintenance programmes

> Hydro systems - energy criteria

23

Deterministic Planning Method

0

1000

2000

3000

4000

5000

0 5 10 15 20 25Years

MW

24

Probabilistic Planning

• Analysis of the generating system & load todetermine the level of load that will not be supplied> Energy not served-ens/unserved energy

• Reliability index –> LOLP (loss of load probability)

• Selection of the value of the index

25

Probabilistic Planning - Choice of Reliability Index

• 0.1 DAYS/YEAR: Large systems in industrial countriesWhich set a high value on reliability

• 0.2 DAYS/YEAR: Similar systems where lower reliability isAcceptable (because of the high cost ofElectrical service there is now a trend toAcceptance of lower reliability)

• 1 DAY/YEAR: Medium sized systems in developingCountries providing a reasonableDegree of reliability

• 5 DAYS/YEAR: Systems in developing countries whereConditions do not allow high reliability

26

Optimum Level of Reliability

27

Planning Models and Techniques - SYPCO

SYPCOSYPCOAdvancedAdvancedPowerPowerSYSYstemstemPPlanninglanningandandProductionProductionCOCOstingstingProgramProgram

28

Step 1 – SYPCO LDC

29

Step 2 – Stacking Peaking and Base Hydro Units

30

Step 3 – Static Optimisation to Determine BaseLoad and Intermediate Load Additions

31

Step 4 – LOLP Analysis to Determine PeakCapacity Additions

32


33


0

5,000

10,000

15,000

20,000

25,000

30,000

1 10 19 28 37 46 55 64 73 82 91 100

Time (%)

MW

Peak Hydro

ST (HFO)

GT(Gas&Diesel)

Other DE(HFO)

WB DE(HFO)



Off-peak Hydro



WB CC 1(Gas&Diesel)



WB CC 2 (Gas&HFO)

ST (Coal)

Nuke

Base Hydro




34

Agenda

Session 2

Engineering Economics

35

Why do We Need Economic Analysis?

• Engineering Economics deals with the concepts andtechniques of analysis useful in evaluating the worth ofsystems, products, and services in relation to their costs

• The main purpose is to help design and select projects thatcontribute to the welfare of a country/region by improvinginvestment efficiency and productivity through resourceoptimisation

• Investment decisions have long-term consequences.Understanding the possible economic impact of the decisionsis critical to future economic development/growth.

• Economic analysis is most useful when used early in theproject cycle, to catch bad projects and bad projectcomponents

Basic Concept - Time Value of Money

• Money has value> Money can be leased or rented

> The payment is called interest> If you put $100 in a bank at 9% interest for one time

period you will receive back your original $100 plus $9

Original amount to be returned = $100Interest to be returned = $100 x .09 = $9

37

Fundamentals of Economic/Financial Analysis

Time value of money and discounting> Future value FV = PV x ( 1 + i ) n

> Present value PV = FV / ( 1 + i ) n

> Discounting and discounted cash flow

FVFV11 FVFV22 FVFVnn

00 nn2211

PVPV

1 / (1 + i )1 / (1 + i )

1 / (1 + i )1 / (1 + i ) 22

1 / (1 + i )1 / (1 + i ) nn

38

Methods for Economic/Financial Evaluation

• Benefit Cost Ratio

Discount of all benefitsDiscount of all costs

• Net Present Value

NPV = Discounted Benefits - Discounted Costs

• Internal Rate of Return for Projects

Discount Rate where Disc. Benefits = Disc. Costs

• Payback Method:Length of time for investment to pay itself back

The first three methods rely on the discounting principle and the timevalue of money.

B/C Ratio =B/C Ratio =

39

Economic Evaluation for the PSMP

• Comparison between alternatives> Equivalent capability for each alternative

> Compliance with planning criteria

• Project sequencing> Present-worth/discounted cash flow

> Least-cost development plan

• Additional considerations> Environmental Impacts

> Social Impacts

40

Investment Costing and Production Costing

Existing System

Reliability Analysis Production Costing

Merit OrderUnit Additions Timing Fuel Cost

Cost of ProductionLOLE/Capital Cost

Total CostInvestment CostingInvestment Costing Production CostingProduction Costing

41

Investment Costing

• Annual investment costs for all investments based ongeneration expansion paln

• Methods of annual investment cost calculation> Uniform Annual Payments (UAP)

> Straight Line Depreciation (SLD)

> Capital Cost Method

42

Relative Investment Costs of the Sectors

Relative Investment CostsDistribution

25%

Generation50%

Transmission10%

Sub-Transmission

15%

43

Production Costing

• Cost of energy production based on the operationsimulations of the power system

• Methods of energy production cost calculation> Simplified method using derated units

> Probabilistic method using outage rates

44

Financial Analysis for Projects

• Economic implies use of resources (labour andcapital)

• Financial implies costs actually paid in currency (mayinclude costs imposed that do not add value, e.g.taxes, interests, minimum wages)

• Financial Constrains/Covenants• Project Financial Viability

> Discounted Cash Flow @ WACC

> Internal Rates of Return (IRR)

> Benefit/Cost Ratios

> Repayment Capablity

45

Risk Assessment and Impact Analysis

Sensitivity studies on key factors:

• Load growth

• Discount rate/weighted average cost of capital (WACC)

• Fuel costs

• Capital costs

• In-service dates

QUESTIONS ?

Commentaires ?

46

ADB TA No. 7073 – INDIA: Developing the Power System Master Plan for Bihar

Training in Generation Planning (SYPCO)Training in Generation Planning (SYPCO)

Day 2

SYPCO Review

Patna, BiharSeptember 2009

2

Session 1: Screening Curve Analysis• Development of screening curves• Demonstration of screening curves model

Session 2: Overview of SYPCO• Program flowchart• SYPCO modules: Load modelling (annual and monthly LDC) Hydro modelling (base, peak and pump hydro) Thermal modelling Costing Modules

• Detailed data requirement

Agenda

3

Agenda

Session 1

Screening Curve Analysis

4

What is a “Screening Curve”?

• It is a graph that has the time (in hours) along the ordinate and the total cost (in dollars) along the abscissa

• Total cost has two parts:

Capital expense (total capital expense, including interest, amortized over some period, say, 30 years),

Operating expense per hour, made up of O&M costs and fuel costs.

• Utilities use screening curves for preliminary analysis of the cost of new supply options and to decide how to mix their generating units

• However, it does not take into account the seasonal or daily load variations and the reliability associated with the different unit types

5

Typical Screening Curves

100

200

300

400

500

600

700

0% 20% 40% 60% 80%

Capacity Factor

$/K

W-y

GT CC ST M. Diesel (F. Oil) M. Diesel (D/G. Oil) L. Diesel (F. Oil) L. Diesel (D/G. Oil)

6

Demontration of Screening Curve Model

• Model description…

7

Session 2:

Overview of SYPCO

8

• Compare the cost of alternative generation scenarios to serve a given load over a selected period of time

• Develop a generation expansion scheme based on given reliability criteria

• Determine investment costs and production costs for each unit for a given simulation period

• Evaluate various alternative scenarios and conduct sensitivity analysis on critical parameters rapidly

The Program is flexible and the level of detail and the The Program is flexible and the level of detail and the options selected can be tailored to the problem at hand.options selected can be tailored to the problem at hand.

SYPCO Program

9

Program Flow Chart

SYPCO SYPCO Advanced Advanced Power Power SYSYstem stem PPlanninglanningand and Production Production COCOsting sting ProgramProgram

10

This module calculates load duration curve to be used for reliability and production costing in the other modules.

* Adjustment are made to shape data to account for changes in load factor from year to year

Load Module

Load Module

11

SYPCO Load Duration Curve

12

• Annual peak load and energy requirement• LDC data to derive annual LDC and/or monthly LDC• LDC can be derived from hourly demand data for a

typical year by a spreadsheet program

Demonstration of LDC spreadsheet programDemonstration of LDC spreadsheet program……

Required Load Data

13

• This module schedules the hydro units and determines the load which has to be served by thermal units.

• Three types of hydro units can be modelled: Base hydro: no storage, operating when water is available

and stacked at the bottom of the LDC

Peak hydro: with storage, scheduled using the insertion technique to utilise all their available energy, if possible

Pumped storage units: represented by an energy-limited generator coupled with a corresponding increase in the load to model the pumped energy

Hydro Module

14

Hydro Scheduling by Insertion Technique

15

Hydro Scheduling by Insertion Technique

16

Stacking Peaking and Base Hydro Units

17

• Base hydro units Hydro capacity Forced outrage rate Fixed O&M Ratio of interval capacity to rated capacity

• Peak hydro units Hydro capacity Forced outrage rate Firm energy Average energy Fixed O&M Ratio of interval capacity to rated capacity Ration of interval energy to annual energy

Hydro Data

18

• Pumped storage units Generation capacity Unit restitution efficiency Unit pumping capacity Unit pumping efficiency Forced outrage rate Storage volume Fixed O&M Ratio of available capacity in an interval to the unit net capacity Ratio of available daily energy in an interval to the storage volume of

the unit

Hydro Data (continued)

19

• Thermal plants will be added automatically to meet a given reliability index calculated by mean of a standard Loss of Load Possibility (LOLP) analysis

• The selection of generation additions will be based on a static optimiszation which builds towards a target mix of generation based on screening curvesscreening curves

Thermal Module

20

Static Optimisation to Determine Base Load and Intermediate Load Additions

21

LOLP Analysis to Determine Peak Capacity Additions

22


23

Production Costing- Options Available

24

Production Costing- Simplified Method

25

Production Costing- Probabilistic Method

26


0

5,000

10,000

15,000

20,000

25,000

30,000

1 10 19 28 37 46 55 64 73 82 91 100

Time (%)

MW

Peak Hydro

ST (HFO)

GT(Gas&Diesel)

Other DE(HFO)

WB DE(HFO)



Off-peak Hydro



WB CC 1(Gas&Diesel)



WB CC 2 (Gas&HFO)

ST (Coal)

Nuke

Base Hydro




27

• Existing and committed thermal units Unit nominal capacity Forced outrage rate Operating factor Heat rate Fuel type Fixed and variable O&M Maintenance schedule Transportation fuel adder cost

• New thermal unitsIn addition to the above information Plant life Capital investment and disbursement

Thermal Unit Data

28

• Investment costing module uses the generation expansion plan and produces a cash flow profile for all investments

• Production costing module simulates the operation of the power system to determine the cost of energy production based on either the annual LDC or the interval LDC

• Total annual costs module combines the annual production costs and annual investment costs to produce the cumulative annual present worth of total costs.

Costing Modules

29

• Uniform Annual Payments (UAP)Annual capital costs are computed using a uniform amount to cover both interest and depreciation for each year of the plant life

A = P x CRF / (1+i)0.5

+ other chargesWhere:A – Annual capital costsP – Given cost of plant as builtCRF – Capital recovery factor = i x(1+i)

n/[((1+i)

n-1]

n – Plant life, yearsi – interest rate* All investments are assumed to be made at mid-year and the first year of

operation is assumed to be at the end of the construction period. (1+i)0.5 is the factor to align costs to mid-year.

Investment Costing Module – Method 1

30

• Straight Line Depreciation (SLD)Annual capital costs are computed using a uniform amount to cover both interest and depreciation

A = D + I + other chargesWhere:A – Annual capital costsD – Annual depreciation = P / [nx(1+i)

0.5]

I – Interest charge, Yearn = (P –[n-1] x D) x I / (1+i)0.5

P – Given cost of plant as builtn – Plant life, yearsi – interest rate


31

• Capital Cost Method

In this method, the entire capitalised investment is assumed to be spent at the beginning of the commissioning year.


32

This module simulates the operation of the system anddetermine the cost of energy production

• Hydro energy is utilised first and the costs associated with the production, generally fixed per year, are computed

• Energy produced by the thermal units can be calculated by either one of two ways: Simplified method Probabilistic method

Production Costing Module

33

Study Time Frame

34

This module calculates the present worth of all costs, operating and investment, for a basic discount rate and for up to 5 additional discount rates

PW= C1/(1+i)0.5 + C2/(1+i)1.5 + … + Cn/(1+i)n-0.5

Where:PW – present worthCn – mid-year annual costsn – simulation periodi – interest rate

Total Annual Cost Module

35

• Study Parameters Study horizon Reference year for present worthing Number of interval for simulation Required LOLP Unserviced energy cost Escalation rates Discount rates

• Fuel Cost Data Fuel type Fuel name Initial fuel cost Escalation rates

Other Data Requirement

QUESTIONS ?

Commentaires ?

36

TRAINING PROGRAMON

TRANSMISSION PLANNING (27TH -28TH DEC 2010)

[ 2 ]© IMaCS 200718-Mar-11© IMaCS 200818-Mar-11

OVERVIEW OF POWER SYSTEM PLANNING


Long Term• National system• 15-25 year time frame• Development of overall strategies

Medium Term• Regional/local systems• 10-15 year time frame• Pre-feasibility evaluation of alternatives associated with specific projects

Short Term• Regional/local systems• 5-10 year time frame• Feasibility & design of specific projects

3

Elements of Power System Planning

Establish a database of the existing demand Establish a coherent database of the existing system & Supply

options available Load forecast Assessment of supply options Generation expansion scenarios Transmission & distribution expansion scenarios Economic evaluation of alternative plans Financial analysis of optimum plan

4

Overview of Planning Process

5

PLANNING BASIS

LOAD DATA

EXISTING DOCUMENTS

GENERATION DATA

TRANSMISSION DATA

RESOURCE DATA

PLANNING CRITERIA

DISTRIBUTIONDATA

LOAD FORECAST

SUPPLY OPTIONS

GENERATION/TRANSMISSION DEVELOPMENT SCENARIOS

OPTIMIZATION OF DEVELOPMENT SCENARIOS

ECONOMIC EVALUATION (FINANCIAL CONSTRAINTS)

SENSITIVITY STUDIES



INVESTMENT PLAN


Planning Criteria

Least Cost Plan Reliability Targets Environment Consideration

6


TRANSMISSION PLANNING

Roles of Transmission Planning

Objectives• Timing of new facilities• Types of transmission required• Location of new facility

Requirements• Existing facilities• Load forecast• Generation Plan

Characteristics• Adequate reliability• Flexibility• Low Cost

8

Development of Alternative Schemes

Identification of generation & load centers Generation/load balances between zones/regions Existing facilities Alternative transmission routes Alternative voltages Alternative transmission types

9

Categories of Transmission System

Bulk Power Transmission• Connects major power plants to Regional Load Centers

Area Transmission• Connects regional supply points to area load centers ( cities/ large

Towns/large Industries)

Sub-Transmission• Connects area supply points to distribution centers

Distribution• Connects distribution centers to Individual customers

10

Type of Transmission Planning

Long-Term• National system over 15-20 years in conjugation with national generation

plan• Determination of requirement of higher voltage level• Estimate required investment

Medium Term• Regional/Local systems over 10-15 years period• Pre-feasibility evaluation of alternatives• Associated with specific projects

Short-Term• Regional/local systems over 5-10 year period• Feasibility and Design of specific transmission project

11

Principle areas of study

Capacity of transmission circuits System steady state behavior System dynamic state behavior Short circuit levels Operation and maintenance Economic impact Environment impact

12

Stages in Transmission Planning

Definition of Objectives Data collection Development of planning criteria Planning methodology Development of alternative schemes Technical analysis of alternatives Selection of optimal alternative Planning report

13

CEA Transmission Planning Criteria

Voltage Limits• +/- 10% (220kV and below)• +/-5% (400kV)• For 765KV : Min-728kV and Max: 800kV

Capacity at Single Sub station• 765kV : 2500 MVA• 400kV: 1000MVA• 220kV: 320 MVA• 132kV: 150 MVA

Rated breaking capacity• 132kV : 25/31kA• 220kV: 31.5/40KA• 400kV: 40kA• 765kV: 40kA

14

CEA Transmission Planning Criteria

Reactive power flows through ICT: less than 10% rating of ICT Thermal/nuclear generators shall not normally run at leading power

factor Line loading limits : It is a function of line length

• With voltage regulation 5% • Phase angle difference: 30 deg

Contingency criteria• Outage of a 132kV D/C line• Outage of 220kV D/C line• Outage of 400kV S/C line• Outage of 765kV S/C line• Outage of one pole of HVDC bipolar line• Outage of ICT

N-2 criteria for large generating complexes and load centers

15

Transmission Planning Methodology

16

HORIZON YEAR

INTEGRATION OF REMOTE PLANTS/SYSTEMS

VOLTAGE/CONDUCTOR SELECTION

NO.OF CIRCUITS

DEVELOP ALTERNATIVE SCHEMES IDENTIFY REQUIREMENTS

ANALYSIS OF ALTERNATIVE SCHEMES FEASIBILITY/COST

TIMING OF NEW FACILITIES INTERMEDIATE YEARS

TRANSMISSION EXPANSION PLAN

Data Requirement in Transmission Planning

Load forecast by sub-station Generation expansion plan Transmission Line Data Substation Data Machine data Operational data Cost data

17

Transmission Planning Criteria

Steady State Criteria• Voltage limits• Equipment loading limits• Contingencies

Dynamic criteria• Type of fault• Fault clearance time• Auto-reclosing• Load shedding

Economic criteria• Discount rate• Cost of losses

18

Types of Analysis Load Flow:

• Scenarios: Maximum Load, Minimum Load, Special generating schedules• Results: Voltage profiles, equipment loading, reactive power balances, losses, reinforcement

requirements

Short-Circuit• Scenarios: Maximum Load, Minimum Load• Results: fault levels, equipment duty, reactive compensation types

Stability• Scenarios: : Maximum Load, Minimum Load, Special generating schedules• Results: system post-fault integrity, fault-clearing times, effects of auto-reclosing, system

control requirement, reactive compensation requirements, reinforcement requirement

Reliability• Adequacy of transmission system

Preliminary Design and costing• Voltage Selection : Voltage levels, power transformer levels, transmission distance• Conductor selection: conductor sizes, power transfer levels, interference levels, losses• Cost of transmission reinforcements, timing of transmission reinforcements

19

PSAF: Screen Shots

20


ECONOMIC ANALYSIS

Why do we need economic analysis

The main purpose is to help design and select projects that contribute to the welfare of a country/region by improving investment efficiency and productivity through resource optimization Investment decisions have long-term consequences. Understanding

the possible economic impact of the decisions is critical to future economic development/growth. Economic analysis is most useful when used early in the project

cycle, to catch bad projects and bad project components

22

Why do we need economic analysis

Time Value of Money and Discounting• Future Value FV = PV x ( 1 + i ) n

• Present Value PV = FV / ( 1 + i ) n

• Discounting and Discounted Cash Flow

23

PVPV FVFV11 FVFV22 FVFVnnFVFV11 FVFV22 FVFVnn

00 nn2211

PVPV

1 / (1 + i ) 1 / (1 + i ) nn

1 / (1 + i )1 / (1 + i )

1 / (1 + i ) 1 / (1 + i ) 22

Methods of Economic/Financial Evaluation

Benefit Cost RatioDiscount of all benefitsDiscount of all costs

Net Present ValueNPV = Discounted Benefits - Discounted Costs

Internal Rate of Return for ProjectsDiscount Rate where Disc. Benefits = Disc. Costs

Payback Method:• Length of time for investment to pay itself back

The first three methods rely on the discounting principle and the time value of money.

24

B/C Ratio =

Methods of Economic/Financial Evaluation

Equivalent capability for each alternative• Compliance with planning criteria

Present-worth/discounted cash flow/constant dollar• Least-cost development plan

Project sequencing

25

Financial Analysis of the Projects

Financial Constrains/Covenants Project Financial Viability

• Discounted Cash Flow• Internal Rates of Return (IRR)• Benefit/Cost Ratios• Repayment Capability

Tariff Studies

26


PSAF PRACTICE SESSION

Sample System (Single Line Diagram)

28

Utility Connection20kAV=102%

400kV

2000MVA, 0.95pf

400kV

2x588MVA 588MVA

400/21kV 400/21kV

1x500MW, 21kV 2x500MW, 21kV

300km

300km

200km

Bus Data

29

Bus Data

ID Status kV Base kV Oper ZoneVmin[p.u.]

Vmax[p.u.]

Genbus1 ON 21 21.21 1 0.95 1.05Genbus2 ON 21 21 1 0.95 1.05HVBus4 ON 400 400 1 0.9 1.05HVBus2 ON 400 400 1 0.9 1.05HVBus3 ON 400 408 1 0.9 1.05HVBus1 ON 400 400 1 0.9 1.05

Utility Connection Data

30

Utility Connection Data

ID Status Duplic From BusP Gen [MW]

Q Gen [MVAR]

Angle [deg]

Power Factor[p.u.] MVA 3P X/R 3P MVA L-G X/R L-G Type

U1 ON 1 HVBus3 0 0 0 1 13856.4 5 13856.4 5 Swing

Generator Data

31

Generator Data

ID DATABASE ID Status Duplic From Bus kVRated[MVA] Generator Type

P Gen[MW]

Q Gen[MVAR]

Angle[deg]

Power Factor[p.u.]

Q Max [MVAR]

Q Min [MVAR] Wdg

G1 500MW-21KV-CEA-LOWH ON 1 Genbus1 21 588 Voltage Controlled 500 0 0 0.85 310 -300 YGG2 500MW-21KV-CEA-LOWH ON 2 Genbus2 21 588 Voltage Controlled 500 0 0 0.85 310 -300 YG

IDR''

[p.u.]X''

[p.u.]R'

[p.u.]X'

[p.u.]R

[p.u.]Xd

[p.u.]R0

[p.u.]X0

[p.u.]Rg

[p.u.]Xg

[p.u.] Ctrled BusID

Stability Model Type Xp Xq T'do X'q T'qo T''do X''q T''qo H KD SGU SGL EU EL

G1 0 0.212 0 0.27 0 2.31 0 0.105 0 0 Genbus1 1 0.18 2.19 9 0.7 2.5 0.04 0.233 0.2 1 0 0.6 0.12 1.2 1G2 0 0.212 0 0.27 0 2.31 0 0.105 0 0 Genbus2 1 0.18 2.19 9 0.7 2.5 0.04 0.233 0.2 1 0 0.6 0.12 1.2 1

Static Load Data

32

Static Load

ID Status Duplic From BusP Load[MW]

Q Load[MVAR] nP nQ

nP(Stab)

nQ(Stab)

User def. Pfreq(Stab)

User def. Qfreq(Stab)

User def. Vth

(Stab)L-4 ON 100 HVBus4 1900 624.5 0 0 1 1 0 0 0.5

Line Data

33

Line Load

ID DATABASE ID Status Duplic From Bus To Bus KV kmR1

[p.u.]X1

[p.u.]B1

[p.u.]R1'

[p.u.]R0

[p.u.]X0

[p.u.]B0

[p.u.]R0'

[p.u.]

Loading Limit[A]

Emgncy Loading

Limit[A]

L1-1 400KV DCDS QUAD MOOSE ON 1 HVBus1 HVBus3 400 200 0.00214 0.03162 1.4624 0.02138 0.02287 0.15125 0.7936 0.02287 3008 3308L1-2 400KV DCDS QUAD MOOSE ON 1 HVBus1 HVBus3 400 200 0.00214 0.03162 1.4624 0.02138 0.02287 0.15125 0.7936 0.02287 3008 3308L2-1 400KV DCDS QUAD MOOSE ON 1 HVBus2 HVBus4 400 300 0.00321 0.04744 2.1936 0.03206 0.03431 0.22687 1.1904 0.03431 3008 3308L2-2 400KV DCDS QUAD MOOSE ON 1 HVBus2 HVBus4 400 300 0.00321 0.04744 2.1936 0.03206 0.03431 0.22687 1.1904 0.03431 3008 3308L3-1 400KV DCDS QUAD MOOSE ON 1 HVBus4 HVBus3 400 300 0.00321 0.04744 2.1936 0.03206 0.03431 0.22687 1.1904 0.03431 3008 3308L3-2 400KV DCDS QUAD MOOSE ON 1 HVBus4 HVBus3 400 300 0.00321 0.04744 2.1936 0.03206 0.03431 0.22687 1.1904 0.03431 3008 3308

Transformer Data

34

Transformer Load

ID DATABASE ID Status # From Bus To BusRated [MVA]

Prim [kV]

Sec [kV]

Prim Wdg

Sec Wdg

Phase Shift

Z1 [p.u.]

Z0 [p.u.]

X/R Pos

X/R Zero

Loading Limit

[MVA]

Emergcy Loading

Limit [MVA]

Prim Tap [%]

F1 400/21KV-580MVA-GENTX ON 1 HVBus1 Genbus1 590 400 21 YG D -30 0.14 0.14 40 40 590 590 100F2 400/21KV-580MVA-GENTX ON 2 HVBus2 Genbus2 590 400 21 YG D -30 0.14 0.14 40 40 590 590 100


THANK YOU

BSEB-ADB DISTRIBUTION PLANNING TRAINING 28-29 Dec 2010

1

Training of Distribution System Planning Software

(CYMDIST)

28282828

1- Distribution Planning Basics

Need Concept of Loads Load allocation Voltage drop / Load flow analysis

2- Cymdist General Overview Introduction to Cymdist Cymdist capabilities

3- Database for Equipment and Feeders Setting the database directories Equipment and Network database description Loading the network

4- Navigating in graphical display The right Mouse Button: Zooming and Planning Navigation to the network

5- Studies Scenarios options New Feeder Introduction. New Transformer

6- Calculation Analysis Modules Load allocation and Voltage Drop Viewing Voltage Drop report and Voltage Drop dialog box result. Viewing an abnormal conditions by using the dialog box result and report Short Circuit Analysis Calculation Reports Generation

Day One, 10:30 to 18:00 hrs


2

Exercise – Hands On Sample Network Modeling and Analysis Queries

Day Two, 10:30 to 18:00 hrs


3

DATA

GRID – Peak Load: - 14 MW

Average Load:- 10MW

Power Factor:- 0.85


4

Network Data

Sectional details:

Sn Section Length (km) Conductor Type 1 AB1 5 Weasel 2 B1B 12 Weasel 3 B1C1 4 Raccoon 4 C1C 7 Rabbit 5 C1D 14 Dog 6 DE1 11 Weasel 7 E1E 9 Squirrel 8 E1F 8 400 Sqmm cable 9 FG 13 Rabbit

10 FH1 17 Raccoon 11 H1H 7 Wolf 12 H1J 20 Squirrel 13 FK 25 Wolf

Typical Parameters Line & Cable:

Sn Conductor name Impedance Loading (A) 1 Squirrel 1.49+0.375 82 2 Weasel 0.99+j0.363 110 3 Rabbit 0.591+j0.3792 165 4 Raccoon 0.424+j0.365 180 5 Dog 0.319+j0.357 280 6 Wolf 0.185+j0.256 400

Sn Cable Impedance Loading (A) 1 400sqmm (XLPE) 0.102+j0.103 345

Exercise:

1. Network Modelling

2. Load Allocation

3. Voltage Drop / Load Flow Analysis

4. Short Circuit Analysis

5. Capacitor Placement / Reconductoring / Loss minimisation

6. Report Generation

Final Report

- 1 -

Appendix 15LIST OF ABBREVATIONS

BHEL Bharat Heavy Electricals Limited BHPC Bihar Hydro Power Corporation BPIC Bihar Power Infrastructure Company BSEB Bihar State Electricity Board BTPS Barauni Thermal Power Plant CCGT Combined Cycle Gas Turbine CCL Central Coal Fields Limited CEA Central Electricity Authority CGS Central Generating Stations CIDA Canadian International Development Agency ECL Eastern Coal Fields Limited ENS Energy Not Served ER Eastern Region EUE Expected Unserved Energy GAIL Gas Authority of India Limited GOB Govt. of Bihar GOI Govt. of India IPP Independent Power Producer JV Joint Venture KBUNL Kanti Bidyut Utpadan Nigam Limited LNG Liquefied Natural gas LOLP Loss of Load Probability MOP Ministry of Power MOU Memorandum of Understanding MTPS Muzaffarpur Thermal Power Station NGG National Gas Garid NPCIL Nuclear Power Corporation of India Limited NR Northern Region NTPC National Thermal Power Corporation PW Present worth RLDC Regional Load Dispatch Centre ROR Run-of-River RSVY Rashtriya Sam Vikas Yojna SIPB State Investment Promotion Board SR Southern Region

SYPCOAdvanced Power System Planning and Production Costing

Final Report

- 2 -

Abbreviations AC Alternating Current ACSR Aluminum Conductor Steel Reinforced BSEB Bihar State Eelectricity Board BTPS Barauni Thermal Power Station D/C Double Circuit DC Direct Current DTR Distribution Transformer EHV Extra High Voltage GI Galvanised Iron GSS Grid Sub Station HT High Tension HTC High Tension Consumer HV High Voltage IOC Indian Oil Corporation km kilo metre kV kilo Volt kVA kilo Volt Ampere LT Low Tension Misc. Miscellaneous MVA Million Volt Ampere MW Mega Watt NTPC National Thermal Power Corporation OLTC On Load Tap Changer PESU Patna Electric Supply Undertaking PESU (E) PESU East PESU (W) PESU West

PGCIL Power Grid Corporation of India Limited

PHED Public Health Engineering Department Rly. Railways S/C Single Circuit S/S Sub Station SLD Single Line Diagram T&D Transmission and Distribution XLPE Cross Linked Poly Ethylene Xmer Transformer

www.snclavalin.com

SNC-LAVALIN Inc. T&D Division 1801 McGill College Ave Montreal, Quebec Canada H3A 2N4 Tel.: (514) 393-1000 Fax: (514) 334-1446

Documents

PRESENTATION ON LOAD FORECAST FOR BIHAR - … ON LOAD FORECAST FOR BIHAR JUNE 4, 2009 ICRA Management Consulting Services Limited © IMaCS 2008 Printed on 18-Mar-11 Background Asian