Regulatory and Commercial Issues_PMI_11.3.2008

7/31/2019 Regulatory and Commercial Issues_PMI_11.3.2008

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Regulatory and

commercial Issues

by

S. K. Sharma

DGM, Commercial

NTPC LIMITED11.3.2008


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Power sector in the country has always beenfacing generation deficit conditions.

There were no dearth of opportunities forNTPC for capacity addition.

Earlier states were encouraging capacity

addition by NTPC in the respective states.

Tariff for sale of power were initially decidedby Govt. of India. Subsequently, from 1999,

CERC was constituted and tariff determinationwas transferred to CERC.

Over the years, CERC has tightened

normsbut norms fixed had margins for earningadequate return.


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NTPC was always considered as one of the

best performing power utilities in the country. Recent developments, particularly after

enactment of Electricity Act, 2003 haschanged the business environment.

Power sector has been opened up forcompetition.

In the generation sector, many private playersare active. Transmission sector which wasvirtually the monopoly of Powergrid, there alsoprivate sector is taking interest.


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SEBs are being restructured into separate

generation, transmission and tradingcompanies. So far NTPC was dealing withone utility in the state. Now in many states,power supplies are to ample distribution

companies.

With privatisation and distribution, privatediscoms are also now customers of NTPC.

Lower tariffs offered by private generators inthe tariff based bidding process of capacityaddition, has set new benchmarks and

challenges for NTPC.


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Tariff Policy issued by GOI on 6th Jan06

stipulate that all new capacity additions evenfor public sector should be through competitivebidding after a period of 5 years or when theRegulatory Commission is convinced that the

time is ripe to introduce such competition.

The above principle implies that in future forcapacity addition, NTPC has to compete with

the private sector for getting projects forcapacity addition.


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Recent tariff quotes by the private utilities forSasan, Mundra, Anapara & Gujarat Projects

indicate that new capacity additions of NTPCare not competitive.

Response of the private sector in case of UltraMega Power Projects has been very

encouraging. Almost about 10 parties hadquoted for these projects, which indicate thatprivate sector is now interested in makinginvestment in generation sector.

Many of the states have initiated action forcapacity addition through tariff based biddingroute.


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Considering lower rates which the states are

getting through tariff based competitive biddingroute, it is expected that in future all the stateswould be going for capacity addition through thisroute.

Future capacity addition for NTPC could be onlythrough the competitive route.

For adding capacity through this route, thequotes have to be competitive for whichreduction in cost of power is must.


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1. PRICE FOR SALE OF ELECTRICITY

Tariff Policy

Interaction with price fixation agencies on principles andparameters

Determination of Tariffs

2. ARRANGEMENTS FOR SALE OF ELECTRICITY

Power Purchase Agreements

Allocation of Power

Metering Arrangements

Regional Energy Accounts

COMMERCIAL FUNCTIONS


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3. REALISATION AGAINST SALE OF ELECTRICITY

Receivables Management

LC / Escrow / State Govt. Guarantee/ Central Appropriation

Bonds / Securitisation / Special Schemes

4. MANAGING THE COMMERCIAL ENVIRONMENT

Electricity Legislation

Policy initiatives with Government and Regulatory

Agencies Sectoral Reforms

Regional Electricity Boards

COMMERCIAL FUNCTIONS contd..


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Billing for 2006-07 - Rs. 30738 Crores

Average Monthly Billing - Rs. 2562 Crores

LC coverage as on date - Rs. 2789 Crores

Realisation for the year 2006-07 - 100.8%

Average NTPC Tariff - 174 p/unit

All states are making full payments within 30 days of

billing except UP. UP is making payments within 60 days.

BILLING AND REALISATION


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Ten Largest Customers

S.No. State Billing (Rs.Cr)

1. Uttar Pradesh 47002. Maharashtra 3037

3. Delhi 2940

4. Andhra Pradesh 2520

5. Tamil Nadu 1950

6. Madhya Pradesh 1865

7. Gujarat 1600

8. Gridco 13069. Haryana 1250

10. Bihar 1010

Others 8560

TOTAL 30738


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Bonds issued under Tripartite Agreement Rs. 18133 Cr

Outstanding amounts :

Delhi - Rs. 1310 Crores


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Allocation of Power Metering

Energy Accounting

Tariff

Billing & Payment Treatment of disputed amounts

Payment by establishment of LC

Right to draw power limited to LC

Rebate & Surcharge Resolution of disputes - Mutual discussion, REB/RPC, Arbitration

Force Majeure

Effective Date & Duration of Agreement (Validity period)

Salient Features Of The PPA


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Risk MitigationTransmission Risk Beneficiaries

Fuel Risk NTPC

Take or Pay Beneficiaries

Payment Risk TPA

Regulation/ Diversion of power

Escrow in future

ITax, Levies, Cess etc Beneficiaries

Change in law Beneficiaries

Salient Features Of The PPA contd..


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Regulatory Framework

in

Indian Power Sector


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Earlier Acts in Indian Power Sector Electricity Supply was earlier governed by

three Acts, namely

Indian Electricity Act, 1910

Electricity (Supply) Act, 1948

Electricity Regulatory Commission Act,1998

Present Act

The Electricity Act, 2003


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Role of Central Regulators (CERC)

Functions of Central Electricity Regulatory Commission

to regulate the tariff of Central Govt. owned or controlled generatingcompanies;

to regulate the tariff of inter-state generating companies

to determine tariff for inter-state transmission of electricity;

to issue licenses for inter-state transmission and trading of electricity;

to adjudicate upon disputes involving generation companies ortransmission licensee

to specify Grid Code

to specify and enforce the standards with respect to quality, continuityand reliability of service by licensees;

to fix the inter-state trading margin, if considered necessary


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Role of State Regulators (SERC)

Functions of State Electricity Regulatory Commission:

Intra-state tariff for generation, supply, transmission and wheeling of electricity,wholesale, bulk or retail

Cross-subsidy surcharge & wheeling charges for open access consumers

regulate electricity purchase and procurement process of distribution licensees;

facilitate intra-State transmission and wheeling of electricity;

issue intra-state licenses for transmission, distribution and electricity trading;

promote cogeneration and renewable sources of energy;

adjudicate and arbitrate upon the disputes between the licensees andgeneration companies;

specify State Grid Code consistent with the Central Grid Code specify or enforce standards with respect to quality, continuity and reliability of

services by licensees;

fix the trading margin in the intra-State trading of electricity, if considered,necessary


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Role of Central Government

Central Government shall prepare- National Electricity Policy

- Tariff policy

- Policy for permitting stand alone system for rural areas.

- National policy for rural electrification Central Electricity Authority shall prepare a National Electricity

Plan.

To issue guidelines for tariff based competitive bidding process.

The Appropriate Central Commission shall be guided by suchdirections in the matter of policy involving public interest as theCentral Government may give in writing.


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NTPCs Current Regulatory Interface

Evolution of Tariff and other Regulations

Central Commission by Notification make Regulations. While notifying the Commission presently follows the following

procedure:

Prepare concept paper /draft regulation and post in Web site.

Comments/Suggestion invited from all Stakeholders and others

Organize open house hearings.

Finalise Regulations and issue detailed orders giving reasons.

Notify in the official Gazette

Important Regulations of Central Commission

Business Regulations in 1999.

Tariff Regulations, 2001 for determination of tariff for the period 2001-04. Tariff Regulations, 2004 for determination of tariff for the period 2004-09.

Open Access Regulations

Trading Licence

Transmission Licence


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Initiation of Proceedings

Suo-moto or on a petition filed by any affected or interested person.

CERC has issued detailed procedure for filing of petitions

The Commission issues notices for hearing and reply and rejoinder bythe affected parties.

The Petition, thereafter, come up before the Commission for hearing

(which may continue for one or more number of hearings).

Services of legal practitioners are availed on specific legal issues only,otherwise case presented by the technical person of the Petitioner.

The Commission, sometime directs various parties during the hearingfor furnishing some additional details.

Commission has expert staff in the arrears of Engg. Finance and legalfor study of petitioner and preparing recommendation.

Thereafter the Commission pass orders on the petition.


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Review of Commissions orders

The Commission has the power to review its decision,direction and orders.

Aggrieved party has to file petition for review by the

Commission within 60 days of the making of theorder.

The Commission, generally, allow review if there isany apparent error on the face of records.


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Appeal

Central Government established Appellate Tribunal forelectricity to hear appeals against order of theCommission.

Aggrieved Party may prefer an appeal to the AppellateTribunal within 45 days from the date of the order.

Second Appeal against the Order of the AppellateTribunal can be filed in Supreme Court.


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Generation Tariff


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DIFFERENT TARIFF PROVISIONS

0

20

40

60

80

100

120

140

160

180

0 20 40 60 80 100 120

DEEMED PLF(AVAILABILITY)

FIX

EDCHARGES

INCENTIVE

SINGLE PART

KPRAO

CERC ORDER


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Generation tariffof regional stations consists of-

Capacity charges Energy charges

UI charges

Capacity charges are recovered at 80% availability & pro-rata

recovery below 80%. For generation above 80%, PLF incentive atthe rate of 25 paise/Unit

Energy charges are based on actual fuel cost and normative

operating parameters. Energy charges are paid based on scheduled

generation.

UI charges are linked to frequency and are levied on deviations from

schedules.

Availability Based Tariff


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UI Charges

0

100

200

300

400

500

600

700800

48

.8

48

.9

49

49

.1

49

.2

49

.3

49

.4

49

.5

49

.6

49

.7

49

.8

49

.9

50

50

.1

50

.2

50

.3

50

.4

50

.5

50

.6

Freqency (Hz.)

Ra

te(P/Un

it)


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UI Charges

Max. UI rate increased to 1000 p/unit. Each 0.02 Hz step isequivalent to 8.0 paise/kWh in the 50.5-49.8 Hz frequency

range, and to 18.0 paise/kWh in the 49.8-49.0 Hz frequency

range

in case of generating stations with coal or lignite firing and

stations burning only APM gas, UI rate shall be capped at

406 paise per kWh

A band has been provided for generation above DC. (5%above DC in any time block, restricted to 1% over a day

for payment of UI for generation above DC has been

provided)


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Capacity charges consists of

Return on equity (ROE)

Interest on Loan

Depreciation

O&M Cost

Interest on Working Capital

Generation Tariff


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Tariff Period - 5 years

Debt : Equity Ratio - 70:30 In case equity is more than 30% it shall be limited to 30%

and excess equity shall be treated as normative loan and

shall be serviced at weighted average rate of interest ofthe outstanding loan.

As per this provision, for the stations where debt:equity

ratio was 50:50, it will now be 70:30 and equity in excess

of 30% will be treated as notional loan.


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Capital Cost For existing stations

Admitted by Commission upto 31.3.2001

+ Addcap & FERV for the period 2001 - 2004.

For new stations

Actual expenditure capitalised

+ Spares @ 2.5% for coal based stations & 4% for gas basedstations & 1.5% for hydro station.

Return on Equity

14% post tax Income Tax pass through on Generation Income.


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Interest on loan

On weighted average actual interest rate

Outstanding loan as on 31.3.2004

Normative repayment during 2004-09.

Interest on loan has been allowed on normative outstanding loan.

Commission has further said that during the period of moratorium,

depreciation recovery shall be considered towards loan repayment

while working out interest on loan.


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Depreciation On straight line basis

3.6% - coal based stations

6% - gas based stations

2.57% - Hydro

Advance Against Depreciation Limited to 1/10th of loan amount i.e. Dep + AAD = 7%

(maximum)


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Interest on working capital

Fuel Cost

Coal based stations - 1 month for pit head and 2 months for non-pithead corresponding to target availability.

Gas based Stations Cost of fuel for 1 month

Secondary Fuel

Coal based stations Cost of secondary fuel oil for 2 months

Gas based Stations Cost of Liquid fuel for month.

O&M expenses for 1 month

Spares 1% of historical capital cost escalated @ 6% from COD.

2 months receivables

Earlier provisions for stock of coal & oil were on normative stock or

actual whichever is lower. Now it has been provided on normative basis.


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These are now fixed on normative basis about 2.5% of

current capital cost.Coal based stations

- 200/210/250 MW - Rs.10.4 lacs/MW

- 500 MW and above - Rs. 9.36 lacs/MW

Gas based stations

- Stations with warranty spares - Rs. 5.2 lacs/MW

- Without warranty spares - Rs. 7.8 lacs/MW

Escalation 4% per year

Tanda & Talcher TPSsO&M cost provision have been

provided based on actual of last 5 years

O&M Charges


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Operating Norms

Heat Rate- 200 MW - 2500 kcal/kwh (same as earlier)

- 500 MW - 2450 kcal/kwh (reduced by 50 kcal/kwh).

In case of MDBFP Heat rate will be reduced by 40

kcal/kwh.- Gandhar / Faridabad / Kayamkulam - 2000 kcal/kwh

- Dadri / Anta / Kawas - 2075 kcal/kwh

- Auraiya - 2100 kcal/kwh

- Future gas based stations

1850 kCal/kwh for Advanced class

1950 kcal/kwh for conventional machines


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Specific Oil Consumption 2 ml / kwh (reduced from - 3.5 ml/kwh)

Auxiliary Power Consumption

Stabilisation Period 180 days allowed only upto March, 2006.

No relaxed norms for target availability have been allowed during stabilisation period.

Without cooling tower With cooling tower

200 MW 8.5 9.0

500 (TDBFP) 7.0 7.5

500 (MDBFP) 8.5 9.0

Gas Stations

Open Cycle 1.0

Combined Cycle 3.0


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Target Availability - 80%

Disincentive pro-rata of fixed charges

Incentive at flat rate of 25 paise/unit on generation above

80% scheduled PLF.

Coal Losses Landed cost of coal shall be computed considering transit

loss of-

CERC Norm- Pit Head 0.3%

- Non Pit Head 0.8%


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Other Provisions

Provision regarding actual or norm whichever is lower hasbeen deleted. It will provide efficiency gain from future

stations.

Commercial Operation Date

Earlier regulation stipulated a period of 180 days between

synchronisation of a coal unit and its commercial

operation.

This provision has been deleted. It is a welcome

change.


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ISSUES OUT OFCERC REGULATIONS

2004-2009


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Capitalisation by Cut-Off Date

As per the Regulations, cut-off date has been defined as FinancialYear closing after one year of the COD of the last unit.

Regulations stipulate that for new projects capitalisation of the work

of approved scope will be allowed only upto the cut-off date except

for ash dyke.

In the past, it has been seen that many works such as township,

road construction, administration building, other off-site works are

executed and capitalised even upto 3-4 years of COD of the lastunit.

In case of new projects, capitalisation of all works before the cut-off

date to be completed.


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Capitalisation After Cut-Off Date

Following categories of works only will be allowed aftercut-off date:

Deferred liability relating to works within the originalscope of work.

Liability to meet arbitration or decree of court

New works on account of change in law.

Works necessary for efficient and successful

operation not included in original scope. Deferred works of ash dyke.

In case of any delay in contract closing, additionalliabilities after cut-off date may not be allowed.


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Items Not Allowed After Cut-Off Date

Any expenditure on minor items/assets like normal

tools and tackles, personal computers, furniture, air-

conditioners, voltage stabilizers, refrigerators, fans,

coolers, TV, washing machines, heat-convectors,carpets, mattresses etc. brought after the cut-off date

shall not be considered for additional capitalisation

for determination of tariff with effect from 1.4.2004.


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Procurement of Initial Spares

Procurement of initial spares and their capitalisation

continue even upto 3-4 years of COD of the last unit.

In some of the cases, entire provision of the initial

spares in approved cost has not been fully utilised.

As per new regulations, capitalisation of initial spares

will have to be completed by cut-off date.

Necessary planning for identification and ordering of

spares full utilisation of initial spares to be ensured.


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In order to supply electricity directly to theDISCOMS and realise the full advantages of

UI, ABT implementation in single statestations to be implemented. ABT at Simhadri,Badarpur, Faridabad, Tanda & TalcherTPShas been implemented for 01.12.2005.

ABT Implementation in Single State Stations


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Average Tariff Of NTPC Stations

1999-2000 - 145.47p/kwh

2000-01 - 157.20p/kwh

2001-02 - 142.84p/kwh

2002-03 - 147.12p/kwh

2003-04 - 146.51p/kwh

2004-05 - 152.06p/kwh

2005-06 - 167.00p/kwh

2006-07 - 174.00p/kwh


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48 Depreciation and Return are the factors which promote investment in the sector,

constitute only 11% and should not be targeted for cost reduction.

8%

6%

7%

35%

6%

8%

5%

25%

100%

Fuel O&M Return

& dep

O&M AT&C Int. TotalDep. &

ReturnIntrest

------------------Generation--------------- -----------------T & D---------------

Elements Of Cost Of Power


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Impact Of Fuel Cost

Almost 60% of the cost ofgeneration is on account of fuel

cost


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150

250

350

450

550

650750

Jan'91

Dec'91

Feb'93

Jun'93

Jun'94

Dec'95

Apr'96

Apr'97

Aug'98

Jun'99

Apr'2K

Feb'01

Sep'01

Aug'02

Oct'03

Jun'04

NCL SECL BCCL CCL ECL MCL

TREND OF COAL PRICE INCREASE(Typical data for minus 200-250 mm Grade F coal)

Figs in Rs/Tonne


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TARIFF OF COAL BASED STATION AS PER EXISTING NORMS -

PITHEAD

0

100

200

300

400

500

600

700

800

900

1 2 3 4 5 6 7 8 910

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

YEAR

PAISE/Kwh

VariableCharges

O&MExpenses

Interest onworkingCapital

Return onEquity

Interest onLoans

Depreciation

paise/Kwh

1.Capital cost 4.0 cr/MW

2.Debt:Equity Ratio 70:30

3.ROE 14%

4. Rate of depreciation 3.6%

5.O&M cost 10 lacs/MW with 4% escalation

6.Interest on loan @ 10%

7.VC based on present cost of fuel

(escalation 10% p.a based on last 9 yrs.data)

CAGR-6.09%


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FIXED AND VARIABLE CHARGES FOR RAMAGUNDAM -

PITHEAD (AT 80% PLF)

0

20

40

60

80

100

120

140

'03-04

'02-03

'01-02

00-01

99-00

98-99

97-98

96-97

95-96

94-95

93-94

92-93

YEAR

PAISE/Kwh

Fixed Charges Variable Charges


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Electricity Act, 2003Provisions to Promote Power Generation

1. Generation Delicensed

2. Liberal captive generation provisions3. Tariff based competitive bidding

4. Open access for supply to direct

consumers5. Trading


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1. Generation Delicensed Earlier TEC from CEA was a pre-condition for setting

up generating capacity CEA used to take considerable time in many cases,

1-1 years for giving TEC. Before TEC, even the beneficiaries were required to

be identified. All these requirements have been dispensed with. Generating company can set up a power plant

without any TEC from CEA provided they haveavailability of

Land Fuel linkage Water linkage Environmental clearance


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There is no pre-condition for identifying customers.

Even the financial institutions are prepared now tofinance the project based on its cost of power, withouthaving a pre-condition of long term PPAs withpurchasers.


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2. Liberal Captive Generation Provisions

Clause 2(8)

Captive generating plant means a power plant set upby any person to generate electricity primarily for hisown use and includes a power plant set up by any co-operative society or association of persons forgenerating electricity primarily for use of members ofsuch co-operative society or association.

No clearance required from CEA or StateGovernment for setting up of captive generatingplant (Clause9(1)).

Captive generating plants are permitted toconstruct dedicated transmission lines and wouldbe free from any regulation by the Commissionexcept in case power is supplied to grid (Clause

9(1)).


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Clause 9(2)

Every person, who has constructed a captivegenerating plant and maintains and operates suchplant, shall have the right to open access for thepurposes of carrying electricity from his captivegenerating plant to the destination of his use.

Clause 38 (provision)

Provided also that such surcharge shall not beleviable in case open access is provided to a personwho has established a captive generating plant forcarrying the electricity to the destination of his ownuse.

What is the meaning of Primarily?


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Govt. of India vide the Rules issued in May05 havefurther clarified that

Generating stations wil quality as a captive plantprovided it has a captive consumption of more than51%.

In case of SPU for setting up captive project acaptive consumer can have equity only upto 26%.

In case of group of members, association ofpersons, all persons together can fulfill above

criteria.

Such liberal provisions will promote addition ofcapacity through captive route.


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3. Tariff based Competitive Bidding

As per section 63 of the Electricity Act, 2003, tariff

determined through the process of competitivebidding will be accepted by the Regulator.

Under this route, state power utilities can invite bidsfor purchase of power wherein a generator will

indicate tariff applicable for the life of the station. Based on the lowest tariff contract for supply of power

is awarded to the generating company.

Supply of power by the generating company could bewithout any fuel and location specific.

Such tariff based competitive bidding will promotecompetition in the sector and induce market drivenpricing mechanism.

O S C


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4. Open Access for Supply to Direct Consumers

Electricity Act 2003 envisages open access to bulkconsumers in a phased manner to ensure openaccess to consumers having connected load of morethan 1MW by January, 2009.

Open access in transmission and distribution willprovide opportunities for the generating companies tosupply power directly to bulk consumers.

These provisions will provide flexibility to the consumerin selection of consumers.

Generator will no more be a captive supplier of StatePower Utilities.

In case of default in payment, generating asset will notbecome stranded and sale of power can take place

through open access route.


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5. Trading

Trading has been recognised as a legal/licensed

activity. After enactment of the Act, almost about 9-10

different inter-state trading companies have gotregistered.

Trading activities have improved utilisation of theexisting generation capacities.

Operating PLF have now improved to almost 74%.

Further, now many of the IPPs are entering intoagreement with trading companies for sale of poweron long term basis.

Trading route provides alternative to generator for

sale of power.

Strong Regional Transmission Grids


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NR

WRER

SR

NER

Grid Size (as on 28.02.07)(Installed Capacity, MW)

Northern Grid (NR): 35,620 MW

North-eastern Grid (NER):2,454 MW

Eastern Grid (ER): 16,215 MW

Southern Grid (SR): 36,823 MW

Western Grid (NR): 37,387 MW

Total Market Size:1,28,580 MW

Expected to grow by 2012to 2,00,000 MW

A Good Inter-Regional Network Backbone


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400 kV D/CMuzaffarpur-Gorakhpur

2000 MW

400 kV D/CMalda-Bgaon

1000 MW

400 kV D/CRaipur-Rourkela

1400 MW

500 kV HVDCTalcher-Kolar Bi-pole

2000 MW

500 kV HVDC B2BJeypore-Gazuwaka

1000 MW

500 kV HVDC B2BVin-Rihand

500 MW

500 kV HVDC B2BChpur-Ramadam

1000 MW

500 kV HVDC B2BSasaram-Allbad

500 MW

At the end of Xth Plani.e.end of 2006-07

Inter-

regionalTrans.Lines

Power

TransferCapacity(MW)**

EAST-NORTH 3800

EAST-WEST 1800

WEST-NORTH 2000

EAST -SOUTH 3100

WESTSOUTH 1700

EAST - NER 1250

** Including smaller 220 kV Lines

Total Inter-regionalTransfer Capacity:

13,650 MW

1X 765 kV S/CAgra-Gwalior

1000 MW (at 400 kV)

400 kV D/CPatna-Balia

1200 MW

Towards A Strong Well-Integrated National Grid


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765 kV S/CSasaram-Fatehpur

2300 MW

400 kV D/CSiliguri-Bgaon

1000 MW

2nd 400 kV D/CRaipur-Rourkela

1400 MW

500 kV HVDC Bi-pole

Upgraded to 2500 MW

2X 765 kV S/CAgra-Gwalior

4600 MW

500 kV HVDC B2BJeypore-Gazuwaka

500 MW

2 X 400 kV D/CBarh-Balia, Bshariff-

Balia2400 MW

At the end of XIth Plani.e.end of 2011-12

Inter-regional

Trans. Lines

Power

TransferCapacity(MW)**

EAST- NORTH 8500

EAST-WEST 6900

WEST-NORTH 7600EAST -SOUTH 4100

WESTSOUTH 4500

EAST - NER 2250

NER-NORTH 4000

** Including smaller 220 kV Lines

Inter-regional TransferCapacity shall grow to

37,850 MW

765 kV S/CRaichur-Sholapur

2300 MW 765 kV S/C + 400 kV D/CRanchi-Sipat, 3700 MW

500 kV HVDC B2BNarendra-Kolhapur

500 MW

600 kV HVDC Bi-poleBiswanath Chariya (NER) -

Agra, 4000 MW

2 X 400 kV D/CZarda-Kankroli, RAPP-

Nagda, 2000 MW

2 X 400 kV D/CZarda-Kankroli, RAPP-

Nagda, 2000 MW

ST Rates & Regional Losses


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NER Loss3.89%

ER Loss3.15%NR Loss

3.87%

(3.15%)

WR Loss

4.09%

SR Loss4.02%

2.78

7.

95

2.

50

5.46

NR2.47

ER2.69

SR3.51

WR1.49

ST_Rates & Regional Losses NER3.87 p/kWh

Rates- in p/kWhw.e.f 1.4.07At 100% load factor

2900 MW

700MW

1000 MW

1000MW


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Merchant Power Plant

Merchant power plant capital investment isnot based on PPA.

Power can be sold on market determinedprices

Transmission system is either merchant orthrough open access .


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Under Section 63 of the Electricity Act, 2003, Guidelinesfor determination of tariff by bidding process forprocurement of power by distribution licensees were

issued on 19th Jan.05.

These Guidelines provide for procurement of power onlong-term basis for a period of 7 years and above and alsoon medium-term basis from 1 year to 7 years.

Tariff Based Bidding Process forProcurement of Power

Tariff Based Bidding contd..


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Procurement of power could be through following

mechanism -

Case 1 - Where location, technology, fuel are not specified byprocurer. Only quantum of power and delivery point are specified.

Case 2 - Location specific projects which procurer intends toset up under tariff based biding process for supply of power. In thisoption fuel arrangement could be either by procurer or bidder.

Existing generation projects are being developed in line

with Case 2. To start with Case 2, mechanism ofprocurement of power could be considered and details forthe same are given in the presentation.



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To bid for complete specified capacity 10% deviationallowed

Term of PPA to coincide with the life of the plant

Plant CoD should be at least 48 months from PPAsigning

Activities to be completed by the procurer beforecommencing bidding process:

1. Site identification and land acquisition

2. Environmental clearance

3. Fuel linkage, if required (may also be asked from bidder imported coal/gas etc.)

4. Water linkage

5. DPR for hydro station with hydrological, geological,meteorological details

Key Features



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Transfer Price of Fuel If price not determined byGovernment or Regulator

Deviations from standard bidding document

No. of qualified bidders less than two

Submission of final PPA and certification ofevaluation committee

Regulatory Interface



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Capacity Charges

Energy Charges Based on Net quoted heat rate and Fuel price

(If price of fuel has not been determined by GOI/Govt. approvedmechanism/Fuel Regulator, the same shall be subject of approvalof Appropriate Commission)

Incentive Maximum of 40% of non-escalable component ofcapacity charge

Disincentive Below Target Availability 1.2 times ofCapacity charges

Tariff Structure



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Target Availability In line with prevailing regulatoryprovisions (present provision 80%)

Payment Security

LC

Escrow

In case of default, bidder is free to supply to othercustomers)



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Power supply by the bidder shall be on ex-bus basis

Transmission system beyond the power station to bearranged by procurer

Power station to be connected with the nearest CTUsystem to ensure supply to other states in case ofany surplus power/default in payment

Evacuation of Power



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Two Stage Bidding

RFQ

RFP

Qualifying Criteria

Based on financial capability to generate internal resourcesfor investment in the project.

In case of Consortium, Joint Deed Agreement to besubmitted.

Bidding Process



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Minimum qualified bidders should be at least 2.

Formation of consortium bidder is permitted. In suchcase, lead members to be identified

Technical and price bids are to be submitted separatelyalong with bid guarantee

Bid shall be evaluated for the composite levallised tariffcombining capacity and energy component.

For the purpose of bid evaluation, escalation in capacitycharges and fuel rate shall be in line with as specified inguidelines.

Bid Evaluation



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Lowest levellised tariff shall be the criteria for

evaluation.

Standard bidding documents are beingdeveloped in line with the guidelines issued. In

case of any deviation from standard biddingdocument, approval of appropriate commissionwould be required,

After completion of the bidding process, tariffdetails along with PPA shall be submitted withthe Appropriate Commission.

Ult M P j t


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MOP along with CEA and PFC has taken an initiative for the

development of Coal based environment friendly Ultra Mega PowerProjects as pit head stations and coastal based stations each with acapacity of about 4000 MW using super critical technology.

These projects to be awarded to developers on the basis of tariff

based competitive bidding guidelines issued by Ministry of Power.The projects are to be developed as per case -2 of the guidelines.

The Competitive Bidding process and project development work shallbe undertaken by the wholly owned subsidiaries (Shell

Companies/SPVs) established by Power Finance Corporation.

These projects will be developed by the developers on BOO (Build,Own and Operate) basis.

Ultra Mega Projects

Main features of Ultra Mega Power Projects initiative


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The Mega Power benefits shall be available to the Ultra Mega Power

Projects.

The expenditure incurred by the shell company in developing the projectshall be recovered from the selected developer.

Main features of Ultra Mega Power Projects initiative

The responsibilities of Shell companies are as under

Initiate land acquisition proceedings.

Allocation of fuel linkage/fuel blocks for pit head projects. Allocation of water by State Governments. Obtain various approvals and statutory clearances like R&R

approval & MoEF clearances. Tie-up for off-take/sale of power Initiate action for development of the power evacuation system. Green field rating of project


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Sasan Ultra Mega Power Project has beenawarded to M/s Reliance Power Limited at thelevellised tariff of Rs 1.196/kWh.

Mundra Ultra Mega Power Project has beenawarded to M/s Tata Power Limited at thelevellised tariff of Rs 2.263/kWh.

The Bid submission date for Krishnapatnam UltraMega Power Project is 21.09.2007.

Competitive Bidding for UMPP

Levellised Tariff of Bidders for Sasan


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Levellised Tariff of Bidders for Sasan

Bidder Levellised Tariff (Paisa/kWh)

Lanco 119.617

Reliance 119.616

Reliance 129.574

Tata 141.209

J P 165.032

Sterlite 174.297

Essar 175.976Jindal 179.879

NTPC 212.615

L&T 225.126


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Almost 10 parties had submitted their bid proposal forthese projects.

Private sector has shown very active interest ininvestment in generation sector.

Private participation in ultra mega has promotedcompetition in generation sector.

Many state utilities have also initiated the process ofcapacity addition through tariff based bidding route.

UP - Unpara

Gujarat - Pipava Punjab, Haryana, Maharashtra etc.

Status of Restructuring of State Power Utilities


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Following 9 states still operating with SEB structure: Punjab, Himachal Pradesh, Chhattisgarh, Kerala, Tamil Nadu, Bihar, Jharkhand,

West Bengal & Assam.

Restructured status of other states is as given below :-

State Generation Transmission Distribution Sale & Purchase

Haryana 2 Discoms Genco

Rajasthan 3 Discoms Discoms

Delhi 5 Discoms Discoms

UP 5 Discoms Transco

Uttaranchal Trading Co.

Gujarat 4 Discoms Trading Co.

Maharashtra 1 Discom Discom

MP 4 Discoms Trading Co.

AP 4 Discoms Discoms

Karnataka 5 Discoms Discoms

Orissa (2) 4 Discoms Trading Co.


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Frequent changes in tariff norms

Stringent norms lower return.

Prudence check of capital costs, O&M etc.

Construction risks and associated delay.

Threat of splitting NTPC

Market domination. Fuel risks

Regulatory Environment

(UNCERTANINITIES)

New Commercial Initiatives


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New Commercial Initiatives(Regulatory)

Regulatory Initiative

Creation of Strategic Think tank

Study regulatory interface in other utilities Competency Requirement

Formation of analytical group

Use of Common Platform Monitoring of SERC orders for NTPC

impact

New Commercial Initiatives (CRM)


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New Commercial Initiatives (CRM)

Commercial Initiatives for Customers Setting up of CRM cells in the regional offices

Customer Roster - A systems to strengtheninterface with customers and position Regional ED as

the single window Customer Relationship Manager. Customer Support Group - To Strengthen the

relationship building program by providing supportservices to customers

Customer Dashboard - A system to capture,analyse and disseminate market intelligence about thestate (including information on customers, competitorsetc) within NTPC


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Realisation after TPA Incentives

Customers health

Supply to multiple Discoms and private Discoms

Direct supply to Bulk Consumers

Fuel Security

Operating in the competitive environment

Capacity addition through tariff based bidding

COMMERCIAL CHALLENGES AHEAD


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ELECTRICITY ACT 2003

AND

GENERATION SECTOR


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Background

Three erstwhile Acts that regulated theelectricity sector :

The Indian Electricity Act, 1910

The Electricity (Supply) Act, 1948

The Electricity Regulatory Commissions Act,1998

Background (contd..)


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The Indian Electricity Act, 1910

Provided basic framework for electric supply industry in India.

Growth of the sector through private licensees. Licence by StateGovt.

Provision for licence for supply of electricity in a specified area.

Legal framework for laying down of wires and other works.

Provisions laying down relationship between licensee and

consumer.

The Electricity (Supply) Act, 1948

Mandated creation of SEBs.

Need for the State to step in (through SEBs) to extend

electrification (so far limited to cities) all across the

country.



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Main amendments to the existing Acts

Amendment in 1975 to enable generation inCentral sector

Amendment to bring in commercial viability in thefunctioning of SEBs

Section 59 amended to make the earning of a minimumreturn of 3% on fixed assets a statutory requirement(w.e.f 1.4.1985)

Amendment in 1991 to open generation to private

sector and establishment of RLDCs

Amendment in 1998 to provide for private sectorparticipation in transmission, and also provisionrelating to Transmission Utilities.



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g

The Electricity Regulatory CommissionsAct, 1998

Provision for setting up of Central / StateElectricity Regulatory Commission to with powers

to determine tariffs.

Constitution of SERC optional for States. .

Distancing of Govt from tariff determination.

Need for the new legislation


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Need for the new legislation

Requirement of harmonizing and rationalizing the

provisions in the existing laws to

Create competitive environment for benchmarkcompetition which will result in enhancing qualityand reliability of service to consumer.

Distancing regulatory responsibilities of Govt.

Reform legislation by several States separately.

Obviating need for individual States to enact their ownreform laws.

Requirement of introducing newer concepts like powertrading, open access, Appellate Tribunal etc.

Special provision for the Rural areas.

Role of Government


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Role of Government

Central Government to prepare (Section 3) - National Electricity Policy; and

Tariff Policy

Policy on development of non-conventional energysources.

Rural Electrification

G ti


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Generation

Generation free from licensing. (Section 7)

Requirement of TEC for non-hydro generation done away

with. (Section 7)

Captive Generation is free from controls. Open access to

Captive generating plants subject to availability oftransmission facility. (Section 9)

Clearance of CEA for hydro projects required. Necessary due

to concern of dam safety and inter-State issues. (Section 8)

Generation from Non-Conventional Sources / Co-generation

to be promoted. Minimum percentage of purchase of power

from renewables may be prescribed by Regulatory

Commissions. (Section 61(h),86 (1) (e))

Transmission


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There would be Transmission Utility at the Centre and in the

States to undertake planning & development of transmission

system. (Sections 38 & 39) Load despatch to be in the hands of a govt company/organisation.

Flexibility regarding keeping Transmission Utility and load

despatch together or separating them. Load Despatch function

critical for grid stability and neutrality vis a vis generators anddistributors. Instructions to be binding on both. (Sections 26,

27,31, 38, 39)

Private transmission companies to be licensed by the Appropriate

Commission after giving due consideration to the views of theTransmission Utility. (Sections 15 (5) (b))

The Load Despatch Centre/Transmission Utility / Transmission

Licensee not to trade in power. Facilitating genuine competition

between generators. (Sections 27, 31, 38, 39,41)


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istribution :

Distribtution to be licensed by SERCs.

Distribution licensee free to take up generation & Generating co.

free to take up distribution licence. This would facilitate private

sector participation without Government guarantee/ Escrow.

(Sections 7, 12)

Retail tariff to be determined by the Regulatory Commission.(Section 62)

Metering made mandatory. (Section 55)

Provision for suspension/revocation of licence by Regulatory

Commission as it is an essential service which can not beallowed to collapse. (Sections 19, 24)

Open Access


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Open Access

Open access to the transmission lines to be provided

to distribution licensees, generating companies.(Sections38-40)

This would generate competitive pressures and lead togradual cost reduction.

Open access in distribution to be allowed by SERC inphases. (Sections 42)

In addition to the wheeling charges provision forsurcharge if open access is allowed before eliminationof cross subsidies, to take care of

a)Current level of cross subsidy

b)Licensees obligation to supply. (Section 42)

This would give choice to customer.


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Trading/ Market development

Trading distinct activity permitted with licencing. (Section

12)

Regulatory Commission may fix ceiling on trading margin toavoid artificial price volatility. (Sections 79 (2) (b) & 86 (2)(b))

The Regulatory Commission to promote development o

market including trading. (Section 66)

Regulatory Commissions/Appellate Tribunal


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State Electricity Regulatory Commission to be constituted within six

months. (Section 82)

Provision for Joint Commission by more than one State/UT. (Section

83)

Provision for constitution of Appellate Tribunal consisting of Chairman

and three Members. (Section 110, 112)

Appellate Tribunal to hear appeals against the orders of CERC/SERC,

and also to exercise general supervision and control over the

Central/State Commissions. (Section 111)

Appeal against the orders of Appellate Tribunal to lie before the

Supreme Court. (Section 125)

Appellate Tribunal considered necessary to-

Reduce litigation and delay in decisions through High Court.

Provide technical expertise in decision on appeals.


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CEA to continue as the main technical Advisor of the

Govt. of India/ State Government with the responsibility of

overall planning. (Section 70)

CEA to specify the technical standards for electrical plantsand electrical lines. (Section 73)

CEA to be technical adviser to CERC as well as

SERCs.(Section 73)

CEA tospecify the safety standards. (Section 53)

Central Electricity Authority

Tariff Principles


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p

Regulatory Commission to determine tariff for supply of electricity by

generating co. on long/medium term contracts. (Section 62)No tariff fixation by regulatory commission if tariff is determined throughcompetitive bidding or where consumers, on being allowed open accessenter into agreement with generators/traders.

Consumer tariff should progressively reduce cross subsidies and move

towards actual cost of supply. (Section61 (g)) State Government may provide subsidy in advance through the budget

for specified target groups if it requires the tariff to be lower than thatdetermined by the Regulatory Commission. (Section65)

Regulatory Commissions may undertake regulation including

determination of multi-year tariff principles, which rewards efficiency andis based on commercial principles. (Section61 (e), (f))

Regulatory Commission to look at the costs of generation, transmissionand distribution separately. (Section62 (2))


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Documents

Regulatory and Commercial Issues_PMI_11.3.2008