6.12

Export of Power

6.12.1

This year another significant departure in our philosophy is to include power purchase for export to outside states as part of the total quantum of power purchase as we feel that export potential would reduce the overall financial burden of power purchase cost by GRIDCO. During FY 2001-02, GRIDCO has estimated around 812.41 MU of sale outside the State and around 1400 MU for the year 2002-03 (clarification to queries 2002-03). For FY 2001-02, looking at the sale of power to AP and CPP for 10 months, the Commission would like to approve 848.81 MU for FY 2001-02.

6.12.2

For FY 2002-03, GRIDCO has estimated a sale of 800 MU to AP and 600 MU to Karnataka which we feel would be very good for the financial health of GRIDCO and as such, we approve 1400 MU for such export of power as suggested by GRIDCO. In fact, some of the objectors have also pleaded for higher export of power in order to lesser the burden on state consumers by earning additional revenue on account of export.

6.12.3

With the above observation, a comparative figure indicating the total require-ment of power for the year 2000-01 to 2002-03 is worked out in Table : 13.

Table : 13
Purchase of Power
(Figures in MU)

Name of the Company

2000-01

Estimated 2001-02

Estimated 2002-03

CESCO

4025.30

4167.77

4321.00

NESCO

2444.15

2253.62

2291.20

WESCO

2870.20

2980.64

3066.54

SOUTHCO

1522.73

1525.07

1682.39

Export & sale to CPPs

894.76

848.81

1400.00

Transmission Loss

570.57

569.16

551.08

Total

12327.71

12345.07

13312.22

6.13

Demand estimation for DISTCOs

6.13.1

GRIDCO in its application for FY 2001-02 in DF-2 has furnished the maximum demand in MVA projected by the DISTCOs for the year as 1932.12 MVA. However, on its own projection GRIDCO has worked out demand as 1746.10 MVA based on average of actual of five months. After verification of the BST bills for 10 months served on the DISTCOs, it is observed that the simultaneous maximum demand in respect of the DISTCOs for the FY 2001-02 works out to 1798.92 MVA which is approved for the purpose of determination of BST.

6.13.2

In the RR application form DF-2 for the FY 2002-03 GRIDCO has projected a demand of 1908 MVA for all the DISTCOs assuming 27% rise in demand for NESCO, 4% rise for CESCO and 1% each for WESCO and SOUTHCO. In its submission dated 30.3.2002, GRIDCO has submitted that NESCO has revised its maximum demand figure to 378.85 MVA and SOUTHCO has revised the figure to 275.40 MVA.

6.13.3

Accordingly, the Commission approves the simultaneous maximum demand of 1798.92 MVA for FY 2001-02 and 1840.83 MVA for FY 2002-03 based on the demand projection made by GRIDCO for the four distribution companies as per submission dated 30.03.2002 and the projections for CESCO and WESCO.

Table : 14
Minimum Demand
(Figures in MVA)

 

FY 2000-01

FY 2001-02

FY 2002-03

CESCO

653.94

663.91

683.25

NESCO

381.45

365.35

378.85

WESCO

477.78

504.45

503.32

SOUTHCO

261.78

265.21

275.40

TOTAL

1774.94

1798.92

1840.83

6.14

Sources of Power Purchase

6.14.1

GRIDCO in its tariff application for the year 2001-02 and RR application for the year 2002-03 have stated that the procurement plan is developed on a monthly forecast of demand and supply to reflect the actual load dispatch with merit order procurement from the generating stations. It has also stated that purchase of expensive power from EREB becomes imperative in certain months due to non-availability of power from cheaper power stations to balance demand and supply. GRIDCO determines the monthly procurement plan by considering the load generation balance report for the year, the monthly energy requirement of the DISTCOs, merit order operation of the generating stations for determination of station wise procurement. Therefore, they have stated that the procurement cost is not linear and depends on the magnitude and mix of purchase in a month from various sources. Calculation of cost of power on the basis of annual procurement ignores the reality of monthly dispatch where there is substantial difference in per unit cost due to low plant load factor in some of the central generating stations.

6.14.2

The Commission while deciding the power procurement for a year from various generating stations also adopts the principle of economic load dispatch, power availability of various generating stations based on PPAs and need based requirement from the central generation stations. GRIDCO is expected to draw a plan of drawl in a manner so as to reflect the least cost combination of power procurement.

6.14.3

For 2001-02 as observed in para 6.11.11, Commission shall be determining the procurement of power from different stations on the basis of actual power drawn in the first ten months of 2001-02 and prorate it for 12 months which also includes power purchase for sale to outside states and the CPPs.

6.14.4

For 2002-03, Commission shall be projecting the drawl schedule from different generating stations on the basis of the subsisting PPAs, schedule of generation given by the generators to meet the requirement of various DISTCOs as well as the export projection made by GRIDCO.

6.15

Computation of Transmission Loss

6.15.1

GRIDCO in para 2.2 of the BST application for the FY 2001-02 has proposed calculation of transmission loss on the net method and has requested to accept a loss figure of 4.6% for FY 2002.

6.15.2

Similarly, in revenue requirement application for the FY 2002-03 in para 2.2 GRIDCO has submitted that the transmission loss for the FY 2000-01 works out to 4.59% (DF-3) in the gross method and 4.6% (DF-4) in the net method. GRIDCO proposes a reduction of transmission loss @ 0.2% per annum successively from FY 2001-02 to achieve 3.7% loss in the FY 2005-06 in its business plan. Accordingly, GRIDCO proposes a transmission loss of 4.40% for FY 2002-03 in the revenue requirement application.

6.15.3

In its BST application of 2001-02 GRIDCO has proposed adoption of Net Method (DF-4) for calculation of transmission loss and submitted that it gets wheeling charges for wheeling of power to MP only and does not get any wheeling charges on the export of power to EREB. Therefore, GRIDCO has prayed that the transmission loss attributable to export of power to EREB should be realized from all users of the system. GRIDCO has therefore submitted that while calculating the transmission loss under Net Method the export to EREB constituents should be deducted to allow a realistic loss to GRIDCO.

6.15.4

The Commission in its BST order 27 dt19.1.01 and also its orders prior to that have approved the gross method of loss calculation. The Commission in its BST order 27 dt.19.01.01 at para 6.4.3 categorically clarified "since GRIDCO gets paid in full for the units lost in transmission on account of wheeling to outside the state it is imperative that the energy exported to EREB is treated both as an input and as an output for the purpose of calculation of transmission loss". Thus, GRIDCO suffers no loss on account of acceptance of gross method of calculation of transmission loss. To be more specific, the loss is being determined on the basis of "as the system operates" and the total loss computed in the transmission system of GRIDCO is apportioned to all users as stated by GRIDCO in their application i.e. the users inside the state as well as the users connected to the system for the purpose of export. Two units of capacity 2 X 210 MW were physically synchronised to WR grid through 220 kV transmission lines from Budhipadar to Korba. That much of power is replenished by EREB through the various 220 kV lines. Bills are raised to GRIDCO based on meter reading at the interconnection point with generators.

6.15.5

For the year 2000-01 while accepting the concept of gross method of loss calculation the Commission had clarified that a credit was given to GRIDCO for the loss of units on account of export to EREB and GRIDCO was being reimbursed in the form of a reduction in miscellaneous receipt.

6.15.6

But for the year 2001-02 & 2002-03 calculation, such a reduction is not necessary as the Commission is considering the cost of power purchase in its entirety from all the generators to determine the cost of power which also includes the energy lost on account of export of power to EREB. This is evident from the concept of power purchase as already explained in previous paragraph.

6.15.7

With the above observation, the apportionment of loss to all the system users based on the consumption figures of the past ten months is given in Table : 15.

Table : 15

ACTUAL TRANSMISSION LOSS FROM APRIL' 01 TO JANUARY 2002

Source

Gross Input (MU)

Gross Output (MU)

Proportionate Loss sharing (MU)

Proportionate Loss sharing (%)

1.

EREB

5001.947

1362.18

59.36

0.52%

State dedicated Stations

i

Hirakud

844.65

ii

Balimela

255.00

iii

Rengali

674.44

 

iv

Upper Kolab

515.43

 

 

v

Indravati

1146.93

A

OHPC

3436.46

B

Machhkund

249.35

C

OPGC

D

TTPS

1963.09

Total State Generation Input

5648.90

2.

CPPs

i

ICCL

412.71

306.32

13.35

0.12%

ii

NALCO

304.77

136.06

5.93

0.05%

iii

INDAL

9.69

iv

RSP

8.48

Total CPP

735.65

442.38

19.28

0.17%

3.

Distco

9106.49

396.81

3.48%

Grand Total

11386.49

10911.05

475.44

4.18%

Loss (MU)

475.44

Loss (%)

4.18

6.15.8

Accordingly, the Commission approves loss figure of 4.18% for the year 2001-02 and 3.88% for 2002-03 assuming a level of reduction of 0.3% as suggested by Kanungo Committee. We shall now proceed to analyze purchase of power from the different generating stations.

6.16

State Hydro:

6.16.1

The installed capacity of various Hydro Stations owned by the Orissa Hydro Power Corporation (OHPC) is 1861.5 MW as on 1st of April 2002.

Sl.No.

Name of the HE Project

Installed capacity MW

Firm Power MW

Design Energy MU

MDDL

FRL

1

Hirakud (Burla & Chiplima)

331.5

134

1174

590 ft.

630 ft.

2.

Balimela

360

135

1183

1440 ft.

1516 ft.

3.

Rengali

250

85

750

109.73 M

123.50 M

4.

Upper Kolab

320

95

832

844M

858M

5.

UIHEP

450

224

1962

625M

642M

6.

Machakund

34.5

34.5

310

2685Ft.

2750Ft.

6.16.2

For 2001-02, OHPC has furnished a generation plan on 30.01.2002, which reflects the actual power drawn from April to December, 2001 and projections made for 1/2002 to 3/2002. These projections for January to March, 2002 has been made by OHPC on the basis of existing reservoir levels and optimum utilisation of water during the year.

6.16.3

The Commission in its order dated 9 July 2001 in case No.15/2000 had approved the design energy/firm energy of old OHPC stations viz. Hirakud, Balimela, Rengali and Upper Kolab as 3711 MU or an availability of 3676.86 MU after excluding auxiliary consumption subject to reassessment by CEA. However, OHPC had projected only 3420.06 MU for the year 2001-02 as against an energy potential of 3676.86 MU due to poor availability of water during the first three months of the FY 2001-02. In its submission dated 30.03.2002, GRIDCO has shown the actual drawal of power from old OHPC stations upto 15 March 2002 and projection made for the balance period. It is noticed that the proposed drawal has been reduced to 3311.78 MU. As this is based on actual drawal upto 15 March and observing the reservoir levels the Commission approves a drawal of 3311.78 MU from old hydro stations.

6.16.4

In case of Upper Indravati station although the design energy is 1942.38 MU, OHPC had projected 2878.20 MU on 30.01.02. Subsequently, GRIDCO in its submission has stated that it can draw 2909.01 MU based on actual generation upto 15.03.2002 and projection for balance period. Accordingly, Commission approves a drawal of 2909.01 MU from Upper Indravati station from the different hydro stations as against the proposal. Accordingly, the approval for power procurement from the different hydro stations as against the proposal of GRIDCO is given in Table : 16.

Table : 16
(Figures in MU)

Hydro Stations

GRIDCOís proposal

Commissionís approval

OHPC (Old)

3676.86

3311.78

Upper Indravati

1942.38

2909.01

Total

5619.24

6220.79

FY 2002-03

6.16.5

GRIDCO has projected a drawl of 5357.88 MU based on the generation plan furnished by OHPC (ED-2 of RR) on gross generation of 5412 MU less 0.5% auxiliary consumption and 0.5% transformer loss for 2002-03. The break up of drawals is given below.

OHPC old stations - 3415.54 MU
Upper Indravati  - 1942.38 MU

6.16.6

As indicated earlier, the design/firm energy of OHPC old stations in a year of normal hydrology being 3676.84 MU, there is absolutely no justification of adopting a figure lower than that for the ensuing year. As such, the Commission considers it appropriate to accept a figure of 3676.86 MU as energy availability from these stations for the year 2002-03.

6.16.7

As far as Upper Indravati Power Station is concerned the Commission approves the power availability as 1942.38 MU based on 90% dependable year i.e. design energy.

Table : 17
(Figures in MU)

Hydro Stations

GRIDCOís proposal

Commissionís approval

OHPC (Old)

3415.50

3676.86

Upper Indravati

1942.38

1942.38

Total

5357.88

5619.24

6.16.8

Machhkund : This hydro power station is a joint venture of Government of Orissa and Andhra Pradesh with an installed capacity of 114.5 MW. GRIDCO has projected a drawal of 301.49 MU corresponding to 34.2 MW of firm power for the FY 2001-02. In their submission dated 30.03.2002, GRIDCO has proposed to draw 319.48 MU based on actual drawal upto 15.03.2002 and projection for balance period. As this is reasonable, Commission approves 319.48 MU.

6.16.9

During 2002-03, GRIDCO proposes to draw 315.29 MU which is an average of the last three years. The Commission accepts this figure of 315.29 MU for the year 2002-03.

6.16.10

A statement indicating the actual drawal for the FY 2000-01 and the approved drawal for the FY 2001-02 and 2002-03 is given in Table : 18.

Table : 18
(Generation in MU)

Source of generation

FY 2000-01 (Actual)

FY 2001-02 (Approval)

FY 2002-03 (Approval)

OHPC (Old stations)

2704.93

3311.78

3676.86

Upper Indravati

1736.05

2909.01

1942.38

Machkund

318.28

319.48

315.29

Total Hydro

4759.26

6540.26

5934.53

6.16.11

From the above analysis of hydro generation availability, it is estimated that GRIDCO would be able to draw a total of 6540.26 MU during 2001-02 and a total of 5934.53 MU during 2002-03.

6.16.12

Since the Commission has estimated the power requirement for 2001-02 at 12345.07 MU, the balance requirement i.e. 5804.81 MU (12345.07 - 6540.26) has to be purchased from other sources during the FY 2001-02. Likewise, the power requirement for the FY 2002-03 being 13312.22 MU, a drawal of (13312.22 - 5934.53) 7377.69 MU is required from other sources during FY 2002-03.

6.16.13

Talcher Thermal Power Station (TTPS) : This 460 MW generating station located almost at the centre of the State is owned and operated by NTPC but fully dedicated to the State. In terms of the PPA entered between GRIDCO (OSEB) and NTPC the plant load factor of TTPS was to be maintained at 62.78% with an auxiliary consumption of 11.75% for 1999-00. Since TTPS is a dedicated power station of the State, its entire fixed cost has to be paid by GRIDCO on account of contractual obligations. During 2000-01 GRIDCO has drawn 2197.17 MU. GRIDCO had prepared the procurement plan for TTPS for FY 2001-02 by considering the actual generation of past 5 months and the balance period as per generation and maintenance schedule provided by TTPS. The energy proposed for procurement from TPPS is 2189.48 MU for FY 2002 considering generation at a PLF of 62.5%.

6.16.14

GRIDCO has submitted that NTPC in December'00 proposed a generation of 2519 MU at a PLF of 62.50%. Subsequently, NTPC filed a petition before the CERC to approve TTPS tariff and provided GRIDCO the indicative tariff computation for FY 01 to FY 05 which shows a generation of 2039 MU for FY 01 to 05 corresponding to a PLF of 57.5%. However, GRIDCO proposes to take up this issue with CERC and in this BST application proposes to adopt PLF of 62.5%.

6.16.15

The PPA for TTPS was valid for a period of 5 years with effect from 08.03.95. Clause 14 of the said PPA provides that the agreement shall continue to operate till the agreement is formally reviewed, extended or replaced. On account of clause 14 of the PPA, the Commission considers that the quantum of generation should be calculated at a PLF of 62.78% as was existing for the year 1999-00 till a fresh PPA is signed with GRIDCO. During the first eleven months for the FY 2001-02 GRIDCO has already procured 2094.91 MU from this power station. Thus, the Commission approves a drawal of 2232.53 MU for the year 2001-02 which can be drawn if the past level of generation of TTPS is maintained.

6.16.16

GRIDCO in its ARR application for FY 2002-03 in para 2.3.3 has stated that NTPC proposes generation for TTPS for FY 03 at a PLF of 60% which is less than 62.5% PLF as mentioned in their generation plan (ED-2 of ARR 02-03). GRIDCO proposes to draw 2203.92 MU on 62.5% PLF during FY 02-03.

6.16.17

The Commission as stated in para 6.16.15 above, of the considers that the quantum of drawal should be calculated at a PLF of 62.78% as agreed for the year 1999-00 until a fresh PPA is signed with GRIDCO and therefore approves a drawal of 2232.53 MU for FY 2002-03.

6.16.18

Ib Thermal (OPGC): Orissa Power Generation Corporation owns the thermal generating stations at Ib with an installed capacity of 420 MW. The normative availability at a plant load factor of 68.49% of Ib TPS is 380.10 MW i.e. 2280.50 MU. During 2000-01, GRIDCO had drawn 2686.56 MU from this station.

6.16.19

GRIDCO in para 2.3.3 of BST application for FY 2001-02 has stated that due to breakdown of 220 KV Ib/Budhipadar line in flash flood on 16 July 2001 the generation at OPGC was affected badly due to evacuation problem. The feeders have been restored temporarily through emergency restoration system and normalization will take more time. Hence, the energy proposed for procurement from OPGC is pegged down to 2280.30 MU at 68.49% PLF (DF-11).

6.16.20

OPGC in their generation plan of December 2000 had projected a target generation of 3018 MU with auxiliary consumption of 301.8 MU thereby showing net availability of 2716.2 MU at GRIDCO bus. The generation projection made by OPGC could not be achieved due to damage to the transmission system which is reflected in the reduced drawal of only 1824.95 MU during April 2001 to January 2002. Therefore, for the FY 2001-02 GRIDCO should at least achieve its own targeted drawal at normative PLF of 68.49% i.e. 2280.50 MU.

6.16.21

As reported by GRIDCO in its ARR application 2002-03 in para 2.3.4 that OPGC in its generation schedule for FY 2002-03 has projected a generation of 3157 MU for the FY 2002-03. After auxiliary consumption calculated at 10% the availability at EHT bus is 2841.3 MU, out of which GRIDCO had considered 2726.62 MU for utilization within the State on the basis of least cost combination of procurement.

6.16.22

On 30.03.2002, OPGC has revised the power procurement figure of 2002-03 to 2330.77 MU quoting problems in ash pond as the reason for lower generation. As such, the Commission feels it reasonable to approve 2280.50 MU for 2002-03 (at normative level of 68.49% PLF). However, Commission urges GRIDCO to take steps to maximise drawal from this station as the plant has attained PLF of 75% to 80% in the previous years.

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