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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.
Tariff Based Bidding contd..
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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
Tariff Based Bidding contd..
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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
Tariff Based Bidding contd..
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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
Tariff Based Bidding contd..
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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)
Tariff Based Bidding contd..
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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
Tariff Based Bidding contd..
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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
Tariff Based Bidding contd..
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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
Tariff Based Bidding contd..
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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.
Background (contd..)
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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.
Background (contd..)
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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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