www.iexindia.com | 01

November'15 ISSUe 8 | volUme 2

N e W S A N D I N F o r m A T I o NIEX Bulletin

In thIs Issue...

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01 Government unveils Uday Scheme for revival of ailing DISCOMs

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02OERC frames draft (Deviation Settlement Mechanism and Related Matters) Regulations, 2015

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03 CERC issues Roadmap to operationalize Reserves

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04 Wholesale Electricity Market in UK

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07 Power Market Update: October’15

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08 REC Market Update: October’15

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09 Trade Data: October’15

reGUlATorY NeWSGovernment unveils Uday Scheme for revival of ailing DISComsOn 5 November, 2015, the Union Cabinet approved a new scheme “UDAY” for revival of ailing Distribution Companies (DISCOMs). The scheme aspires to bring financial turnaround of DISCOMs by reducing their interest cost of DISCOMs, improving operational efficiencies, reduction of cost of power and enforcing financial discipline through state finances. This is the most significant reform undertaken by the Central Government to fix the finances of some the most stressed DISCOMs and create an enabling environment for a quick turnaround.

The Key highlights of the scheme are as below:

z Financial Engineering: � States shall take over 75% of outstanding DISCOM debt as on

30 September 2015 over next two years - 50% of DISCOM debt shall be taken over in FY16 and 25% in FY17. States will be exempt from calculation of fiscal deficit of the states in FY16 and FY17.

� States will issue non-SLR including State Development bonds in the market or directly to the respective banks/Financial Institutions (FIs) holding the DISCOM debt.

� DISCOM debt not taken over by the State shall be converted by the Banks/FIs into loans or bonds with interest rate not more than the bank’s base rate plus 0.1%. Alternately, this debt may be fully or partly issued by the DISCOM as State guaranteed DISCOM bonds at the prevailing market rates which shall be equal to or less than bank base rate plus 0.1%.

z Financial Discipline: The future losses of the States will be taken over by the States upto 50% by FY21. The tariff will be increased by the regulators on quarterly basis.

Year FY16 FY17 FY18 FY19 FY20 FY21Previous Year’s DISCOM loss to be taken over by State

0% of the loss of 2014-15

0% of the loss of FY16

5% of the loss of FY17

10% of the loss of FY18

25% of the loss of FY19

50% of the previous year loss

z Reduction of cost for Power: Participating States can avail additional coal at notified prices, additional power from NTPC and other PSU’s. In addition, coal linkage rationalization, coal swaps from inefficient to efficient plants, coal price rationalization based on GCV can also be availed.

z Reduction of AT&C Losses: States participating in the scheme and performing as per operational milestones will be given additional funding through Deendayal Upadhyaya Gram Jyoti Yojana (DDUGJY), Integrated Power Development Scheme (IPDS), Power Sector Development Fund (PSDF) or other such schemes. In case states are not able to meet milestones, the state will forfeit any claim to such funds.

Additional conditions: States will have to comply with Renewable Purchase Obligation from April 2012. Participation in the scheme is optional for the states.

In the long run, the restructuring creates fiscal room for discoms to start buying power from the market as well as float bids for long term PPAs, which will be positive for the power generating companies.

More information: www.powermin.nic.in

02 | www.iexindia.com

oerC frames draft (Deviation Settlement mechanism and related matters) regulations, 2015

In September, 2015, OERC framed draft (Deviation Settlement Mechanism and Related Matters) Regulations, 2015 with an objective to maintain grid discipline and security as envisaged under the IEGC and Odisha Grid Code.

These Regulations shall apply to the following Intra-State entities:

z Users those are required to give daily schedules to SLDC, unless excluded from the applicability of Deviation Settlement Mechanism under these Regulations.

z All Generating Stations in Odisha, except ISGS, all CGPs with capacity of 5 MVA and above, power plants of capacity below 5 MW excluding OHPC power plants.

z All Distribution/Trading Licensees and also to all Open Access Customers (Above 5 MW) only in respect to the electricity supplied to them by the ISGS including CGP/licensee to the extent of such supply only.

DSM Charges

z DSM charges shall be worked out on average frequency basis at the rates specified in the graph below, provided that the charges for Deviation for under drawals by buyer in a time block in excess of 5% of schedule, shall be zero and charges for Deviation for over-injection by seller in a time block in excess of 5% of schedule shall be zero, except in case of injection of infirm power.

z The Intra-State Wind or Solar Generators shall pay deviation charges for shortfall in generation to Odisha Deviation Pool Account fund as given in table below provided Fixed Rate is PPA rate as determined by the Commission under section 62 of the Act or adopted by the Commission under section 63 of the Act.

z In case of multiple PPAs, weighted average of PPA rates shall be taken as Fixed Rate. Also, Fixed Rate for Open Access participants selling power which is not accounted for RPO compliance of buyer, and captive wind or solar plants, shall be APPC rate at GRIDCO level, as determined by the Commission from time to time.

z The Intra-State Wind or Solar generators shall be paid DSM charges for the excess generation from Odisha Deviation Pool Account fund as in table below:

z DSM charges may be reviewed by the Commission from time to time and shall be re-notified accordingly.

More information: www.orierc.org

Deviation Charges in case of over injection

Sl. No. Absolute Error in the 15 Minute time block Deviation Charges Payable to Odisha Deviation Pool Account

1 <=15% FR for excess energy up to 15%

2 >15% but <=25% (1) + 90% Fixed Rate for excess energy beyond 15% to 25%

3 >25% but <=35% (2) + 80% Fixed Rate for excess energy beyond 25% to 35%

4 >35% (3) + 70% Fixed Rate for excess energy beyond 35%

Paise

/kW

h

50.0

5 an

d Ab

ove

50.0

450

.03

50.0

250

.01

50.0

049

.99

49.9

849

.97

49.9

649

.95

49.9

449

.93

49.9

249

.91

49.9

049

.89

49.8

849

.87

49.8

649

.85

49.8

449

.83

49.8

249

.81

49.8

049

.79

49.7

849

.77

49.7

649

.75

49.7

449

.73

49.7

249

.71

49.7

0Be

low

49.

70

900800700600500400300200100

0

Charges for Deviation (Paise/kWh)

Frequency

Deviation Charges in case of under injection

Sl. No. Absolute Error in the 15 Minute time block Deviation Charges Payable to Odisha Deviation Pool Account

1 <=15% Fixed Rate (FR) for shortfall for up to 15% absolute error

2 >15% but <=25% (1) + 110% FR for balance beyond 15% to 25%

3 >25% but <=35% (2) + 120% FR for balance beyond 25% to 35%

4 >35% (3) + 130% FR for balance beyond 35%

www.iexindia.com | 03

Additional Charges z In addition to DSM charges, Additional Charge for Deviation shall be applicable for over-drawal as well as under-injection

of electricity for each time block in excess of the volume limit are as below:

CerC issues roadmap to operationalize reserves

CERC vide its order dated 13 October, 2015 has charted the road map for introduction of reserves. The summary of the order is as below:

z It is essential for the grid operators to have access to distributed Spinning Reserves which are dispatched taking due care of transmission constraints whenever required.

z The Commission reiterates the need for mandating Primary Reserves as well as Automatic Generation Control (AGC) for enabling Secondary Reserves.

� All generating stations that are regional entities must plan to operationalise AGC along with reliable telemetry and communication by 1st April, 2017.

� NLDC /RLDCs and SLDCs should plan to be ready with requisite software and procedures by the same date.

� The Central Commission advises the State Commissions to issue orders for intra-state generators in line with this timeline as AGC is essential for reliable operation of India’s large inter-connected grid.

z To start with, a regulated framework in line with the Ancillary Services Regulations would need be evolved for identification and utilising of spinning reserves and implemented with effect from 1st April, 2016. This framework may continue till 31st March, 2017. This may only include generating stations regulated by CERC, which could be started off with a manual process for secondary reserves.

z In the long term, a market based framework is required for efficient provision of secondary reserves from all generators across the country. For this, NLDC/POSOCO is directed to commission a detailed study through a consultant and suggest a proposal to the Commission for implementation by 1st April, 2017, giving due consideration to the experience gained in the implementation of Spinning Reserves w.e.f. 1st April, 2016.

z States must undertake separate scheduling and energy accounting of all generating and load entities.

z Load forecasting is must for all DISCOMs.

z Adequate defense mechanisms such as Under Frequency Relays (UFRs), df/dt (rate of change of frequency), System Protection Schemes (SPS), etc. must be put in place and which also need to be periodically reviewed and checked for healthiness.

Depending on the market needs, there is a need for newer products in the electricity market to provide more opportunities to the participants to balance their portfolio. The Commission directs the staff to examine this aspect of market design and submit a proposal for consideration of the Commission.More information: www.cercind.gov.in

Additional Charges for Over Injection and Under Drawal

i. For over drawal in excess of 5% and up to 15% of the schedule in a time block

Equivalent to 20% of the Charge for deviation corresponding to average grid frequency of the time block

ii. For over drawal in excess of 15% and up 20% of the schedule in a time block

Equivalent to 40% of the Charge for Deviation corresponding to average grid frequency of the time block

iii. For over drawal in excess of 20% of the schedule in a time block

Equivalent to 100% of the Charge for Deviation corresponding to average grid frequency of the time block

iv. For under injection in excess of 5% and up to 15% of the schedule in a time block

Equivalent to 20% of the Charge for Deviation corresponding to average grid frequency of the time block

v. For under injection in excess of 15% and up to 20% of the schedule in a time block

Equivalent to 40% of the Charge for Deviation corresponding to average grid frequency of the time block

vi. For under injection in excess of 20% of the schedule in a time block

Equivalent to 100% of the Charge for Deviation corresponding to average grid frequency of the time block

04 | www.iexindia.com

Wholesale electricity market in Uk

Evolution of Wholesale Electricity Market in UK 1947: British Electricity Authority, as the generator and transmission system owner and operator was created along with the Area Electricity Boards – which were responsible for distribution and supply.

1957: Consequent to the Electricity Act 1957, British Electricity Authority was replaced by the Central Electricity Generating Board (CEGB). The CEGB was responsible for generation, transmission and supply of bulk energy to the Area Boards. CEGB was also responsible for system operation. Almost entire electricity requirement of England and Wales was generated by CEGB.

The 12 Area Boards were the only customers of bulk electricity from CEGB.

1989: The Electricity Act 1989 laid the legislative foundations for the restructuring and privatisation of the electricity industry in Great Britain. The act made provision for a change in ownership from the state to private investors, the introduction of competitive markets, and a system of independent regulation.

31 March 1990: Unbundling of generation and transmission function and horizontal break-up of generation was considered imperative for introduction of competition.

z CEGB was Split the CEGB into 2 generating companies and a transmission company. The two successor generating

companies were known as Big G (later National Power) and Little G (later PowerGen) and National Grid Company (NGC) was the transmission company

z The Area boards were replaced with 12 Regional Electricity Companies (RECs). The local distribution systems were transferred to the RECs and each REC was obliged to supply on request all reasonable demands for electricity in its authorised area.

z Establishment of the Electricity Pool: The centerpiece of restructuring was the creation of this wholesale electricity market i.e. the Electricity Pool. The pool required generators, each day on a day-ahead basis, to provide details of the price at which they were prepared to make generation available. NGC, on behalf of the pool members, provided an estimate of system demand at the day-ahead, calculated a schedule of generation to meet this estimate, and determined pool prices. All suppliers were assured supply at this wholesale pool price which could be hedged with financial contracts.

z Issues with the Electricity Pool: � Lack of competition in price setting: This model

was very concentrated as the 2 generators were basically setting the price of the market.

� Absence of demand side participation: no role of buyers in setting price.

� Manipulation of pool prices: since market power was concentrated, manipulation easy.

� Inefficient market: Less competition.

z The actions of the Regulator and government led to National Power and PowerGen to sell off generating plant in 1996 and again in 1999 to other companies to increase diversity in the market.

2000: The Utilities Act 2000 made provision for the implementation of New Electricity Trading Arrangements (NETA) to replace the mandatory pool and central dispatch with a model of voluntary bilateral contracting and self-dispatch1. Under NETA (introduced on 27th March 2001), this is achieved by suppliers contracting with generators bilaterally to meet their own contracted demand. NETA was based on bilateral trading between generators, suppliers, traders and customers through forwards and futures markets and short-term power exchanges. Suppliers are required to forecast their own demand and face strong commercial penalties under the Balancing and Settlement Code and have to balance their own portfolio through their contracts. The trading under NETA was closer to the event i.e. an hour and a half to actual delivery whereas in case of the pool trading was 19 to 43 hours ahead.

1. Self-dispatch: Each generator is responsible for determining the level of output from each of its units as opposed to the National grid schduling on behalf of all generators under the pool.

mArkeT INSIGhT

Figure 1: Quick Facts About the UK Power SectorEnergy Mix in UK

Other, 6.15%

Gas, 36.61%

Nuclear, 22.84%

Coal, 19.24%

Wind, 5.77%

Interconnectors with France and Netherland

8.88%

Hydro, 0.51%

z 2014 Power consumption (excluding losses): 303.41 TWh � Industrial: 93.37 TWh,

� Domestic: 108.88 TWh,

� Commercial, transport & agriculture: 101.16 TWh, z 4,001 kilowatt hours (KWh): Avg electricity

consumption/household (2014)

www.iexindia.com | 05

On 1st April 2005, NETA was extended to cover Scotland and is now known as BETTA (British Electricity Trading and Transmission Agreement).

Positive effects of NETA on the UK Wholesale Market z Increased competition: Number of generators increased

to 35 (from 6) in 2001 after NETA was established. z Reduced prices: Reduction in prices by 25% experienced

soon after NETA was adopted. z Enhanced liquidity

Trading in the Wholesale Electricity Market in UKParticipants of the UK Wholesale Electricity Market:

z Suppliers (Big 6 & Independent Suppliers) z Generators z Power Exchanges (N2EX & APX) z Brokers for OTC Market z National Grid, as system operator z Elexon for imbalance settlement

Under the prevailing system in UK, the Supplier procures electricity to be provided to the end consumer either through the Power Exchanges or Bilateral contract directly with generator or through brokers. In UK, large energy users can also purchase direct through the wholesale market.

Types of contracts in the wholesale market: z Bilateral/OTC contracts: Free formats, less liquid. z Contracts on Power Exchange:

� Long duration contracts: Physical and financial with different standardized format.

� Day Ahead Market (like in India). � Intraday market/Spot Market (like in India).

z System Operator runs balancing market and market for operating reserves

Baseload products are traded through long term contracts due to certainty around requirements, the supplier

purchases short term peak products to shape their portfolio to the changing demand of their customers within day. Short term products can be purchased bilaterally or through brokers, but can also be traded through Day-Ahead Auctions and Intraday (Spot) market (run by Power Exchanges: APX and N2EX). The long term contracts range mostly upto 24 months ahead. Very limited volume is traded in products ranging more than 24 months. Following the historical trend there is a greater volume of trade for near term delivery (day ahead/intraday) than in the longer term, though there was continued liquidity for the season ahead. All companies trade to manage risks and suppliers shape their portfolio to meet expected consumer demand. From the perspective of a supplier, forecasts that are closer to delivery are more accurate than the longer forecasts which entail greater risks. As a result, interest lessens in trades further out.

Most long term contracts are traded in the OTC (Over the Counter) Market i.e. bilateral non standardized contracts. The volume comparison is given below:

Tota

l Vol

ume

(TW

h)

Chur

n Ra

tio

160

140

120

100

80

60

40

20

0

9.0

8.0

7.0

6.0

5.0

3.0

4.0

2.0

1.0

0.0

OTC ICE N2EX APX Churn

Jan-

11

Apr-

11

Jul-1

1

Oct

-11

Jan-

12

Apr-

12

Jul-1

2

Oct

-12

Jan-

13

Apr-

13

Jul-1

3

Oct

-13

Jan-

14

Apr-

14

Jul-1

4

Oct

-14

Jan-

15

Apr-

15

Figure 3: GB wholesale electricity trading volumes and churn, 2011-2015

Trading "Wholesale" market

OTC Market Exchange

Spot Market Spot MarketFutures Market Futures Market

Physical Physical

Forwards/ options/

structured products

Settlement: physical and

financial

Futures/options

Settlement: mainly financial

Figure 2:

Source: ICIS, APX, Nord Pool Spot, ICE, DECC Energy Trends

06 | www.iexindia.com

20072008200920102011201220132014

20072008200920102011201220132014

20072008200920102011201220132014

0% 20% 40% 60% 80% 100%

Spot/prompt 2-12 months 13-24 months > 24 months

Baseload

Peak

O�-Peak

Figure 4: Shares of OTC power trading volumes by time to delivery, 2007-2014

Figure 5: Average Wholesale baseload UK Power Prices by Delivery Date, £/MWh

Source: ICIS, Ofgem analysis

Source: APX, LEBA, ICE (Intercontinental Exchange)

₤80

₤75

₤70

₤65

₤60

₤55

₤50

01-1

0-20

12

01-1

2-20

12

01-0

2-20

13

01-0

4-20

13

01-0

6-20

13

01-0

8-20

13

01-1

0-20

13

01-1

2-20

13

01-0

2-20

14

01-0

4-20

14

01-0

6-20

14

01-0

8-20

14

01-1

0-20

14

01-1

2-20

14

01-0

2-20

15

01-0

4-20

15

01-0

6-20

15

01-0

8-20

15

01-1

0-20

15

₤45

₤40

₤35

₤30

Spot Month ahead Season ahead Year ahead Two Years ahead

The prices as experienced in India as well, are most competitive in case of Day Ahead Auction, the same is

evident in most scenarios from the graph below in case of UK as well.

www.iexindia.com | 07

mArkeT NeWSPower market Update: october’15With average Area Clearing Price (ACP) in all regions except South at `2.89 per unit, almost 16% lower than ACP of `3.42 per unit in September, the IEX Spot Power Market was more buyer friendly throughout the month of October.

Average daily trade in October was 105 MUs with average daily participation of 926 participants. The market continued with its buyers’ bias as average daily sell bids at 142 MUs exceeding buy bids of 132 MUs.

As regards Inter-state transmission congestion, with the recent commissioning of West-North inter-regional Gwalior – Jaipur 765 KV double circuit link, the congestion experienced earlier by the Exchange towards importing power into Northern States is not there anymore. However, congestion towards the South continues to remain a deterrent to trade. The Exchange lost 164 MUs in October as a result of congestion in the Inter-State Transmission System towards Southern Region.

Volumes A few key power market highlights are as given below:

� Total Sell bids – 4.10 BUs � Total buy bids – 4.43 BUs

The Northern and Southern States were the Net Buyers.

� Northern States bought – 1,298 MUs, 17% less over the previous month.

� Southern States bought - 272 MUs, same as the previous month.

The Eastern, Western and North-Eastern States were the Net Sellers

� Western States Sold – 1,610 MUs, 19% more over the previous month.

� Eastern States Sold – 775 MUs, 29% more over the previous month.

� The North-Eastern States Sold – 138 MUs, 16% less over the previous month.

The table below gives complete Buy-Sell Picture for October’15 vis-à-vis September’15:

REGIONBUY (MU) SELL (MU)

NETOctober'15 September'15 Change (%) October'15 September'15 Change (%)

North East 55 36 53% 138 165 -16% SELL

East 548 612 -10% 775 602 29% SELL

North 1298 1555 -17% 561 787 -29% BUY

West 1073 713 50% 1610 1357 19% SELL

South 272 272 0% 162 278 -42% BUY

Prices (ACP)

The Average Area Clearing Price (ACP) in October across all regions except South was `2.89 per unit, 16% lower than ACP of `3.42 per unit last month. The dip in demand due to the setting in of winters in the Northern region coupled with the easing of congestion and ample supply led to the decrease in prices this month.

In South, price was `4.88 per unit, 21% lower than `6.18 per unit in the previous month, owing to relative easing of transmission congestion as well as availability of generation within the region.

The average area prices in October vis-à-vis September are as summarised in the table below:

Transmission Congestion Analysis � ER-SR & WR-SR corridors were congested for about

80% of time through the month.

Participation

926 participants traded in the spot market on an average daily basis, with the highest participation on 20 October, 2015 when 992 participants traded on the Exchange.

Term-Ahead Market:

A total of 27.60 MUs were transacted in October - 20.88 MUs in the Intra-Day segment and 6.72 MUs in the Day-Ahead Contingency segment.

BID AREASAverage Area Prices - ACP (`/kWh)

October'15

Rest of India 2.89

South (SR) 4.88

MCP* 3.03

* MCP (Market Clearing Price) refers to the price discovered before accounting for congestion in Inter-State transmission network.

* ACP (Area Clearing Price) refers to the bid area prices discovered after accounting for congestion in the Inter-State transmission network.

08 | www.iexindia.com

Eligible Entities (RE Generators) 1,764 are Obligated Entities (DISCOMs, Open Access Consumers & Captive Generators) and 13 are registered as Voluntary Entities.

An overview of participation in the REC Market at IEX as on 31st October, 2015:

The REC Market session at IEX held on 28th October 2015 witnessed trade of 80,608 RECs – 68,663 N-Solar and 11,945 Solar RECs.

� In the non-solar segment, total buy bids were 68,663 and total sell bids were 73,25,684. All the buy bids were cleared at floor price of `1,500 per REC.

� In the solar segment, total buy bids were 11,945 RECs and sell bids were 22,21,069 RECs. All buy bids were cleared at floor price of `3,500 per REC.

REC trade this month saw a decrease of over 48% over the previous month when a total of 1.56 lacs RECs were traded.

Participants

A total of 1,033 participants traded at IEX with 702 participants in non-solar segment and 331 participants in the solar segment.

On an overall basis, a total of 2,561 participants are registered in the REC segment at IEX. Of this, 784 are

Total number of registered participants 2,561

Obligated Entity 1,762

DISCOMs 26

Open Access consumers 1,637

Captive Consumer 77

Voluntary 13

Eligible Entity (Private Generators) 786

Highest participation in a session March'15 1,315

3,428 (29%)

4,483 (37%)4,034 (34%)

Solar Buyer Mix

DiscomOpen Access Consumer

Distribution LicenseeCaptive User Open Access

Non Solar Buyer Mix

25,882 (38%)714 (1%)

42,067 (61%)

Captive User

reC mArkeT UPDATe: oCTober’15

www.iexindia.com | 09

TrADe INFo: oCTober’15

moNThlY PrICe SNAPShoT

moNThlY volUme SNAPShoT 1 mU = 1 million kWh = 1 GWh

Minimum MCP Maximum MCP Average MCP

` 3.03/kWh ` 4.90/kWh` 0.90/kWh

Average Daily

Volume

105 MUs

Unconstrained Volume

3,409

4,583

Cleared Volume

3,246

4,363

PurchaseBids

4,103

5,515

Sell Bids

4,431

5,956

Cumulative Cleared

Volume (MU)

19,525For FY'16

VOLUME

Average Daily (MW)

TotalVolume (MUs)

Term AheAD mArkeT SNAPShoT – october’15

Total Volume (MWh)

Max Price (`/kWh)

Min Price (`/kWh)Contracts

6,718 4.80 2.80Day-Ahead Contingency

- - -Weekly

20,881 6.25 2.00Intraday

- - -Daily

AreA PrICeS

Prices (`/kWh)

Area Min Max RTC* (0-24 hr)

Peak* (18-23 hr)

Non Peak* (1-17 & 24 hr)

Night* (1-6 & 24 hr)

South 1.80 12.00 4.88 5.74 4.60 3.27

RoI 0.70 4.75 2.89 3.11 2.81 2.73

10 | www.iexindia.com

PArTICIPATIoN SNAPShoT (as on 31st october, 2015)

Total Registered Participants

3,500+

Open Access Consumers

3,203

Private Generators

312

Highest Participation

1,410, 22nd June '13

RP: Registered Projects, AP: Accreditated Projects

reC mArkeT SNAPShoT

Trade Session on 28 October, 2015

RECPurchase

Bids Sell Bids Cleared (REC) Price (`/REC)

Participants

73,25,684 1,50068,663 702Non Solar 68,663

11,945 3,500Solar 11,945 22,21,069 331

1036

738

350

137

370

155

203

83 73117 296

Registered Projects

Source-wise RE Capacity (MW) State-wise RE Capacity (MW)

Small Hydro

Solar

Others

Wind

Bio-fuel Cogeneration

Biomass

Tamil Nadu

Karnataka

Chhattisgarh

Maharashtra

Rajasthan

Punjab

Uttar Pradesh

Andhra Pradesh

Himachal Pradesh

Gujarat

Madhya Pradesh

Others

2274

924

699

291

595 2

Registered Projects

RP: 4785 MW RP: 4785 MW

1227

www.iexindia.com | 11

CoNGeSTIoN ProFIle (october 2015)

E�NW�NS1�S2W�SE�S

79.8% 79.8%

0.0% 0.0% 0.0%0.0%

10.0%

20.0%

30.0%

40.0%

50.0%

60.0%

70.0%

80.0%

90.0%% of time congestion

First time in the year, no congestion in W�N, E�N

HoursHourly MCV (MWh) Hourly MCP (`/kWh)

Volu

me

(MW

h)

Pric

e (`

/kW

h)

3.90

4.00

4.10

4.20

4.30

4.40

4.50

4.60

4.70

4.80

0.00500.00

1000.001500.002000.002500.003000.003500.004000.004500.005000.00

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

Average Hourly Market Clearing Volume and Price for the month

Pric

e `/

kWh

Volu

me

MW

h

01-1

0-20

15

02-1

0-20

15

03-1

0-20

15

04-1

0-20

15

05-1

0-20

15

06-1

0-20

15

07-1

0-20

15

08-1

0-20

15

09-1

0-20

15

10-1

0-20

15

11-1

0-20

15

12-1

0-20

15

13-1

0-20

15

14-1

0-20

15

15-1

0-20

15

16-1

0-20

15

17-1

0-20

15

18-1

0-20

15

19-1

0-20

15

20-1

0-20

15

21-1

0-20

15

22-1

0-20

15

23-1

0-20

15

24-1

0-20

15

25-1

0-20

15

26-1

0-20

15

27-1

0-20

15

28-1

0-20

15

29-1

0-20

15

30-1

0-20

15

31-1

0-20

15

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00IEX Price and Volume Trend in October 2015

Cleared Volume (MWh) MCP N1 S1

Pric

e D

i�er

entia

l (`/

kWh)

00.5

11.5

22.5

33.5

South Import

01-1

0-20

15

02-1

0-20

15

03-1

0-20

15

04-1

0-20

15

05-1

0-20

15

06-1

0-20

15

07-1

0-20

15

08-1

0-20

15

09-1

0-20

15

10-1

0-20

15

11-1

0-20

15

12-1

0-20

15

13-1

0-20

15

14-1

0-20

15

15-1

0-20

15

16-1

0-20

15

17-1

0-20

15

18-1

0-20

15

19-1

0-20

15

20-1

0-20

15

21-1

0-20

15

22-1

0-20

15

23-1

0-20

15

24-1

0-20

15

25-1

0-20

15

26-1

0-20

15

27-1

0-20

15

28-1

0-20

15

29-1

0-20

15

30-1

0-20

15

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2015

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