© IMaCS 2008Printed on 18-Mar-11
June 3, 2009
PRESENTATION ON
LOAD FORECAST FOR BIHAR
JUNE 4, 2009
ICRA Management Consulting Services Limited
© IMaCS 2008Printed on 18-Mar-11
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
© IMaCS 2008Printed on 18-Mar-11
Objective
•Present the approach, methodology and assumptions used for the
load forecast
•
Share results of the exercise
© IMaCS 2008Printed on 18-Mar-11
Contents
Key Issues in Load Forecasting
Approach and Methodology
Key Assumptions
Derivation
Final Results
© IMaCS 2008Printed on 18-Mar-11
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
© IMaCS 2008Printed on 18-Mar-11
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%
© IMaCS 2008Printed on 18-Mar-11
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
© IMaCS 2008Printed on 18-Mar-11
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
© IMaCS 2008Printed on 18-Mar-11
Contents
Key Issues in Load Forecasting
Approach and Methodology
Key Assumptions
Derivation
Final Results
© IMaCS 2008Printed on 18-Mar-11
Possible Load Forecasting Approaches
1. Extrapolation/ Trend Approach
2. Econometric Approach
3. End Use Approach
© IMaCS 2008Printed on 18-Mar-11
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
© IMaCS 2008Printed on 18-Mar-11
Possible Load Forecasting Approaches (Contd.)
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
© IMaCS 2008Printed on 18-Mar-11
Possible Load Forecasting Approaches (Contd.)
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
© IMaCS 2008Printed on 18-Mar-11
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
© IMaCS 2008Printed on 18-Mar-11
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
© IMaCS 2008Printed on 18-Mar-11
Data Sources
© IMaCS 2008Printed on 18-Mar-11
Contents
Key Issues in Load Forecasting
Approach and Methodology
Key Assumptions
Derivation
Final Results
© IMaCS 2008Printed on 18-Mar-11
Unconstrained Sales
© IMaCS 2008Printed on 18-Mar-11
Current and Required Hours of Supply
© IMaCS 2008Printed on 18-Mar-11
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
© IMaCS 2008Printed on 18-Mar-11
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
© IMaCS 2008Printed on 18-Mar-11
Unconstrained System Load Factor (USLF)
© IMaCS 2008Printed on 18-Mar-11
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
© IMaCS 2008Printed on 18-Mar-11
T&D Losses
© IMaCS 2008Printed on 18-Mar-11
Transmission and Distribution (T&D) Losses
© IMaCS 2008Printed on 18-Mar-11
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
© IMaCS 2008Printed on 18-Mar-11
Gross Domestic Product
© IMaCS 2008Printed on 18-Mar-11
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
© IMaCS 2008Printed on 18-Mar-11
Gross Domestic Product (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.
© IMaCS 2008Printed on 18-Mar-11
Gross Domestic Product (GDP)
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
© IMaCS 2008Printed on 18-Mar-11
Gross Domestic Product (GDP)
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
© IMaCS 2008Printed on 18-Mar-11
Population
© IMaCS 2008Printed on 18-Mar-11
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
© IMaCS 2008Printed on 18-Mar-11
Contents
Key Issues in Load Forecasting
Approach and Methodology
Key Assumptions
Derivation
Final Results
© IMaCS 2008Printed on 18-Mar-11
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%
© IMaCS 2008Printed on 18-Mar-11
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%
© IMaCS 2008Printed on 18-Mar-11
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
FY 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018Base Case 9.5% 10.0% 11.0% 12.0% 12.0% 12.0% 12.0% 12.0% 12.0% 9.5%Optimistic Case 12.5% 13.0% 14.0% 15.0% 15.0% 15.0% 15.0% 15.0% 15.0% 12.5%
© IMaCS 2008Printed on 18-Mar-11
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
FY 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018Base Case 6.6% 6.6% 6.6% 6.6% 6.6% 6.6% 6.6% 6.6% 6.6% 6.6%Optimistic Case 9.6% 9.6% 9.6% 9.6% 9.6% 9.6% 9.6% 9.6% 9.6% 9.6%
© IMaCS 2008Printed on 18-Mar-11
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%
© IMaCS 2008Printed on 18-Mar-11
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
FY 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018Base Case 5.7% 5.7% 5.7% 5.7% 5.7% 5.7% 5.7% 5.7% 5.7% 5.7%Optimistic Case 8.7% 8.7% 8.7% 8.7% 8.7% 8.7% 8.7% 8.7% 8.7% 8.7%
© IMaCS 2008Printed on 18-Mar-11
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
FY 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018Base Case 1.63% 1.60% 1.57% 1.54% 1.51% 1.48% 1.45% 1.42% 1.39% 1.36%Optimistic Case 1.73% 1.70% 1.67% 1.64% 1.61% 1.58% 1.55% 1.52% 1.49% 1.46%
© IMaCS 2008Printed on 18-Mar-11
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
© IMaCS 2008Printed on 18-Mar-11
Contents
Key Issues in Load Forecasting
Approach and Methodology
Key Assumptions
Derivation
Final Results
© IMaCS 2008Printed on 18-Mar-11
Load Forecast
© IMaCS 2008Printed on 18-Mar-11
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%
© IMaCS 2008Printed on 18-Mar-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%
© IMaCS 2008Printed on 18-Mar-11
Category Wise CAGR
© IMaCS 2008Printed on 18-Mar-11
Comparison with CEA’s 17th EPS Forecast
© IMaCS 2008Printed on 18-Mar-11
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
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
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
Session 2: Generation Planning• Approach and Methodology• Planning Models and Techniques• Generation Planning for Bihar
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
Session 2: Generation Planning• Approach and Methodology• Planning Models and Techniques• Generation Planning for Bihar
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
Session 2: Generation Planning• Approach and Methodology• Planning Models and Techniques• Generation Planning for Bihar
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
Session 2: Generation Planning• Approach and Methodology• Planning Models and Techniques• Generation Planning for Bihar
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
Session 2: Generation Planning• Approach and Methodology• Planning Models and Techniques• Generation Planning for Bihar
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 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 & 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
New CC 2(Gas&Diesel)
Existing ST (Gas&HFO))
WB CC 1(Gas&Diesel)
New 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%
CC-209Capcity Factor ~ 80%
49
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 & 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
Generation Planning for Bihar
• 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
Generation Planning for Bihar
53
Generation Planning for Bihar
• Existing Units (BSEB)
Generation Planning for Bihar
• 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
Generation Planning for Bihar
• 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
Generation Planning for Bihar
• 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
Generation Planning for Bihar
• 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
Generation Planning for Bihar
• 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
Generation Planning for Bihar
• 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
> 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 specificprojects
• Short Term> Regional/local systems
> 5-10 year time frame
> 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
SELECTED SCENARIO(S)
DISTRIBUTION INVESTMENT PLANNING
INVESTMENT PLAN
FINANCIAL ANALYSIS/TARIFFS
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
Tie Capacity Optimisation
33
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
New CC 2(Gas&Diesel)
Existing ST (Gas&HFO))
WB CC 1(Gas&Diesel)
New 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%
CC-209Capcity Factor ~ 80%
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
Tie Capacity Optimisation
23
Production Costing- Options Available
24
Production Costing- Simplified Method
25
Production Costing- Probabilistic Method
26
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
New CC 2(Gas&Diesel)
Existing ST (Gas&HFO))
WB CC 1(Gas&Diesel)
New 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%
CC-209Capcity Factor ~ 80%
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
Investment Costing Module – Method 2
31
• Capital Cost Method
In this method, the entire capitalised investment is assumed to be spent at the beginning of the commissioning year.
Investment Costing Module – Method 3
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
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
SELECTED SCENARIO(S)
DISTRIBUTION INVESTMENT PLANNING
INVESTMENT PLAN
FINANCIAL ANALYSIS/TARIFFS
Planning Criteria
Least Cost Plan Reliability Targets Environment Consideration
6
[ 7 ]© IMaCS 200718-Mar-11© IMaCS 200818-Mar-11
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
[ 21 ]© IMaCS 200718-Mar-11© IMaCS 200818-Mar-11
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
[ 27 ]© IMaCS 200718-Mar-11© IMaCS 200818-Mar-11
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
[ 35 ]© IMaCS 200718-Mar-11© IMaCS 200818-Mar-11
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
BSEB-ADB DISTRIBUTION PLANNING TRAINING 28-29 Dec 2010
2
Exercise – Hands On Sample Network Modeling and Analysis Queries
Day Two, 10:30 to 18:00 hrs
BSEB-ADB DISTRIBUTION PLANNING TRAINING 28-29 Dec 2010
3
DATA
GRID – Peak Load: - 14 MW
Average Load:- 10MW
Power Factor:- 0.85
BSEB-ADB DISTRIBUTION PLANNING TRAINING 28-29 Dec 2010
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