TRADING STRATEGIES AND PORTFOLIO OPTIMISATION

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Power Markets and Trade in South Asia: Opportunities for Nepal

February 14-15, 2011

Overview

� Portfolio Optimisation Objectives

� Ensuring adequate availability

� Minimising costs and/or

� Maximising revenues

� Optimisation approaches

� Bidding strategies

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� Bidding strategies

� Hourly strategies

� Block bids

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What is Portfolio Management?

� A portfolio is defined as the overall collection of commodities and financialpositions on these commodities owned by a person or a company

� The purpose of a portfolio is to reduce risk by diversification.

� In the electric power industry, portfolio management is an aggregationand management of a diverse portfolio of

� spot-market purchases,

� contracts-for-differences,

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� contracts-for-differences,

� futures contracts and

� other market-hedging contracts and mechanisms

� The Structure of Portfolio is different for

� Generator

� Distribution Company

� A Trader

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Example of a Portfolio of a GenCo

Net Long Position

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Net Short Position

Elements of a Successful Portfolio Management

� The first element is defining the trade-off level between risk (security) and the participant’s perceived profit, i.e., the level which the portfolio should be hedged.

� A complete security of a portfolio could be implemented by total hedging which could be accompanied by reduced profit opportunities.

� The second element is defining the optimal timing of taking short or long position in the portfolio which would depend on experience with market moves (e.g., when the price is going to rise or drop) and depend on reliable analytical tools and trustable price forecasts.

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reliable analytical tools and trustable price forecasts.

� The third element is finding the optimal distribution or mix of different positions of the portfolio in order to balance the portfolio, i.e., how many firm contracts, futures contracts, options contracts, swaps, or others should be included in the portfolio.

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Features of Different Sale Modes

Sale Mode Description Key Features

MOU Route (PPA)

Legal contract between an electricity generator and a power purchaser at an agreed price to both the entities

• Based on norms approved by CERC• PPA negotiated between state and developer

• PPA approved by SERC

Case 1 Bidding

Where the location, technology, or fuel is not specified by the procurer

• Tariff discovered through competitive bidding route

• Standard PPA• Evaluation at delivery point• Sale at delivery point• Capacity and Energy charges to be quoted

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• Capacity and Energy charges to be quoted

Sales on the Power Exchange

Access to various products including term ahead, day ahead and intra day

• Transparent auction processes• Price signals visible• Could be useful for storage projects• Various product options possible

Sales to an intermediary or portfolio aggregator (e.g., PTC)

Legal contract between an electricity generator and an intermediary to buy power and intermediary in turn sells power to the third entity at a regulated margin and bears all the risk.

• Guarantee of minimum quantity and price• Back to Back PPA• Useful for non/limited storage projects since risks are transferred to aggregator

• Various products possible

Portfolio Optimization

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Portfolio Optimization

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MW

April 2010

Peak Load

Average Hourly Load

Minimum Load

Availability

Trading Strategies

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During a month, the daily demand can vary around the daily average hourly load by +/- 2 sigma (standard deviation). From a planning standpoint, while average (typical) demand can be used, it is important for the state to prepare for the peak demand expected in the highest load days as well 8

MW

April 2012

Peak Load

Average Hourly Load

Minimum Load

Availability

Trading Strategies

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Availability of power in the month of April 2010 was not able to meet the peak demand but in 2012 as more capacity comes up in the state, supply is able to also meet peak demand in most of the hours of the day. Trading strategy will thus differ during April month when demand supply situation changes

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• Average Hourly Load served during an hour, which shows that in various days for any particular hour there would be a need to have an active trading strategy to manage purchases. Typically the Average Load will be addressed through:

• Self generation or long term purchases• Intermediate products

• Difference between Peak Load and Average Load during the hour will always be addressed through a short term

Trading Strategies

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the hour will always be addressed through a short term trading strategy

• Differences between Loads between various hours will have to be addressed through a combination of Intermediate and Short term products, depending on standard/typical products that are available in the market

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Product Options in Medium and Short-term market

S. No. Products Definition

1. RTC (Round The Clock)

• Defined for the complete 24 in hours in a given day. • Needed when the state has deficit throughout the day.

2. Off Peak • Defined for the off peak time in a day• Provides a benefit over other products during off peak

days.

3. Night Power • Defined for the night time . • Have a comparatively lower MW to offers matching the

demand at night time4. Day Peak • Defined for the day peak, especially during the weak days

when the industries need to cater their electricity demand.

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5. Winter Hydro • Particularly for the winter season. • The product comes with a contract of specified amount,

duration and slots of its usage for the complete season. • It can be contiguously used for any 2 hrs in the morning

and 3hrs in the evening. The time may vary within the day but the traded amount of MW are constant over the entire season

6. Evening Peak • Defined specifically for the evening time . • Can cater the needs of evening peaks which hugely differs

from the day peak.7. Exchange • Can be used to buy or sell extra MW.

• It entails forecasting of prices of MWs 8. A&W • Schedule power as and when required.

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Prices in various Short term sales products by end of XI & XII plan

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Prices expected to prevail in various products is one of the crucial factors along with the generation profile that drives the sales portfolio mix of the power project during

various months and over the life of the project.

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Generation Profile

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Number of hours of generation during a day in various months will form the basis for portfolio mix of various short term products in merchant market

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Power Sales Mix

Medium-term

Short-term

2011-12 20% 80%

2012-13 20% 80%

2013-14 25% 75%

2014-15 25% 75%

2015-16 40% 60%

2016-17 40% 60%

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Given the prices prevailing in the various markets, the risks attached to it and the energy and peak deficit in the country, the portfolio consist of an appropriate mix of intermediate and short term market. The blend of mix varies till 2013-14 and beyond 2019 when the country is in deficit and fuel shortage exist, the portfolio focus more

on short-term but between 2013-14 and 2018-19, when the nation is relatively energy surplus but peak deficit continues, the blend of mix shifts towards medium term tie ups. The medium term will however be opportunity dependent. The mix

varies across the months depending upon the availability of the plant.

2016-17 40% 60%

Capacity is apportioned in

Medium term and short term

based on the available

energy during the year

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Power Sale Strategy in Merchant Market –Various Bilateral Market Products

Bilateral Products

November - April

Months

Lean Period Evening Peak, Power Exchange

Peak PeriodJune - September RTC, Peak, Off-

Peak, Power Exchange

Day Peak, Evening Peak

June - August September

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Exchange

Intermediate Period

May, October

Given the Generation and Prices in long-term, medium-term and short-term in various months and given the availability of standard products in short-term market, the portfolio of bilateral products varies during peak, intermediate and lean period.

Day Peak

May October

Day Peak, Evening Peak,

Off-Peak

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Power Sale Strategy in Merchant Market – Power Exchange

1 2 3 4 65 87 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 240

First PrioritySecond Priority Third Priority

First PrioritySecond Priority

Third Priority

Lean Period

Peak Period

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1 2 3 4 65 87 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 240

1 2 3 4 65 87 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 240

First PrioritySecond PriorityThird PriorityIntermediate Period

Till 2013-14 when the nation is in deficit, the prices prevailing in most of the hours are high. Till 2013-14, in peak and intermediate period, the plant can earn high

returns by selling during most hours of the day except 0-5 hours. Strategy for sale of power in various periods from 2013-14 when country turns into surplus varies depending upon generation, time of the year and prices expected to prevail in

merchant market.16

Monthly Portfolio Mix

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

ST Peak 0 0 0 0 0 0 0 0 0 401 401 401 0 0 0 0 0 0 401 401 401 0 0 0

MT

Peak 0 0 0 0 0 0 0 0 0 101 101 101 0 0 0 0 0 0 101 101 101 0 0 0

January

July1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

ST RTC 725 725 725 725 725 725 725 725 725 725 725 725 725 725 725 725 725 725 725 725 725 725 725 725

ST Other

than

Peak 101 101 101 101 101 101 101 101 101 0 0 0 101 101 101 101 101 101 0 0 0 101 101 101

MT Peak 0 0 0 0 0 0 0 0 0 101 101 101 0 0 0 0 0 0 101 101 101 0 0 0

October

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October1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

ST RTC 137 137 137 137 137 137 137 137 137 137 137 137 137 137 137 137 137 137 137 137 137 137 137 137

ST Peak 0 0 0 0 0 0 0 0 0 588 588 588 0 0 0 0 0 0 588 588 588 0 0 0

MT Peak 0 0 0 0 0 0 0 0 0 101 101 101 0 0 0 0 0 0 101 101 101 0 0 0

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Monthly Portfolio Mix: Illustrative Change With Storage

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

ST Peak 0 0 0 0 0 0 0 0 0 401 401 401 0 0 0 0 0 324 401 401 401 324 0 0

MT

Peak 0 0 0 0 0 0 0 0 0 425 425 425 0 0 0 0 0 0 425 425 425 0 0 0

January

July1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

ST RTC 500 500 500 500 500 500 500 500 500 500 500 500 500 500 500 500 500 500 500 500 500 500 500 500

ST Other

than

Peak 101 101 101 101 101 101 101 101 101 0 0 0 101 101 101 101 101 101 0 0 0 101 101 101

MT Peak 0 0 0 0 0 0 0 0 0 101 101 101 0 0 0 0 0 0 101 101 101 0 0 0

October

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October1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

ST RTC 137 137 137 137 137 137 137 137 137 137 137 137 137 137 137 137 137 137 137 137 137 137 137 137

ST Peak 0 0 0 0 0 0 0 0 0 588 588 588 0 0 0 0 0 0 588 588 588 0 0 0

MT Peak 0 0 0 0 0 0 0 0 0 101 101 101 0 0 0 0 0 0 101 101 101 0 0 0

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TRANSMISSION PRICING – THE EMERGING

REGIME IN INDIA

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REGIME IN INDIA

Tariff Policy Mandate

� Para 7.1 (2)

� Transmission charges should be sensitive to

� Distance

� Direction, and

� Quantum of flow

� Para 7.1 (3)

� Network users should share transmission costs in proportion of

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� Network users should share transmission costs in proportion of their respective utilization of the transmission network

� Para 7.1 (4)

� Prior Agreement with the beneficiaries should not to be a pre-condition for transmission capacity expansion

� Network expansion in consonance with the National Electricity Plan and in consultation with stakeholders, after due regulatory approvals

PGCIL Map (Till 2012)

� Evolution of high density coridors between NE/E to W and N

� Frequency integration of all regions currently, except South

� South to be integrated

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� South to be integrated better after 2012. Single national grid to become operational

� Predominantly unidirectional flows for long term transactions

Pricing under Postage Stamp (Long term User) – An Example

Exporting

Region-

NER

Loss 4%

Importing Region - NR Pooling stn.

TC=20

Loss 4%

400 km ~ 20

ps/kwh. Loss

2%

Rs. 3 per kwh

Intermediate Region -

ER

TC=20

Loss 4%

De - Pooling stn.

TC=20

100 km ~ 10

ps/kwh. Loss

2%

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2%

• Cost of delivery – Cost at Generator Terminals – 300 ps/kwh

– Transmission costs to load centre – 90 ps/kwh

– Cost of losses – 74.28 ps/kwh

– Final costs – 464.28 ps/kwh

• Much of the cost levels are genuine. There could even be element of cross-subsidisation of new transmission costs by existing beneficiaries

• If new line costs are loaded on to first user(s), then the cost of delivery can be prohibitive

• There could be a tendency of over-estimation of losses

• Hence the need to ensure a fairer allocation

Overall Options

Transmission Pricing

Based on Differences in LMPsCost and losses/congestion

�

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For India cost and congestion based pricing is relevant on account of design and

operations of the power markets

Based on Differences in LMPsCost and losses/congestion

based pricing �

Results of for 2008-09 and 2011-12 – Generation Access Charges – NEW Grid

2011-12 2008-09

Zones

Rs Lakh / MW /

Annum Ps/kWh

Rs Lakh / MW /

Annum Ps/kWh

Bhutan 10.31 11.77 12.56 14.34

Bihar-KH 9.84 11.23 13.06 14.91

CHTIS-KOR 7.64 8.72 10.15 11.59

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CHTIS-KOR 7.64 8.72 10.15 11.59

CHTIS-OTHER 10.41 11.88 12.97 14.81

Delhi, HR, Raj,

UP-W 2.09 2.38 2.98 3.40

GUJ 3.63 4.15 4.25 4.85

HP-CHM 5.06 5.78 10.77 12.30

HP-DH 4.49 5.12 4.89 5.58

HP-NJB 8.51 9.72 13.87 15.83

JandK 4.78 5.46 6.88 7.85

Results for 2008-09 and 2011-12 – Generation Access Charges – NEW Grid

2011-12 2008-09

Zones

Rs Lakh / MW /

Annum Ps/kWh

Rs Lakh / MW /

Annum Ps/kWh

Jharkhand 8.66 9.88 15.51 17.70

Maha 2.65 3.02 2.90 3.32

MP 7.70 8.79 9.45 10.79

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MP 7.70 8.79 9.45 10.79

NER 7.18 8.19 8.25 9.42

Orissa-STR 9.01 10.29

ORISSA 3.74 4.27 4.85 5.54

Sikkim 15.14 17.28 17.75 20.27

UK 4.78 5.46 5.92 6.76

UP-E&C 6.72 7.67 8.71 9.95

UP-W 1.67 1.91 2.98 3.40

WB-BFP 6.71 7.66 8.72 9.95

Results for 2008-09 and 2011-12 – Demand Access Charges – NEW Grid

2011-12 2008-09

Zone

Rs Lakh / MW

/ Annum Ps / kWh Rs Lakh / MW Ps/kWh

Bihar 6.63 7.57 8.84 10.09

Chattisgarh 3.50 4.00 4.39 5.01

Delhi 5.87 6.70 10.20 11.65

Goa 10.50 11.98 8.37 9.56

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Goa 10.50 11.98 8.37 9.56

Gujarat 5.60 6.39 6.98 7.97

Haryana 5.75 6.56 11.80 13.47

Himachal

Pradesh 4.41 5.03 8.13 9.28

JandK 5.46 6.23 13.75 15.70

Jharkhand 4.23 4.83 7.69 8.77

Results for 2008-09 and 2011-12 – Demand Access Charges – NEW Grid

2011-12 2008-09

Zone

Rs Lakh / MW

/ Annum Ps / kWh Rs Lakh / MW Ps/kWh

Maharashtra 4.87 5.56 6.75 7.71

Madhya

Pradesh 8.47 9.67 11.55 13.19

NER 14.36 16.39 12.85 14.67

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NER 14.36 16.39 12.85 14.67

Orissa 5.16 5.89 3.78 4.32

Punjab 11.06 12.62 16.81 19.19

Rajasthan 9.98 11.39 9.65 11.02

Uttarakhand 5.98 6.83 7.39 8.43

Uttar Pradesh 5.63 6.42 7.43 8.49

West Bengal 2.19 2.51 3.24 3.69

ZONAL LOSSES – Generation – NEW Grid –2008-09

Zones

Scaled up Loss as % of

Energy

Bhutan 2.27%

Bihar 3.71%

CHTIS - KORBA 3.76%

CHTIS - Other 3.73%

GUJARAT and Rajasthan South 0.42%

HP-Chamera Area 0.91%

HP-Dehar Area 0.37%

HP-Natpha Jhakri Area 1.37%

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HP-Natpha Jhakri Area 1.37%

J&K 0.55%

Jharkhand 3.87%

Maharashtra 0.84%

MP 3.43%

NER 2.84%

Orissa 0.52%

Sikkim 3.10%

UK 0.37%

UP-E&C 3.47%UP-W, Haryana, Punjab, Rajasthan-North & Delhi 0.39%

WB 1.20%

ZONAL LOSSES - Demand – NEW Grid – 2008-09

States Loss as a % of energy

Bhutan 0.28%

Bihar 1.68%

Chattisgarh 1.56%

Delhi 4.11%

Goa 1.03%

Guj 1.60%

Haryana 3.71%

HP 1.16%

JandK 2.62%

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JandK 2.62%

Jharkhand 1.34%

Maha 2.00%

MP 3.53%

NER 2.72%

Orissa 0.63%

Punjab 4.15%

Rajasthan 3.12%

UK 5.47%

UP 3.19%

West Bengal and Sikkim 0.46%

Benefits of the proposed POC methodology if extended to International Generators

� Significantly reduced transmission impact on account of avoidance of pancaking

� Ability to evaluate the most efficient interconnection point in India from a transmission cost and overall cost perspective

� Ability to access the power markets with limited or no additional costs

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costs

� Easier financing of projects on account of removal of uncertainties

� Reduced costs if transmission usage is pooled by generators

Thank You

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Thank You

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