Power Procurement: Planning, Regulation and Practices Training-2014/IITK... · Training Program on "Power Procurement Strategy and Power Exchanges" 28-30 July, 2014 ... Compulsory

…Message Box ( Arial, Font size 18 Bold)

Power Procurement: Planning, Regulation and Practices

28 August, 2014 IIT Kanpur

Puneet Munjal, Head (Commercial), Tata Power

Indian Institute of Technology Kanpur (IITK) and Indian Energy Exchange (IEX) are delighted to announce Training Program on

"Power Procurement Strategy and Power Exchanges" 28-30 July, 2014


Presentation Structure• Indian Electricity Structure

– Development– Overview

• Framework for Power Procurement• Key features of New Bidding Documents

– Overview– Major risks

• Power Management– The Challenge– Planning through Forecasting– Power Portfolio Optimisation


Development of Indian Electricity Structure

1910 1948 1956 1991 1998 2003 2013

Electricity Act

1910, license structure

Electricity Supply Act 1948; State legislature

IE Rules 1956

1991:FDI 100%;

Generation opened to Pvt

Sector1998 ERC

Act, regulatory structure and two part tariff;

Pvt Sector participation in

Tx

E-Act 2003

Draft Amendments to EA 2003


Overview of Indian Power Sector

All segments are witnessing changes

GenerationDe-licensed

TransmissionLicensed

Largest share of central and state

DistributionLicensed

Largest share of state utilities

NTPCState Utilities

RelianceTataAdani

PowerGridState Utilities

RelianceTata

State UtilitiesTata

RelianceAES

CESC

TradingLicensed

PTCTPTCL

RTLLANCO

IEX and PXIL

Regulated Returns of 15.5-16% Post

Tax


Tax


Tax

Trading Margin

Ministry of PowerMinistry of Coal

CEAMoEFCERCSERC

Ministry of PowerRLDC/SLDC

MoEFCEA

CERC/SERC

State UtilitiesSERC

CERC

Key Agencies Key Players Expected Returns

Recent Trends

Increased private participation

Increased participation from Private Players

Franchisee route is preferred by State

Utilities

Reduction in Short term tariffExchanges

developing new products

Sub-Sectors


Entry Models for a private player

Generation Transmission Distribution Trading

Winning a project through tariff based competitive bidding

Developing project based on MoUs

Developing project as Merchant Power Producer ie without any firm PPA

Developing a power plant for own consumption as CPP

Winning a project through competitive bidding

Privatisation as an when it happens

As a franchisee which as of now is the most preferred route for utilities as it does not result in parting with the ownership

As a licensee

As members of the exchanges


Ownership Segregation

coal gas diesel Nuclear Hydro RES

0

20000

40000

60000

80000

100000

120000

140000

160000

MW

Ownership Segregation in Generation(30.09.2013)

State Private Central

0

20000

40000

60000

80000

100000

120000

140000

160000

500 kV HVDC 765 kV 400 kV 220kV

CkM

Ownership Segregation-Transmission(30.11.2013)

State JV/Private Central

Growing interests of private players

Maximum interests of private players

Source: CEA


Framework for Procurement of Power• Section 63 of E-Act and National Tariff Policy paved way for a new route to

procure power i.e tariff based competitive bidding.• In essence, selecting a bidder based on Quoted Tariff• Based on this principle, two routes evolved:

– Case-1, where primarily Procurer specified the requirement and deliverypoint. Procurer does not provide any project inputs

– Case-2, where Procurer specifies a location and fuel• To streamline the process, Ministry of Power issued Standard Bidding

Documents for both these routes (in 2008), specifying the biddingconditions, terms of supply, escrow arrangements, hypothecationarrangements.

• Over the period, it was observed that fuel risk that too for longer terms,Developers can not take the burden of fuel risk

• Policymakers also felt that the SBD required certain changes.• Thus, MoP has come out with New Bidding Document


Key features of New Bidding Documents1. Mitigation of Fuel price risk

a) Fuel charge is a pass through at the heat rate specified, subject to appropriateindexation

2. Project Structure: Design Build Finance Operate & Transfer / Own (DBFOT)/(DBFOO)

Case - IIa) Utility’s land given to the selected bidder (Concessionaire)b) Compulsory buyout of Project assets by Utility at the expiry / termination of the PPAc) Term: 25 – 30 years from financial closure with two extensions of 10 – 15 years each

3. Fixed Chargea) Bidders to quote First Year Fixed charge as on Bid Dateb) Fixed charge payable each year shall be revised based on pre determined Indexationc) In case of fuel shortfall for reasons not attributable to Concessionaire, 70% of such

shortfall shall be treated as deemed availability for fixed charge recovery.


4. Capacity classification

a) Dedicated capacity: 80 – 85% of Installed capacity dedicated to Utility usingconcessional fuel

b) Open Capacity: 15 – 20% of capacity available for sale to third parties using nonconcessional fuel

c) Third Party Sale on Concessional Fuel s.t. Sharing of revenues

5. Operating Normso Normative availability of 90% for 100% fixed charge recoveryo Station heat rate of 2300 kcal/kWh at point of delivery (point of interconnection of

power station with grid)

6. Project Expansion – Additional Capacity

o Additional Capacity – Limited to 50% of the Installed capacityo 80 – 85% of the Additional Capacity dedicated to Utilityo 15 – 20% of Additional Capacity is Open Capacity

Key features of New Bidding Documents


Tariff to be quoted under the various fuel options

Option 1 Option 2 Option 3 Option 4 Option 5

Particulars Linkagefrom CIL

Captive coal block already allotted toConcessionaire

Captive coal block allotted by Utility

Imported fuel at market prices

Imported fuel from captive mines or Long term fuel contract

Fixed Charge

Fuel Charge X X X

Boundary limit for Fuel Charge Quote

Floor price & ceiling to be provided in the RFP

ceiling : 80 – 90% ofavg of prevailing price for last 180 days preceding the Bid dateFloor – To be specified in RFP

Key features of New Bidding Documents


Major Risks Risk Category MitigationFuel Availability – Supplies from CIL / Imported coal atMarket Prices

Moderate Concessionaire gets deemed availability to the extent of 70% for non availability of fuel Supplies from CIL / Imported fuel at Market prices

Fuel Availability for supplies from captive mines - In case the reserves are lower than estimated

Moderate Not addressed in the bid. May petition Regulatory Commission / GoI (MoP/MoC).

Non recovery of Fuel charge on account of actual Heat rate being higher than the Test results

High Corrections to be applied during the performance test to ensure that adequate margin is available for operations.

Under recovery of fixed charge due to higher Normative availability (90%)

Low Normative availability of 90% for 100% fixed charge recovery includes Deemed availability for unscheduled maintenance (3 – 5%) & hence in line with the current Normative availability of 85%.


Major RisksRisk Category Mitigation

Under recovery of Fuel charge on account of higher than estimated or inferred miningcost

Moderate May approach the Regulatory Commission in such a case as the current bidding document is premised on fuel charge pass through

Impact of change in law Low PPA provides for adequate protection to compensate for material adverse effect due to change in law in India & in the jurisdiction where captive mines is located.

LDs on account of delayed Commissioning within the scheduled completion date (44 months from appointed date)

Moderate Good project management

Increase in Project cost due to delay in FC on account of Lenders concern re the financial health of Utilities

High Not to bid where the procurer utilities are in bad health or seek sovereign guarantees

Increase in Project cost on account of delay in obtainingRoW for Transmission line

Moderate Would suggest the State or Central Transmission Utility to implement the Transmission Project


Constituent of Discom's Annual Revenue Requirement

81%

8%

3%6%

1% -1%

Purchase of power incl. Tx.

O&M Expenses

Depreciation

Return on Capital Employed (RoCE)Income Tax

Less: Non-tariff income

Power Purchase Cost constitutes over 80% of a Discom’s total Outlay


The Challenge

14

Rising Power Purchase Costs

Lower Surplus Disposal Rates

25-30% surplus power

5

4.11

2.96 2.94 3 3.08

2.86 3.68

4.25

5.29 5.455.66

0

1

2

3

4

5

6

7

FY 08-09 FY 09-10 FY 10-11 FY 11-12 FY 12-13 FY 13-14

Rs./

unit

Power Purchase from Central Generating Stations Power Purchase from Delhi Genco

Surplus Sale Transmission Costs

Power Purchase Cost


Need for Power Portfolio Optimization

• Multiple uncertainties to address– In demand (including weather vagaries which are highly uncertain) – In supply – In Exchange/UI rates– Availability of power transmission corridors/ transmission congestions– Buying /Selling/ Shedding pattern of other discoms

• Typical Load Curve of Delhi – surplus/ deficit needs to be planned more accurately– Huge variation in day and night loads : 500 MW in summer / 600 MW

in winters– Huge variation in summer and winter demands : 400-500 MW

• Disposal of surplus power over the next 3-4 years

15

…Message Box ( Arial, Font size 18 Bold) 16

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

36

34

32

30

28

26

24

22Bilateral (Base load) contract

Bilateral (peak load) contract

Day Ahead Hour Ahead

Sell

BuyBuy

Sell

Forecasted demand

Ancillary Service

Intra Day demand

Real-time demand

Schematic Approach to Power Procurement Optimisation

Hours

Volu

me

Due to the combination of long term and short term supplies, differing fuels, base and peaking contracts and power market procurements, optimisation has to be done for (a)

long term planning and (b) short term procurement and sale

Presenter

Presentation Notes

A significant quantum of need is traded through long term bilateral contracts. But the availability of tools to optimize demand helps the operator.


Power Procurement Process (Long Term)

• Demand Projection– As per 18th Electric Power Survey (EPS) by CEA– CAGR Growth in the licensed area

• Estimated availability from Long Term Supply– Latest Information Available from Various Sources like CEA,

Meetings, Seminars, Site Visits etc.

• Demand Supply Gap Estimated • Planning for Shortfall / Surplus Arrangements • Types of Arrangements

– Allocated– Contracted (Competitive Bidding / Long Term Bilaterals)

17


Illustrative Long Term Demand Supply Scenario

18

TPDDL Demand-Supply Scenario (Peak demand of 12-13)

DescriptionYear 13-14

Year 14-15

Year 15-16

Year 16-17

Year 17-18

Year 18-19

Year 19-20

Year 20-21

DEMAND (6% escalation on FY 13-14 YOY)NDPL Peak Demand Forecast 1508 1598 1694 1796 1904 2018 2139 2267

SUPPLYTotal Availability from CPSU Existing Power Stations 1353 1353 1353 1353 1156 1148 1148 1148

Total Availability from CPSU future Power Stations 33 134 138 208 479 489 505 505RPO as per DERC 47 65 85 106 106 106 106 106Total Availability from Delhi Genco Existing Power Stations 245 245 245 356 310 310 310 310Total Availability from Delhi Genco future Power Stations 0 0 0 0 0 0 0 0Total Availability 1678 1797 1821 2024 2051 2052 2069 2069

Shortfall / Surplus (-/+) of Total (Peak Demand) 170 199 126 228 147 34 -70 -199

10% Contingency on Demand 1659 1758 1864 1976 2094 2220 2353 2494

Shortfall / Surplus (-/+) on 10 % on Demand 19 39 -43 48 -43 -168 -284 -425

Availability Contingency of 5% 1594 1707 1729 1922 1948 1950 1965 1965

Shortfall / Surplus (-/+) on Spinning Margin of 10 % on Demand and 5 % Availability Contingency -65 -51 -134 -53 -146 -270 -388 -529


Year 13-14

Year 14-15 Year 15-16 Year 16-17 Year 17-18 Year 18-19 Year 19-20 Year 20-21

Availability Existing from Outside Delhi 1353 1353 1353 1353 1156 1148 1148 1148

Availability Future from Outside Delhi 33 134 138 208 479 489 505 505

Availability Existing from Within Delhi 245 245 245 356 310 310 310 310

Availability Future from Within Delhi 0 0 0 0 0 0 0 0

Total Availability 1678 1797 1821 2024 2051 2052 2069 2069

Peak Demand 1508 1598 1694 1796 1904 2018 2139 2267

Shortfall / Surplus (-/+) 170 199 126 228 147 34 -70 -199

1678

1797 18212024 2051 2052 2069 2069

1508 1598 1694 1796 1904 20182139

2267

170 199 126 228 147 34 -70-199

-1500

-500

500

1500

2500

MW

TPDDL Demand Supply Scenario


Power Procurement Process (Short Term)

• Demand Projection – 1 year Ahead (Reviewed Monthly or Earlier – as required – Max./ Avg. Probability– Scenario Building on Parameters

• Estimated availability from Long Term Supply based on Load Generation Balance Report (LGBR)

• Demand Supply Gap Estimated • Planning for Shortfall / Surplus Arrangements • Types of Arrangements

– Bilateral– Banking– Power Exchange– Real Time Balancing through UI 20


Decision Matrix for Short term Sale / Purchase

21

Start

Identification of Shortage / Surplus wrt 3rd

Peak Demand (fortnightly – Hourly)

Is there any ShortageShortageSurplus

Sale of Surplus Power1. Tender2. Traders /

Utilities

Whether sale or Banking is viable

PurchaseSaleBanking

Banking of Surplus Power1. Tender2. Traders /

Utilities

Whether purchase or Banking is viable

Purchase of Shortfall Power1. Tender2. Traders /

Utilities

Banking

Banking of Shortfall Power1. Tender2. Traders /

Utilities


Short Term Demand Supply Scenario

HourDemand

forecast in MW

Availability from GENCOS

Bilateral Purchase

(+)/ Banking Receipt

Bilateral Sale (-)/ Banking Return

Plant Mtc Outage

(Assumptions)

Net Availability

Shortage (-)/ Surplus (+)

w.r.t.Demand Forecast

0 to 1 916 1582 0 285 1297 3811 to 2 845 1582 0 285 1297 4522 to 3 806 1582 0 285 1297 4913 to 4 783 1582 0 285 1297 5134 to 5 761 1582 0 285 1297 5365 to 6 808 1582 0 285 1297 4896 to 7 861 1582 0 85 1497 6357 to 8 866 1582 0 85 1497 6318 to 9 885 1582 0 85 1497 612

9 to 10 1016 1582 0 85 1497 48110 to 11 1074 1582 0 205 1377 30311 to 12 1092 1582 0 205 1377 28412 to 13 1106 1582 0 205 1377 27113 to 14 1065 1582 0 205 1377 31114 to 15 1097 1582 0 205 1377 27915 to 16 1102 1582 0 205 1377 27516 to 17 1095 1582 0 205 1377 28217 to 18 1076 1582 0 205 1377 30118 to 19 1070 1582 0 205 1377 30719 to 20 1101 1582 0 85 1497 39520 to 21 1070 1582 0 85 1497 42621 to 22 1007 1582 0 85 1497 49022 to 23 1020 1582 0 285 1297 27623 to 24 1005 1582 0 285 1297 291

Demand & Availability scenario for first fortnight of April'2014


HourDemand forecast in MW

Availability from GENCOS

Bilateral Purchase

(+)/ Banking Receipt

Bilateral Sale

(-)/ Bankin

g Return

Plant Mtc Outage +

Contingency

Net Availabil

ity

Shortage (-)/ Surplus

(+) w.r.t.Dem

and Forecast

0 to 1 1085 1582 0 285 1297 2121 to 2 1029 1582 0 285 1297 2682 to 3 995 1582 0 285 1297 3023 to 4 938 1582 0 285 1297 3584 to 5 908 1582 0 285 1297 3885 to 6 892 1582 0 285 1297 4046 to 7 898 1582 0 85 1497 5987 to 8 901 1582 0 85 1497 5958 to 9 909 1582 0 85 1497 588

9 to 10 1044 1582 0 85 1497 45210 to 11 1132 1582 0 205 1377 24511 to 12 1160 1582 0 205 1377 21712 to 13 1171 1582 0 205 1377 20613 to 14 1131 1582 0 205 1377 24614 to 15 1192 1582 0 205 1377 18515 to 16 1203 1582 0 205 1377 17316 to 17 1198 1582 0 205 1377 17817 to 18 1169 1582 0 205 1377 20818 to 19 1139 1582 0 205 1377 23819 to 20 1174 1582 0 85 1497 32320 to 21 1173 1582 0 85 1497 32421 to 22 1115 1582 0 85 1497 38122 to 23 1128 1582 0 285 1297 16923 to 24 1129 1582 0 285 1297 168

Demand & Availability scenario for second fortnight of April'2014

Short Term Demand Supply Scenario


Power Procurement Process (Day Ahead)

• Demand Projection – Based on trend for Same Day of Previous Three Weeksand past two days, along with factors of Temperature, Humidity Rainfall,Holiday Status and Weekday using Demand Forecasting Software.

• Estimated availability from:– Long Term Supply based on Load Generation Balance Report (LGBR) and

Forced Outage Report of Generating Stations– Availability from Bilateral / Banking Arrangements already made

• Demand Supply Gap Estimated

• Planning for Shortfall / Surplus Arrangements

• Types of Arrangements (Day Ahead Bilateral / Power Exchange / Real TimeAdjustment through Unscheduled Interchange (UI))

24


Optimizing Power Purchase Cost

Initiatives for optimizing Availability and PPC• Continuous analysis and schedule based on merit order (must run and projects

with lower VC scheduled in priority)• Backing down initiated where VC of plants is higher than surplus sale rate in

Exchange/UI• Backing down of power plants with higher variable costs such as Bawana,

Aravali, Dadri 1&2, BTPS etc. during night hours as per requirement.

Demand Forecasting• Improved demand forecasting through sophisticated forecasting Model which

incorporates weather forecasts for optimizing Short term procurement andsale of surplus

• Pursuing development of Power Portfolio Management Application tooptimize Power Purchase Costs – Tender floated

25


Optimizing Power Purchase Cost

Initiatives for Sale Optimization• Emphasis on maximizing power sale through bilateral contracts• Day ahead sale through exchange preferred over disposing through UI• Continuous information sharing and discussions with leading traders such as

TPTCL, GMR, NVVNL, PTC for sale of surplus power• Surplus power information sent to all states and published in leading

newspapers, also published on website on regular basis.

Emphasis on contingency planning through Banking (non cash transactions)• Tender for banking of power to meet demand during summer and reduce

surplus during winters in FY 13-14

26


Desired Features in Power Portfolio Software Module (1/2)

• Demand Forecasting– Historical Demand Patterns– Weather Patterns and Forecasts– Planning Commission/CEA’s Forecasts

• Supply Forecasting– Historical Availability Data– Historical Outage Data and Turnaround times– Annual Maintenance Plan (LGBR)– Real Time Supply Scenario

• Price Forecasting– Historical Trends in Exchange– Demand Supply Pattern across India– Bilateral Market Trends

• Transmission Availability Forecasting– Congestion Data – Corridor Availability– Future Transmission Planning Scenarios

28

Power Portfolio

SCADA

SLDC/RLDC

Exchange Websites

SAP

Seamless integration with various IT Platforms


Desired Features in Power Portfolio Software Module (2/2)

• Work flow Automation– Billing/ Invoice Generation– Bill Verification/ Reconciliation– UI Settlements– Contracts Creation and Settlement– Payment Reconciliation– Seamless data integration with various IT platforms

• Optimization Scenario Planning– Risk Appetite Based– Contingency Planning

• MIS Generation for Regulatory Compliance

29

Power Portfolio

SCADA

SLDC/RLDC

Exchange Websites

SAP

Seamless integration with various IT Platforms


Benefits expected from Forecasting Software

30

1. System to generate rolling optimised portfolio

2. Long term planning – The optimisation process needs to aid Discom’s longterm planning exercises to ensure that future cost burden is limited withoutcompromising quality of supply

3. Helps in rebalancing the long term portfolio

4. Helps in managing the Contracts with different suppliers - The keycontractual provisions relating to take or pay, minimum offtake, plannedoutage, etc in the various supply conditions can be acted upon

5. Should facilitate Short term trading decisions– Help in taking positions inthe bilateral and spot markets (buy and sell) based on the optimisedportfolio thus maximising revenues and minimising costs.


Challenges in Portfolio Optimisation

• Unavailability of off the shelf tried and tested Portfolio Optimization Solutions

• Unavailability of integrated Data Repositories to make informed decisions– Demand and Supply of all States– Buying Selling Pattern and Rates for all states– Transmission congestion data– UI/Exchange historic data– Historical weather pattern

31


Website: www.tatapower.comEmail ID: [email protected] Contact No: +91-9871234287


Prices on the Power exchanges clearly indicate a high concentration for a few contiguous hours with a sharplydipping trend in the major part of the year….

• Prices in the markets have been steadily falling. It is economical to buy a part of the power from the short term markets and the exchanges at present

33

Price Trends on Exchange

0

2000

4000

6000

8000

10000

12000

14000

16000

18000

11

77

35

35

29

70

58

81

10

57

12

33

14

09

15

85

17

61

19

37

21

13

22

89

24

65

26

41

28

17

29

93

31

69

33

45

35

21

36

97

38

73

40

49

42

25

44

01

45

77

47

53

49

29

51

05

52

81

54

57

56

33

58

09

59

85

61

61

63

37

65

13

66

89

68

65

70

41

72

17

73

93

75

69

77

45

79

21

80

97

82

73

84

49

86

25

Pri

ce(P

/k

Wh

)

2009-10Average-Rs. 5.171/kWh

Hour Price Price Duration

0

2000

4000

6000

8000

10000

12000

14000

16000

18000

117

735

352

970

588

110

5712

3314

0915

8517

6119

3721

1322

8924

6526

4128

1729

9331

6933

4535

2136

9738

7340

4942

2544

0145

7747

5349

2951

0552

8154

5756

3358

0959

8561

6163

3765

1366

8968

6570

4172

1773

9375

6977

4579

2180

9782

7384

4986

25

Pri

ce(P

/kW

h)

2010-11Average-Rs.3.564/kWh

Hour Price Price Duration

0

2000

4000

6000

8000

10000

12000

14000

16000

18000

113

727

340

954

568

181

795

310

8912

2513

6114

9716

3317

6919

0520

4121

7723

1324

4925

8527

2128

5729

9331

2932

6534

0135

3736

7338

0939

4540

8142

1743

5344

8946

2547

6148

9750

3351

6953

0554

4155

7757

1358

4959

8561

2162

5763

9365

2966

6568

0169

3770

7372

0973

4574

8176

1777

5378

8980

2581

6182

9784

3385

6987

05

Pri

ce(P

/kW

h)

2011-12Average-Rs. 3.498/kWh

Hour Price Price duration

0.00

2000.00

4000.00

6000.00

8000.00

10000.00

12000.00

14000.00

16000.00

18000.00

121

542

964

385

710

7112

8514

9917

1319

2721

4123

5525

6927

8329

9732

1134

2536

3938

5340

6742

8144

9547

0949

2351

3753

5155

6557

7959

9362

0764

2166

3568

4970

6372

7774

9177

0579

1981

3383

4785

61

Pric

e (P

/kW

h)

2012-13Average - Rs 2.794/kWh

Hour Price Price Duarion


TPDDL – Demand and Supply Portfolio

34

YearEnergy requirement

(Mus)Peak Demand

(MW)

2006-07 5986 967

2007-08 6275 1068

2008-09 6371 1140

2009-10 6917 1212

2010-11 7306 1293

2011-12 7549 1401

2012-13 7764 1573

CAGR 4.43% 8.45%

• Energy requirement growing slowly, but demand is peakier

• The load duration curve indicates an aveage load of 870 MW as compared to the peak of approximately 1500 MW

• Taking a baseload duration of 16 hours, the baseload demand for FY 13 was 965 MW

• In contrast TPDDL has a large baseload component in its supply portfolio for FY 14, which aggregates 1678 MW

0250500750

1000125015001750

1 48 95 142

189

236

283

330

377

424

471

518

565

612

659

706

753

800

847

894

941

988

1035

1082

1129

TPDDL Load Duration Curve

Max.load Avg.load


Typical Summer Curve

35

0200400600800

10001200140016001800

1 3 5 7 9 11131517192123252729313335373941434547495153555759616365676971737577798183858789919395

Load Curve- July 2012

Max.load

Avg.load

0200400600800

1000120014001600

1 3 5 7 9 11131517192123252729313335373941434547495153555759616365676971737577798183858789919395

Load Curve- June 2012

Max.load

Avg.load


Typical Winter Load Curve

36

0

200

400

600

800

1000

1200

1 3 5 7 9 11131517192123252729313335373941434547495153555759616365676971737577798183858789919395Load Curve-Dec'12

Max. Load

Avg. Load

0

200

400

600

800

1000

1200

1400

1 3 5 7 9 11131517192123252729313335373941434547495153555759616365676971737577798183858789919395Load Curve-Jan'13

Max. Load

Avg. Load


Estimated Surplus Scenario

37

3487 34683280

37763432

0

500

1000

1500

2000

2500

3000

3500

4000

FY 14-15 FY 15-16 FY 16-17 FY 17-18 FY 18-19

Surplus Mus


FORECAST ACCURACY 2012 & 2013

© 2013 Skymet Weather Services Pvt. Ltd

TEMP (%) 2012 2013

JULY 62 63

AUGUST 64 79

RH (%) 2012 2013

JULY 73 81

AUGUST 78 91

RAIN (%) 2012 2013

JULY 97 96

AUGUST 96 95

RAINY DAYS 2012 2013

JULY 6 9

AUGUST 12 16


Sr. No. Name of StationSource of Fuel

Total cost

Ps/unit

Effective Gen. Cap.

MWDelhi Entl.

Delhi Share MW

TPDDL Share MW

After Aux

Year 13-14

Year 14-15

Year 15-16

Year 16-17

Year 17-18

Year 18-19

Year 19-20

Year 20-21

Year 21-22

A1 Singrauli STPS Coal 212 2000 7.50 150 44 39 32 32 32 32 0 0 0 0 02 Rihand STPS-I Coal 254 1000 10.00 100 29 26 22 22 22 22 0 0 0 0 03 Rihand STPS-II Coal 302 1000 12.60 126 37 33 27 27 27 27 27 27 27 27 27

Rihand STPS-III Coal 1000 13.19 132 38 35 28 28 28 28 28 28 28 28 284 ANTA GPS Gas 346 419 10.50 44 13 12 10 10 10 10 0 0 0 0 05 Auriya GPS Gas 327 663 10.86 72 21 20 17 17 17 17 0 0 0 0 06 Dadri GPS Gas 309 830 10.96 91 27 26 21 21 21 21 21 21 21 21 217 Unchahaar-I TPS Coal 316 420 5.71 24 7 6 5 5 5 5 5 0 0 0 08 Unchahaar-II TPS Coal 333 420 11.19 47 14 12 10 10 10 10 10 10 10 10 109 Unchahaar-III TPS Coal 372 210 13.81 29 8 8 6 6 6 6 6 6 6 6 610 Dadri NCTPS(Th) Coal 402 840 90.00 631 184 166 136 136 136 136 136 136 136 136 13611 Dadri Stage -II Coal 450 980 75.00 735 214 199 163 163 163 163 163 163 163 163 16312 BTPS Coal 320 705 100.00 530 155 139 117 117 117 117 0 0 0 0 0

2711 791 723 595 595 595 595 397 392 392 392 392B1 Bairasul Hydro 146 180 11.00 20 6 6 3 3 3 3 3 0 0 0 02 Salal- I Hydro 83 690 11.62 80 23 23 11 11 11 11 11 11 11 11 113 Tanakpur Hydro 196 94 12.81 12 4 3 2 2 2 2 2 2 2 2 24 Chamera -I Hydro 149 540 7.90 43 12 12 6 6 6 6 6 6 6 6 65 Chamera-II Hydro 322 300 13.33 40 12 12 6 6 6 6 6 6 6 6 66 Chamera-III Hydro 350 231 11.26 26 8 8 4 4 4 4 4 4 4 4 47 Uri-I Hydro 167 480 11.04 53 15 15 7 7 7 7 7 7 7 7 78 Dhauliganga Hydro 255 280 13.21 37 11 11 5 5 5 5 5 5 5 5 59 Dulhasti Hydro 497 390 12.83 50 15 14 7 7 7 7 7 7 7 7 710 Sewa-II Hydro 485 120 - 10 3 3 1 1 1 1 1 1 1 1 1

371 108 107 52 52 52 52 52 49 49 49 49C

1 Narora APS Atomic 204 440 10.68 47 14 12 10 10 10 10 10 10 10 10 10

2 RAPP 5 & 6 Atomic 302 440 12.5 55 16 15 13 13 13 13 13 13 13 13 13

102 30 28 23 23 23 23 23 23 23 23 23F1 NTPC, Jhajjar Coal 477 1500 50 750 219 204 167 167 167 167 167 167 167 167 167

D

1 Nathpa Jhakri HPS Hydro 247 1500 9.47 142 41 41 20 20 20 20 20 20 20 20 20

E

1 Tehri HPP Hydro 451 1000 10.3 103 30 30 14 14 14 14 14 14 14 14 14

2 Koteshwar Hep Hydro 350 400 9.86 39 12 11 5 5 5 5 5 5 5 5 5

41 20 20 20 20 20 20 20 20 20F

1 K'Gaon I Coal 465 840 7.54 63 18 17 13 13 13 13 13 13 13 13 13

2 K'Gaon II Coal 503 1500 10.77 162 47 42 34 34 34 34 34 34 34 34 34

3 Farakka Coal 525 1600 1.85 30 9 8 6 6 6 6 6 6 6 6 6

4 Tala HEP Hydro 184 1020 2.94 30 9 9 4 4 4 4 4 4 4 4 4

5 Mejia #6 Coal 392 250 11.76 29 9 8 6 6 6 6 6 6 6 6 6

314 92 83 65 65 65 65 65 65 65 65 65G

1 Mejia #6 Coal 382 100 29 26 21 21 21 21 21 21 21 21 212 Chandrapura TPS 2 X 250 MW Coal 423 500 - 300 88 81 65 65 65 65 65 65 65 65 65

86 86 86 86 86 86 86 86 86Maithon Power Limited

1 Maithon Power Limited Coal 256 1050 300 300 279 226 226 226 226 226 226 226 226 226

China Light & Power1 CLP, Jhajjar Coal 299 1320 - 132 132 124 100 100 100 100 100 100 100 100 100

3843 1121 1038 1353 1353 1353 1353 1156 1148 1148 1148 1148

Sr. No. Name of Station

Generation Capacity

MW

Delhi Share MW

NDPL Share MW

After Aux

Year 13-14

Year 14-15

Year 15-16

Year 16-17

Year 17-18

Year 18-19

Year 19-20

Year 20-21

Year 21-22

H2 Rajghat Coal 440 135 115 33 30 21 21 21 0 0 0 0 0 03 Pragati Gas 281 330 196 57 55 44 44 44 44 44 44 44 44 444 GT Gas 420 282 240 70 68 47 47 47 47 0 0 0 0 01 Pragati-III / Bawana Gas 517 1371 - 835 244 236 66 66 66 198 198 198 198 198 1985 NDPL UA Quota 75 68 68 68 68 68 68 68 68 68 68

1385 525 498 245 245 245 356 310 310 310 310 3105227 1646 1536 1598 1598 1598 1710 1465 1457 1457 1457 1457

NTPC Existing Stations

NHPC Existing Stations

NPC Existing Stations

THDC Existing Stations

SVJNL Existing Stations

Total

Total

Joint Power Project with Aravali Power Corpn. Jhajjar future

Estimated Capacity from Existing Plants

Damodar Vally Corporation Existing Stations

Total Availability from Existing Power Stations

Total ER

Delhi Gencos

TOTAL Existing

Delhi Own Generation existing

Total Availability from Existing Power Stations

Total

Eastern Region & Tala,HPS(BHUTAN)


Sr. NoName of StationSource of Fuel

Indicative cost

Ps/unit

Effective Gen. Cap.

MWDelhi Entl.%

Delhi Share MW

TPDDL Share MW

After Aux

Year 13-14

Year 14-15

Year 15-16

Year 16-17

Year 17-18

Year 18-19

Year 19-20

Year 20-21

Year 21-22

A

4 North Karanpura DERC Coal - 1980 7.93 157 46 43 0 0 0 35 35 35 35 35 355 Badarpur Stage - IV Coal - 980 85 833 243 226 0 0 0 0 0 0 0 0 06 Koldam HEP DERC Hydro 350 800 10.88 87 25 25 0 12 12 12 12 12 12 12 127 Tanda- II PPA Coal 278 1320 5.75 76 22 21 0 0 0 0 17 17 17 17 178 Singrauli -III PPA Coal 253 500 13.2 66 19 18 0 0 0 0 15 15 15 15 159 MUVL Meja Stage- I PPA Coal 299 1320 5.68 75 22 20 0 0 0 17 17 17 17 17 17

10 Tapovan Vishnugad PPA Hydro 200 520 13.26 69 20 20 0 0 0 10 10 10 10 10 1011 Lata Tapovan PPA Hydro 300 171 12.86 22 6 6 0 0 0 3 3 3 3 3 312 Gidderbaha Coal 327 2640 7.57 200 58 54 0 0 0 0 0 0 0 0 013 Bilhaur PPA Coal 299 1320 9.46 125 36 34 0 0 0 0 28 28 28 28 2814 Singrauli SHPS PPA Hydro 384 8 50 4 1 1 0 0 0 1 1 1 1 1 115 Unchahar-IV PPA Coal 327 500 13.81 69 20 19 0 0 0 0 15 15 15 15 15

1783 520 487 0 12 12 77 151 151 151 151 151B1 Kishan Ganga DERC Hydro 350 330 10 33 10 10 0 0 0 0 5 5 5 5 52 Parbati HEP-II DERC Hydro 350 800 8.13 65 19 19 0 9 9 9 9 9 9 9 93 Parbati HEP-III DERC Hydro 350 520 8.08 42 12 12 0 6 6 6 6 6 6 6 64 Pakal Dul HEP DERC Hydro 350 1000 2.6 26 8 8 0 0 4 4 4 4 4 4 46 Uri-II DERC Hydro 350 240 7.92 19 6 5 0 3 3 3 3 3 3 3 37 Kotibhel Stage I-A DERC Hydro 350 195 - 0 0 0 - - - - - - - - - 8 Kotibhel Stage I-B DERC Hydro 350 320 - 0 0 0 - - - - - - - - - 9 Kotibhel Stage II DERC Hydro 350 530 - 0 0 0 - - - - - - - - -

185 54 53 0 18 21 21 26 26 26 26 26C1 RAPP 7 & 8 MoP Atomic 320 1400 7.22 101 30 27 0 0 0 0 22 22 22 22 22

D1 Rampur HEP DERC Hydro 350 434 10 43 13 13 0 6 6 6 6 6 6 6 6

E

1 Tehri Pump Storage DERC Hydro 650 1000 60 600 175 173 0 0 0 0 142 142 142 142 1423 Vishnugad Pipalkoti PPA Hydro 300 444 0 0 0 0 0 0 0 0 0 0 0 0

600 175 173 0 0 0 0 142 142 142 142 142G

1 Sasan, MP DERC Coal 119 4000 11.25 450 131 122 33 98 98 98 98 98 98 98 98

2 Tilaiya PPA Coal 177 4000 3.75 150 44 41 0 0 0 0 17 26 33 33 333 Orissa 1 - Shaki Gopal PPA Coal - 4000 3.00 120 35 33 0 0 0 6 17 17 26 26 26

720 210 195 33 98 98 104 132 141 158 158 158K1 Dibang Hydro - 3000 - 34 10 10 0 0 0 0 0 0 0 0 0

L1 Subansiri HEP Hydro - 2000 - 113 33 33 0 0 0 0 0 0 0 0 0

6111 1789 1561 33 134 138 208 479 489 505 505 505N

Solar 2 3 3 4 4 4 4 4 4Non-solar 45 62 82 102 102 102 102 102 102

0 0 0 47 65 85 106 106 106 106 106 106

6219 1897 1666 80 199 222 314 586 595 612 612 612TOTAL Future

Kameng

Subansiri HEP

RPO (as per RFP)

Total

Estimated Capacity Addition from Future Plants

NHPC Future Power Stations

NPC Future Stations

SVJNL Future Stations

Total

Total

NTPC Future Power Stations

Total

Total

THDC Future stations

Ultra Mega Power Project future

Total Availability from future Power Stations (CPSUs)