SOUTH BIHAR POWER DISTRIBUTION COMPANY ... - sbpdcl

BEFORE

THE HON’BLE BIHAR ELECTRICITY REGULATORY COMMISSION

FILING OF THE PETITION FOR TRUE UP FOR FY 2017-18,

ANNUAL PERFORMANCE REVIEW (APR) FOR FY 2018-19

AND

ANNUAL REVENUE REQUIREMENT (ARR) FOR FY 2019-20, FY 2020-21, FY 2021-22

FILED BY,

SOUTH BIHAR POWER DISTRIBUTION COMPANY LIMITED, PATNA

CHIEF ENGINEER (COMMERCIAL), SBPDCL

2nd FLOOR, VIDYUT BHAWAN, BAILEY ROAD, PATNA - 800 001

Petition for True up for FY 2017-18, APR for 2018-19 and ARR for FY 2019-20 to FY 2021-22

South Bihar Power Distribution Company Limited

BEFORE THE BIHAR ELECTRICITY REGULATORY COMMISSION, PATNA

IN THE MATTER OF: Filing of the Petition for Truing up for FY 2017-18, Annual Performance

Review (APR) for FY 2018-19 under Bihar Electricity Regulatory Commission

(Multi Year Distribution Tariff) Regulations, 2015 and Annual Revenue

Requirement (ARR) for FY 2019-20, 2020-21, 2021-22 under Bihar Electricity

Regulatory Commission (Multi Year Distribution Tariff) Regulations, 2018 and

its amendments thereof along with the other guidelines and directives issued

by the BERC from time to time and under Section 45, 46, 47, 61, 62, 64 and

86 of The Electricity Act 2003 read with the relevant guidelines.

AND

IN THE MATTER OF: South Bihar Power Distribution Company Limited (hereinafter referred to as

"SBPDCL” or “Petitioner” which shall mean for the purpose of this petition the

Licensee),having its registered office at Vidyut Bhawan, Bailey Road, Patna.

The Petitioner respectfully submits as under: -

1. The Petitioner was formerly integrated as a part of the Bihar State Electricity Board

(hereinafter referred to as “BSEB” or “Board”) which was engaged in electricity generation,

transmission, distribution and related activities in the State of Bihar.

2. The Board is now unbundled into five (5) successor companies – Bihar State Power (Holding)

Company Limited, Bihar State Power Generating Company Limited (hereinafter referred to as

“BSPGCL”), Bihar State Power Transmission Company Limited (hereinafter referred to as

“BSPTCL”), North Bihar Power Distribution Company Limited and South Bihar Power

Distribution Company Limited (hereinafter referred to as “Discoms”) as per Energy

Department, Government of Bihar Notification no:

under The Bihar State Electricity Reforms

Transfer Scheme 2012.

3. Pursuant to the enactment of the Electricity Act, 2003, every utility is required to submit its

Aggregate Revenue Requirement (ARR) for the control period and Tariff Petitions as per

procedures outlined in section 61, 62 and 64, of Electricity Act 2003, and the governing

regulations thereof.

4. The Petition for True-up for FY 2016-17, Annual Performance Review (APR) for the FY 2017-

18 and Annual Revenue Requirement (ARR) for FY 2018-19 was filed by South Bihar Power

Distribution Company Limited (SBPDCL) on 05.12.2017, and accordingly the Hon’ble

Commission had issued the relevant tariff order on 21.03.2018.



5. The present petition is filed with the Hon’ble Commission for True up for FY 2017-18, Annual

Performance Review (APR) of FY 2018-19, and estimating the Annual Revenue Requirement

(ARR) for the 3rd Control Period i.e. for FY 2019-20, FY 2020-21, FY 2021-22.

6. This Petition has been prepared in accordance with the provisions of Sections 61 and 62 of

the Electricity Act, 2003 and has taken into consideration the Bihar Electricity Regulatory

Commission (Multi Year Distribution Tariff) Regulations, 2015, Bihar Electricity Regulatory

Commission (Multi Year Distribution Tariff) (First Amendment) Regulations, 2017, Bihar

Electricity Regulatory Commission (Multi Year Distribution Tariff) Regulations, 2018 and other

amendments and orders issued by the Hon’ble Commission from time to time.

7. SBPDCL along with this petition is submitting the regulatory formats with data & information to

an extent applicable and would make available any further information/ additional data

required by the Hon’ble Commission during the course of proceedings.

Prayers to the Commission:

The Petitioner respectfully prays that the Hon’ble Commission may:

a. Admit this Petition;

b. Examine the proposal submitted by the Petitioner in the enclosed petition for a favorable

dispensation;

c. Approve the Annual Revenue Requirement (ARR) for the 3rd Control Period for FY 2019-20 to

FY 2021-22 under Bihar Electricity Regulatory Commission (Multi Year Distribution Tariff)

Regulations, 2015, Bihar Electricity Regulatory Commission (Multi Year Distribution Tariff)

(First Amendment) Regulations, 2017, Bihar Electricity Regulatory Commission (Multi Year

Distribution Tariff) Regulations, 2018, other amendments and orders issued by the Hon’ble

Commission from time to time.

d. Pass suitable Orders with respect to the True up for FY 2017-18, Annual Performance

Review (APR) for FY 2018-19, and Annual Revenue Requirement (ARR) for the 3rd Control

Period for FY 2019-20 to FY 2021-22.

e. Approve the proposed tariff schedule along with open access charges and the schedule for

general and miscellaneous charges as proposed in this petition for different category of

consumers to be made applicable from 1st April, 2019.

f. Pass separate Order for the Petitioner against the present petition;

g. SBPDCL may also be permitted to propose suitable changes to the respective ARRs, prior to

the final approval by the Hon’ble Commission. SBPDCL believes that such an approach

would go a long way towards providing a fair treatment to all the stakeholders and may

eliminate the need for a review or clarification.

h. Condone any inadvertent omissions / errors / shortcomings and permit SBPDCL to add /

change / modify / alter this filing and make further submissions as may be required at a future

date.

i. Pass such Order, as the Hon’ble Commission may deem fit and appropriate keeping in view

the facts and circumstances of the case.

South Bihar Power Distribution Company Limited, Patna

Petitioner

Location: Patna

Date: 30/11/2018



Table of Contents

1. Introduction ................................................................................................................... 10

1.1. Background ............................................................................................................................................ 10

1.2. Profile of SBPDCL .................................................................................................................................. 11

1.3. Procedural History .................................................................................................................................. 12

1.4. Judgment of Hon’ble APTEL on Appeal No. 141 and Appeal No. 142 of 2016 ................................ 14

1.5. BERC Order against the Judgment of Hon’ble APTEL on Appeal No. 141 and Appeal No. 142 of

2016 15

1.6. Appeal No. 154 and Appeal No. 155 of 2017....................................................................................... 16

1.7. Appeal No. 117 of 2017 and Appeal No. 118 f 2017 of 2017 ............................................................. 16

1.8. Instant Petition ........................................................................................................................................ 16

1.9. Contents of the Petition ......................................................................................................................... 17

2. Overall approach for present filing .................................................................................. 18

2.1. Present Approach.................................................................................................................................. 18

2.2. Data and information sources for estimating the Aggregate Revenue Requirement ....................... 18

3. True-up Summary for FY 2017-18 .................................................................................... 19

3.1. Preamble ................................................................................................................................................. 19

3.2. Number of Consumers, Connected Load and Sales ........................................................................... 19

3.3. Distribution Loss .................................................................................................................................... 22

3.4. Transmission losses.............................................................................................................................. 23

3.5. Power Purchase .................................................................................................................................... 23

3.6. Actual Power Purchase quantum ......................................................................................................... 25

3.7. Energy Balance ..................................................................................................................................... 26

3.8. Power Purchase Cost ........................................................................................................................... 27

3.9. Transmission charges ........................................................................................................................... 32

3.10. Disallowance of power purchase due to excess Distribution loss ................................................... 32

3.11. Capital Investment Plan, Capitalization and Funding ....................................................................... 33

3.12. Gross Fixed Assets ............................................................................................................................. 34

3.13. Depreciation ........................................................................................................................................ 35

3.14. Other finance charges ........................................................................................................................ 36

3.15. Operation & Maintenance charges .................................................................................................... 36

3.16. Interest on working capital .................................................................................................................. 39

3.17. Return on Equity................................................................................................................................... 41

3.18. Interest on Loans ................................................................................................................................ 42

3.19. Interest on Consumer Security Deposit ............................................................................................. 43

3.20. Provision for RPO ............................................................................................................................... 44

3.21. Non-Tariff income ................................................................................................................................ 44

3.22. Revenue from Sale of Power at Existing Tariff ................................................................................. 45

3.23. Net ARR and revenue gap for FY 2017-18 ....................................................................................... 46

4. APR Summary for FY 2018-19 ......................................................................................... 48

4.1. Preamble ................................................................................................................................................ 48



4.2. Estimate of category wise number of consumers, connected load and sales for FY 2018-19 ........ 48

4.3. Distribution Loss ..................................................................................................................................... 51

4.4. State Transmission losses .................................................................................................................... 52

4.5. Central Transmission Loss ................................................................................................................... 52

4.6. Power Purchase .................................................................................................................................... 52

4.7. Energy Balance ..................................................................................................................................... 58

4.8. Power Purchase Cost ........................................................................................................................... 59

4.9. Transmission Charges .......................................................................................................................... 65

4.10. Capital Investment Plan, Capitalization and Funding ....................................................................... 65

4.11. Operation & Maintenance (O&M) Expenses ..................................................................................... 67

4.12. Gross Fixed Assets .............................................................................................................................. 71

4.13. Depreciation on Gross Fixed Assets ................................................................................................. 72

4.14. Return of Equity ................................................................................................................................... 73

4.15. Interest on Consumer Security Deposit ............................................................................................. 74

4.16. Interest on Working Capital ................................................................................................................ 74

4.17. Contribution to Contingency Reserve ................................................................................................ 76

4.18. Non-Tariff Income ............................................................................................................................... 76

4.19. Interest on Normative Debt .................................................................................................................77

4.20. Other Finance Charges ...................................................................................................................... 78


4.22. Net ARR and Revenue Gap for FY 2018-19 ..................................................................................... 80

5. Annual Revenue Requirement (ARR) for FY 2019-20 to FY 2021-22 .................................... 82

5.1. Preamble ................................................................................................................................................ 82

5.2. Historical Assessment of Number of Consumers and Sales ............................................................. 82

5.3. Projected Sales (MU), Number of Consumers and Connected Load for 3rd

Control Period ........... 84

5.4. Detailed category-wise projections for ARR period for the 3rd

Control Period .................................. 88

5.5. Distribution Loss .................................................................................................................................. 100

5.6. State Transmission Losses ................................................................................................................. 103

5.7. Central Transmission Losses ............................................................................................................. 104

5.8. Power Purchase .................................................................................................................................. 104

5.9. Energy Balance ................................................................................................................................... 107

5.10. Renewable Power Purchase Obligation .......................................................................................... 108

5.11. Power Purchase Cost ....................................................................................................................... 109

5.12. Transmission Charges .......................................................................................................................123

5.13. Capital Investment Plan, Capitalization and Funding .......................................................................123

5.14. Gross Fixed Assets ............................................................................................................................ 125

5.15. Depreciation on GFA ......................................................................................................................... 126

5.16. Interest on Loans ................................................................................................................................ 127

5.17. Other Financial Charges ................................................................................................................... 129

5.18. Operation & Maintenance (O&M) Expenses ................................................................................... 130

5.19. Return on Equity .................................................................................................................................133

5.20. Interest on Consumer Security Deposit ........................................................................................... 134



5.21. Interest on Working Capital ................................................................................................................ 135

5.22. Non-Tariff Income .............................................................................................................................. 136


5.24. Annual Revenue Requirement for FY 2019-20 to FY 2021-22 ..................................................... 138

5.25. Net Gap at Existing Tariff .................................................................................................................. 139

5.26. Revenue from Sale of Power at Proposed Tariff ............................................................................. 140

5.27. Revenue gap for FY 2018-19 at proposed tariff ............................................................................... 141

6. Voltage-wise cost of supply ...........................................................................................142

6.1. Preamble .............................................................................................................................................. 142

6.2. Background .......................................................................................................................................... 142

6.3. Methodology adopted for Computation of Voltage wise Cost of Supply .......................................... 142

6.4. Determination of Voltage wise Losses ............................................................................................... 143

6.5. Information required for arriving Voltage Wise Cost of Supply.......................................................... 144

6.6. Methodology adopted for determination of Cost of Supply ................................................................ 145

7. Miscellaneous and General Charges .............................................................................. 150

7.1. Schedule of Miscellaneous and General Charges ............................................................................ 150

7.2. Meter Rent ........................................................................................................................................... 150

7.3. SLC charges ......................................................................................................................................... 151

7.4. Security Deposit .................................................................................................................................... 153

7.5. Interest on Security Deposit ................................................................................................................. 154

8. Proposed Tariff Schedule for FY 2019-20 ........................................................................ 155

8.1. Simplification of tariff structures for electricity consumers in Bihar ..................................................... 155

8.2. Terms and Conditions of Low Tension Tariff ...................................................................................... 165

9. Wheeling and Open Access Charges .............................................................................. 175

9.1. Background ........................................................................................................................................... 175

9.2. Wheeling Charges ................................................................................................................................ 175

9.3. Cross Subsidy Surcharge .................................................................................................................... 177

9.4. Reactive Energy charges ..................................................................................................................... 178

9.5. Standby Charges .................................................................................................................................. 178

9.6. Roadmap for reduction of Cross Subsidy Surcharge ......................................................................... 178

Annexure B – Additional Data Submission to BERC ................................................................... 180



List of Tables

Table 1: Existing distribution infrastructure of SBPDCL ........................................................................................... 11

Table 2: Discoms’ Areas and Circles ......................................................................................................................... 11

Table 3: Discoms’ Circles & Other Establishment ............................................. Error! Bookmark not defined.

Table 4: Procedural History of Filing .......................................................................................................................... 12

Table 5: Highlights of the Hon’ble APTEL Judgment dated 25.11.2016 ................................................................. 14

Table 6: Number of Consumers as on 31st March 2018 ........................................................................................... 19

Table 7: No. of Consumers of Gaya Distribution Franchisee .................................................................................. 20

Table 8: Total connected load (in kW) as on 21st March, 2018 ................................................................................ 21

Table 9: Total connected load (in kW) of Gaya Distribution Franchisee Area ........................................................ 21

Table 10: Total Energy Sales (in MU) for FY 2017-18............................................................................................. 22

Table 16: Distribution Losses (in %) ......................................................................................................................... 23

Table 17: Renewable Purchase Obligation (%) ....................................................................................................... 24

Table 18: RPO met for FY 2017-18 (in INR Crore) .................................................................................................. 25

Table 19: Actual Power Purchased (MU) in FY 2017-18 ......................................................................................... 25

Table 20: Energy balance (MU) in FY 2017-18 ........................................................................................................ 26

Table 21: Actual Power Purchased (MU) in FY 2017-18 ......................................................................................... 29

Table 22: PGCIL, POSCO and ERLDC charges ..................................................................................................... 32

Table 23: State transmission charges ....................................................................................................................... 32

Table 25: CWIP, Capex, Capitalization and Funding (in INR Crore) ...................................................................... 33

Table 26: Gross Fixed Assets (in INR Crore) ........................................................................................................... 34

Table 27: Depreciation (in INR Crore) ..................................................................................................................... 35

Table 28: Other Finance charges (in INR Crore) ..................................................................................................... 36

Table 29: Employee expenses (in INR Crore) .......................................................................................................... 36

Table 30: R&M expenses (in INR Crore) ................................................................................................................... 37

Table 31: A&G expenses (in INR Crore) ................................................................................................................... 37

Table 32: Holding cost (in INR Crore) ....................................................................................................................... 38

Table 33: O&M expenses (in INR Crore) .................................................................................................................. 38

Table 34: Interest on working capital (in INR Crore) ................................................................................................ 40

Table 35: Return on equity (in INR Crore) ................................................................................................................ 42

Table 36: Interest on Loans Claimed for FY 2017-18 (in INR Crore) ..................................................................... 42

Table 37: Interest on Loans Claimed for FY 2017-18 (in INR Crore) ..................................................................... 43

Table 38: Interest on Consumer Security Deposit (in INR Crore) ........................................................................... 43

Table 41: Non-Tariff Income (in INR Crore) ............................................................................................................. 44

Table 42: Revenue from sales of power at existing tariff......................................................................................... 45

Table 43: Net ARR and revenue gap for FY 2017-18 (in INR Crore) ..................................................................... 46

Table 44: Category-wise no. of consumers projected for FY 2018-19 ................................................................... 48

Table 45: Category-wise sales (MUs) projected for FY 2018-19 ............................................................................ 50

Table 46: Category-wise connected load (kW) for FY 2018-19 .............................................................................. 50

Table 47: Distribution loss .......................................................................................................................................... 52

Table 48: Details of RPO to be met for APR ............................................................................................................ 53

Table 49: Power purchase Allocation projected for FY 2018-19 (in MW) .............................................................. 54



Table 50: Total power purchase for APR (in MU) ..................................................................................................... 57

Table 51: Energy Balance for APR FY 2018-19 ...................................................................................................... 58

Table 52: Power Purchase Projection for APR (in MW) for FY 2018-19 ................................................................. 61

Table 53: Transmission charges for APR (in INR Crore) ........................................................................................ 65

Table 54: Capitalization plan for FY 2018-19 (in INR Crore) .................................................................................. 66

Table 55: CWIP, Capitalization and Funding of Capitalization projected for FY 2018-19 (in INR Crore) ............ 67

Table 56: Employee Expenses for APR (in INR Crore) ........................................................................................... 68

Table 57: Calculation of “K” Factor for FY 2018-19 ................................................................................................. 68

Table 58: R&M Expenses for APR (in INR Crore) ................................................................................................... 69

Table 59: A&G Expenses for APR (in INR Crore) .................................................................................................... 70

Table 60: Allocation of Holding Company Cost for FY 2018-19 (in INR Crore) ...................................................... 71

Table 61: Summary of O&M Expenses for APR (in INR Crore) ............................................................................... 71

Table 62: Summary GFA for FY 2018-19 (in INR Crore) ......................................................................................... 71

Table 63: Depreciation on GFA for APR (in INR Crore) ...........................................................................................72

Table 64: Return on equity for FY 2018-19 (in INR Crore) ....................................................................................... 73

Table 65: Interest on consumer security deposit (in INR Crore) ..............................................................................74

Table 66: Interest on working capital for APR (in INR Crore) .................................................................................. 75

Table 67: Contribution to contingency reserve for FY 2018-19 (in INR Crore) ...................................................... 76

Table 68: Net-Non-tariff income for APR (in INR Crore) ......................................................................................... 76

Table 69: Computation of weighted average rate of interest on project loans (in INR Crore) ............................... 77

Table 70: Interest on Normative debt (in INR Crore) ................................................................................................ 77

Table 71: Other finance charges (in INR Crore) ....................................................................................................... 78

Table 72: Revenue from sales of power at existing tariff for FY 2018-19 (in INR Crore) ...................................... 78

Table 73: Revenue requirement for FY 2018-19 (in INR Crore) ............................................................................ 80

Table 76: Category wise number of consumer for past few years .......................................................................... 82

Table 77: Category wise sales for the past few years (in MU) ............................................................................... 83

Table 78: Category-wise no. of consumers projected for 3rd

Control Period ......................................................... 85

Table 80: Category-wise sales projected for 3rd

Control Period.............................................................................. 86

Table 81: Category-wise connected load (kW) projected for the 3rd

Control Period ............................................. 87

Table 82: Distribution Loss Trajectory .................................................................................................................... 102

Table 82: Distribution Loss Trajectory .................................................................................................................... 102

Table 83: Power purchase Quantum for FY 2019-20 (in MW) .......................... Error! Bookmark not defined.

Table 84: Total power purchase (MU) for 3rd

Control Period ................................................................................. 105

Table 86: Energy Balancing for ARR for 3rd Control Period .................................................................................. 108

Table 85: Renewable energy purchase obligation for FY 2019-20 ...................................................................... 108

Table 87: Detailed power purchase costs for FY 2019-20 (in INR Crore) .............................................................. 111

Table 87: Detailed power purchase costs for FY 2020-21 (in INR Crore) ............................................................. 115

Table 87: Detailed power purchase costs for FY 2021-22 (in INR Crore) ............................................................. 119

Table 88: Transmission charges for ARR (in INR Crore) ....................................................................................... 123

Table 89: Capitalization in 3rd Control Period(in INR Crore) ................................................................................. 123

Table 90: Capital works in progress for 3rd

Control Period (in INR Crore) ............................................................ 124

Table 91: GFA for FY 2019-20 (in INR Crore) ......................................................................................................... 125





Table 92: Depreciation on GFA (in INR Crore) ....................................................................................................... 127

Table 93: Detailed loan schedule for FY 2019-20 (in INR Crore) .......................................................................... 127

Table 93: Detailed loan schedule for FY 2020-21 (in INR Crore) ..........................................................................128

Table 93: Detailed loan schedule for FY 2021-22 (in INR Crore) .......................................................................... 129

Table 95: Interest on normative debt for the 3rd

Control Period (in INR Crore) .................................................... 129

Table 96: Other finance charges (in INR Crore) .................................................................................................... 130

Table 98: Employee expenses for the 3rd

Control Period (in INR Crore) .............................................................. 131

Table 99: Calculation of “K” Factor & R&M Expense for 3rd

Control Period.......................................................... 131

Table 101: A&G expenses for ARR (in INR Crore) ................................................................................................. 132

Table 102: Holding company cost for 3rd

Control Period (in INR Crore) ............................................................... 132

Table 103: Return on equity for ARR (in INR Crore) .............................................................................................. 134

Table 104: Interest on consumer security deposits (in INR Crore) ........................................................................ 134

Table 105: Interest on working capital for the 3rd

Control Period (in INR Crore) .................................................. 136

Table 106: Non-tariff income for ARR (in INR Crore) ............................................................................................. 136

Table 107: Revenue from sale of power at existing tariff for FY 2019-20 (in INR Crore) .................................... 137

Table 108: Net ARR for FY 2018-19, FY 2020-21 and FY 2021-22 (in INR Crore) ............................................. 138

Table 75: Unrecovered Gap for FY 2017-18 along with carrying cost (in INR Crore) .......................................... 139

Table 110: Net revenue gap at existing tariff for FY 2019-20 ................................................................................ 139

Table 110: Net revenue gap at existing tariff for FY 2019-20 and FY 2017-18 .................................................... 139

Table 111: Total revenue from sale of power at proposed tariff for FY 2019-20 ................................................ 140

Table 112: The revenue gap at proposed tariff for FY 2019-20 ............................................................................ 141

Table 116: Voltage wise Technical losses considered for the 3rd Control Period ............................................... 144

Table 117: Classification of Categories on the basis of Voltage of power supply ............................................... 144

Table 118: Voltage wise Technical losses considered for the Control Period ..................................................... 145

Table 119: Apportionment of technical losses to voltage wise sale for FY 2019-20 ........................................... 145



Table 120: Apportionment of Commercial losses to voltage wise sale for FY 2019-20 ..................................... 146



Table 121: Allocation of power purchase cost to the energy sales for FY 2019-20 ............................................ 147



Table 122: Allocation of Network Cost for the 3rd Control Period.......................................................................... 147

Table 123: Cost of Supply at different Voltage Levels for FY 2019-20 ............................................................... 148



Table 128: Proposed Monthly Meter Rent .............................................................................................................. 151

Table 129: Application fee ........................................................................................................................................ 151

Table 130: Meter testing fee..................................................................................................................................... 152



Table 131: Meter testing fee for own installation .................................................................................................... 152

Table 132: Removal/ refixing/ change of meter fee ............................................................................................... 152

Table 133: Reconnection charges ........................................................................................................................... 153

Table 134: Supervision, labour and establishment charges for service connection ............................................ 153

The BPL consumers in the State are served through the Kutir Jyoti tariff category. ..................................... 157

At present, the consumption of Kutir Jyoti consumers is capped at 50 units per month, with the balance

consumption being levied as per DS-I tariffs. .......................................................................................................... 157

This will be applicable to all huts (Kutir) and dwelling houses of rural and urban families below the poverty

line (BPL) as per the list / notification published by Grameen Vikas Vibhag, Govt. of Bihar from time to time. . 157

Considering that there are still a significant no. of unmetered consumers in this category, two sub-

categories have been retained. ................................................................................................................................ 157

At present, two part tariff structure is applicable for metered Kutir Jyoti consumers, with fixed charges to be

levied on a-per connection basis per month. ........................................................................................................... 157

The Distribution Licensees propose to retain the two-part tariff structure for metered Kutir Jyoti consumers,

with fixed charges being levied on a-per KW connected load basis per month.................................................... 157

The tariff structure is proposed below. .............................................................................................................. 157

Table 135: Proposed tariff structure for KJ category .............................................................................................. 157

Table 136: Proposed tariff structure for DS category ............................................................................................. 158

Table 137: Proposed tariff structure for NDS category ........................................................................................... 159

Table 138: Proposed tariff structure for IAS category ............................................................................................ 160

Table 139: Proposed tariff structure for LTIS category .......................................................................................... 160

Table 140: Proposed tariff structure for PWW category ......................................................................................... 161

Table 141: Proposed tariff structure for SS category .............................................................................................. 161

Table 142: Proposed tariff structure for HT category .............................................................................................. 162

Table 143: Proposed tariff structure for RTS category ........................................................................................... 162

Table 144: Tariff schedule considering ‘Zero’ GoB Subsidy .................................................................................. 164

Table 147: Proposed tariff rate for seasonal supply ............................................................................................... 172

Table 149: Segregation of Wires and Retail Supply Costs .................................................................................... 175

Table 150: Wheeling Charges at 33 kV for 3rd

Control Period ............................................................................... 176

Table 151: Wheeling charges at 11 kV for the 3rd

Control Period.......................................................................... 176

Table 152: Power purchase cost for FY 2019-20.................................................................................................... 177

Table 152: Intra-state Transmission Charge for FY 2019-20 ................................................................................. 177


South Bihar Power Distribution Company Limited 10

1. Introduction

1.1. Background

1.1.1. Bihar State Electricity Board (“Board” or “BSEB”) originally constituted on 1st April 1958

under Section 5 of the Electricity (Supply) Act, 1948 and was engaged in the management

of electricity generation, transmission, distribution and related activities in the State of

Bihar.

1.1.2. Under the new 'Bihar State Electricity Reforms Transfer Scheme 2012', the BSEB has

been unbundled into five companies:

a. Bihar State Power (Holding) Company Limited (BSPHCL),

b. Bihar State Power Transmission Company Limited (BSPTCL),

c. Bihar State Power Generation Company Limited (BSPGCL),

d. South Bihar Power Distribution Company Limited (SBPDCL),

e. North Bihar Power Distribution Company (NBPDCL)

with effect from 1st November’ 2012 vide notification no.

dated 30-10-2012.

a) “Bihar State Power (Holding) Company Limited” means the Company that will own

shares of newly incorporated reorganized four companies i.e. Bihar State Power

Generation Company Limited, Bihar State Power Transmission Company Limited,

South Bihar Power Distribution Company Limited, and North Bihar Power

Distribution Company Limited.

b) “Bihar State Power Generation Company Limited” means the Generating

Company to which the Generating Undertakings of the Board are to be transferred

in accordance with this Scheme.

c) “Bihar State Power Transmission Company Limited” means the Transmission

Company to which the Transmission Undertakings of the Board are to be

transferred in accordance with this Scheme.

d) “South Bihar Power Distribution Company Limited” And “North Bihar Power

Distribution Company Limited”, collectively mean the Distribution Companies, to

which the Distribution Undertakings of the Board are to be transferred in

accordance with this Scheme.

1.1.3. This Petition is being submitted separately by “South Bihar Power Distribution Company

Limited”.



1.2. Profile of SBPDCL

1.2.1. SBPDCL is a company registered under the provisions of the Companies Act 1956 and is

a fully owned subsidiary Company of BSPHCL.

1.2.2. SBPDCL is engaged primarily in the business of distribution and retail supply of electricity.

It has been vested with the distribution assets, interest in property, rights and liabilities of

the erstwhile BSEB necessary for the business of distribution in its area of distribution

comprising of all 9 circles of South Bihar.

1.2.3. SBPDCL has been given the status of a Distribution Licensee as per Section 14 of the

Electricity Act 2003, in order to fulfil the obligations of the Distribution Licensee as

mandated under the provisions of the Bihar State Electricity Reforms Transfer Scheme

2012 and the Electricity Act, 2003.

1.2.4. The Bihar State Electricity Reforms Transfer Scheme, 2012 details out the following for

the distribution business of SBPDCL:

Schedule-C, Part-I: Description of Assets, Liabilities etc.;

Schedule-C, Part-II: Provisional Balance Sheet as on 1st November 2012;

Schedule-C, Part-III: Function and Duties of SBPDCL.

1.2.5. SBPDCL has divided its area of supply into 9 Distribution Circles which further comprises

of 44 divisions and 120 subdivisions.

1.2.6. The Petitioner has a total consumer base of 44.77 lakhs as on 31st March 2018.

1.2.7. The details of the existing distribution infrastructure of the Petitioner as on 31st March

2018 are tabulated below for reference:

Table 1: Existing distribution infrastructure of SBPDCL

S. No. Particulars Unit Quantity

1 No. of electrified villages No *18,304

2 No. of consumers No 44,77,393

3 No. of capacity of 33/11 kV Substations No/MVA 394/6454 MVA

4 No. of capacity of 11/0.4 kV 3 phase Transformers No/MVA 66,563/6,386 MVA

5 Length of 33 kV line CKM 5700

6 Length of 11 kV line CKM 45,349

7 Length of LT line CKM 1,08,792

*Now all the 18521 villages (as per 2011 Census) are electrified and SBPDCL has achieved 100% electrification

1.2.8. The two distribution companies were created based on reorientation of seven area offices.

The reorientation was done based on regrouping of circles. As such from a circle level and

below there is no change from the previous system.

Table 2: Discoms’ Areas and Circles

Area Circle



Area Circle

PESU PESU East

PESU West

Patna Central

Patna

Bhojpur (Ara)

Nalanda

Magadh Gaya

Rohtas

Bhagalpur Bhagalpur

Munger

Tirhut

Muzaffarpur

Chapra

Motihari

Mithila Darbhanga

Samastipur

Kosi Saharsa

Purnea

1.2.9. The four area offices i.e. PESU, Patna central, Magadh and Bhagalpur were regrouped to

form one company, i.e. South Bihar Power Distribution Company Limited. Hence the

circles – PESU (East), PESU (West), Patna, Ara, Nalanda, Gaya, Rohtas, Bhagalpur and

Munger constitute the South Bihar Power Distribution Company Limited (SBPDCL). The

remaining three area offices viz. Tirhut, Mithila and Kosi Areas were combined to form

another company, i.e. North Bihar Power Distribution Company Limited (NBPDCL).

Consequently Muzaffarpur, Chapra, Motihari, Darbhanga, Samastipur, Saharsa and

Purnea Circles are combined within the company North Bihar Power Distribution

Company Limited.

1.3. Procedural History

1.3.1. The procedural history of the filings of petition of erstwhile BSEB, BSPHCL and individual

companies is tabulated below for ready reference:

Table 3: Procedural History of Filing

S. No. Scope of Filing in Petition

Filing Date Order Date Remarks

1 ARR & Tariff Petition for FY 2006-07

10.04.2006 29.11.2006 -


18.12.2007 - Delayed filing & hence directed to file petition for FY 2008-09 by 31.01.2008


14.02.2008 26.08.2008 Review of FY 2006-07 was also undertaken in this order


09.10.2009 - Delayed filing & hence directed to file petition for FY 2010-11.


03.02.2010 06.12.2010 Review of FY 2008-09 was also undertaken in this order


17.02.2011 01.06.2011 Order effective from 1.5.2011

7 True-up Petition for FY 2006- 01.09.2011 04.01.2012 -





07, FY 2007-08 and FY 2008-09 Addendum to this petition

17.10.2011

8 True-up Petition for FY 2009-10

13.10.2011 27.01.2012 -

9 Review of ARR for FY 2010-11 based on provisional accounts Submission of Audited Accounts for FY 2010-11 Submission of True-up petition for FY 2010-11 based on Audited Accounts

13.10.2011 02.03.2012 16.03.2012

- Commission directed to file petition for review along with petition of FY 2012-13

10 ARR & Tariff Petition for FY 2012-13 Supplementary petition for FY 2012-13

15.11.2011 02.01.2012

30.03.2012 Order included True-up of FY 2010-11 & Review of FY 2011-12

11 Business Plan for Control Period FY 2013-14 to FY 2015-16 filed by BSPGCL, BSPTCL and 2 DISCOMs Revised Business Plan as per Commissions directive Re-Revised Business Plan for BSPGCL & BSPTCL Re-Revised Business Plan for 2 DISCOMs

20.09.2012 14.11.2012 03.01.2013 04.01.2013

15.03.2013 Commission directed to submit revise business plan. Commission again directed to submit revised business plan vide letter dated 21.12.2012 Approved along with MYT Order

12 Provisional True-up for FY2011-12, Review petition for FY 2012-13 and MYT Petition for FY 2013-14 to FY 2015-16 for BSPGCL, BSPTCL and 2 DISCOMs Revised petition for True-up of FY 2011-12 based on Audited Accounts

15.11.2012 24.12.2012

15.03.2013 Commission issued MYT order according to petition

13 True up for FY 2012-13 by BSPHCL Annual Performance Review for FY 2013-14 and Revised Annual Revenue Requirement for FY 2014-15 for BSPGCL, BSPTCL and 2 DISCOMs

- 28.02.2014 Commission issued Tariff order according to petition

14 True up for FY 2013-14, Annual Performance Review for FY 2014-15 and Annual Revenue Requirement for FY 2015-16 for NBPDCL and SBPDCL

- 16.03.2015 Commission issued Tariff order according to petition

15 True-up for FY 2014-15, 15.11.2015 21.03.2016 Commission issued Tariff





Annual Performance Review (APR) for the FY 2015-16 Annual Revenue Requirement (ARR) for the control period FY 2016-17 to FY 2018-19

order according to petition, but disallowed various claims.

16 True-up for FY 2015-16, Annual Performance Review (APR) for the FY 2016-17 Annual Revenue Requirement (ARR) for FY 2017-18

06.12.2016 24.03.2017 Commission issued Tariff order according to petition, but disallowed various claims.

17 True-up for FY 2016-17, Annual Performance Review (APR) for the FY 2017-18 Annual Revenue Requirement (ARR) for FY 2018-19

05.12.2017 21.03.2018 Commission issued Tariff order according to petition, but disallowed various claims.

18 Business Plan for Control Period FY 2019-20 to FY 2021-22 filed Bihar DISCOMs True-up for FY 2017-18, Annual Performance Review (APR) for the FY 2018-19 Annual Revenue Requirement (ARR) for FY 2019-20, 2020-21 and 2021-22

05.11.2018 30.11.2018

1.4. Judgment of Hon’ble APTEL on Appeal No. 141 and Appeal No. 142 of 2016

1.4.1. Hon’ble BERC had issued Tariff Order dated 21.03.2016 in response to Petitions filed by

the Discoms with regard to True-up of FY 2014-15, the APR for FY 2015-16, and the

ARR for the control period FY 2016-17 to FY 2018-19. In the said Tariff Order Hon’ble

Commission had disallowed claims of SBPDCL and NBPDCL in the matter of power

Purchase Cost, Depreciation, Return on equity, Sales, Prior Period Expenses etc.

Aggrieved by the disallowance made by the Hon’ble Commission in the Tariff Orders

dated 21.03.2016 Appeal No. 141 of 2016 and Appeal No. 142 of 2016 were filed by the

SBPDCL and NBPDCL respectively before Hon’ble Appellate Tribunal for Electricity

(APTEL).

1.4.2. Subsequently, the Hon’ble APTEL decided the matter vide Judgment dated 25th

November, 2016. Brief of the major observations made by the Hon’ble APTEL are as

follows:

Table 4: Highlights of the Hon’ble APTEL Judgment dated 25.11.2016

Parameter Observations of the Hon’ble APTEL

Power Purchase Cost

In respect of this Issue, we direct the State Commission to re-examine to the extent to which the power purchase cost is to be allowed on the quantum of power purchase allowed with reference to all the bills from the generators and other sources of power procurement and if the State Commission finds any specific quantum of power purchase claim is not supported by such bills may seek specific documents from the Appellant in



Parameter Observations of the Hon’ble APTEL

this regard. The State Commission should also treat the power purchase rate of SBPDCL for FY 2014-15 as per audited accounts as there is eventually no adverse impact on the consumers

Depreciation and Gross Value of Assets

In our opinion, the depreciation is an important segment and needs to be re-examined by the State Commission keeping in view the relevant details submitted by the Appellant subject to its prudent check. The Appellant is entitled to raise the issue of rate of depreciation also before the State Commission while the depreciation amount is being re-examined by the State Commission.

Return on Equity The matter for consideration is only whether the amount contributed by the State Government towards equity capital should be considered equity or not. To be fair to the Appellant, the State Commission is directed to re-examine whether the contribution of the State Government towards equity capital should be considered as equity or not and accordingly pass an appropriate order.

Net Prior Period (Credit/Charges)

The State Commission is hereby directed to look into this issue based on the details claimed by the Appellant to have been furnished and even the audited accounts of the Appellant.

Energy Sales Our observation on this issue is limited to the point that the progress on the part of the Appellant in implementing these schemes in the remaining part of the current financial year could be kept under close watch and if considerable progress is achieved by the Appellant in the ensuing period, the State Commission can reconsider the projections and consumers mix etc. afresh for FY 2017-18 onwards.

Recovery of Gap/Surplus of the past period

We have observed that in the Impugned Order, the State Commission had deferred the carrying cost. We observe that the surplus of the past period pertaining to the erstwhile BSEB and also the issue regarding disallowance of carrying cost need to be reviewed by the State Commission.

Employee Cost and A&G Expenditures

In light of the fact that the details of both these employees cost and A&G expenses for FY 2015-16 are now available as stated by the Appellant, the State Commission may look into the employee cost and A&G expenses for the FY 2015-16 and subsequently employee cost and A&G expenses for FY 2015-16 should be considered a base year for estimating the same for the FY 2016-17 onwards. Since the matter is being remanded to the State Commission, the Appellant is given the liberty to raise the above aspect in the remand proceedings with satisfactory details for consideration in regard to Employees Cost and A&G expenses.

Distribution Losses Trajectory

We have also noted that the reasoning of the State Commission to the effect that a non-achievement of loss level as per the trajectory already decided by the State Commission is on account of the inefficiencies of the Appellant and the consumers should not be burdened for such inefficiencies. We do not wish to interfere with the impugned findings of this State Commission in its Order since the State Commission is in a better position to ascertain the efficiency of the Appellant. However, since the matter is being remanded to the State Commission for various issues as brought out above, we would like to state only that the State Commission should have to relook and decide only to the extent that such numbers should not become unachievable but not on account of the inefficiencies of the Appellant, if the State Commission observes so.

1.5. BERC Order against the Judgment of Hon’ble APTEL on Appeal No. 141 and Appeal

No. 142 of 2016

1.5.1. The Hon’ble APTEL had disposed of the Appeal No. 141/2016 (pertaining to Case No.

50/2015 of SBPDCL) and Appeal No. 142/2016 (pertaining to Case No. 49/2015 of

NBPDCL) by its common order dated 25th November 2016 setting aside the order of the



Commission and remanded the case to Hon’ble BERC to reconsider eight issues and

pass fresh order.

1.5.2. The Hon’ble BERC had passed separated Tariff Orders for SBPDCL and NBPDCL on 8th

March 2017 on the eight issues. Hon’ble BERC in its revised order has allowed an

additional ARR of INR 25.54 Crores in revised True up order of 2014-15 for SBPDCL and

an additional ARR of INR 33.25 Crores in revised True up order of 2014-15 for NBPDCL.

The same amount was considered in True up order of FY 2015-16 with applicable

carrying costs in the Tariff Order for SBPDCL and NBPDCL dated 24th March 2017.

1.6. Appeal No. 117 and Appeal No. 118 of 2017

1.6.1. The Hon’ble BERC has proceeded to disallow the claims of SBPDCL and NBPDCL on the

issues of Net prior period charges (FY 2014-15) and Recovery of Gap/(Surplus) of the

past period in its revised Tariff Order for SBPDCL and NBPDCL dated 8th March 2017.

1.6.2. SBPDCL and NBPDCL had filed an appeal against the order of the Hon’ble Commission

dated 8th March, 2017 vide appeal no 117/2017 and 118/2017 of FY 2016-17. Appeal no.

154/2017 and 155/2017 against BERC Tariff Order dated 24.03.2017 were filed by the

Discoms before the Hon’ble APTEL and is sub-judice till date.

1.7. Appeal No. 117 of 2017 and Appeal No. 118 f 2017 of 2017

1.7.1. The Hon’ble APTEL had disposed of the Appeal No. 117/2017 (pertaining to NBPDCL Vs.

BERC) and Appeal No. 118/2017 (pertaining to SBPDCL Vs. BERC) by its common order

dated 25th October 2018 upheld the Order passed by the Hon’ble Commission.

1.8. Instant Petition

1.8.1. Section 62 of the Electricity Act, 2003 requires the Distribution Licensee to furnish details

as may be specified by the SERC for determination of tariff. In addition, as per the

regulations issued by the Hon’ble Commission, BSEB or its unbundled companies are

required to file petition for all reasonable expenses which they believe they would incur

over the next financial year and seek the approval of the Hon’ble Commission for the

same in advance. The filing is to be done based on the projections of expected costs and

revenue.

1.8.2. The current petition has been prepared in accordance with the provisions of the following

Acts/ Policies/ Regulations:

a) The Electricity Act, 2003;

b) The National Electricity Policy;



c) The National Tariff Policy, and amendments issued therein;

d) Bihar Electricity Regulatory Commission (Multi Year Distribution Tariff)

Regulations, 2015, Bihar Electricity Regulatory Commission (Multi Year

Distribution Tariff) (First Amendment) Regulations, 2017 and its

amendments thereof, Bihar Electricity Regulatory Commission (Multi Year

Distribution Tariff) Regulations, 2018 along with the other guidelines and

directives issued by the BERC from time to time

e) BERC (Terms and Conditions for Open Access) Regulations, 2005

1.8.3. The Petitioner has made genuine efforts for compiling all relevant information relating to

the True-up, APR, and ARR petition as required by the regulations issued by the Hon’ble

Commission and has also made every effort to ensure that the information provided to the

Hon’ble Commission is accurate and free from material errors. However, there may be

certain deficiencies owing to the limited operations of Distribution Company on

independent basis. The Petitioner therefore prays to the Hon’ble Commission that the

information provided be accepted for the current filing and at the same time assures that it

is taking appropriate measures to improve its management information system for

improved data collection.

1.9. Contents of the Petition

1.9.1. This petition comprises of following sections:

True up for FY 2017-18

Annual Performance Review for FY 2018-19

Annual Revenue Requirement for FY 2019-20, FY 2020-21, FY 2021-22

Revenue Gap and Tariff Proposal for FY 2019-20

Miscellaneous and General Charges

Voltage Wise Cost of Supply

Proposed tariff Schedule for FY 2019-20

Wheeling and Open access charges



2. Overall approach for present filing

2.1. Present Approach

2.1.1. The Petitioner requests the Hon’ble Commission to determine the ARR for FY 2019-20. It

further requests the Hon’ble Commission to determine norms for the Petitioner for this

period based on the learnings and its independent operations till FY 2017-18.

2.1.2. In line with the above, SBPDCL is filing its True-Up petition for FY 2017-18, Annual

Performance Review petition for FY 2018-19 and Annual Revenue Requirement petition

for FY 2019-20, FY 2020-21 and FY 2021-22 for the consideration of the Hon’ble

Commission.

2.1.3. The Petitioner requests the Hon’ble Commission to kindly approve the True-Up, APR and

ARR, keeping in view the actual segregated figures now available for the entire year in the

audited books of accounts for FY 2017-18.

2.2. Data and information sources for estimating the Aggregate Revenue Requirement

2.2.1. In this Petition, the true up is based on the actual audited accounts for

FY 2017-18. The APR for FY 2018-19 is based on actual figures for the first 6 months (as

available) for power purchase, and for components like O&M expenses etc. of the

financial year. Appropriate pro-rata projections and escalations have been taken over the

previous year, keeping in mind guiding principles defined by the Hon’ble Commission. The

ARR for FY 2019-20, 2020-21 and 2021-22 is based on projections and escalations over

the previous year, keeping in mind the historical trends and key initiatives planned for the

future, in line with the guidelines provided by the Hon’ble Commission for determining the

same.



3. True-up Summary for FY 2017-18

3.1. Preamble

3.1.1. This section outlines the performance of the Petitioner for FY 2017-18.

3.1.2. In line with the provisions of the BERC (Multi Year Distribution Tariff) Regulations, 2015

and amendments issued thereof, the Petitioner hereby submits the True Up petition for FY

2017-18. The expenses of the Petitioner for FY 2017-18 presented for true-up are based

on the audited books of accounts, and other principles adopted by the Hon’ble

Commission for estimating normative interest on term loan, Return on Equity, interest on

working capital loan and depreciation. The ARR so arrived has been compared with that

approved by the Hon’ble Commission vide its Tariff Order dated 21st March, 2018.

Accordingly, the revised Aggregate Revenue Requirement, revenue and gap for FY 2017-

18 have been given in the subsequent sub-sections of this chapter.

3.2. Number of Consumers, Connected Load and Sales

Number of Consumers

3.2.1. The actual no. of consumers at the end of FY 2017-18 against the no of consumers

revised approved in the Tariff Order dated 21st March, 2018 is provided in the table below.

Table 5: Number of Consumers as on 31st March 2018

Category Approved by Commission for

FY 2017-18 (RE)

Actual For FY 2017-18

Kutir Jyoti 1172518 1053164

Domestic-I 1533667 1501556

Domestic-II 1179222 1210324

Non-Domestic-I 55789 49561

Non-Domestic-II 249184 254513

Street Light-I 454 466

Street Light-II 378 441

IAS-I 167788 156959

IAS-II 4399 3814

Public Water Works 1782 1806

LTIS-I 31415 46964

LTIS-II 3179 3792

HTS-I 1385 1475

HTS-II 110 104

HTS-III 4 5

HTSS 16 13

Railway 15 15

Total 4401305 4284972



3.2.2. The above comparison of consumer numbers in Table 6 clearly brings out the fact that

Petitioner has added a significant number of consumers during the year and the actual no.

of consumers is in fact higher by almost 18.19% over previous year. Increase can be

observed in certain major categories like KJY (27%), IAS (11%), DS-I (18%) and NDS-I

(25%), PWW (30%), LTIS (76%) over previous year. As the Hon’ble Commission is also

aware that the Petitioner had engaged an Input based Franchisee in Gaya and Bhagalpur

area for accessing greater consumer base with prompt meter reading, billing and

collection. It is to be noted that with effect from 26.11.2017, the Petitioner has

terminated the Distribution Franchisee Agreement with M/S BEDCPL for distribution of

electricity in the Bhagalpur area. Similarly, the Gaya DF has also been terminated

w.e.f. 04.07.2018 in view of its poor performance. The category wise consumers in the

area of Distribution Franchisee (DF) are provided below:

Table 6: No. of Consumers of Gaya Distribution Franchisee

Category Approved in APR for FY 2017-18

Actual For FY 2017-18

Kutir Jyoti- BPL Consumers 56478 54,116

Domestic – I 26719 28,575

Domestic – II 93130 87,286

Non-Domestic – I 1552 1,753

Non-Domestic – II 20612 19,093

Street Light – I 202 192

Street Light – II 44 40

IAS – I 5803 9,130

IAS – II 17 6

PWW 140 283

LTIS – I 2361 2,204

LTIS – II 71 67

HTS – I 87 95

HTS – II 2 3

HTS – III 0 -

HTSS 0 -

Railway 0 -

Grand Total 207218 2,02,843

3.2.3. It is pertinent to understand that the Petitioner has engaged the DF for facilitating its billing,

collection and other activities, for serving its consumers in the designated geographical

area. Other than that, all the consumers in the DF area are billed as per the applicable

tariff approved by the Hon’ble Commission in its Tariff Orders for the prevalent period.

Connected Load

3.2.4. The actual connected load at the end of FY 2017-18 against the connected load revised

approved in the Tariff Order dated 21st March, 2018 is provided below:



Table 7: Total connected load (in kW) as on 21st March, 2018

Category Approved in APR FY 2017-18

Actual for FY 2017-18

KJ 97449 89187

DS-I 1655472 1523232

DS-II 2486034 3451634

NDS-I 65338 53848

NDS-II 981436 934628

SS-I 2462 5643

SS-II 2631 4751

IAS-I 383966 338229

IAS-II 48235 41194

PWW 25031 33817

LTIS-I 325675 416862

LTIS-II 164902 210253

HTS-I 292485 295283

HTS-II 170383 171560

HTS-III 43800 86850

HTSS 121041 95703

RT 151380 155160

Total 7017720 7907833

3.2.5. It is to be noted that the connected load of the Petitioner has increased by 34% from

59,10,584 kW in FY 2016-17 to 79,07,833 kW in FY 2017-18.

3.2.6. The Hon’ble Commission is also aware that the Petitioner had engaged an Input based

Franchisee in the Gaya area for accessing greater consumer base with prompt meter

reading, billing and collection. The category wise connected load in the area of Distribution

Franchisee (DF) is provided below:

Table 8: Total connected load (in kW) of Gaya Distribution Franchisee Area



Kutir Jyoti- BPL Consumers 11296 4,583

Domestic - I 25383 28,988

Domestic - II 176991 248,925

Non-Domestic - I 2964 1,905

Non-Domestic - II 67720 70,110

Street Light - I 870 2,325

Street Light - II 243 431

IAS – I 10748 19,674

IAS – II 149 65

PWW 1563 5,299

LTIS – I 19445 19,563





LTIS - II 2926 3,715

HTS-I 17415

HTS-II 2350

Total 337355 4,25,346

3.2.7. The Hon’ble Commission is requested to approve the actual load of 4,05,581 kW of the

consumers of Gaya DF area.

Sales

3.2.8. The category wise actual sales (MUs) at the end of FY 2017-18 against the sales revised

approved in the Tariff Order dated 21st March 2018 is provided below:

Table 9: Total Energy Sales (in MU) for FY 2017-18



KJ 435.54 487

DS-I 1,333.46 1415

DS-II 3,238.49 2248

NDS-I 41.71 44

NDS-II 987.60 1007

SS-I 9.06 7

SS-II 11.83 30

IAS-I 312.17 216

IAS-II 148.06 101

PWW 63.81 84

LTIS-I 216.76 196

LTIS-II 165.64 155

HTS-I 562.06 567

HTS-II 334.38 348

HTS-III 172.31 130

HTSS 810.39 718

RT 563.61 579

DF 944.21 *1171

Total 10351.09 9503

* The sales to Distribution Franchisee refers to the energy sold by SBPDCL to the DF

3.2.9. The Commission is hereby prayed to consider the sales of 9,503 MUs for SBPDCL.

3.3. Distribution Loss

3.3.1. The Hon’ble Commission has approved 30% distribution loss in its MYT Order dated 24th

March 2017 for FY 2017-18. However, it is important to bring into the kind notice of the

Hon’ble Commission that the actual distribution losses for the Petitioner is higher than the

loss trajectory approved by the Hon’ble Commission.



3.3.2. The following table captures the distribution loss for FY 2017-18:

Table 16: Distribution Losses (in %)

Particulars Approved in MYT Order

dated 24.03.2017 Approved in APR FY

2017-18 Actual for FY

2017-18 As per UDAY

MoU

Distribution Loss 30% 30% 34.80% *30%

* SBPDCL was given a target of achieving 30% AT&C loss for FY 2017-18 under the UDAY Scheme with billing

efficiency of 70% and collection efficiency of 100%.

3.3.3. It may kindly be noted that the Hon’ble Commission has aligned its distribution loss

trajectory for FY 2017-18 with the trajectory agreed by the Discom under UDAY MoU.

Therefore, the Discom has computed the distribution loss for FY 2017-18, as per

the methodology accepted for UDAY. Two different approach for computing the loss

would result in different figures and a case may arise where one approach would show

targeted level of loss has been achieved and the other approach would show non-

achievement of target. In order avoid such differences, the Hon’ble Commission is

requested to approve the methodology of computing distribution loss for FY 2017-18 and

onwards as proposed in this petition by the Discom.

3.3.4. The difference in the loss target and the actual loss levels is practically impossible to

achieve in the given period, and therefore this shall add on to the burden of the Discom.

The Hon’ble Commission is also requested to see the growth rates in consumer base of

SBPDCL and consider the challenging operating scenario of the Petitioner wherein most

consumers being added are in rural and remote areas further adding to network losses,

ongoing measures, and regulatory precedents to approve the actual distribution loss for

FY 2017-18. Therefore, the Hon’ble Commission is kindly requested to consider the actual

loss of 34.80%.

3.4. Transmission losses

3.4.1. Intra-State Transmission Loss: It is submitted that the Petitioner has taken the State

transmission loss as per actuals i.e. 707.55 MUs from the audited accounts for

FY 2017-18 and accordingly requests the Hon’ble Commission to approve the same.

3.4.2. Inter-State Transmission Loss: It is submitted that the Petitioner has taken the Central

Transmission loss as per actuals i.e. 317.35 MUs from the audited accounts for FY 2017-

18 and accordingly requests the Hon’ble Commission to approve the same.

3.5. Power Purchase

3.5.1. Bihar has historically been a State with limited natural resources which has led to an

underdeveloped power generation sector in the State. As a result, the State Power

Distribution Companies rely heavily on allocation from central generating stations and



other outside State projects for procuring power for sale to consumers within the State.

This dependence as a consequence creates a significant amount of uncertainty in terms

of reliability and also significantly pushes up the power purchase costs (due to the fact that

sometimes the power allocation is made from inefficient plants in addition to the higher

inter-state transmission charges and losses).

3.5.2. Power is procured by the power management cell of BSP(H)CL, and this is allocated

between the two Discoms, NBPDCL and SBPDCL, in the proportion as determined by the

board resolution based on the demand growth requirement and consequent power supply

requirement.

3.5.3. Long term power purchase: The power purchase for existing sources has primarily been

NTPC, NHPC and the same has been considered based on the actual quantum with

adjustments to capture overall power purchase cost in a reasonable manner. Other

sources of power include power procured from State Generating companies (RE and Non

RE Sources) and IPPs.

3.5.4. Medium / Short Term power purchase: The power purchase from these sources are

namely IEX, DEEP Portal etc., and these have been adequately considered as per the

actual power purchase data provided.

3.5.5. Renewable Power Purchase Obligation: It is submitted that the Hon’ble Commission

has notified the BERC (Renewable Purchase Obligation, its Compliance and REC

Framework Implementation) Regulations, 2010 and BERC (Terms and Conditions for

Tariff Determination from Solar Energy Sources) Regulations, 2010. Further Hon’ble

Commission initiated a Suo-Motu proceedings no. 42/2016 dated 24.11.2016 to bring in

2nd amendment in the BERC (Renewable Purchase Obligation, its Compliance and REC

Framework Implementation) Regulations, 2010 dated 29.03.2017 to incorporate the

various new/amended provisions specified in the revised Tariff Policy,2016 notified by the

Ministry of Power Govt. of India vide gazette notification dated 28.01.2016 and revised the

RPO as follows:

Table 17: Renewable Purchase Obligation (%)

From Renewable

Sources

FY 16-17 FY 17-18 FY 18-19 FY 19-20 FY 20-21 FY 21-22

RPO (%) 6.50% 7.75% 9.25% 11.50% 14.25% 17.00%

Solar (%) 1.50% 2.25% 3.25% 4.75% 6.75% 8.00%

Non-Solar (%) 5.00% 5.50% 6.00% 6.75% 7.50% 9.00%



3.5.6. In line with the above, the details of the Renewable Energy based power procured during

FY 2017-18, has been given in the table below:

Table 18: RPO met for FY 2017-18

S. No. Particulars Unit FY 2017-18

1 Energy consumption MU 9,503.22

2 % of RPO Obligation % 7.75%

Solar % 2.25%

Non-Solar % 5.50%

3 MUs required as per RPO for the year MU 736.50

Solar MU 213.82

Non-Solar MU 522.68

4 Solar Energy procured during the year MU 92.44

5 Non-Solar Energy procured during the year MU 547.03

6 Solar REC purchased during the year MU *149.28

7 Non-solar REC purchased during the year MU

* In light of Regulation 5.1 of the BERC and as per BERC Order dated 23.02.2018 non solar RECs were purchased by SBPDCL to meet the required Renewable Purchase obligation (Solar and Non Solar) for the FY 2017-18 as the trading of Solar RECs was banned by Hon'ble Supreme Court.

3.6. Actual Power Purchase quantum

3.6.1. The details of actual power purchased from various sources in FY 2017-18 is as follows:-

Table 19: Actual Power Purchased (MU) in FY 2017-18

S. No. Power Purchase Sources

Share allocation (MW) Energy(MU)

1 Central Sector Stations 1,604.92 10,521.95 2 Talcher – I ( 2 x 500 MW) 222.72 1,664.17 3 Farakka – I & II (1600 MW) 271.28 1,686.34 4 Farakka – III (500 MW) 71.60 390.31 5 Kahalgaon – I (840 MW) 189.86 1,285.56 6 Kahalgaon – II (1500 MW) 40.34 354.58 7 Barh-II 542.07 3,944.30 8 Korba 13.50 55.96 9 Rangit – HEP 11.34 68.25

10 Teesta - HEP 58.55 344.53 11 Chukha 43.20 299.32 12 Tala 140.45 428.63 13 State Generating Stations 559.12 1,036.23 14 KBUNL 1 118.80 376.56 15 KBUNL 2 157.90 491.55 16 BRBCL 47.52 58.79 17 Small Hydro (BSHPCL) 13.50 5.80 18 BTPS 59.40 20.47 19 JINDAL 162.00 83.07 20 IPP 140.40 951.06 21 GMR Kamalanga Energy 140.40 951.06 22 Renewable 127.66 183.10 23 SECI 5.40 10.96 24 ACME Magadh 5.40 8.95 25 ACME Nalanda 8.10 12.49



S. No. Power Purchase Sources

Share allocation (MW) Energy(MU)

26 Sunmark 5.40 9.05 27 Avantika 2.70 1.10 28 AZURE 5.40 5.94 29 ALFA 8.10 8.73 30 Udipta Energy & Equipment Pvt ltd 2.70 2.29 31 Glatt 1.62 1.66 32 Welspun 2 8.10 12.91 33 Welspun 1 5.40 5.14 34 Welspun 3 8.10 7.90 35 Response Renewable Energy 5.40 5.34 36 New Swadeshi Sugar Mill,Narkatiaganj 3.78 6.83 37 Harinagar Sugar Mills,Harinagar 5.94 25.52 38 Bharat SugarMills,SidhiwaliaGopalganj 5.94 16.18 39 Lauriya Sugar Mill 10.80 14.96 40 Sugauli Sugar Mill 10.80 12.14 41 Hasanpur Sugar Mills,Samastipur 5.40 5.25 42 Riga Sugar Company Ltd,Sitamarhi 1.62 1.70 43 Tirupati 6.00 5.26 44 Siddhashram Rice Mill Cluster Pvt Ltd 0.54 1.85 45 BDBPL 5.02 0.98 46 Open Market Purchase 2,908.87 47 IEX/PXIL - 2,031.48 48 JAYPEE NIGRIE - 197.84 49 JPL - 29.21 50 UPPCL - 0.52 51 GMR ETL - 11.79 52 Arunachal - 4.49 53 TATA ETL - 81.53

TATA (Hydel) 17.33 54 Manikaran Power (Wind) - 397.09 55 Manikaran Power (Thermal) 7.69 56 NEA - 3.96 57 NVVNL - 21.33 58 Adani - 12.45 59 UI - 92.18 60 Sub Total Power Purchase 2,432.10 15,601.22

3.6.2. Accordingly, the Hon’ble Commission is requested to approve the power purchase quantum

for the Petitioner on actual basis provided above.

3.7. Energy Balance

3.7.1. The Petitioner has calculated the energy balance based on the actual sales, distribution

losses and the power availability during FY 2017-18. The details are as provided in the

following table:-

Table 20: Energy balance (MU) in FY 2017-18



Particulars Unit Approved by Commission for FY 2017-18 (RE)

Actual for FY-2017-18

Energy sales including DF MU 10351.09 9,503.22

Distribution loss % 30.00% 34.80%

Distribution Loss MU 4436.18 5,073.09

Energy required at Distribution periphery MU 14787.27 14,576.31

State Transmission Loss % 3.92% 4.63%

State Transmission Loss MU 603.31 707.55

Energy required at State Transmission periphery MU 15390.58 15,283.86

Power available from CGS,SGS and others MU 15337.14 15,601.21

Power purchases from CGS and others MU 14231.92 14,065.78

Losses in Regional Transmission system (excluding state generating stations)

% 2.26% 2.26%

Losses in Regional Transmission System (MU) MU 321.64 317.35

Power Purchase from SGS and others MU 1105.22 *1,535.43

Energy available at State Transmission Periphery

MU 15015.50 15,283.86

Surplus energy MU -375.08 0.00 *It includes power from KBUNL-I, BSP(H)CL, BTPS, JITPL, all solar plants excluding SECI, all biomass and bagasse power plants, short term power purchase except IEX, UPPCL, NEA and UI

3.7.2. As stated above the Discom has computed the distribution loss for FY 2017-18, as per the

methodology accepted for UDAY. As the Hon’ble Commission has approved the loss

trajectory as agreed under UDAY, the methodology for computation of such loss has to be

same as accepted in UDAY. Two different approach for computing the loss would result in

different figures and a case may arise where one approach would show targeted level of

loss has been achieved and the other approach would show non-achievement of target. In

order avoid such differences, the Hon’ble Commission is requested to approve the

methodology of computing distribution loss for FY 2017-18 and onwards as proposed in

this petition by the Discom .The Petitioner requests the Hon’ble Commission to approve

the energy balance based on actual calculations for FY 2017-18.

3.8. Power Purchase Cost

3.8.1. The power purchase cost mainly comprises of fixed and energy charges for two part tariff

PPAs which are essentially with NTPC, NHPC, PTC, GMR Kamalanga, sugar mills,

biomass, bagasse and only energy charges in case of single part tariff based PPAs, which

are typically for BSHPC, Solar and short term power purchase etc. The Petitioner has

presented the actual expenditure incurred on power purchase based on bills raised by the

various power sellers. This actual amount has been considered and captured accordingly

as a break up of two part tariff, wherever applicable, as per the audited accounts of the

Petitioner. The Petitioner therefore humbly requests the Hon’ble Commission to allow the

actual power purchase cost under this true-up process.



3.8.2. In line with the above, the Petitioner presents its power purchase cost for FY 2017-18

based on audited annual accounts, for the kind consideration of the Hon’ble Commission.



Table 21: Actual Power Purchased (MU) in FY 2017-18

S. No.

Power Purchase Sources

Previous Year (FY 17-18)

Share allocation

(MW)

Units Purchase

d (MU)

PLF (%) Fixed Charge

rate (INR/M

U)

Fixed charge (INR Cr)

Energy Rate

(INR/kW h)

Energy charge (INR Cr)

Other charges

((INR Cr)

Total Charges (INR Cr)

Avg. Tariff Rate (INR/ kWh)

1 Central Sector Stations 1,604.92 10,521.95 1.299 1,367.32 2.167 2,280.44 3.49 3,669.57 3.49

2 Talcher – I ( 2 x 500 MW) 222.72 1,664.17 86.5% 0.92 153.86 1.58 262.74 2.55 424.43 2.55

3 Farakka – I & II (1600 MW) 271.28 1,686.34 71.9% 0.94 158.96 2.49 420.16 3.44 579.79 3.44

4 Farakka – III (500 MW) 71.60 390.31 63.1% 1.83 71.52 2.53 98.80 4.40 171.68 4.40

5 Kahalgaon – I (840 MW) 189.86 1,285.56 78.4% 1.07 137.16 2.37 305.19 3.44 442.58 3.44

6 Kahalgaon – II (1500 MW) 40.34 354.58 101.7% 0.93 32.98 2.35 83.48 3.29 116.51 3.29

7 Barh-II 542.07 3,944.30 84.2% 1.90 750.83 2.25 888.44 4.16 1,639.68 4.16

8 Korba 13.50 55.96 48.0% 1.34 7.49 1.20 6.73 2.67 14.95 2.67

9 Rangit – HEP 11.34 68.25 69.7% 1.95 13.31 1.79 12.18 3.92 26.78 3.92

10 Teesta - HEP 58.55 344.53 68.1% 1.20 41.21 1.11 38.24 2.57 88.70 2.57

11 Chukha 43.20 299.32 80.2% - - 2.40 71.89 2.40 71.89 2.40

12 Tala 140.45 428.63 35.3% - - 2.16 92.58 2.16 92.58 2.16

13 State Generating Stations 559.12 1,036.23 2.137 221.49 2.736 283.57 4.87 504.52 4.87

14 KBUNL 1 118.80 376.56 36.7% 1.37 51.50 3.34 125.67 4.69 176.63 4.69

15 KBUNL 2 157.90 491.55 36.0% 2.52 123.96 2.62 128.75 5.14 252.71 5.14

16 BRBCL 47.52 58.79 14.3% 4.89 28.75 1.86 10.92 6.75 39.68 6.75

17 Small Hydro (BSHPCL) 13.50 5.80 5.0% - - 2.49 1.44 2.49 1.44 2.49

18 BTPS 59.40 20.47 4.0% - - 4.10 8.39 4.10 8.39 4.10

19 JINDAL 162.00 83.07 5.9% 2.08 17.28 1.01 8.39 3.09 25.67 3.09

20 IPP 140.40 951.06 1.940 184.53 1.027 97.67 3.707 352.58 3.71

21 GMR Kamalanga Energy 140.40 951.06 37% 1.94 184.53 1.03 97.67 3.71 352.58 3.71

22 Renewable 127.66 183.10 - - 6.59 120.74 6.59 120.74 6.59

23 SECI 5.40 10.96 - - - 5.85 6.41 5.85 6.41 5.85

24 ACME Magadh 5.40 8.95 - - - 8.73 7.81 8.73 7.81 8.73

25 ACME Nalanda 8.10 12.49 - - - 8.73 10.91 8.73 10.91 8.73

26 Sunmark 5.40 9.05 0.17 - - 6.46 5.85 6.46 5.85 6.46

27 Avantika 2.70 1.10 0.23 - - 7.69 0.84 7.69 0.84 7.69

28 AZURE 5.40 5.94 0.19 - - 8.39 4.98 8.39 4.98 8.39

29 ALFA 8.10 8.73 0.18 - - 7.87 6.87 7.87 6.87 7.87



S. No.



Share allocation

(MW)

Units Purchase

d (MU)


rate (INR/M

U)


Energy Rate

(INR/kW h)


Other charges

((INR Cr)



30 Udipta Energy & Equipment Pvt ltd 2.70 2.29 0.18 - - 7.98 1.82 7.98 1.82 7.98

31 Glatt 1.62 1.66 0.19 - - 5.67 0.94 5.67 0.94 5.67

32 Welspun 2 8.10 12.91 0.05 - - 8.64 11.15 8.64 11.15 8.64

33 Welspun 1 5.40 5.14 0.13 - - 8.70 4.47 8.70 4.47 8.70

34 Welspun 3 8.10 7.90 0.10 - - 8.56 6.76 8.56 6.76 8.56

35 Response Renewable Energy 5.40 5.34 0.12 - - 5.67 3.03 5.67 3.03 5.67

36 New Swadeshi Sugar Mill,Narkatiaganj

3.78 6.83 0.18 - - 4.60 3.14 4.60 3.14 4.60

37 Harinagar Sugar Mills,Harinagar 5.94 25.52 0.11 - - 5.37 13.70 5.37 13.70 5.37

38 Bharat SugarMills,SidhiwaliaGopalganj

5.94 16.18 0.11 - - 5.07 8.20 5.07 8.20 5.07

39 Lauriya Sugar Mill 10.80 14.96 0.11 - - 5.37 8.04 5.37 8.04 5.37

40 Sugauli Sugar Mill 10.80 12.14 0.21 - - 5.38 6.52 5.38 6.52 5.38

41 Hasanpur Sugar Mills,Samastipur 5.40 5.25 0.50 - - 5.91 3.10 5.91 3.10 5.91

42 Riga Sugar Company Ltd,Sitamarhi 1.62 1.70 0.50 - - 5.88 1.00 5.88 1.00 5.88

43 Tirupati 6.00 5.26 0.32 - - 6.15 3.23 6.15 3.23 6.15

44 Siddhashram Rice Mill Cluster Pvt Ltd

0.54 1.85 0.16 - - 7.41 1.37 7.41 1.37 7.41

45 BDBPL 5.02 0.98 0.13 - - 6.02 0.59 6.02 0.59 6.02

46 Open Market Purchase 2,908.87 0.02 6.24 4.19 1,219.75 4.22 1,226.74 4.22

47 IEX/PXIL - 2,031.48 0.13 0.03 6.24 4.06 824.48 4.09 831.47 4.09

48 JAYPEE NIGRIE - 197.84 0.10 - - 3.07 60.74 3.07 60.74 3.07

49 JPL - 29.21 0.40 - - 2.86 8.37 2.86 8.37 2.86

50 UPPCL - 0.52 0.02 - - 7.02 0.36 7.02 0.36 7.02

51 GMR ETL - 11.79 0.02 - - 3.36 3.96 3.36 3.96 3.36

52 Arunachal - 4.49 - - - 5.26 2.36 5.26 2.36 5.26

53 TATA ETL - 98.86 - - - 4.42 43.66 4.42 43.66 4.42

54 Manikaran Power (Wind) - 397.09 - - - 4.66 185.10 4.66 185.10 4.65

Manikaran Power (Thermal) 7.69 3.87 2.98 3.87 2.98 3.87

55 NEA - 3.96 - - - 5.56 2.20 5.56 2.20 5.56

56 NVVNL - 21.33 - - - 4.54 9.68 4.54 9.68 4.54

57 Adani - 12.45 - - - 4.95 6.16 4.95 6.16 4.95



S. No.



Share allocation

(MW)

Units Purchase

d (MU)


rate (INR/M

U)


Energy Rate

(INR/kW h)


Other charges

((INR Cr)



58 UI- Adjustment - 92.18 - - - 7.56 69.68 7.56 69.68 7.56

59 Sub Total Power Purchase 2,432.10 15,601.22 1.14 1,779.58 2.57 4,002.17 3.77 5,874.15 3.77

60 Transmission charges - - 988.93

61 PGCIL + POSOCO / ERLDC (Transmission Charges)

- - 514.00

62 SLDC Charge 3.09

63 BGCL 116.53

64 BSPTCL 355.32

65 Total Power Purchase 2,432.10 15,601.22 1.14 1,779.58 2.57 4,002.17 4.40 6,863.08 4.40

Less: Power Purchase Adjustment for earlier year

23.38

Power available for sale 2,432.10 15,601.22 1.14 1,779.58 2.57 4,002.17 4.40 6,839.70 4.69



3.9. Transmission charges

3.9.1. Interstate Transmission charges

3.9.1.1. It is submitted that the Petitioner has to pay transmission charges to PGCIL for use of

transmission facilities enabling power drawl from the Eastern region. The transmission

charges payable to PGCIL are computed based on new transmission pricing mechanism

and the figures for computation for FY 2017-18 and based on actual bills.

3.9.1.2. Further, the Petitioner also incurs POSOCO charges and Open Access charges.

3.9.1.3. The summary of expenses towards PGCIL, POSOCO and ERLDC charges for FY 2017-

18 based on actual audited accounts is given in the table below:

Table 22: PGCIL, POSCO and ERLDC charges

Source Total (in INR Crore)

PGCIL 514.00

POSOCO / ERLDC Charges

3.9.2. Intrastate Transmission charges

3.9.2.1. The charges payable to State Transmission Utility i.e. BSPTCL, BGCL , SLDC based on

actuals for FY 2017-18 is shown below.

Table 23: State transmission charges

Source Total (in INR Crore)

BSPTCL, BGCL & SLDC Charges 474.93

3.9.3. Given the above information, the Hon’ble Commission is therefore requested to approve

the total transmission charges of INR 988.93 Crore (INR 514.00 Cr. + INR 474.93 Cr.) in

true up for FY 2017-18.

3.10. Disallowance of power purchase due to excess Distribution loss

3.10.1. In FY 2017-18, the Petitioner has added around 12% consumers to the consumer base of

FY 2016-17 with increase of around 27% in KJY category. Due to addition in the number

of consumers it is imperative that more effort is required to control the losses due to the

existing consumers and also to ensure that the loss due to addition of the new consumers

should also not exceed the existing level. Even in such a situation, the Petitioner was able

to reduce the actual distribution loss level to 34.80%.

3.10.2. The present trajectory of Distribution Losses aims at 30% losses in FY 2017-18 which is

less than the actual losses of 34.80% of the utility. Also in the light of this fact, it is



pertinent to note that the state of Bihar and SBPDCL have signed a tripartite

Memorandum of Understanding (MoU) of Ujwal Discom Assurance Yojana with the

Ministry of Power, Government of India on 22nd February, 2016. Under UDAY scheme the

Discoms have targeted to reduce the AT&C losses and bring it to the level of 15% by FY

2019-20.

3.10.3. In compliance to the Hon’ble Commission’s directive to increase supply hours, the

Petitioner has increased the hours of supply in both rural and urban areas. Currently, the

utility is providing more than 18-20 hours per day to its rural consumers and around 20-24

hours per day to its urban consumers. The Petitioner is continuously doing efforts to

reduce the loss levels by introducing spot billing, various payment channels etc.

3.10.4. In view of the efforts made by the utility to reduce the losses with increased supply hours

and growth in domestic consumers, the Commission is hereby requested to adopt the

actual distribution loss of 34.80% for FY 2017-18 for calculation of disallowance of power

purchase cost due to excess distribution loss.

3.10.5. It is to be noted that the Discom has received an amount of Rs. 1029 Crore as OFR

funding infused by GoB in terms of equity contribution towards meeting its shortfall in

achieving the AT&C loss target. Since, the fund received is in terms of equity, same

cannot be used for offsetting the disallowance towards excess power purchased above

the approved distribution loss trajectory. Therefore, such amount has not been considered

for calculation of Annual Revenue Requirement for FY 2018-19.

3.11. Capital Investment Plan, Capitalization and Funding

3.11.1. During the year, Petitioner has capitalized INR 959.22 Crores of which INR 767.38 Crore

pertains to CWIP and INR 191.84 Crore is towards new investment in FY 2017-18. As

depicted in the table below, INR 431.18 Crore pertains to grants. These grants were

received under various schemes. Apart from grants, fixed assets are funded through loans

and equities too. The funding through loans amounts to INR. 51.58 Crore and through

equity it is INR 476.46 Crore.

3.11.2. The table given below depicts the audited balance of Capital Works in Progress (CWIP),

Gross Fixed Assets (GFA) and Grants etc. for FY 2017-18.

Table 25: CWIP, Capex, Capitalization and Funding (in INR Crore)

S. No. Particulars Approved in MYT Order dated 21.03.2016

Approved in APR FY 2017-18




S. No. Particulars Approved in MYT Order dated 21.03.2016



1 Opening CWIP 3167.41 2888.25 2310.72

2 New Investment 3143.15 5647.15 1757.25

3 Less: Capitalization (4+5) 3155.27 3386.95 959.22

4 CWIP 1583.70 2709.52 767.38

5 New Investment 1571.57 677.43 191.84

6 Closing CWIP (1+2-3) 3155.29 5148.45 *3108.75

7 Funding

8 CWIP Capitalization(9+10+11) 1583.70 2709.52 767.38

9 Grant 1341.77 1334.69 344.94

10 Equity 146.91 806.61 381.17

11 Loan 95.02 568.22 41.26

12 New Investment (13+14+15) 1571.57 677.43 191.84

13 Grant 719.87 333.69 86.24

14 Equity 426.15 197.59 95.29

15 Loan 425.55 146.15 10.32

16 Total Capitalization (8+12) 3155.27 3386.95 959.22

17 Total Grant (9+13) 2061.64 1668.38 431.18

18 Total Equity (10+14) 573.06 1004.20 476.46

19 Total Loan (11+15) 520.57 714.37 51.58

*Correction entry amounting to INR 1.08 Crore for repaired transformer wrongly taken at current value of transformer in the previous financial year has been rectified

3.11.3. The Hon’ble Commission is therefore requested to approve the actual capitalization plan

for FY 2017-18. In addition, the Petitioner can furnish the adequate supporting document

validating the amounts if required by the Commission.

3.12. Gross Fixed Assets

3.12.1. The Petitioner hereby submits the computation of Gross Fixed Assets considering the

opening GFA as per Audited Annual Accounts.

3.12.2. The details of the opening and closing GFA for FY 2017-18 have been provided in the

table below:

Table 26: Gross Fixed Assets (in INR Crore)

S. No. Particulars Approved in MYT Order

dated 21.03.2016



1 Opening GFA 9855.31 6854.91 5667.06

2 Additions during the year 3155.27 3386.95 959.22

3 Add : IDC 33.84 -- 0

4 Add: Employee cost capitalized 14.30 -- 0

5 Closing GFA (1 to 4) 13058.71 10241.86 6626.28



3.12.3. The Petitioner requests the Hon’ble Commission to approve closing Gross Fixed assets

as INR 6626.28 Crore as per the audited accounts for FY 2017-18.

3.13. Depreciation

3.13.1. As per regulation 23 of Bihar Electricity Regulatory Commission (Multi Year Distribution

Tariff) Regulations, 2015, the Petitioner is claiming the depreciation expense after

deducting the value of grant, depreciation on land and consumer contribution amortized in

the ratio of depreciation

3.13.2. Depreciation is an important cost component for any Distribution Licensee. The Petitioner

in the below table submits the depreciation for FY 2017-18 on the various assets within

GFA.

Table 27: Depreciation (in INR Crore)


dated 21.03.2016

Approved in APR FY 2017-

18


1 Opening GFA 9855.31 - 5667.06

2 Less: Value of land 1517.37 - 1528.55

3 Net opening GFA (1-2) 8337.95 5326.36 4138.51

4 Additions during the year (excl. value of land)

3155.27 3373.57 951.59

5 IDC 14.30 -- --

6 Expenses capitalized 33.84 -- --

7 Closing GFA (3+4+5+6) 11541.35 8699.93 5090.10

8 Average GFA (3+7)/2 9939.65 7013.15 4614.31

9 Weighted average rate of depreciation 4.63% 4.18% 5.11%

10 Depreciation fr the year (8*9) 460.21 293.21 235.94

11 Opening Grants 8645.32 3848.37 2547.41

12 Grants during the year 2061.64 1661.79 431.18

13 Total Grants (11+12) 10706.96 5510.16 2978.58

14 Average Grants (11+13)/2 9676.14 4679.27 2762.99

15 Weighted average rate of Depreciation 4.63% 4.18% 5.43%

16 Depreciation for GFA on Grants (14*15) 448.01 195.64 149.90

17 Depreciation for GFA on Loans (10-16) 12.20 97.57 86.04

3.13.3. The depreciation expense incurred by the Petitioner in FY 2017-18 amounts to INR

235.94 Crore of which INR 149.90 Crore pertains to amortization of grants in the ratio of

depreciation. The Petitioner is claiming depreciation by reducing the value of grants and

consumer contribution amortized in FY 2017-18.

3.13.4. The Petitioner requests the Hon’ble Commission to approve depreciation as per the

actuals i.e. INR 86.04 Crore for FY 2017-18.



3.14. Other finance charges

3.14.1. Other finance charges include power factor rebate, interest to suppliers, bank charges etc.

The below table captures the various head wise other finance charges as incurred for FY

2017-18:-

Table 28: Other Finance charges (in INR Crore)


dated 21.03.2016



1 Discount to consumers for timely payment of Bills (Rebate)

36.45

2 Power Factor Rebate 0.00

3 Other Bank Charges 4.13

4 Other finance charges as per base year 51.93 17.33

5 Escalation percentage 10% 10%

6 Add: increase in finance charges 5.19 1.73

7 Other finance charges 57.12 19.06 40.57

3.14.2. The Petitioner requests the Hon’ble Commission to approve INR 40.57 Crore towards

Other Finance charges for FY 2017-18.

3.15. Operation & Maintenance charges

3.15.1.1. As per Regulation 22 of Bihar Electricity Regulatory Commission (Multi Year Distribution

Tariff) Regulations, 2015 the Petitioner has claimed O&M expenses. Operation and

Maintenance charges comprises of Employee expenses, A&G expenses, R&M expenses

and Holding company expenses. The Petitioner has furnished the details of O&M

expenses in the below paragraphs. The Hon’ble Commission is requested to consider the

same while truing up for FY 2017-18.

3.15.2. Employee Expenses:

3.15.2.1. The employee expenses further primarily include costs towards salaries, Dearness

Allowances, bonus, staff welfare and medical benefits, leave travel and earned leave

encashment, and the terminal benefits in the form of pension, gratuity etc. The details of

actual employee expenses as per the audited accounts for the

FY 2017-18 is shown below:

Table 29: Employee expenses (in INR Crore)

S. No.

Particulars Approved in T.O. dated 21.03.2016

Approved in Review for FY 2017-18 (RE)

Actuals for FY 2017-18

1 Terminal Benefits *70.89

2 Employee Expenses 271.66 288.21 316.90

3 Inflationary index 5.25% 3.24%



S. No.

Particulars Approved in T.O. dated 21.03.2016

Approved in Review for FY 2017-18 (RE)

Actuals for FY 2017-18

4 Add: Inflationary increase 14.26 9.34

5 Pay revision impact @15% (on 1) -- 43.23

6 Employee Cost 285.92 340.78

7 Less: Capitalized 14.30

8 Total Employee Cost (4-5) 271.62 340.78 387.79

*Out of INR 86.96 Crore expense towards terminal benefits INR 16.07 Crore has been deducted as terminal benefit recoverable from GoB

3.15.2.2. As per the audited accounts the employee expenses incurred by the Petitioner is INR

387.79 Crore. The Hon’ble Commission is therefore requested to approve the same as

per the audited accounts.

3.15.3. Repairs and maintenance:

3.15.3.1. The R&M expenses primarily include costs related to repair of different class of fixed

assets etc. The detailed R&M expenses for the FY 2017-18 is shown below:

Table 30: R&M expenses (in INR Crore)

Sl.

No.

Particulars Approved in MYT Order dated 21.03.2016

Approved in RE for FY 2017-18


1 Plant and Machinery 9.37

2 Building 2.48

4 Hydraulic Works & Civil Works 2.22

5 Line Cable Net Works 84.43

6 Vehicles 0.00

7 Furniture and Fixture 0.02

8 Office Equipment 0.18

9 Opening GFA 9855.31 6854.91 98.71

10 K factor 1.50% 1.53% -

11 R & M expenses 147.83 104.88 98.71

3.15.3.2. As per the audited accounts the R&M expense incurred by the Petitioner is INR 98.71

Crore. The Hon’ble Commission is requested to approve the same as per the audited

accounts.

3.15.4. Administrative expenses:

3.15.4.1. Administration and General expenses mainly comprise costs towards rent charges,

telephone and other communication expenses, professional charges, conveyance and

travelling allowances and other debits. The detailed A&G expenses for the FY 2017-18 is

shown below:

Table 31: A&G expenses (in INR Crore)




dated 21.03.2016

Approved in RE FY 2017-

18


1 Rent, rates & taxes 0.83

2 Insurance 2.75

3 Telephone, postage & Telegrams 2.93

4 Consultancy fees 1.18

5 Technical fees 1.66

6 Conveyance & travel expenses 11.61

7 Electricity & Water charges 8.46

8 Freight 0.77

9 Other material related expenses 4.45

10 Compensation 0.29

11 Any other expenses 38.51

12 A&G expenses 47.93 56.62 73.42

13 Inflationary index 2.63% -

14 Inflationary increase 1.26 -

15 A&G expenses 49.20 56.62 73.42

3.15.4.2. As per the audited accounts, the A&G expense incurred by the Petitioner is INR 73.42

Crore. The Hon’ble Commission is therefore requested to approve the same as per the

audited accounts.

3.15.5. Allocation of holding cost:

3.15.5.1. The allocation of the Holding company expenses for FY 2017-18 as per the provisions of

the Transfer Scheme 2012, and based on the actual audited accounts has been tabulated

below:

Table 32: Holding cost (in INR Crore)




Holding company expenses 7.02 5.99 10.68

3.15.5.2. It is requested that the Hon’ble Commission approve the above holding expenses of INR

10.68 Crore as a part of O&M expenses.

3.15.6. Gist of O&M expenses: The following table captures the total O&M expenses incurred by

Petitioner in the FY 2017-18:-

Table 33: O&M expenses (in INR Crore)


dated 21.03.2016



1 Employee cost 285.92 340.78 387.79

2 R&M expenses 147.83 104.88 98.71

3 A&G Expenses 49.20 56.62 73.42

4 Holding company expenses 7.02 5.99 10.68




dated 21.03.2016



5 Total O& M cost 489.98 508.27 570.61

3.15.7. The Hon’ble Commission is therefore requested to approve INR 570.61 Crores as O&M

expenses for FY 2017-18.

3.16. Interest on working capital

3.16.1. The clause 26 of BERC (MYT) Regulations, 2015 with regard to Interest on Working

Capital is as follows:

“The Distribution Licensee shall be allowed interest on estimated level of working

capital for the financial year, computed as follows:

a) O&M expenses for one month

b) Two months equivalent of expected revenue

c) Maintenance spares @ 40% of R&M expenses for one month:

Less:

(j) Power purchase cost, transmission charges and load dispatch charges of one

month

(ii) Depreciation, return on equity and contribution to contingency reserves

(iii) Security deposits from consumers, if any.

Provided that the interest on working capital shall be on normative basis and rate of

interest shall be equal to the State Bank Advance Rate (SBAR) as of the date on

which petition for determination of tariff is accepted by the Commission.

Provided further that interest shall be allowed on consumer security deposits and

security deposits from Distribution System users at the Bank Rate as of the date on

which the petition for determination of tariff is accepted by the Commission.

Provided further that if the State Government is providing resource gap grant or

subsidy, working capital shall be reduced by that amount.” [Emphasis Supplied]

3.16.2. It can be observed from above provision that the BERC (Multi Year Distribution Tariff)

Regulations, 2015 had a provision of considering the O&M expense of one month for

calculation of Interest on Working Capital. The Hon’ble Commission vide its notification

dated 30.06.2017 issued Bihar Electricity Regulatory Commission (Multi Year Distribution

Tariff) (First Amendment) Regulations, 2017 in which the formula for calculation of Interest

on Working Capital was amended as follows and O&M cost of one month which was a

part of earlier Regulations was removed:

“The Distribution Licensee shall be allowed interest on estimated level of working capital for the financial year, computed as follows: a) Two months equivalent of expected revenue b) Maintenance spares@40% of R&M expenses for one month: Less: (i) Power purchase cost, transmission charges and load dispatch charges of one month



(ii) Depreciation, return on equity and contribution to contingency reserves equivalent to two months (iii) Security deposits from consumers, if any

Provided that the interest on working capital shall be on normative basis and rate of interest shall be equal to the State Bank Advance Rate (SBAR) as of the date on which petition for determination of tariff is accepted by the Commission.

Provided further that interest shall be allowed on consumer security deposits and security deposits from Distribution System users at the Bank Rate as of the date on which petition for determination of tariff is accepted by the Commission.

Provided further that if the State Government is providing resource gap grant or subsidy, working capital shall be reduced by that amount.”

3.16.3. The first amendment to the MYT Regulations specify that it shall be applicable from the

date of its notification i.e. 30.06.2017. Subsequently the Hon’ble Commission in its Tariff

Order has calculated the Interest on Working Capital as per amended Regulations for FY

2018-19 as well as for FY 2017-18. The Commission has issued the Tariff Order for FY

2018-19 on 21.03.2018, which became effective from 01.04.2018 i.e. after expiry of FY

2017-18. The Hon’ble Commission has changed its methodology for calculation of Interest

on working Capital retrospectively by making an amendment to the Regulations during the

year for which the Tariff and ARR has already been determined by the Commission. It is a

gross violation of the MYT Tariff Order dated 21.03.2016 and MYT Distribution Tariff

Regulations, 2015. Therefore the Commission is requested to calculate the Interest on

Working Capital for FY 2017-18 as per the applicable Regulations i.e. BERC (Multi Year

Distribution Tariff) Regulations, 2015.

3.16.4. The Petitioner would like to submit that it has arrived at the working capital requirement

according to the applicable norms for Distribution function as provided in the BERC (Multi

Year Distribution Tariff) Regulations, 2015, the calculation for which has been captured in

the following table:

Table 34: Interest on working capital (in INR Crore)

S. No.



18


1 O&M expenses (1 month) 39.64 -- 47.55

2 Two months equivalent expected revenue 1457.06 1256.32 1,328.48

3 Maintenance spares @40% of R&M expenses for one month

4.93 3.50 3.29

4 Sub-total (1+2+3) 1501.62 1259.81 1,379.32

5 Less:

(i) Power purchase cost, transmission charges and load dispatch charges of one month

683.06 554.25 569.98

(ii) Depreciation, return on equity and contribution to contingency reserve

20.27 48.98 37.94

(iii) Grant received from the State Govt. for power purchase and other O&M expenses

433.16 -- --

(iv) Security Deposit from consumers -- 477.74 418.24



S. No.



18


6 Sub-total (5(i)+5(ii)+5(iii)+5(iv)) 865.90 1080.97 1,026.16

7 Net working capital requirement (4-6) 635.72 178.85 353.17

8 Rate of interest % 14.75% 14.05% 14.05%

9 Interest on working capital (7*8) 93.77 25.13 49.62

3.16.5. The Petitioner has considered O&M expenses equivalent to one month amounting to INR

47.55 Crore according to the above mentioned Regulation. Also, the Petitioner would like

to submit that for calculating the maintenance spares, 40% of R&M expense for one

month to arrive at an amount of INR 3.29 Crore. Two months equivalent revenue

requirement deducted by non-tariff income has been considered for calculation of gross

working capital of INR 1,379.32 Crore.

3.16.6. The Gross working capital requirement is then reduced by opening Security deposits from

consumers in FY 2017-18 and Depreciation amounting to INR 418.24 Crore and INR

37.94 Crore respectively. The power purchase cost inclusive of transmission charges is

there by reduced by one month amounting to INR 569.98 Crore. Finally, an interest rate

@ 14.05% at the SBAR as on 01.04.2017 has been taken on this quantum of working

capital loan requirement.

3.16.7. Therefore, the Hon’ble Commission is requested to kindly approve the interest on working

capital loan i.e. INR 49.62 Crore for FY 2017-18.

3.17. Return on Equity

3.17.1. As per regulation 27 of the BERC MYT regulations 2015, Return on Equity shall be

calculated as follows:-

(a) “Return on equity shall be computed on 30% of the capital base or actual equity,

whichever is lower:

Provided that assets funded by consumer contribution, capital subsidies/ grants

and corresponding depreciation shall not form part of the capital base. Actual

equity invested in the Distribution Licensee as per book value shall be considered

as perpetual and shall be used for computation in this Regulation:

(b) The return on the equity invested shall be allowed from the date of start of

commercial operation:

(c) The project which will be commissioned w.e.f. 01.04.2016 will be allowed RoE of

15.5% and if project is completed in schedule period 0.5% incentives in form of

RoE will be allowed.”

3.17.2. It is to be noted that the actual equity infused in the company is greater than the norm of

30% of capital base. However in line with the above cited regulation, the return on equity

is calculated on 30% of the capital base only.



Table 35: Return on equity (in INR Crore)


dated 21.03.2016


18

Claimed in True Up for FY

2017-18

1 Closing equity to end of 31.03.2016 638.06 574.36

2 Rate of return on equity % 14.00% 14.00%

3 Return on Equity 89.33 80.41

Equity with effect from 1st April 2016

4 Opening equity 258.97 315.65

5 Equity Addition during the year 515.57 158.41

6 Closing Equity 774.54 474.07

7 Average Equity 43.65 516.76 394.86

8 Rate of return on equity with effect from 1.4.2016

15.50% 15.50% 15.50%

9 Return on Equity 67.53 80.10 61.20

10 Total Return on Equity 178.41 169.43 141.61

3.17.3. In view of the above, the Petitioner requests the Hon’ble Commission to approve INR 141.61

Crore towards Return on Equity.

3.18. Interest on Loans

3.18.1. Interest on loans includes loans against schemes, central and state government loans, Bank

Overdrafts, public bonds etc.

3.18.2. For computing the interest rate on the normative debt, the weighted average rate of actual

loan portfolio is calculated as 12.71%. The table provided below captures the calculation of

weighted average rate of interest for FY 2017-18

Table 36: Interest on Loans Claimed for FY 2017-18 (in INR Crore)

Sl. No.

Particulars Opening Balance

Rate of Interest

Addition during

the year

Repayment during the year

Closing balance

Amount of interest paid

1 REC (RGGVY) Term Loan 65.88 11% 16.31 - 82.19 5.69

2 REC (R-APDRP) Term Loan 349.26 10.40% - - 349.26 36.32

3 PFC (R-APDRP) Term Loan 177.26 9% - 1.85 175.41 15.88

4 PFC (APDRP) Term Loan 4.30 9% - 4.30 - 0.27

5 PFC (BRGF) Term Loan 140.00 10% - 140.00 - 12.18

6 REC (BRGF) Term Loan - 10% 125.00 125.00 - 2.99

7 State Govt.-Non-Plan Loan 79.07 13% 24.02 73.22 29.87 12.86

8 BSPHCL (ADB) Loan 43.50 13% - 40.85 2.65 24.09

9 Canara Bank Term Loan 56.57 10% - - 56.57 52.36

10 Working Capital Loan 341.93 10% 790.00 526.16 605.77

Total 1,257.77 955.33 911.38 1,301.72 162.64

Average Loan during the year

1279.75

Weighted average rate of Interest

12.71%



3.18.3. The Petitioner has considered INR 86.04 Crore claimed under depreciation as normative

repayment for the period. The below table captures interest expense against loans as

incurred for FY 2017-18:-

Table 37: Interest on Loans Claimed for FY 2017-18 (in INR Crore)

S. No. Particulars Approved in MYT order

dated 21.03.2016

Approved for FY 2017-18

(RE)

Claimed in True Up for FY

2017-18

1 Opening Loan 925.76 1217.06 2,183.76

2 Additions during the year 520.57 1203.00 369.63

3 Normative Repayment 12.20 97.58 86.04

4 Closing Loan 1434.13 2322.48 2,467.35

5 Average Loan 1179.95 1769.77 2,325.55

6 Interest Rate / Weighted Average Rate 8.20% 5.35% 12.71%

7 Interest Charges 96.76 94.68 295.55

3.18.4. The Petitioner therefore requests the Hon’ble Commission to approve Interest on loan of

INR 295.55 Crore for FY 2017-18.

3.19. Interest on Consumer Security Deposit

3.19.1. Section 47(1) (a) of the Electricity Act, 2003 specifies that any person who requires a

supply of electricity, should provide a reasonable amount of security deposit in respect of

the electricity supplied to such person. The BERC Supply Code Regulations 2007

specifies that the Distribution Licensee shall pay interest at the RBI Bank rate, applicable

on security deposits taken from the consumers. And the interest amount of the previous

financial year, shall be adjusted in the energy bill issued in May/June of each financial

year, depending on the billing cycle.

3.19.2. The Petitioner would like to submit that as per the regulation, interest on consumer’s

security deposit is paid to HT and LT consumers and the Petitioner possesses the details

of the same. A summary of the same has been represented below.

Table 38: Interest on Consumer Security Deposit (in INR Crore)

Sl. No.

Particulars Approved in

MYT order dated

21.03.2016


Actual for FY 2017-

18

1 Opening Security Deposit 393.16 418.24 418.24

2 Addition / (Deletion) during the year 40.00 59.50 94.74

3 Closing Security Deposit 433.16 477.74 512.98

4 Average Security Deposit (1+3)/2 413.16 447.99 465.61

5 RBI Bank Rate 7.50% 6.25% 6.75%

6 Interest on Security Deposit 30.99 28.00 31.43



3.19.3. The Hon’ble Commission is therefore requested to approve INR 31.43 Crore towards

interest on consumer security deposits, as per the audited accounts for FY 2017-18.

3.20. Provision for RPO

3.20.1. In FY 2017-18 the Petitioner has made provision of INR 151.17 Crore for meeting its RPO

obligations. The Petitioner requests Hon’ble Commission to approve the same towards

Deposit for RPO obligation. The details of the target and shortfall for meeting the RPO

obligation is provided in the table below:

Period SOLAR(RPO) NON-SOLAR(RPO)

Target (MU)

Achievement ( MU)

Shortfall (MU)

REC Purchase

d

Amount to be

deposited ( Rs.

Cr.)

Target (MU)

Achievement (MU)

Shortfall (MU)

REC Purchased (MU)

Amount to be

deposited ( Rs. Cr.)

FY 2010 to FY

2013(BSEB PERIOD

15.73 (NBPDCL&SBPDCL)

0 15.73 (NBPDC

L & SBPDCL)

yes 21.08Cr. 7.38Cr.NBPDCL 13.70Cr.SBPDCL

435.91 (NBPDC

L& SBPDCL

)

344.72 91.19 yes not required

2013-14 23.74 0 23.74 yes 13.77Cr. 189.95 132.6 57.35 yes 18.93Cr.

2014-15 42.17 0 42.17 yes 24.46Cr. 238.99 154.1 84.89 yes 28.02Cr.

2015-16 70.87 3.83 67.04 yes 38.88Cr. 318.91 122.73 196.18 yes 64.74Cr

2016-17 128.22 52.66 75.56 yes NA 427.4 123.69 303.71 387.27

NA

2017-18 213.82 92.44 121.38 yes NA 522.68 547.03 (24.35) 149.28

NA

Note: In view of Regulation 5.1 of the BERC and as per BERC Order dated 23.02.2018 non-solar RECs were purchased by

SBPDCL to meet the required Renewable Purchase obligation (Solar and Non Solar) for the FY 2017-18 as Hon’ble Supreme Court banned the trading of Solar RECs.

3.21. Non-Tariff income

3.21.1. The Petitioner presents the non-Tariff income earned by it in FY 2017-18:-

Table 41: Non-Tariff Income (in INR Crore)

Particulars Approved in MYT order

dated 21.03.2016



Interest Income

Interest on Advances to Suppliers/Contractors 0.41

Interest on Saving Accounts 9.77

Sub-total 10.18

Other Income

Delayed Payment Surcharge from Consumers 136.69

Income From Interest on TDS Refund 0.77

Income from trading 0.05

Miscellaneous Receipts 26.99

Rebate and Discount Received 0.09




dated 21.03.2016



Incentive for timely payment of power purchase bills 25.83

Sub-total 190.42

Others

Meter Rent/ Service Line Rental 75.44

Miscellaneous Recoveries 66.06

Sub-total 269.50 123.22 141.49

Rate of Increase 10.00% 10.00% -

Increase in Non-Tariff Income 26.95 12.32 -

Total Non-tariff income 296.45 135.54 342.09

Delayed Payment Surcharge from Consumers - - 136.69

Principal amount on which DPS Charged - - 759.40

Interest Rate of funding DPS - - 14.05%

Interest on funding Principal - - 106.70

Net Non-Tariff Income 296.45 135.54 235.40

3.21.2. It is prayed to the Hon’ble Commission to consider INR 235.40 Crore as Non-Tariff

income during FY 2017-18.

3.22. Revenue from Sale of Power at Existing Tariff

3.22.1. Following is the category wise revenue based on the tariff approved for FY 2017-18.

Table 42: Revenue from sales of power at existing tariff

Sl. No.

Consumer Category Revenue form Sale of energy (INR in Crore)

Subsidy Receivable from State Govt.

(INR in Crore)

1 Domestic 2,426.94 701.97

Kutir Jyoti - BPL Consumer

253.25 132.40

Domestic – I 683.52 330.56

Domestic – II 1,490.17 239.00

2 Commercial 746.87 33.24

Non-Domestic – I 24.69 8.84

Non-Domestic – II 722.19 24.40

3 Public Lighting 28.88 -

Street Light – I 4.45 -

Street Light – II 24.43 -

4 Irrigation 194.27 96.01

IAS – I 128.50 96.01

IAS – II 65.77 -

5 Public Water Works 66.09 0.00 6 Industrial LT 242.67 6.66

LTIS – I 138.72 3.46

LTIS – II 103.95 3.19

7 Industrial HT 1,218.33 51.46

HTS – I 456.53 11.85

HTS – II 273.36 12.44



Sl. No.

Consumer Category Revenue form Sale of energy (INR in Crore)

Subsidy Receivable from State Govt.

(INR in Crore)

HTS – III 117.79 5.47

HTSS 370.65 21.70

8 Railway 427.48 -

9 DF – Bhagalpur & Gaya

365.98 -

10 Total 5,717.51 #889.34

Consumer Ledger Adjustment

*679.98

Net Revenue from Sale of Power

5,037.53

# Subsidy included in the total revenue from sale of power *Adjustment of consumer billed on wrong meter reading etc. has been made for INR 679.98 Crore and shown under the head of Bad Debts Adjustment in the Audited Accounts for FY 2017-18. Actually if a consumer billed on hypothetical high units thereby reflecting increase in sales when wrong units corrected it should have been booked by adjusting the earlier sales units. Accordingly adjustments made in consumer bills have been adjusted with revenue from sale of power. 3.22.2. The Petitioner requests the Hon’ble Commission to kindly approve the revenue from sale

of power as submitted above.

3.23. Net ARR and revenue gap for FY 2017-18

3.23.1. The Gross ARR for the distribution company consists of the power purchase costs,

interest and finance costs, O&M costs, depreciation and interest on working capital. These

costs are then adjusted for Non-Tariff Income and other Income. Following is the total

revenue requirement for FY 2017-18 against allocation from total approved revenue

requirement by the Hon’ble Commission for FY 2017-18.

Table 43: Net ARR and revenue gap for FY 2017-18 (in INR Crore)

Sl. No. Particulars Approved in

MYT order

dated

21.03.2016


18

True-Up for FY 2017-18

1 Power purchase cost 7383.36 5764.17 5,850.77

2 PGCIL & other transmission charges 495.52 436.55 514.00

3 State Transmission charges 317.83 450.23 474.93

4 O&M Expenses

i) Employee Cost 271.63 340.78 387.79

ii) R&M expenses 147.83 104.88 98.71

iii) A&G expenses 49.20 56.62 73.42

5 Share of Holding Company expenses 7.02 5.99 10.68



Sl. No. Particulars Approved in

MYT order

dated

21.03.2016


18

True-Up for FY 2017-18

6 Depreciation 12.20 97.57 86.04

7 Interest and Finance charges 153.88 113.74 336.12

8 Interest on working capital 93.77 25.13 49.62

9 Return on equity 67.53 169.43 141.61

10 Income Tax 0.00 0.00 0.00

11 Interest on security deposit 30.99 28.00 31.43

12 Bad debts (if any) 0.00 0.00 0.00

13 Contingency reserves (if any) 41.88 26.88 0.00

14 Deposit for RPO Obligation 0 53.46 151.17

15 Less: IDC 33.84 - 0.00

16 Total Revenue Requirement 9038.79 7673.43 8,206.30

17 Less: Non-tariff income 296.45 135.54 235.40

18 Less: Expenditure disallowed due to excess T&D losses

1623.50 0.00 0.00

19 Aggregate Revenue Requirement 7118.84 7537.90 7,970.90

20 Revenue from Existing Tariff 4221.12 7321.72 5,037.53

21 Gap / (Surplus) for FY 2017-18 2897.72 216.18 2,933.37

22 Gap / (Surplus) carried forward from FY 2015-16 as per Tariff Order dated

21.03.2018

585.07 585.07

23 Total gap at end of FY 2017-18 801.25 3518.44

3.23.2. The Petitioner requests the Hon’ble Commission to approve INR 3,518.44 Crore as

Revenue gap for FY 2017-18.



4. APR Summary for FY 2018-19

4.1. Preamble

4.1.1. The Petitioner has submitted this instant Tariff Petition for FY 2019-20 which includes

Annual Performance Review (APR) for FY 2018-19. While projecting the APR for FY

2018-19 the Petitioner has considered the actual figures for the first 6 months (i.e. from

April 2018 to September 2018) for components like power purchase, O&M expenses etc.

and pro-rata projections & escalations over previous year has been considered, keeping

in mind the guiding principles defined by the Hon’ble Commission.

4.2. Estimate of category wise number of consumers, connected load and sales for FY

2018-19

4.2.1. Estimate of category wise number of consumers

4.2.1.1. While projecting energy sales for FY 2018-19 the 24x7, Power For All plan, Har Ghar

Bijli and the Saubhagya scheme along with the large scale initiatives taken by Central

Government and the State Government are taken into consideration. These initiatives

aim for the overall development of the power sector in the State. The objective of the

24x7 Power For All initiative is to make 24x7 power available to all households,

industry, commercial businesses, public needs, any other electricity consuming

entity and adequate power to agriculture farm holdings by FY 2018-19.

4.2.1.2. These plans are mainly targeted for rural consumers in KJ, DS-I and IAS-I category

and the growth rate projected under this category is above the normal CAGR growth as

large number of new connections are to be released in the ensuing years. The Petitioner

has also considered 6 months provisional data for revising the growth in number of

consumers for FY 2018-19.

Table 44: Category-wise no. of consumers projected for FY 2018-19

Consumer Category FY 18-19 (APR)

Domestic 5450398

Kutir Jyoti 1834164

Domestic - I 2241723

Domestic - II 1374512

Commercial 358445

NDS-I 59908

NDS-II 298537

Public Lighting 1275

Street Light - I 848




Street Light – II 427

Irrigation 1,12,869

IAS – I 1,08,883

IAS – II 3986

Public Service Connections 2750

Public Water Works 2750

Industrial LT 65103

LTIS – I 61100

LTIS – II 4003

Industrial HT 1823

HTS – I 1688

HTS – II 115

HTS – III 7

HTSS 13

Railway 15

Total 59,92,678

4.2.2. Estimate of Category wise Sales

4.2.2.1. Under the Chief Minister Seven Resolution the Discom is determined to provide

electricity to every household. Discom is also going to avail the facility of wide spread

rural electrification as per Saubhagya Scheme.

4.2.2.2. The Petitioner has projected the category-wise sales based on the CAGR of the previous

years’ data and considering factors like available average consumption per consumer per

month, new consumers to be added, population data, expected conversion of

unauthorized connections, connected load factor and specific growth factors and

wherever the data was incongruous such incongruity was ignored while projecting the

load growth for the ensuing years.

4.2.2.3. The Petitioner submits that the forecast model projects the specific consumption level

(consumption per consumer) appropriate for each customer category. The Petitioner

submits that this forecast is based on expected growth relationships to income and price,

effect of Demand Side Management and impact of hours of service.

4.2.2.4. The Petitioner also submits that the specific consumption level along with the number of

consumers in each category gives the sales figure for that particular sub-category and the

final detailed calculations estimate the connected load for each tariff category. Also, 6

months provisional figure was also used for revising the category wise sales for the above

projected number of consumers for FY 2018-19. The units sold are projected by taking



average consumption per consumer per month and multiplying the same to the projected

number of consumers to arrive at units sold for a year.

Table 45: Category-wise sales (MUs) projected for FY 2018-19


Domestic 7285

Kutir Jyoti- BPL Consumers 1100

Domestic - I 2662

Domestic - II 3523

Commercial 1235

Non-Domestic - I 54

Non-Domestic - II 1182

Public Lighting 42

Street Light - I 13

Street Light - II 29

Irrigation 479

IAS – I 327

IAS – II 152

Public Service Connection 127


Industrial LT 714

LTIS – I 464

LTIS – II 250

Industrial HT 2005

HTS – I 649

HTS – II 385

HTS – III 182

HTSS 790

Railway 579

Total 12,467

4.2.2.5. The Petitioner has calculated the connected load considering average Load per

consumer as per the actuals, CAGR of past years and multiplying it by projected

number of consumers to arrive at the connected load.

Table 46: Category-wise connected load (kW) for FY 2018-19


Domestic 6377369

Kutir Jyoti- BPL Consumers 183416

Domestic - I 2274084

Domestic - II 3919869




Commercial 1162686

Non-Domestic – I 66392

Non-Domestic – II 1096294

Public Lighting 14867

Street Light - I 10,270

Street Light - II 4,597

Irrigation 322042

IAS – I 268822

IAS – II 53220

Public Service Connections 51493


Industrial LT 7,64,265

LTIS – I 542336

LTIS – II 221930

Industrial HT 8,22,415

HTS – I 350758

HTS – II 209687

HTS – III 142625

HTSS 119345

Railway 1,70,200

Total 96,85,338


4.3.1. In FY 2017-18 and FY 2018-19 the Petitioner has planned addition of large number of

rural consumers in view of Chief Minister Seven Resolution Scheme and Saubhagya

Scheme.

4.3.2. Also, in the light of the fact, the state of Bihar and South Bihar Power Distribution

Company Limited (SBPDCL) have signed a tripartite Memorandum of Understanding

(MoU) of Ujwal Discom Assurance Yojana with the Ministry of Power, Government of

India on 22nd February, 2016. The present trajectory of Distribution Losses aims at

22% losses in FY 2018-19 which is far below the actual losses of the utility. In UDAY

scheme the Discoms have targeted to reduce the AT&C losses and bring it to the

level of 15% by FY 2019-20. Due to addition in the number of consumers, especially in

rural and remote areas, it is expected the Distribution Licensee may not be able to

achieve the target for distribution loss.

4.3.3. Therefore, it is prayed to the Hon’ble Commission to consider the losses as per the

actual distribution loss as provided in the table below.



Table 47: Distribution loss

Approved in Tariff Order for FY 2018-19

FY 2018-19 (Projected)

Distribution Losses 22% 29 %

4.4. State Transmission losses

4.4.1. The Petitioner has considered transmission loss of 3.92% as approved by the Hon’ble

Commission in its previous Tariff Order as the State transmission loss. The basis for this figure

is the approved normative loss, as the actual loss incurred during the period between April

2018 and September 2018 is still in the process of getting reconciled.

4.5. Central Transmission Loss

4.5.1. The Petitioner has considered transmission loss of 2.26% as approved by the Hon’ble

Commission in its previous Tariff Order as the Inter-State transmission loss. The

Petitioner requests the Hon’ble Commission to consider the Central transmission loss of

2.26%.

4.6. Power Purchase

4.6.1. The Discoms rely on allocation from central generating stations and state projects for

procuring power for sale in the state. This power has been proposed to be allocated

between North and South Bihar in the proportion as determined by the board resolution

as detailed below.

4.6.2. Bihar State Power Holding Company Ltd (BSPHCL) issued vide its Resolution No.55-

10 dated 14th July 2017 for approval regarding distribution of power purchase

agreement between NBPDCL and SBPDCL. The notification states that,

“RESOLVED THAT Power Purchase & Transmission charges bills are to be admitted and payment by both discoms i.e NBPDCL and SBPDCL in the ratio 46:54 respectively w.e.f.1-4-2017subjected to the final reconciliation of actual consumption” RESOLVED FURTHER THAT Chairman cum Managing Director, BSHPCL are here by authorized for deciding the power consumption ratio subsequently as per the actual consumption of both the DISCOMS based on the average consumption of the last 6 months of power drawal of both the discoms i.e. NBPDCL and SBPDCL”

The Board further ratifies the submission made in attached agenda note

4.6.3. The Copy of above mentioned board resolution regarding power sharing ratio between

DISCOM’s is attached as Annexure.



4.6.4. NHPC, NTPC & PTC: The power purchase for existing sources has been NTPC,

NHPC and PTC has been considered based on the 24 X 7 Power for All (PFA)

projection and recent trends of the power plant. The power purchase is further

segregated into NBPDCL and SBPDCL as per allocation ratio.

4.6.5. New Sources: The power purchase for the new sources has been considered based

on the commissioning status received from generators and CEA reports. Further the

allocation of power from the new projects is in the ratio of 46:54 for NBPDCL & SBPDCL

as per the board resolution.

4.6.6. Taking the realistic point of view currently 250 MW from Mangdechu HEP and 1/3rd of

Contracted capacity (1553 MW) from NPGCL, Nabinagar plants added to the share

allocation as per latest information on Commercial Operational Date (COD) for FY 2018-

19.

4.6.7. Medium/Short Term Sources: The power purchase from these sources are namely

GMR Kamalanga and PTC. An agreement with PTC and PFCCL is executed under

pilot scheme for medium term through PFC consulting limited as Nodal agency and

PTC India Limited as an aggregator for 200 MW.

4.6.8. The Petitioner shall purchase power through short term from MSTC (DEEP

Portal/IEX during the year in any financial year where the quantum and rate of this

short term power purchase shall be within the limit of total quantum and rate of

power purchase approved by the Hon'ble Commission.

4.6.9. Open Market Purchase: Petitioner is currently procuring power from IEX, DB power,

GMR ETL and TATA ETL on the basis of Demand.

4.6.10. Renewable Power Purchase Obligation: It is submitted that Hon’ble Commission

has notified the BERC (Renewable Purchase Obligation, its Compliance and REC

Framework Implementation), Regulations, 2010, BERC (Multi Year Distribution Tariff)

Regulations, 2015 and BERC (Terms and Conditions for Tariff Determination from

Solar Energy Sources) Regulations, 2010. Further there were amendments in both

Regulations wherein the RPO was modified.

4.6.11. The details of RPO to be met by the Petitioner for FY 2018-19 are given in the table

below:

Table 48: Details of RPO to be met for APR

S. No.

Particulars Unit FY 2018-19



S. No.

Particulars Unit FY 2018-19

1 Energy consumption excluding Nepal MU 12,467 2 % of RPO Obligation % 9.25%

Solar % 3.25%

Non-Solar % 6.00%

3 MUs required as per RPO for the year MU 1,153 Solar MU 405 Non-Solar MU 748 4 Solar Energy to be procured during the year MU 113

5 Non-Solar Energy to be procured during the year

MU 159

6 Balance Solar to be procured MU 292

7 Balance Non-Solar to be procured MU 589

4.6.12. The Petitioner has already been drawing solar power from a few sources like SECI,

Welspun, ACME clean tech, Avantika and Azure Power. The Petitioner has also made

PPA with SECI, NTPC and PTC for purchase of renewable power (Solar and Non

Solar) to the tune of 2100 MW till FY 2021-22.

4.6.13. The Petitioner is also taking efforts to tie-up solar power through competitive bid

process. Hence, the Petitioner has considered the quantum as approved by

Hon’ble Commission for FY 2018-19 for solar and Non-solar. The Petitioner submits

that the shortfall may please be allowed to carry forward to next year so as to meet the

total RPO on cumulative basis. As has been the practice in the past, in case the

Petitioner fails to achieve the Solar and Non-solar RPO, it shall maintain a separate

account where the cost of purchase of solar and non-solar power, equivalent to the

quantum of shortfall shall be maintained.

4.6.14. Projections for power purchase: Accordingly the revised projections of power

purchase for FY 2018-19 is tabulated below:

Table 49: Power purchase Allocation projected for FY 2018-19 (in MW)

Name of The Source SBPDCL NBPDCL

Central Sector Stations 2,168.68 1,539.19

Talcher – I ( 2 x 500 MW) 222.72 189.73

Farakka – I & II (1600 MW) 271.28 231.09

Farakka – III (500 MW) 71.60 60.99

Kahalgaon – I (840 MW) 189.86 161.74

Kahalgaon – II (1500 MW) 40.34 34.36

Barh-II 542.07 461.76

Korba 13.50 11.50

Rangit – HEP 11.34 9.66

Teesta - HEP 58.55 49.88




Chukha 43.20 36.80

Tala 140.45 119.65

Barh Stage-I (3 X 660 MW) 0.00 0.00

KBUNL 1 59.40 50.60

KBUNL 2 142.56 121.44

Barauni Stage I 118.80 0.00

Barauni Stage II 0.00 0.00

PFC_ Medium Term 108.00 0.00

Talcher-II (2x500) 0.00 0.00

Arun –III 0.00 0.00

Mangdechhu, HEP, 135.00 0.00

Punatsangchhu & 0.00 0.00

North Karanpura, Jharkhand (3 X 660MW) 0.00 0.00

Darlipalli STPS (4 X 800 MW) 0.00 0.00

TAWANG-I 0.00 0.00

TAWANAG-II 0.00 0.00

TEESTA-IV 0.00 0.00

State Generating Stations 5.40 4.60

Small Hydro (BSHPCL) 5.40 4.60

IPP 289.76 246.84

GMR Kamalanga Energy 127.76 108.84

JITPL 162.00 138.00

JV projects 281.38 239.70

Nabinagar Railway (4 X 250 Mw) 27.00 23.00

Nabinagar Stage-I (3 X 660 254.38 216.70

Nabinagar JV (3 X 660 MW) Stage-II 0.00 0.00

Renewable 137.40 91.60

SECI-Solar 5.40 4.60

SECI-Wind 0.00 0.00

PTC-Wind 0.00 0.00

SECI Solar 0.00 0.00

NTPC Nokh 0.00 0.00

NTPC-Solar 0.00 0.00

ACME Magadh+B5 5.40 4.60

ACME Nalanda 8.10 6.90

Sunmark 5.40 4.60

Avantika 2.70 2.30

AZURE 5.40 4.60

Udipta Energy & Equipment Pvt ltd 2.70 2.30

Glatt 1.62 1.38

Welspun 2 8.10 6.90

Welspun 1 5.40 4.60

Welspun 3 8.10 6.90

Response Renewable energy 5.40 4.60




ALFA INFRAPOP 8.10 6.90

TIRUPATI SUGAR 5.40 4.60

New Swadeshi Sugar Mill,Narkatiaganj 3.78 3.22

Harinagar Sugar Mills,Harinagar 5.94 5.06

Bharat SugarMills,SidhiwaliaGopalganj 5.94 5.06

Lauriya Sugar Mill 10.80 9.20

Sugauli Sugar Mill 10.80 9.20

Hasanpur Sugar Mills,Samastipur 5.40 4.60

Riga Sugar Company Ltd,Sitamarhi 1.62 1.38

Siddhashram Rice Mill Cluster Pvt Ltd 0.54 0.46

BDBPL 1.62 1.38

Total 2,882.63 2,121.93

4.6.15. For Projecting the Power Purchase Quantum for FY 2018-19, The Petitioner has considered

the actual Power Purchase quantum for the period April to September 2018 and projected

for remaining months based on the following methodology.

i. Share allocation has been considered as actuals of April 2018 to September 2018.

ii. The Plant Load Factor (PLF) for each plant has been calculated on actual basis of

FY 2017-18 and then Petitioner has considered normative PLF and same has been

taken for the next six months of FY 2018-19 from October 2018 to March 2019.

iii. Normative Plant Load Factor Plant (PLF) provided by Central Electricity Regulatory

Commission (CERC) for the thermal and hydro plants and the auxiliary

consumptions specified for plants. For the state plants PLF highest among the PLF

norms specified by BERC and the plant wise auxiliary consumption determined by

BERC for thermal, and biomass has been considered. For the solar plants highest

among the CUF of 19%. The normative PLF and Auxiliary consumptions

considered for FY 18-19 are attached in the Annexure B.3

iv. Actual Plant Load Factor (PLF) of the thermal, hydro, biomass and solar plants in

the previous financial year i.e. FY 2017-18

v. Considering the PLF as mentioned above and using the power purchase allocation

data mentioned in the above table total number of units purchased were

calculated from every source/ plant for every month separately.

vi. Actual PLF for first six months of FY 2018-19 and PLF’s considered for last six



months of FY 2018-19 shall be provided if required

4.6.16. The actual power purchase Quantum for the first six months of FY 2018-19 is shall

be provided on request.

4.6.17. Total power purchase: The month wise projections data for the months of

October 2018 to March 2019 is added to the actuals of April 2018 to September

2018. The total power purchase (MU) is therefore captured in the below table.

Table 50: Total power purchase for APR (in MU)

Name of The Source Share allocated (MW) for FY

2018-19

Units purchased (MU) for FY 2018-19

Central Sector Stations 2,049.88 11,752.70

Talcher – I ( 2 x 500 MW) 222.72 1,540.88

Farakka – I & II (1600 MW) 271.28 1,739.13

Farakka – III (500 MW) 71.60 491.41

Kahalgaon – I (840 MW) 189.86 1,238.75

Kahalgaon – II (1500 MW) 40.34 285.77

Barh-II 542.07 3,734.64

Korba 13.50 97.05

Rangit – HEP 11.34 95.65

Teesta - HEP 58.55 321.40

Chukha 43.20 272.10

Tala 140.45 374.09

KBUNL 1 59.40 308.94

KBUNL 2 142.56 899.32

PFC_ Medium Term 108.00 132.58

Mangdechhu, HEP, 135.00 220.97

State Generating Stations 5.40 3.35

Small Hydro (BSHPCL) 5.40 3.35

IPP 289.76 1,718.62

GMR Kamalanga Energy 127.76 928.06

JITPL 162.00 790.55

JV projects 281.38 555.34

Nabinagar Railway (4 X 250 Mw) 27.00 141.11

Nabinagar Stage-I (3 X 660 254.38 414.23

Nabinagar JV (3 X 660 MW) Stage-II - -

Renewable 123.66 268.97

SECI Solar 5.40 9.10

ACME Magadh 5.40 8.68

ACME Nalanda 8.10 12.68

Sunmark 5.40 8.62

Avantika 2.70 3.08

AZURE 5.40 7.00



Name of The Source Share allocated (MW) for FY

2018-19

Units purchased (MU) for FY 2018-19

Udipta Energy & Equipment Pvt ltd 2.70 3.90

Glatt 1.62 2.67

Welspun 2 8.10 12.62

Welspun 1 5.40 8.39

Welspun 3 8.10 12.81

Response Renewable Energy 5.40 8.68

ALFA INFRAPOP 8.10 14.68

TIRUPATI SUGAR 5.40 12.80

New Swadeshi Sugar Mill,Narkatiaganj 3.78 10.13

Harinagar Sugar Mills,Harinagar 5.94 32.63

Bharat SugarMills,SidhiwaliaGopalganj 5.94 26.74

Lauriya Sugar Mill 10.80 26.64

Sugauli Sugar Mill 10.80 25.47

Hasanpur Sugar Mills,Samastipur 5.40 14.02

Riga Sugar Company Ltd,Sitamarhi 1.62 3.84

Siddhashram Rice Mill Cluster Pvt Ltd 0.54 1.13

BDBPL 1.62 2.66

Open Market Purchase 4,293.36

IEX/PXIL - 3,700.54

Manikaran Power - 80.10

KSEB- Short Term - 66.44

Tata Power - Short Term - 88.43

PTC-Short Term - 357.85

Sub Total Power Purchase 2,750.09 18,592.34

4.6.18. The petitioner has arrived at a power purchase of 18,592.34 MU for FY 2018-19.

4.7. Energy Balance

4.7.1. Based on above discussed elements such as sales, losses & power availability, the

revised projected energy balance for FY 2018-19 is as under –

Table 51: Energy Balance for APR FY 2018-19

Sl No Particulars Unit Approved by Commission for

FY 2018-19

FY 2018-19 Current Year

(RE)

A Energy Requirement

1 Energy sales MU 12284.74 12,467

2 Less: Inter-state sales, if any

MU 0 -

3 Energy sales excluding Inter-state sales, if any

MU 12284.74 12,467

4 Distribution Loss % 22% 29%



Sl No Particulars Unit Approved by Commission for

FY 2018-19

FY 2018-19 Current Year

(RE)

5 Add: Distribution Loss MU 3464.93 5,092

6 Total energy required at Distribution periphery

MU 15749.67 17,559

7 Add: Inter-state sales, if any MU 0 0

8 Total energy required at Distribution periphery including Inter-state sales

MU 15749.67 17,559

9 State Transmission Loss % 3.92% 3.92%

10 Add: State Transmission Loss

MU 642.58 716

11 Total energy required at State Transmission periphery

MU 16392.24 18,275

B Energy Available

1 Power Purchase from CGS, SGS, IPPs/JVs, Renewables and others

MU 16,706.38 18.909

2 Power Purchase from CGS,IPPs/JVs

MU 13,900.02 14,027

3 Inter-state Transmission Loss (%)

% 2.26% 2.26%

4 Inter-state Transmission Loss (MUs)

MU 314.14 317

5 Net Power Purchase from CGS, IPPs & JVs

MU 13585.88 13,710

6 Power Purchase from SGS and others

MU 2,806.36 4,566

7 Energy available at State Transmission Periphery

% 16,392.24 18,275

10 Energy Surplus/(Deficit) at State Periphery

MU 0.00 0.00

4.7.2. We humbly request the Hon’ble Commission to a pprove the aforementioned

revised energy balance for FY 2018-19.


4.8.1. The power purchase cost mainly comprises of fixed charges and energy charges for

two part tariff stations i.e. NTPC, NHPC & PTC in case of Petitioner. The Petitioner has

considered the actual energy charges and fixed cost for these power stations based on

actual 12 months data for FY 2017-18 and actual 6 months information from April 2018 to

September 2018.The average power purchase cost as mentioned below.

i. Petitioner has considered the new plants whose COD is in the next 6 months i.e.

October 2018 to March 2019.

ii. The power purchase cost projections have been undertaken by considering the average



of actual fixed cost and fuel costs respectively for the previous 6 months.

iii. The fuel costs have been projected by escalating the average of actual fuel costs of

the FY 2017-18 data by 4% percent for FY 2019-20

4.8.2. The Petitioner requests Hon’ble Commission to allow power purchase costs for APR

period FY 2018-19 as provided in the table below.

4.8.3. Power purchase costs: The table here provides detailed power purchase costs-



Table 52: Power Purchase Projection for APR (in MW) for FY 2018-19

Name of The Source

Share allocated (MW)

Units purchase

d (MU)

PLF (%)

Fixed Cost

(Rs/kWh)

Fixed charge

(Rs Crs)

Energy Cost

(Rs/kWh)

Energy cost (Rs

Crs)

Misc. cost (Rs

Crs)

Total Cost (Rs Crs)

Average Cost

Central Sector Stations 2,049.88 11,752.70 65.45% 1.398 1,643.20

2.38 2,794.77 4.83 4,325.68 3.68

Talcher – I ( 2 x 500 MW) 222.72 1,540.88 78.8% 1.01 155.37 1.79 275.58 2.95 433.90 2.82

Farakka – I & II (1600 MW) 271.28 1,739.13 73.0% 0.93 161.30 2.40 417.17 0.18 578.65 3.33

Farakka – III (500 MW) 71.60 491.41 78.1% 1.62 79.47 2.41 118.42 0.05 197.93 4.03

Kahalgaon – I (840 MW) 189.86 1,238.75 74.3% 1.27 157.15 2.39 295.94 0.11 453.20 3.66

Kahalgaon – II (1500 MW) 40.34 285.77 80.7% 1.06 30.26 2.32 66.36 0.03 96.65 3.38

Barh-II 542.07 3,734.64 78.4% 1.93 719.22 2.40 894.93 1.06 1,615.21 4.32

Korba 13.50 97.05 81.8% 1.32 12.79 1.28 12.44 0.38 25.61 2.64

Rangit – HEP 11.34 95.65 96.0% 1.93 18.50 2.00 19.11 0.01 37.62 3.93

Teesta - HEP 58.55 321.40 62.5% 1.03 33.16 1.20 38.62 0.05 71.83 2.23

Chukha 43.20 272.10 71.7% - - 2.47 67.14 - 67.14 2.47

Tala 140.45 374.09 30.3% - - 2.16 80.80 - 80.80 2.16

Barh Stage-I (3 X 660 MW) - - 0.0% - - - - - - -

KBUNL 1 59.40 308.94 59.2% 1.38 42.66 3.60 111.16 - 153.81 4.98

KBUNL 2 142.56 899.32 71.8% 2.59 233.32 2.81 252.50 0.02 368.72 4.10

Barauni Stage I - - - - - - - -

Barauni Stage II - - - - - - - - -

PFC_ Medium Term 108.00 132.58 14.0% - - 4.24 56.21 - 56.21 4.24

Talcher-II (2x500) -

Arun –III -

Mangdechhu, HEP, 135.00 220.97 18.6% - - 4.00 88.39 - 88.39 4.00

North Karanpura, Jharkhand (3 X 660MW)

-

Darlipalli STPS (4 X 800 MW) -



Name of The Source


Units purchase

d (MU)

PLF (%)

Fixed Cost

(Rs/kWh)

Fixed charge

(Rs Crs)

Energy Cost

(Rs/kWh)

Energy cost (Rs

Crs)

Misc. cost (Rs

Crs)

Total Cost (Rs Crs)

Average Cost

TAWANG-I -

TAWANAG-II -

TEESTA-IV -

State Generating Stations 5.40 3.35 7.08% - - 2.49 0.83 - 0.83 2.49

Small Hydro (BSHPCL) 5.40 3.35 7.1% - - 2.49 0.83 - 0.83 2.49

IPP 289.76 1,718.62 5.64% 2.419 415.70 1.063 182.71 69.79 668.20 3.89

GMR Kamalanga Energy 127.76 928.06 83% 1.95 180.90 1.03 95.75 69.60 346.26 3.73

JITPL 162.00 790.55 56% 2.97 234.79 1.10 86.96 0.19 321.94 4.07

JV projects 281.38 555.34 23% 2.12 117.99 1.38 76.57 0.01 194.56 3.50

Nabinagar Railway (4 X 250 Mw) 27.00 141.11 59.7% 2.61 36.80 1.97 5.32 0.01 42.13 2.99

Nabinagar Stage-I (3 X 660 254.38 414.23 19% 1.96 81.19 1.72 71.25 - 152.44 3.68

Nabinagar JV (3 X 660 MW) Stage-II

- - - - - - - - - -

Renewable 123.66 268.97 25% - - 5.61 150.85 0.14 150.99 5.61

SECI Solar 5.40 9.10 19% - - 5.50 5.01 0.14 5.14 5.65

SECI-Wind-300 -

PTC-Wind- -

SECI-Solar -500 -

NTPC-Nokh - 500 -

NTPC-Solar -500 -

ACME Magadh 5.40 8.68 18% - - 8.73 7.58 - 7.58 8.73

ACME Nalanda 8.10 12.68 18% - - 8.73 11.07 - 11.07 8.73

Sunmark 5.40 8.62 18% - - 5.67 4.89 - 4.89 5.67

Avantika 2.70 3.08 13% - - 7.69 2.37 - 2.37 7.69

AZURE 5.40 7.00 15% - - 8.39 5.88 - 5.88 8.39

Udipta Energy & Equipment Pvt ltd 2.70 3.90 16% - - 7.98 3.11 - 3.11 7.98

Glatt 1.62 2.67 19% - - 6.11 1.63 - 1.63 6.11



Name of The Source


Units purchase

d (MU)

PLF (%)

Fixed Cost

(Rs/kWh)

Fixed charge

(Rs Crs)

Energy Cost

(Rs/kWh)

Energy cost (Rs

Crs)

Misc. cost (Rs

Crs)

Total Cost (Rs Crs)

Average Cost

Welspun 2 8.10 12.62 18% - - 8.64 10.90 - 10.90 8.64

Welspun 1 5.40 8.39 18% - - 8.70 7.30 - 7.30 8.70

Welspun 3 8.10 12.81 18% - - 8.65 11.08 - 11.08 8.65

Response Renewable Energy 5.40 8.68 18% - - 5.67 4.92 - 4.92 5.67

ALFA INFRAPOP 8.10 14.68 21% - - 4.76 6.99 - 6.99 4.76

TIRUPATI SUGAR 5.40 12.80 27% - - 3.61 4.62 - 4.62 3.61

New Swadeshi Sugar Mill,Narkatiaganj

3.78 10.13 30% - - 3.71 3.76 - 3.76 3.71

Harinagar Sugar Mills,Harinagar 5.94 32.63 63% - - 4.44 14.49 - 14.49 4.44

Bharat SugarMills,SidhiwaliaGopalganj

5.94 26.74 51% - - 4.91 13.13 - 13.13 4.91

Lauriya Sugar Mill 10.80 26.64 28% - - 3.67 9.78 - 9.78 3.67

Sugauli Sugar Mill 10.80 25.47 27% - - 5.34 13.60 - 13.60 5.34

Hasanpur Sugar Mills,Samastipur 5.40 14.02 30% - - 3.79 5.31 - 5.31 3.79

Riga Sugar Company Ltd,Sitamarhi 1.62 3.84 27% - - 3.62 1.39 - 1.39 3.62

Siddhashram Rice Mill Cluster Pvt Ltd

0.54 1.13 24% - - 5.60 0.64 - 0.64 5.60

BDBPL 1.62 2.66 19% - - 5.35 1.42 - 1.42 5.35

Open Market Purchase 4,293.36 - - 4.21 1,809.08 - 1,809.08 4.21

IEX/PXIL - 3,700.54 - - - 4.36 1,613.12 - 1,613.12 4.36

DB Power - - - - - - - - - -

JAYPEE NIGRIE - - - - - - - - - -

GMR ETL - - - - - - - - - -

TATA ETL - - - - - - - - - -

Manikaran Power - 80.10 - - - 4.02 32.23 - 32.23 4.02

NEA - - - - - - - - - -

NVVNL - - - - - - - - - -



Name of The Source


Units purchase

d (MU)

PLF (%)

Fixed Cost

(Rs/kWh)

Fixed charge

(Rs Crs)

Energy Cost

(Rs/kWh)

Energy cost (Rs

Crs)

Misc. cost (Rs

Crs)

Total Cost (Rs Crs)

Average Cost

PVVNL - - - - - - - - - -

KSEB- Short Term - 66.44 - - - 2.45 16.30 - 16.30 2.45

Tata Power - Short Term - 88.43 - - - 4.03 35.64 - 35.64 4.03

PTC -Ostro Kutch - Short Term - - - - - - - -

PTC-Short Term - 357.85 - - - 3.12 111.79 - 111.79 3.12

Adani Short Term - - - - - - -

UI -

Solar REC to meet RPO 1.00 29.26

Non-solar REC to meet RPO 1.25 73.63

Sub Total Power Purchase 2,750.09 18,592.34 1.17 2,176.89

2.70 5,014.80 74.77 7,252.23 3.90



4.8.4. The Petitioner humbly requests the Hon’ble Commission to approve the above

mentioned revised power purchase cost for the utility for FY 2018-19.

4.9. Transmission Charges

4.9.1. It is submitted that the Petitioner has to pay transmission charges to PGCIL for use of

transmission facilities enabling power drawl from eastern region. The calculation of

PGCIL charges is done by taking the average of 6 months actuals for the next six

months

4.9.2. Further, the Petitioner also pays BSPTCL, POSOCO charges and Open Access

charges which are projected in the similar way as projected for PGCIL charges.

4.9.3. We request the Hon’ble Commission to approve the transmission and related

charges for inter-state as well as intra-state transmission transactions for FY 2018-19

as per the below given table –

Table 53: Transmission charges for APR (in INR Crore)

Utilities Approved by the Commission for FY

2018-19

Projected for FY 2018-19 (RE)

PGCIL + ULDC 455.70 539.70

POSOCO & SLDC Charges 4.99 5.06

BSPTCL charges 644.96 677.21

BGCL 149.17 156.63

Total transmission Charges 1254.82 1,378.61


4.10.1. The Petitioner submits that it has estimated Capex, Capitalization and funding taking into

account the capital expenditure and investments to be done as per the recent

developments and keeping in mind the targets to be achieved for capitalisation under

various schemes during the forthcoming years. In line with the above, the Petitioner has

computed the capitalization of investment on the assumption that 80% of the

capitalization will come from Opening CWIP and 20% of the capitalization from fresh

investment would capitalize in FY 2018-19.

4.10.2. During FY 2018-19 and forthcoming years Petitioner is owing to huge capitalization since,

various schemes (BRGF, RAPDRP, RGGVY, MP LADS, NABARD etc.) are in the final

stage of completion. The Discoms are specifically focusing on capitalization of assets

created under various schemes post unbundling of BSEB



4.10.3. The opening figures of CWIP, Gross Fixed Assets, Grants, etc. are taken from the

audited annual accounts for FY 2017-18.

4.10.4. It is to be noted that the Petitioner has considered the sources of funding into Grant,

equity and Loan as per the actual sources and have documentary evidence in this

regard. Also, the Petitioner is submitting the detailed capitalisation plan in the

Additional formats requested by the Hon’ble Commission.

4.10.5. The below table represents the capitalization plan for the Petitioner

Table 54: Capitalization plan for FY 2018-19 (in INR Crore)

SI. No Name of the Scheme Name of the funding agency

FY 18-19 (APR)

Ongoing Schemes

1 BRGF GOI/GOB 1,366.95

2 R-APDRP GOI(PFC)/GOB 976.13

3 NABARD Phase VIII 1.27

4 NABARD Phase XI 10.51

5 MP/CM LAD 1.68

6 Deposit Scheme 3.77

7 ADB GoI 58.19

8 ACA State Plan GoB 24.34

9 Burnt DTR State Plan GoB 17.50

10 State Plan GoB 115.21

Subtotal(A) 2575.56

New Schemes

11 Re-conductoring 180.00

12 IPDS GOI/PFC 361.38

Subtotal(B) 541.38

13 RGGVY GOI/REC 444.88

Subtotal (C) 444.88

New Schemes

14 DDUGJY GOI/GOB 752.32

15 APL Connection GoB 152.50

Subtotal(D) 904.82

Grand Total (A+B+C+D) 4466.64

16 Own Sources Utility 174.88

Total 4641.53

4.10.6. The Hon’ble Commission is requested to consider the capitalization plan as estimated for

FY 2018-19.

4.10.7. The details of the opening CWIP, investment during the year, capitalization and

funding for CAPEX for FY 2018-19 is detailed in the table below:



Table 55: CWIP, Capitalization and Funding of Capitalization projected for FY 2018-19 (in INR Crore)

Sl. No.

Particulars Approved for FY 2018-19 in

MYT order dated

21.03.2016


Projected for FY 2018-19

(RE)

1 Opening CWIP 3155.29 5148.45 3108.75

2 New Investment - 2559.67 3309.37

3 Less Capitalization 1577.64 4624.90 4642.04

(a) CWIP 1577.64 3699.92 3713.63

(b) New Investment - 924.98 928.41

4 Closing CWIP (1+2-3)

1577.65 3083.27 1776.08

5 Funding

(a) CWIP Capitalization 1577.64 3699.92 3713.63

(i) Grant 1319.94 1570.08 953.11

(ii) Equity 102.10 1170.22 1197.66

(iii) Loan 155.60 959.62 957.98

(b) New Investment Capitalization

- 924.98 928.41

(i) Grant - 392.52 1003.92

(ii) Equity - 292.56 1620.34

(iii) Loan - 239.90 685.11

6 Total capitalization 1577.64 4624.90 4642.04

(i) Total Grant 1319.94 1962.60 1177.35

(ii) Total Equity 102.10 1462.78 2234.80

(iii) Total Loan 155.60 1199.52 1229.88

4.11. Operation & Maintenance (O&M) Expenses

4.11.1. As per regulation 22 of BERC (Multi Year Distribution Tariff) Regulations, 2015, O&M

expenses comprises of Repair and maintenance expenses, Administrative & General

expenses and employee expenses. In the below paragraphs the Petitioner would like to

submit the estimated expenses on account of O&M for FY 2018-19 along with the

reasoning and basis of projections.

4.11.2. Employee Expenses: Regulation 22.1 of Bihar Electricity Regulatory Commission (Multi

Year Distribution Tariff) Regulations, 2015 provides methodology for calculation of

Employee Cost as follows:

“Employee cost shall be computed as per the approved norm escalated by consumer price index (CPI), adjusted by provisions for expenses beyond the control of the Distribution Licensee and one time expected expenses, such as recovery/adjustment of terminal benefits, implications of pay commission, arrears and Interim Relief, governed by the following formula: EMPn = (EMPb * CPI inflation) + Provision Where: EMPn : Employee expense for the year n EMPb : Employee expense as per the norm CPI inflation : is the average increase in the Consumer Price Index (CPI)



for immediately preceding three years Provision : Provision for expenses beyond control of the Distribution Licensee and expected one-time expenses as specified above. Till the norms is specified by the Commission the employee cost shall be determined on the basis of actual historical cost.”

4.11.2.1. The Petitioner has considered audited accounts of FY 2017-18 as base year for

projecting employee expenses.

4.11.2.2. The terminal benefits and all the other benefits are increased in proportion of the total

employee cost. The detail of employee expenses for FY 2018-19 are shown as below –

Table 56: Employee Expenses for APR (in INR Crore)

S. No. Particulars Approved for FY 2018-19 in MYT order

Dated 21.03.2016

Approved for FY

2018-19


1 Employee cost of Previous Year 285.92 340.78 387.79

2 Inflationary index 5.25% 3.24% 2.40%

3 Inflationary increase 15.01 11.04 9.29

4 Employee Cost (1+3) 300.93 351.82 397.08

5 Less: Capitalisation 15.05 -- -

6 Total Employee Cost (4-5) 285.88 351.82 397.08

4.11.2.3. The Petitioner would like to submit that projections have been done on the basis of CPI

inflation index over FY 2017-18. Therefore, it is requested to the Hon’ble Commission to

approve the above given figure towards employee cost for FY 2018-19.

4.11.3. Repair and maintenance expenses: The R&M expenses primarily includes expenses

incurred by the Petitioner related to repair of different class of fixed assets etc. Regulation

22.2 of Bihar Electricity Regulatory Commission (Multi Year Distribution Tariff)

Regulations, 2015 provides methodology for calculation of Employee Cost as follows:

“22.2 Repairs and Maintenance (R&M) Expense Repairs and Maintenance expense shall be calculated as percentage (as per the norm determined) of Opening Gross Fixed Assets for the year governed by following formula: R&Mn = Kb * GFAn Where: R&Mn : Repairs & Maintenance expense for nth year GFAn : Opening Gross Fixed Assets for nth year Kb : Percentage point as per the norm”

4.11.3.1. The Petitioner has accordingly computed the ‘K’ factor (i.e. R&M norm) based on

available 3 (three) years audited accounts for FY 2015-16 to FY 2017-18 as given below:

Table 57: Calculation of “K” Factor for FY 2018-19

Particulars FY 2015-16 FY 2016-17 FY 2017-18

Opening GFA (in INR Crore) 4,281.61 3,657.17 5,667.06

R&M Cost (in INR Crore) 68.86 70.77 98.71

% of R&M Cost on Opening GFA 1.61% 1.94% 1.74%



Average percentage of R&M to GFA 1.75%

4.11.3.2. The Petitioner has computed the R&M expenses adopting ‘K’ factor on the Opening GFA

for FY 2018-19 as detailed in the Table below:-

Table 58: R&M Expenses for APR (in INR Crore)

Sl. No.

Particulars Approved for FY 2018-19 in MYT

order dated 21.03.2016



1 Opening GFA 13058.71 10241.86 6,626.28

2 K’ factor 1.50% 1.53% 1.75%

3 R & M expenses 195.88 156.70 116.08

4.11.3.3. Therefore, it is requested to the Hon’ble Commission to approve INR 116.08 Crore

towards expenses against R&M as claimed by the Petitioner.

4.11.4. Administrative and General Expenses: Administration and General expenses mainly

comprise costs towards rent charges, telephone and other communication expenses,

professional charges, conveyance and travelling allowances and other debits. Regulation


Regulations, 2015 provides methodology for calculation of A&G Cost as follows:

“22.3 Administrative and General (A&G) Expense A&G expense shall be computed as per the norm escalated by wholesale price index (WPI) and adjusted by provisions for confirmed initiatives (IT etc. initiatives as proposed by the Distribution Licensee and validated by the Commission) or other expected one-time expenses, and shall be governed by following formula: A&Gn = (A&Gb * WPI inflation) + Provision Where: A&Gn: A&G expense for the year n A&Gb: A&G expense as per the norm WPI inflation: is the average increase in the Wholesale Price Index (WPI) for immediately preceding three years Provision: Cost for initiatives or other one-time expenses as proposed by the Distribution Licensee and validated by the Commission. Till the norms of A&G expenses is specified by the Commission, the actual historical cost will be considered for determination of A&G expenses.”

4.11.5. The Commission has computed the average increase in the WPI for immediately

preceding three years i.e. FY 2015-16 and FY 2017-18 which worked out to 1.54%

(CAGR) as given below:

Sl. No. Particulars Index Points

1 Average Wholesale price index points for 2017-18 (A)

114.88

2 Average Wholesale price index points for 2015-16 109.72



(B) 3 No of years (C) 3

4 CAGR – WPI (A/B)^(1/C)-1 1.54%

4.11.6. The table below represents the estimated expenses determined by the Petitioner on

account of Administrative & General expenses.

Table 59: A&G Expenses for APR (in INR Crore)

Sl. No. Particulars Approved for FY 2018-19 in MYT


Approved for

FY 2018-19


(RE)

1 Base A&G expenses 49.20 56.62 73.42

2 WPI Inflationary index % 2.63% -- 1.54%

3 Inflationary increase (1*2) 1.29 -- 1.13

4 A&G expenses (1+3) 50.50 56.62 74.56

4.11.6.1. It is requested to the Hon’ble Commission to approve the Administrative and General

expenses of INR 74.56 Crore for FY 2018-19.

4.11.7. Allocation of Holding Company cost: As per Schedule ‘F”, the Holding Company

shall handle all issues relating to the subsidiary companies in respect of: -

“SCHEDULE “F” REORGANISATION OF BSEB & TRANSFER OF PERSONNEL Part II COMMON SERVICES The Testing Divisions, Training Department at Head-Quarter and all the Departments at the Corporate Head Office like –

General Administration

Accounts and Finance

IT

Stores & Purchase

Transmission/Distribution/Generation

Personnel

Publicity

Legal

Vigilance and Security

Commercial

Planning

Civil Engineering

Transmission (O&M)

Rural Electrification Shall constitute “Common Services‟ which shall continue to provide services to all successor entities during the Interregnum period, until issue of further transfer notifications allocating the employees to respective companies.”

4.11.7.1. The Petitioner is claiming the holding company expenses taking the expenses incurred in

FY 2017-18 as the same and escalating it by 10% for projecting for Annual performance



review of FY 2018-19. The below table represents the allocation of Holding Company cost

towards the Petitioner for FY 2018-19:-

Table 60: Allocation of Holding Company Cost for FY 2018-19 (in INR Crore)

S. No. Particulars Approved for FY 2018- 19 in MYT



FY 2018-19 (RE)

1 Holding company expenses considered for FY 2017-18 (RE)

10.68

2 Escalation % considered 10%

3 Increase considered 1.07

4 Total 7.56 6.59 11.75

4.11.7.2. Therefore, the Petitioner requests the Hon’ble Commission to approve INR 11.75 Crore

towards holding company expenses for FY 2018-19.

4.11.8. Summary of O&M Expenses: The below table summarizes the O&M expenses

estimated by the Petitioner for FY 2018-19:-

Table 61: Summary of O&M Expenses for APR (in INR Crore)

S. No. Particulars Approved for FY 2018-19 in

MYT Order dated

21.03.2016



1 Employee Cost 285.88 351.82 397.08

2 R&M Expense 195.88 156.70 116.08

3 A&G Expenses 50.50 56.62 74.56

4 Holding Company Expenses 7.56 6.59 11.75

5 Total O&M Cost 539.81 571.73 599.46

6 Less: Expenses capitalised 15.05 - -

7 Net O&M expenses (5-6) 524.77 571.73 599.46



opening fixed assets, capitalization as per the new schemes in FY 2018-19.

4.12.2. Through various new schemes like DDUGJY, IPDS etc introduced during FY 2017-18

huge Capitalization is planned in FY 2018-19. The Petitioner has provided the detailed

Capitalization plan in additional information requested by the Hon’ble Commission

explaining the sources of funding in every schemes like equity, loan and grants.

4.12.3. The table below demonstrates the Asset addition planned in FY 2018-19 and closing

balance of Gross Fixed Assets as on FY 2017-18 –

Table 62: Summary GFA for FY 2018-19 (in INR Crore)



S. No.

Assets group Closing balance FY 2017-18

Addition during FY 2018-19 (RE)

Closing balance FY 2018-19 (RE)

1 Land and land rights 1,536.17 1,076.17 2,612.34

2 Buildings 46.87 32.84 79.71

3 Hydraulic Works 0.33 0.23 0.57

4 Others Civil Works 30.03 21.04 51.07

5 Plant and Machinery 1,315.00 921.22 2,236.22

6 Lines and Cable Network 3,688.38 2,583.90 6,272.28

7 Vehicles 1.34 0.94 2.27

8 Furniture and Fixtures 3.23 2.26 5.49

9 Office Equipment 3.41 2.39 5.79

11 Spare Units/Service Units 1.19 0.83 2.02

13 Assets taken over from Licensees pending final valuation

0.32 0.23 0.55

GRAND TOTAL 6,626.28 4,642.04 11,268.31

4.12.4. The funding of GFA is done through equity, Loan and grants. The Hon’ble Commission is

requested to approve the GFA as determined by the Petitioner for FY 2018-19. The

Petitioner has annexed the detailed capitalization plan in the additional formats requested

by the Hon’ble Commission.

4.13. Depreciation on Gross Fixed Assets

4.13.1. As per regulation 23 of Bihar Electricity Regulatory Commission (Multi Year Distribution

Tariff) Regulations, 2015 the Petitioner has estimated the depreciation on the Gross

Fixed assets reduced by grants. The Petitioner has calculated depreciation on GFA

based on the Capitalization plan for FY 2018-19.

4.13.2. The Petitioner would like to clarify that while claiming the depreciation the value of Land and

addition thereon is reduced from the opening value and additions during the year.

4.13.3. As per the standard practice, the Petitioner shall not be allowed any depreciation on

account of assets that has been capitalized through grants. Therefore, the Petitioner has

reduced the Depreciation on the assets, which were added through grants.

4.13.4. Below is the table representing the calculations for claiming depreciation for FY 2018-19 :

Table 63: Depreciation on GFA for APR (in INR Crore)

Sl. No.


MYT order dated

21.03.2016



1 Gross fixed assets of the beginning of the year

11541.35 8699.93 5,090.10

2 Additions during the year 1577.64 4606.63 3,565.48

3 Employee cost capitalised 15.05 - -

4 IDC 10.11 - -

5 Closing GFA 13144.15 13306.56 8,655.97

6 Average GFA 12342.75 11003.25 6,873.04



Sl. No.


MYT order dated

21.03.2016



7 Weighted Average Rate of Depreciation 4.63% 4.18% 5.84%

8 Gross Depreciation at the end of the year 571.47 460.03 401.22

9 Opening grants 10706.96 5510.16 2,978.58

10 Grants during the year 1319.94 1962.60 1,177.35

12 Total Grants 12026.91 7472.76 4,155.94

13 Average Grants 11366.94 6491.46 3,567.26

14 Weighted Average rate of Depreciation 4.63% 4.18% 4.15%

15 Depreciation for GFA on Grants 526.29 271.40 147.98

16 Net Depreciation of GFA on loans (8-15) 45.18 188.63 253.24

4.13.5. Therefore, in the light of the above facts and calculations, it is requested to the Hon’ble

Commission to approve the above given figure of INR 253.24 Crore towards depreciation

on Fixed Assets for FY 2018-19.

4.14. Return of Equity

4.14.1. The Regulation 27 of BERC (Multi Year Distribution Tariff) Regulations, 2015

provides for calculation of Return on Equity as demonstrated as under:

“27. Treatment of Return on equity (a) Return on equity shall be computed on 30% of the capital base or actual equity, whichever is lower: Provided that assets funded by consumer contribution, capital subsidies/ grants and corresponding depreciation shall not form part of the capital base. Actual equity invested in the Distribution Licensee as per book value shall be considered as perpetual and shall be used for computation in this Regulation: (b) The return on the equity invested shall be allowed from the date of start of commercial operation: (c) The project which will be commissioned w.e.f. 01.04.2016 will be allowed RoE of 15.5% and if project is completed in schedule period 0.5% incentives in form of RoE will be allowed.”

4.14.2. The Petitioner has calculated return on equity on the basis of the closing balance of

fixed assets as claimed in True up for FY 2017-18.The 30% of the addition in GFA

is added to the opening GFA which is further reduced by 30% of the grant

contributing to the addition of Fixed Assets. Further, RoE shall be allowed @14%

on the net capital base as on 31.03.2016 and @15.50% on the net capital base

w.e.f. 01.04.2016.

4.14.3. The table below demonstrates the calculation for Return on equity:-

Table 64: Return on equity for FY 2018-19 (in INR Crore)


dated


19




21.03.2016

1 Closing equity to end of 31.03.2016 638.06 574.36

2 Rate of return on equity % 14.00% 14.00%

3 Return on Equity 89.33 80.41


4 Opening equity 774.54 474.07

5 Equity Addition during the year 798.69 1039.41

6 Closing Equity 1573.89 1513.47

7 Average Equity 1173.89 993.77


15.50% 15.50% 15.50%

9 Return on Equity 100.65 181.95 154.03


4.14.4. In the light of above facts, the Petitioner requests the Hon’ble Commission to approve INR

234.44 Crore towards return on equity for FY 2018-19.


4.15.1. The Petitioner has taken the opening balance of consumer security deposit as per the

audited financial statements for FY 2017-18.

4.15.2. It has been assumed that the additions to the balance of consumer security deposits is

as per actual addition in FY 2017-18. Therefore, INR 94.74 Crore is considered as addition

in consumer security deposits for FY 2018-19.

4.15.3. The interest on consumer security deposits is calculated at the rate of 6.25% which is

bank rate of RBI as on 01.04.2018.

Table 65: Interest on consumer security deposit (in INR Crore)

S. No. Particulars Approved for FY 2018-19 in

MYT order Dated 21.03.2016

Approved for FY

2018-19

FY 2018-19 (RE)





5 RBI Bank Rate 7.50% 6.00% 6.25%


4.15.4. The Petitioner requests Hon’ble Commission to approve the computation of interest on

security deposit for FY 2018-19.

4.16. Interest on Working Capital

4.16.1. The Petitioner has estimated the amount of interest on Working capital for FY 2018-19 as

per amended Regulation 26 of Bihar Electricity Regulatory Commission (Multi Year

Distribution Tariff) (First Amendment) Regulations, 2017.



“The Distribution Licensee shall be allowed interest on estimated level of working capital for the financial year, computed as follows: a) Two months equivalent of expected revenue b) Maintenance spares@40% of R&M expenses for one month: Less: (i) Power purchase cost, transmission charges and load dispatch charges of one month (ii) Depreciation, return on equity and contribution to contingency reserves equivalent to two months (iii) Security deposits from consumers, if any Provided that the interest on working capital shall be on normative basis and rate of interest shall be equal to the State Bank Advance Rate (SBAR) as of the date on which petition for determination of tariff is accepted by the Commission. Provided further that interest shall be allowed on consumer security deposits and security deposits from Distribution System users at the Bank Rate as of the date on which petition for determination of tariff is accepted by the Commission. Provided further that if the State Government is providing resource gap grant or subsidy, working capital shall be reduced by that amount.”

4.16.2. The Petitioner has not considered any grant against disallowed power purchase for low

distribution loss, since the support in terms of OFR by State Govt. is being infused in terms

of equity and not in terms of grant.

4.16.3. The interest on working capital is calculated at the rate of 13.45% which is SBI advance

rate.

4.16.4. In addition, it is pertinent to note that the Petitioner has taken short term loans from REC

and PFC for payment of Power Purchase liability. In addition to it there are other short term

loans like bank overdraft etc. on which Petitioner is bearing huge interest burden.

4.16.5. In the light of the above facts the Petitioner would submit that it is incurring the interest on

working capital at a higher level than as calculated as per normative requirement.

Table 66: Interest on working capital for APR (in INR Crore)

Sl. No.




(RE)

1 O&M expenses (1 month) 44.98 -- --

2 Two months equivalent expected revenue 1801.83 1538.11 1663.51


6.53 5.22 3.87

4 Sub-total (1+2+3) 1853.35 1543.33 1667.38

5 Less:

(i) Power purchase cost, transmission charges and load dispatch charges of one month

838.88 672.35 719.24

(ii) Depreciation, return on equity and contribution to contingency reserve

33.95 83.95 86.80

(iii) Grant received from the State Govt. for power purchase and other O&M expenses

-- -- --

(iv) Security Deposit from consumers 473.17 537.24 512.98

6 Sub-total (5(i)+5(ii)+5(iii)+5(iv)) 1052.16 1293.54 1319.02

7 Net working capital requirement (4-6) 801.19 249.79 348.36



Sl. No.




(RE)

8 Rate of interest % 14.75% 13.70% 13.45%

9 Interest on working capital (7*8) 118.18 34.22 46.85

4.16.6. The Petitioner requests Hon’ble Commission to approve the interest on working capital at

INR 46.66 Crore for FY 2018-19.

4.17. Contribution to Contingency Reserve

4.17.1. Regulation 24 (a) of the BERC (Multi Year Distribution Tariff) Regulations, 2015 specify “if

the distribution licensee has made an appropriation to the Contingency Reserve, a sum

not less than 0.25 per cent and not more than 0.5 per cent of the original cost of fixed

assets shall be allowed annually towards such appropriation in the calculation of ARR”.

4.17.2. The Petitioner has projected opening GFA at Rs.6626.28 crore for FY 2018-19. The

Opening GFA, contingency reserve considered for FY 2018-19 is given in the Table

below:

Table 67: Contribution to contingency reserve for FY 2018-19 (in INR Crore)

Sl. No.

Particulars Approved for FY 2018-19


1 Opening GFA 10241.86

2 Less: Assets revalued 1478.84

3 Original cost of GFA 8763.02 6,626.28

4 % of Appropriation to Contingency Reserve 0.50% 0.50%

5 Contingency reserve (3* 4) 43.82 33.13

4.18. Non-Tariff Income

4.18.1. Non-Tariff income includes meter rent, bank charges, interest on investments and bank

balances. The Petitioner has projected non-tariff income for FY 2018-19 on the basis of

10% escalation on the non-tariff income in FY 2017-18. The Petitioner has then deducted

the cost of funding the DPS from the total Non-Tariff Income and calculated the net Non-

tariff income as follows:

Table 68: Net-Non-tariff income for APR (in INR Crore)

Sl. No.





1 Base Non-tariff Income 296.45 135.54 342.09

2 Rate of Increase 10.00% 10.00% 10.00%

3 Increase in Non-tariff Income 29.64 13.56 34.21

4 Sub-total 326.09 149.10 376.30



Sl. No.





5 Additional income due to release of new connections

-- 47.04 --

Interest on funding of DPS (@13.45%- SBI PLR)

*112.35

6 Total non-tariff income 326.09 196.14 263.95

*The DPS for FY 2018-19 has been considered in proportion for FY 2017-18 over the total non-tariff income

4.18.2. The Petitioner requests Hon’ble Commission to approve net non-tariff income for FY

2018-19 amounting to INR 263.95 Crore.

4.19. Interest on Normative Debt

4.19.1. The Petitioner has calculated normative interest on loans on 70% of the addition in GFA in

FY 2018-19.

4.19.2. The addition to GFA as per the estimations is INR 2425.28 Crore which is 70% of the

addition during the year excluding contribution from grant.

4.19.3. The interest on normative debt is calculated at the rate of 10.09 % i.e. weighted average rate

on project Loans. The detailed calculation of the weighted average rate of interest is

provided in the table below:-

Table 69: Computation of weighted average rate of interest on project loans (in INR Crore)

S.N Particulars Opening balance

Rate of Interest

Repayment during the

year

Closing balance

Amount of interest paid

1 REC (RGGVY) Term Loan 82.19 11% - 82.19 9.04

2 REC (R-APDRP) Term Loan 349.26 10% - 349.26 36.32

3 PFC (R-APDRP) Term Loan 175.41 9% 1.85 173.56 15.70

4 PFC (APDRP) Term Loan - 9% - - -

5 PFC (BRGF) Term Loan - 10% - - -

6 REC (BRGF) Term Loan - 10% - - -

7 State Govt.-Non-Plan Loan 29.87 13% 29.87 - 1.94

8 BSPHCL (ADB) Loan 2.65 13% 2.65 - 0.17

9 Canara Bank Term Loan 56.57 10% - 56.57 5.66

10 Working Capital Loan 605.77 10% 526.16 79.61 34.27

Total 1,301.72 560.53 741.19 103.11

Average Loan during the year 1021.46

Weighted average rate of interest 10.09%

Table 70: Interest on Normative debt (in INR Crore)

S. No.

Particulars Approved for FY

Approved for




2018-19 in MYT


FY 2018-19 (RE)

1 Opening loan balance 1434.14 2322.48 2,553.38

2 Addition during the year 155.60 1863.61 2,425.28

3 Normative Repayment 45.18 188.63 253.24

4 Closing Loan 1544.56 3997.45 4,725.42

5 Average Loan 1489.36 3159.96 3,639.40

6 Interest Rate 8.20% 5.35% 10.09%

7 Interest Charge 122.13 169.06 367.37

4.19.4. Therefore, the Petitioner requests the Hon’ble Commission to approve interest on

normative debt at INR 367.37 Crore

4.20. Other Finance Charges

4.20.1. Other Finance charges includes power factor rebate, Interest to suppliers/ contractors,

rebate to consumers etc. The finance charges for FY 2018-19 is calculated by

escalating the Finance charges for FY 2017-18 by 10%.

4.20.2. The below table demonstrates the Finance charges estimated for FY 2018-19:-

Table 71: Other finance charges (in INR Crore)



Approved for FY

2018-19

Projected for FY

2018-19 (RE)

Other Finance Charges for the base year

57.12 19.06 40.57

Escalation Considered 10.00% 10.00% 10%

Escalated Amount 5.71 1.91 4.05

Finance Charge 62.83 20.97 44.63

4.20.3. Therefore, the Petitioner requests the Hon’ble Commission to approve the finance

charges of INR 44.63 Crore for FY 2018-19.


4.21.1. Following is the category wise revenue based on the existing tariff for FY 2018-19

based on existing tariff:

Table 72: Revenue from sales of power at existing tariff for FY 2018-19 (in INR Crore)

Category Sales (MU) Total Revenue (INR Crores)

Domestic

Kutir Jyoti

Unmetered 44 24.16

Metered (0-50) 1,056 670.82

Total - KJ 1,100 694.98

DS-I (Rural) -

Unmetered 53 26.90




Metered -

First 50 Units 1,623 1043.44

51 - 100 Units 454 292.32

Above 100 Units 532 353.23

Total 2,662 1715.88

DS-II (Urban- Demand Based) -

1-100 U/Month 599 408.26

101 - 200 U/Month 1,303 918.41

201 -300 U/Month 1,268 926.02

above 300 U/Month 352 270.51

Total 3,523 2523.20

Total - Domestic 7,285 4239.09

NDS-I (Rural) -

Unmetered - 0.00

Metered -

1-100 U/Month 9 6.71

101 - 200 U/Month 31 20.88

above 200 U/Month 13 9.19

Total 54 36.78

NDS-II (Demand Based) -

Contract Demand < 0.5 kW 6 4.43

Contract Demand > 0.5 kW -

First 100 Units 696 545.72

101 - 200 Units 421 396.48

Above 200 Units 59 61.36

Total 1,182 1007.98

Total - NDS 1,235 1044.76

Street Light Services -

SS-I (Metered) 13 11.48

SS-II (Unmetered) 29 17.58

Total - Street Light 42 29.06

IAS-I (Pvt Tubewell) -

Unmetered 286 138.43

Metered 41 30.56

Total 327 169.00

IAS-II (State Tubewell) -

Unmetered - 0.00

Metered 152 118.23

Total 152 118.23

Total - IAS 479 287.22

Public Service Connections -

Public Water Works 127 133.39

Har Ghar Nal -

Total PWW 127 133.39

LTIS -

LTIS-I (Contract Demand < 19 kW)

464 406.61

LTIS-II (Contract Demand 19-74 kW))

250 217.42

Total - LTIS 714 624.04

HTS-I (11 kV) 649 598.52

HTS-II (33 kV) 385 353.76

HTS-III (132 kV) 182 180.73

HTSS (33 / 11 kV) 790 458.74

RTS (132 kV) 579 491.21




Nepal -

Grand Total 12,467 9,135

4.21.2. It is submitted by Petitioner that above computed revenue is based on the approved tariffs

and revised projections of sales, consumers and load for respective years and requests

Hon’ble Commission to approve the same.

4.22. Net ARR and Revenue Gap for FY 2018-19

4.22.1. The Gross ARR for the distribution company consist of the power purchase costs, interest

and finance costs, O&M costs, depreciation and interest on working capital.

4.22.2. The below tables demonstrates the net gap for FY 2018-19 taking into account all the

expenses estimated for the entire year reduced by revenue from sale of power and Other

income.

4.22.3. Following is the total revenue requirement for FY 2018-19 against allocation from total

approved revenue requirement by the Hon’ble commission for FY 2018-19.

Table 73: Revenue requirement for FY 2018-19 (in INR Crore)

Sl. No.


dated 21.03.2016

Approved for FY

2018-19


1 Power purchase cost 9094.87 6,894.05 7,252.33

Less: 1% Rebate - (80.71) -

2 PGCIL & other transmission charges 545.07 458.38 544.76 3 State Transmission charges 426.61 796.44 833.84

4 O&M Expenses

i) Employee Cost 285.88 351.82 397.08

ii) R&M expenses 195.88 156.70 116.08

iii) A&G expenses 50.50 56.62 74.56

5 Share of Holding Company expenses 7.56 6.59 11.75 6 Depreciation 45.18 188.63 253.24

7 Interest and Finance charges 184.96 190.03 412.00 8 Interest on working capital 118.18 33.6 46.85

9 Return on equity 100.65 271.28 234.44

10 Income Tax 0 0 0


12 Bad debts (if any) 0 0.00 0

13 Contingency reserves (if any) 57.90 43.82 33.13 Deposit for RPO Obligation 0.00 0.00 0.00

14 Total Revenue Requirement 11137.10 9,397.70 10,245.00

15 Less: Non-tariff income 326.09 196.14 263.95

16 Less: Power purchase cost disallowed due to higher T&D loss

1763.02 0.00 0.00



Sl. No.


dated 21.03.2016

Approved for FY

2018-19


17 Aggregate Revenue Requirement 9047.98 9,201.56 9,981.05

Less : Revenue from Existing Tariff 9,362.82 9,135.50

Deficit / (Surplus) (161.26) 845.55

4.22.4. In the light of the above explanation the Petitioner would request the Hon’ble

Commission to approve the figure of INR 845.55 Crore towards net gap in FY 2018-19.



5. Annual Revenue Requirement (ARR) for FY 2019-20 to FY

2021-22

5.1. Preamble

5.1.1. The Petitioner has provided this section for Annual Revenue Requirement for the FY 2019-

20, FY 2020-21, FY 2021-22. Rational estimation of category-wise energy sales for the

control period is essential to arrive at the optimum quantum of power to be purchased and

the likely revenue by sale of energy. Likewise it is essential that the cost components driving

ARR should be projected in an optimal manner. The below sections deals with the

projections of ARR components for FY 2019-20, FY 2020-21, FY 2021-22.

5.2. Historical Assessment of Number of Consumers and Sales

5.2.1. Rational estimation of category-wise energy sales for the ensuing year is essential to

arrive at the optimum quantum of power to be purchased, and the likely revenue from sale

of energy. This section examines in detail the consumer category-wise energy sales

projected for the distribution company in the Petition for the period of FY 2019-20, FY

2020-21, FY 2021-22 for approval of ARR.

5.2.2. The Petitioner serves more than 44,77 lakh consumers (as on 31st March 2018). The

electricity consumers in the Discom have increased by approximately 12% over the last

year. This high rate of growth is also reflective of the efforts that the Discoms are

putting in to connect un-electrified consumers to the grid to enhance electricity access

in recent years. The historical trend in the number of consumers serviced by the Discom as

per the data available in its audited books of accounts, has been captured in the following

table.

Table 76: Category wise number of consumer for past few years

Consumer Category FY 2013-14 FY 2014-15 FY 2015-16 FY 2016-17 FY 2017-18

Domestic 1562785 1989856 2508730 3185872 3765044

Kutir Jyoti- BPL Consumers 443182 418817 528381 831,932 1,053,164

Domestic – I 297781 701786 1012042 1,276,524 1,501,556

Domestic – II 821797 869238 968267 1,077,407 1,210,324

Domestic – III 25 15 40 9 0

Commercial 166493 183452 220786 262420 304074

Non-Domestic – I 7871 16222 28305 39,738 49,561

Non-Domestic – II 158479 167095 192276 222,527 254,513

Non-Domestic – III 143 135 205 155 0

Public Lighting 277 321 467 700 907

Street Light – I 99 138 193 378 466

Street Light – II 178 183 274 322 441




Irrigation 47660 47893 63869 144954 160773

IAS – I 45969 46031 61824 141,288 156,959

IAS – II 1691 1862 2045 3,666 3,814

Public Water Works 662 670 900 1,391 1,806

Industrial LT 11024 12175 15233 28828 50756

LTIS – I 9809 10811 13138 26,179 46,964

LTIS – II 1215 1364 2095 2,649 3,792

Industrial HT 1056 1093 1052 1360 1597

HTS – I 919 1010 955 1,250 1,475

HTS – II 120 67 80 94 104

HTS - III 2 3 3 3 5

HTSS 15 13 14 13 13

Railway 17 15 15 15 15

DF Bhagalpur & Gaya 288475 329295 373,666 *202843

Total 1,789,975 2,523,951 3,140,348 3,999,206 4,487,815

*Represents number of consumers of erstwhile DF area.

5.2.3. This increase in the number of consumers leads to further increase in energy sales

under various categories of consumers. Following table covers the energy sale trend of

the Petitioner in the past few years –

Table 77: Category wise sales for the past few years (in MU)


Domestic 1673.12 1858.96 2607.69 3556.56 4150.33

Kutir Jyoti- BPL Consumers 159.55 144.34 200.56 325.04 486.90

Domestic - I 295.13 396.58 708.02 982.17 1,415.26

Domestic - II 1217.91 1318.00 1698.84 2,249.21 2,248.17

Domestic - III 0.54 0.04 0.27 0.14

Commercial 520.79 557.45 712.85 913.70 1051.68

Non-Domestic - I 8.41 13.42 20.31 29.71 44.38

Non-Domestic - II 509.98 543.35 691.27 881.94 1,007.30

Non-Domestic - III 2.40 0.68 1.27 1.92

Public Lighting 19.65 10.77 19.90 15.84 37.39

Street Light - I 1.69 4.00 7.65 5.77 7.22

Street Light - II 17.96 6.77 12.25 10.07 30.17

Irrigation 216.95 210.02 224.36 233.77 317.06

IAS – I 146.31 139.37 149.32 168.38 216.46

IAS – II 70.64 70.65 75.04 65.39 100.60

Public Service Connection 34.26 37.02 45.62 49.63 83.65

Public Water Works 34.26 37.02 45.62 49.63 83.65

Industrial LT 190.65 184.79 239.99 318.66 350.94

LTIS – I 102.10 96.84 120.19 180.63 196.40

LTIS – II 88.55 87.95 119.80 138.03 154.54




Industrial HT 1202.07 1176.45 1378.38 1580.69 1762.58

HTS – I 488.19 424.35 448.96 507.28 566.73

HTS – II 169.65 202.58 253.35 285.74 348.31

HTS - III 63.45 70.45 118.10 129.23 129.79

HTSS 480.78 479.07 557.97 658.44 717.75

Railway 511.90 527.21 579.95 563.61 578.65

U I 155.26 240.19 114.71 113.39

DF Bhagalpur & Gaya 112.01 1011.39 1278.04 1,315.60 *1,170.94

Total 4,636.66 5,814.25 7,201.49 8,661.45 9,503.22

YoY Growth (%) 25.40% 23.86% 20.27% 9.72%

*The sales to DF corresponds to energy injected at input point

5.3. Projected Sales (MU), Number of Consumers and Connected Load for 3rd Control Period

5.3.1. The projection of energy sales for the control period is based on the 24x7 Power For All

in line with the large scale initiative being taken by Central Government and the State

Government with an aim of overall development of the power sector in the state. The

objective of the above mentioned initiatives is to make power available to all households,

industry, commercial businesses, public needs, any other electricity consuming entity and

adequate power to agriculture farm holdings.

5.3.2. The initiatives of Discom are expected to mainly impact the rural consumers who would

fall under the Kutir Jyoti, DS-I and IAS-I categories, since a lot and the growth rate

projected under this category is above the normal CAGR growth as large number of new

connections to be released in the ensuing years.

5.3.3. It is to be noted that with effect from 26.11.2017, the Petitioner has terminated the

Distribution Franchisee Agreement with M/S BEDCPL for distribution of electricity in the

Bhagalpur area. Therefore for the purpose of projections, the Petitioner has now

considered the Bhagalpur area under its jurisdiction for the projections of consumers,

connected load and sales for the 3rd control period. Since the Petitioner has taken over

the operations in Bhagalpur area from the Distribution franchisee, the entire process of

taking over the Distribution franchisee has already been completed. Similarly, the Gaya

DF has also been terminated w.e.f. 04.07.2018 in view of its poor performance. Therefore

the provisional number of consumers as available on September, 2018 which is inclusive

of the consumers of the DF areas were considered for projection of consumers for the 3rd

control period i.e. FY 2019-20 to FY 2021-22.

5.3.4. However, with release of huge number of connections to the rural households and left

over urban households in recent years under various State and Central Govt. schemes

the scope of adding new consumers is getting minimized. Therefore, less number of

consumers are expected to be added over next control period in comparison to the



previous years. Taking the same into account, the growth in number of consumers for

various categories have been considered at a lower rate as compared to previous years.

The number of consumers projected to be added over the next control period is provided

below:

Table 78: Category-wise no. of consumers projected for 3rd Control Period

Consumer Category

FY 17-18 (Actual)

FY 18-19 (APR)

FY 19-20 (Proj.)

FY 20-21 (Proj.)

FY 21-22 (Proj.)

Growth Rate (YoY)

FY 19 FY 20 FY 21 FY 22

Domestic 3765044 5450398 5857898 6280471 6719273 45% 7% 7% 7%

Kutir Jyoti 1053164 1834164 1907531 1964756 2004052 74% 4% 3% 2%

Domestic - I 1501556 2241723 2465895 2712484 2983733 49% 10% 10% 10%

Domestic - II 1210324 1374512 1484473 1603231 1731489 14% 8% 8% 8%

Commercial 304074 358445 394290 433719 477091 18% 10% 10% 10%

NDS-I 49561 59908 65899 72489 79738 21% 10% 10% 10%

NDS-II 254513 298537 328391 361230 397353 17% 10% 10% 10%

Public Lighting

907 1275 1402 1543 1697 41% 10% 10% 10%

Street Light - I

466 848 1018 1197 1386 82% 20% 18% 16%

Street Light – II

441 427 384 346 311 -3% -10% -10% -10%

Irrigation 160773 112869 153030 193197 233372 -30% 36% 26% 21%

IAS – I 156959 108883 148883 188883 228883 -31% 37% 27% 21%

IAS – II 3814 3986 4147 4314 4488 5% 4% 4% 4%

Public Service Connections

1806 2750 16827 35923 48606 52% 512% 113% 35%

Public Water Works

1806 2750 3827 5326 7413 52% 39% 39% 39%

Har Ghar Nal 13000 30597 41193 135% 35%

Industrial LT 50756 65103 86037 108866 134741 28% 32% 27% 24%

LTIS – I 46964 61100 80652 101622 124994 30% 32% 26% 23%

LTIS – II 3792 4003 5385 7245 9747 6% 35% 35% 35%

Industrial HT 1597 1823 2064 2337 2646 14% 13% 13% 13%

HTS – I 1475 1688 1915 2173 2465 14% 13% 13% 13%

HTS – II 104 115 127 141 156 11% 11% 11% 11%

HTS – III 5 7 8 10 12 40% 19% 19% 19%

HTSS 13 13 13 13 13 0% 0% 0% 0%

Railway 15 15 15 15 15 0% 0% 0% 0%

DF Bhagalpur & Gaya

202843

Total 4487815 5992678 6511563 7056071 7617441 34% 9% 8% 8%

Note: The growth rates in the projections are higher since consumer of erstwhile DF area are considered under SBPDCL in FY 2019-20



5.3.5. The Petitioner has also been making other efforts to enhance the overall power

availability for the consumers of the State. This includes contracting additional power

from various sources across the State and the country, and enhancing the State’s power

transmission capacity for bringing it to the distribution network.

5.3.6. The commissioning of the transmission capacity shall also lead to a higher energy supply

to urban areas of the Discoms. The category wise projections of energy sales for FY

2018-19, has been done taking into account the above factors.

Table 80: Category-wise sales projected for 3rd Control Period

Consumer Category

FY 17-18 (Actual)

FY 18-19 (APR)

FY 19-20 (Proj.)

FY 20-21

(Proj.)

FY 21-22

(Proj.)

Growth Rate (YoY)

FY 19 FY 20

FY 21 FY 22

Domestic 4150 7285 8328 9010 9739 76% 14% 8% 8%

Kutir Jyoti- BPL Consumers

487 1100 1145 1179 1202 126% 4% 3% 2%

Domestic - I 1415 2662 3379 3722 4099 88% 27% 10% 10%

Domestic - II 2248 3523 3804 4109 4437 57% 8% 8% 8%

Commercial 1052 1235 1359 1495 1644 17% 10% 10% 10%

Non-Domestic - I

44 54 59 65 71 21% 10% 10% 10%

Non-Domestic – II

1007 1182 1300 1430 1573 17% 10% 10% 10%

Public Lighting

37 42 42 42 43 13% -1% 0% 1%

Street Light - I 7 13 16 19 21 82% 20% 18% 16%

Street Light - II 30 29 26 24 21 -3% -10% -10% -10%

Irrigation 317 479 577 794 1070 51% 21% 37% 35%

IAS – I 216 327 435 646 916 51% 33% 48% 42%

IAS – II 101 152 142 148 154 51% -6% 4% 4%

Public Service Connection

84 127 240 395 542 52% 88% 64% 37%

Public Water Works

84 127 177 247 343 52% 39% 39% 39%

Har Ghar Nal 63 148 199 135% 35%

Industrial LT 351 714 949 1224 1558 103% 33% 29% 27%

LTIS – I 196 464 612 771 949 136% 32% 26% 23%

LTIS – II 155 250 337 453 609 62% 35% 35% 35%

Industrial HT 1763 2005 2167 2351 2561 14% 8% 9% 9%

HTS – I 567 649 736 835 947 14% 13% 13% 13%

HTS – II 348 385 426 471 522 11% 11% 11% 11%

HTS - III 130 182 215 255 303 40% 19% 19% 19%

HTSS 718 790 790 790 790 10% 0% 0% 0%

Railway 579 579 579 579 579 0% 0% 0% 0%

DF Bhagalpur & Gaya

1171

Total 9503 12467 14241 15889 17736 31% 14% 12% 12%



Table 81: Category-wise connected load (kW) projected for the 3rd Control Period

Consumer Category FY 17-18 (Actual)

FY 18-19 (APR)

FY 19-20 (Proj.)

FY 20-21 (Proj.)

FY 21-22 (Proj.)

Growth Rate (YoY)

FY 19 FY 20

FY 21 FY 22

Domestic 5064053 6377369 6925704 7520252 8165117 26% 9% 9% 9%

Kutir Jyoti- BPL Consumers 89187 183416 190753 196476 200405 106% 4% 3% 2%

Domestic – I 1523232 2274084 2501492 2751641 3026806 49% 10% 10% 10%

Domestic – II 3451634 3919869 4233459 4572135 4937906 14% 8% 8% 8%

Commercial 988476 1162686 1278955 1406850 1547535 18% 10% 10% 10%

Non-Domestic – I 53848 66392 73031 80334 88368 23% 10% 10% 10%

Non-Domestic – II 934628 1096294 1205923 1326516 1459167 17% 10% 10% 10%

Public Lighting 10393 14867 16468 18217 20131 43% 11% 11% 11%

Street Light - I 5643 10270 12331 14494 16780 82% 20% 18% 16%

Street Light - II 4751 4597 4137 3723 3351 -3% -10% -10% -10%

Irrigation 379423 322042 422946 523938 625019 -15% 31% 24% 19%

IAS – I 338229 268822 367578 466333 565089 -21% 37% 27% 21%

IAS – II 41194 53220 55369 57604 59930 29% 4% 4% 4%

Public Service Connections 33817 51493 100745 168180 230951 52% 96% 67% 37%

Public Water Works 33817 51493 71664 99735 138801 52% 39% 39% 39%

Har Ghar Nal 29081 68445 92150 135% 35%

Industrial LT 627114 764265 1014460 1303710 1649908 22% 33% 29% 27%

LTIS – I 416862 542336 715883 902012 1109475 30% 32% 26% 23%

LTIS – II 210253 221930 298578 401698 540433 6% 35% 35% 35%

Industrial HT 649396 822415 918392 1028007 1153279 27% 12% 12% 12%

HTS – I 295283 350758 397952 451497 512245 19% 13% 13% 13%

HTS – II 171560 209687 231994 256674 283980 22% 11% 11% 11%

HTS – III 86850 142625 169101 200491 237708 64% 19% 19% 19%

HTSS 95703 119345 119345 119345 119345 25% 0% 0% 0%

Railway 155160 170200 170200 170200 170200 10% 0% 0% 0%

DF Bhagalpur & Gaya 425346

Total 8333179 9685338 10847870 12139354 13562140 17% 12% 12% 12%

5.3.7. The general approach followed for projection of all categories include:-

i. The consumer numbers for FY 2018-19 are projected considering the provisional

figures as available for September, 2018 and thereafter a reduced growth rate

across the categories has been considered resulting in total growth of 21% by the

end of FY 2018-19 over September, 2018. Thereafter, the overall growth rate has

been assumed to be around 9% for FY 2019-20 and 8% for the subsequent years

in the next control period.



ii. For projecting the connected load, an average connected load per consumer has

been taken as per the actual data of the past few years. This has then been then

multiplied by projected number of consumers to arrive at the connected Load.

iii. The energy sales has been projected by considering the average consumption per

consumer per month and then multiplying the same to the projected number of

consumers.

iv. The number of years taken for estimating the CAGR however varies since the

trend in certain categories is impacted by multiple other factors, and taking a

uniform period for calculating the CAGR skews the outcome.

v. In addition to the CAGR, it has also been ensured that other factors impacting

demand, such as growth in the no. of consumers (due to schemes including 24X7

Power For All, Chief Minister scheme and Saubhagya scheme), enhanced power

procurement, strengthening of distribution network for enhancing quality of supply,

energy efficiency and DSM measures etc., have been adequately incorporated to

reflect a realistic demand scenario.

The following paragraphs capture highlights of the approach and assumptions used for projecting the

specific category wise number of consumers, connected load and energy sales for the ensuing year.

5.4. Detailed category-wise projections for ARR period for the 3rd Control Period

a. Kutir Jyoti: The projections in Kutir Jyoti category are done considering the following

assumptions:-

i. Consumers: A major drive to enhance access to electricity in the State, and the majority of

the new potential consumers under Kutir Jyoti, DS-I and IAS-I categories has been

undertaken in recent years. It is expected that the programme of addition of new

consumers will achieve saturation in the near future. Therefore, the Petitioner In line with all

schemes, has estimated a growth rate of 36% over the consumers as on September, 2018

for FY 2018-19. Subsequently a growth rate of 4%, 3% and 2% has been assumed for

each year of the 3rd control period in view of saturation in addition of consumers in this

category and finalization of the ongoing schemes.

ii. Connected Load: The connected load for this category is projected considering average

load per consumer at 100 W and multiplying it by number of consumers to arrive at

the connected Load.

iii. Units sold: An increase of 30% in the consumption pattern for KJY category

over the consumption for FY 2017-18 has been assumed. The Petitioner has



considered an average monthly consumption of 50 kWh per consumer per month and

multiplying with total number of consumers projected in this category for FY 2018-19 to

arrive at an estimated sales figure. For the control period also same average monthly

consumption per consumer has been considered.

b. Domestic Service I: The projections in DS I category are done considering the following

assumptions:-

i. Consumers: The CAGR for FY 2017-18 over FY 2016-17 was found to be 18%.

Then the provisional figures for September, 2018 was considered which showed

an increase of 19% over the number of consumers as on FY 2017-18. Keeping

the same in view another 25% increase in number of consumers of this category

has been projected for FY 2018-19. Thereafter, an increase of 10% over

previous year in the number of consumers of this category has been considered

for the control period.

ii. Connected Load: The overall connected load for this category has been projected

considering no escalation on the average connected load per consumer for FY 2017-

18 and multiplying it by the projected number of consumers fur FY 2018-19.

Similarly, no escalation has been considered for projection of connected load for the

control period.

iii. Units sold: An increase of 26% in the average consumption per month per

consumer for DS-I category over the consumption for FY 2017-18 has been

assumed. The Petitioner has considered an average monthly consumption of 98.97

kWh per consumer per month and multiplying with total number of consumers

projected in this category for FY 2018-19 to arrive at an estimated sales figure. For the

control period, 15% over FY 2018-19 has been assumed for FY 2019-20 thereafter

same average monthly consumption per consumer has been considered for rest of

years of the control period.

c. Domestic Service II: The projections in DS II category are done considering the following

assumptions:-



an increase of 9% over the number of consumers as on FY 2017-18. Keeping the

same in view another 4% increase in number of consumers of this category has

been projected for FY 2018-19 considering the fact that majority of the new

consumers has already been added. Thereafter, an increase of 8% over previous



year in the number of consumers of this category has been considered for the

control period.


considering no escalation on the average connected load per consumer for FY 2017-

18 and multiplying it by the projected number of consumers fur FY 2018-19. Similarly,

no escalation has been considered for projection of connected load per consumer for

the control period.


consumer for DS-II category over the consumption for FY 2017-18 has been


kWh per consumer per month and multiplying with total number of consumers projected

in this category for FY 2018-19 to arrive at an estimated sales figure. For rest of the

years of control period also, same average monthly consumption per consumer has

been considered.

d. Non-Domestic Service I: The projections in NDS-I category are done considering the

following assumptions:-





has been projected for FY 2018-19 considering the fact that majority of the new

consumers has already been added. Thereafter, an increase of 10% over




considering no escalation on the average connected load per consumer for

September, 2018 and multiplying it by the projected number of consumers fur FY

2018-19. Similarly, no escalation has been considered for projection of connected

load per consumer for the control period.

iii. Units sold: No increase in the average consumption per month per consumer

for NDS-I category over the consumption for FY 2017-18 has been assumed.

The Petitioner has considered an average monthly consumption of 74.62 kWh per

consumer per month and multiplying with total number of consumers projected in this

category for FY 2018-19 to arrive at an estimated sales figure. For the control period,

also same average monthly consumption per consumer has been considered.



e. Non-Domestic Service II: The projections in NDS-II category are done considering the

following assumptions:-






consumers has already been added. Thereafter, an increase of 10% over




considering no escalation on the average connected load per consumer for maximum

of FY 2017-18 and September, 2018 and multiplying it by the projected number of

consumers fur FY 2018-19. Same average connected load per consumer as

considered for FY 2018-19 has been considered for projection of connected load for

the control period.


for NDS-II category over the consumption for FY 2017-18 has been assumed.





f. SS-I: The projections in SS-I category are done considering the following assumptions:-






consumers has already been added and there will be conversion of unmetered

consumers into metered consumers. Thereafter, an increase of 20%, 18% and

16% respectively over previous year in the number of consumers of this category

has been considered for the control period.

ii. Connected Load: The Petitioner has made efforts towards Demand Side

Management (DSM) by replacement of 150W lamps with 40-50W sodium vapour



lamps which has reduced the average connected load per consumer drastically.

Therefore, Petitioner has considered average connected load per consumer for FY

2018-19 same as for FY 2017-18. Same average connected load per consumer as


the control period.


for SS-I category over the consumption for FY 2017-18 has been assumed. The

Petitioner has considered an average monthly consumption of 1291.13 kWh per




g. SS-II: The projections in SS-II category are done considering the following assumptions:




the same in view and considering the fact that there will be conversion of

unmetered consumers to metered ones there will be 15% decrease in number of

consumers of this category has been projected for FY 2018-19. Thereafter, a

decrease of 10% over previous year in the number of consumers of this category


ii. Connected Load: The average Load in this category is calculated by considering 0%

growth rate on average Load per consumer for FY 2017-18 over FY 2016-17 and

multiplying by number of consumers projected in this category.


for SS-II category over the consumption for FY 2017-18 has been assumed. The

Petitioner has considered an average monthly consumption of 5701.06 kWh per



also same average monthly consumption per consumer has been considered. In the

Street Lights category the process is going on for replacement of 150W lamps with 40-

50W Sodium vapour lamps which shall possibly reduce the units consumed in Street

Lights category.

h. IAS-I: The projections in IAS-I category are done considering the following assumptions:-





an decrease in the number of consumers as on FY 2017-18. The reduced

number of IAS-I consumers considered as per the software data and only active

consumers are considered. Most of these consumers which were not considered

are unmetered and are kept under temporary disconnection. Due to logical

constraint in the soft ware which requires meter number for removal of the

specific consumers from the list could not be removed. The Discom is putting its

continuous effort to address the issue and update the software with actual

numbers which may also reflect in the audited accounts for next financial year.

Keeping the same in view 16% increase in number of consumers of this category

has been projected for FY 2018-19 over number of consumers as on September,

2018. Thereafter, 40,000 consumers over previous year in the number of

consumers of this category has been considered for the control period in view of

growing demand of the agricultural consumers.






the control period.

iii. Units sold: A 10% increase in the average consumption per month per

consumer for IAS-I category over the consumption for FY 2015-16 has been

assumed which otherwise was showing an abnormal drop in the consumption

pattern for FY 2016-17 and FY 2017-18. The Petitioner has considered an average

monthly consumption of 221.40 kWh per consumer per month and multiplying with

total number of consumers projected in this category for FY 2018-19 to arrive at an

estimated sales figure. For FY 2019-20, also 10% increase in average monthly

consumption per consumer has been considered and thereafter an increase of 17% in

sales over previous year has been considered during the control period. Agriculture

feeder separation is under process, once it is done separate transformers will be

issued connecting to pump sets. Promotion of Solar Pump sets will be done to reduce

demand.

i. IAS- II: The projections in IAS-II category are done considering the following assumptions:-




Then the provisional figures for September 2018 was considered which showed

very marginal increase over the number of consumers as on FY 2017-18.

Keeping the same in view, only 4% increase in number of consumers of this

category has been projected for FY 2018-19. Thereafter, an increase of 4% over








the control period.

iii. Units sold: A 30% increase in the average consumption per month per

consumer for IAS-II category over the consumption for FY 2017-18 has been




control period, also same average monthly consumption per consumer has been

considered.

j. Public waterworks: The projections in PWW category are done considering the following

assumptions:-




the same in view, another 10% increase in number of consumers of this category

has been projected for FY 2018-19. Thereafter, an increase of 39% over previous

year in the number of consumers of this category has been considered for the

control period.






the control period.




for PWW category over the consumption for FY 2017-18 has been assumed.





k. Har Ghar Nal: The GoB has decided to provide water connections to the households in rural

and urban areas. For this purpose a total of 1,10,000 water distribution facility are proposed to

be set up for the State. It requires a 2 or 3 HP pump to be installed for pumping of water to the

overhead tank from where the water shall be distributed to the households. There are 152

Panchayats in NBPDCL and 91 Panchayats in SBPDCL. Accordingly, for the purpose of

projection the total no. of connections are divided in the ratio of no. of panchayats between the

Discoms. This new sub-category shall be proposed in the subsequent Tariff Petition to be filed

by the Petitioner. The projections under this category are done considering the following

assumptions:-

i. Consumers: To start with 13,000 consumers are proposed to be added in FY

2019-20 and which shall be added by 17,597, 10,597 number of consumers for

the rest of the control period.

ii. Connected Load: The connections released under this category shall be mainly

used for the purpose of supplying water though pipeline to households for which a 2

HP, 3 HP and 5 HP pump shall be used for pumping the ground water to an overhead

tank. Therefore, the connected load has been assumed to be on the basis 3 HP per

connection.

iii. Units sold: 6 hours consumption per kW per day has been assumed for

calculation of average monthly consumption. Thereafter, it is multiplied with

number of consumers for calculation of total consumption for the month.

l. LTIS-I: The projections in LTIS-I category are done considering the following assumptions:-


Then the provisional figures for September 2018 was considered which showed a

marginal increase over the number of consumers as on FY 2017-18. Keeping the

same in view, another 30% increase in number of consumers of this category has

been projected for FY 2018-19. Thereafter, an increase of 33%, 26%, 23% over










the control period.


consumer for this category over the consumption for FY 2016-17 has been


kWh per consumer per month and multiplying with total number of consumers projected

in this category for FY 2018-19 to arrive at an estimated sales figure. For the control

period, also same average monthly consumption per consumer has been considered.

m. LTIS-II: The projections in LTIS-II category are done considering the following assumptions:-



a marginal increase over the number of consumers as on FY 2017-18. Keeping

the same in view, another 5% increase in number of consumers over the

consumers of as on September, 2018 has been projected for FY 2018-19.

Thereafter, an increase of 35% over previous year in the number of consumers

of this category has been considered for the control period.






the control period.






control period, also same average monthly consumption per consumer has been

considered.

n. HTS-I: The projections in HTS-I category are done considering the following assumptions:-



i. Consumers: Recently the Discoms have seen an increasing trend in the addition of

consumers in the HTS-I category, including both conversions from the LTIS

categories and addition of new consumers. The CAGR for FY 2017-18 over FY

2016-17 was found to be 18%. Then the provisional figures for September 2018

was considered which showed an increase of 9% over the number of consumers

as on FY 2017-18. Keeping the same in view, another 5% increase in number of

consumers of this category has been projected for FY 2018-19. Thereafter, an

increase of 13% over previous year in the number of consumers of this category


iv. Connected Load: The overall connected load for this category has been projected





the control period.

ii. Units sold: An increase of 10% in the average consumption per month per


assumed. The Petitioner has considered an average monthly consumption per




o. HTS-II: The projections in HTS-II category are done considering the following assumptions:-

i. Consumers: Recently the Discoms have seen an increasing trend in the addition of

consumers in the HTS-II category, including both conversions from the LTIS

categories and addition of new consumers. The CAGR for FY 2017-18 over FY

2016-17 was found to be 11%. Then the provisional figures for September 2018

was considered which showed an increase of 5% over the number of consumers

as on FY 2017-18. Keeping the same in view, another 5% increase in number of

consumers of this category has been projected for FY 2018-19. Thereafter, a

uniform increase of 11% over previous year in the number of consumers of this

category has been considered for the control period.








the control period.


for this category over the consumption for FY 2017-18 has been assumed. The

Petitioner has considered an average monthly consumption per consumer per month

and multiplying with total number of consumers projected in this category for FY 2018-

19 to arrive at an estimated sales figure. For the control period, also same average

monthly consumption per consumer has been considered.

p. HTS-III: The projections in HTS-III category are done considering the following assumptions:-

i. Consumers: The CAGR for FY 2017-18 over FY 2016-17 was found to be 67%

in comparison to last 2 year’s CAGR of 29% and 3 year’s CAGR of 19% which

seems to be quite abnormal. Then the provisional figures for September 2018

was considered which showed an increase of 33% over the number of

consumers as on FY 2017-18. Keeping the same in view, another 5% increase

in number of consumers of this category has been projected for FY 2018-19.

Thereafter, a uniform increase of 19% over previous year in the number of

consumers of this category has been considered for the control period.






the control period.







q. HTSS: The projections in HTSS category are done considering the following assumptions:-

i. Consumers: The number of consumers for FY 2016-17 and FY 2017-18 has

been found to be same. Then the provisional figures for September 2018 was

considered which also showed no increase in the number of consumers.



Keeping the same in view, no increase in number of consumers of this category

has been projected for FY 2018-19 and same number of consumers has been

considered for the control period.






the control period.

iii. Units sold: 10% increase in the average consumption per month per consumer






r. Railways: The projections in RTS category are done considering the following assumptions:-

i. Consumers: There has been no growth rate assumed in the railways category for

projecting number of consumers. The number of consumers are considered as 15,

which is equivalent to last year.






the control period.







5.4.1. Distribution Franchisee: Since, both the DFs i.e. Bhagalpur and Gaya have been

terminated during FY 2017-18 and FY 2018-19. The number of consumers, load and sales



for the DF area are merged with that of the Discom. Therefore, same has not been

projected separately.


5.5.1. Emphasizing on the commitment to reform themselves by achieving a financial and

operational turnaround, the Government of Bihar and the two Distribution

Companies have signed a tripartite Memorandum of Understanding (MoU) of Ujwal Discom

Assurance Yojana (UDAY) with the Ministry of Power, Government of India on 22nd

February, 2016. This combined with other initiatives that the State Government and

the Discoms are taking, are targeted to achieve the following vision for the State of

Bihar.

1. Ensuring 24X7 Power for All by 2019: A detailed action plan to achieve the

vision of providing electricity access to all Households in the State has been

prepared by the state. The aim is to achieve 24X7 availability of reliable power to all

households, industrial, commercial establishments and all other electricity

consuming entities by FY19.

2. 100% village electrification: The State has electrified all villages and

households.

3. Reducing AT&C losses to 15%: Along with achieving the multiple

objectives such as enhancing the reach, reliability and quality of electricity,

Petitioner has endeavoured to bring down AT&C losses to below 15% by FY19.

Several focused interventions at all levels are being undertaken, including metering

of feeders, distribution transformers and consumers, improving and augmenting

existing sub-transmission and distribution infrastructure, enhancing revenue

collection initiatives and ensuring consumer satisfaction.

4. Reducing the gap between ACS and ARR to zero: As a foremost step towards

building a financially sustainability, the state is initiating several steps to bring down

the wide gap between Average Cost of Supply (ACS) and Average Revenue

Realized (ARR). Historically, the retail tariff for electricity in Bihar has been one of

the lowest in the Country and has remained non-reflective of the actual costs. The

utility’s comprehensive plan to reduce AT&C losses, improve billing and collection

efficiency coupled with realistic tariff increase and rationalizations to cover the costs

sufficiently are key to ensuring financial viability of the sector.

5.5.2. The UDAY MoU and the corresponding action plan, which are targeted to specifically

address operational inefficiency as well, set out a clear performance improvement

roadmap, setting specific key performance targets. This would include taking multiple

initiatives towards the goals:



5.5.3. Increasing Billing Efficiency:

a. Automatic Meter Reading of Industrial Consumers

b. Metering including prepaid/ Smart Meter

c. Web based Spot Billing through Mobile

d. Image of Meter Reading on Bill

e. Consumer Indexing & GIS Mapping

f. Frequent raids and inspection of consumer premises to prevent power theft.

g. 100% feeder metering

h. 100% DT metering in urban areas.

i. Energy Accounting and Audit

5.5.4. Increasing Collection Efficiency

a. Appointment of Rural Revenue Franchisee for door to door collection from

rural consumers

b. Uploading of all Electricity bill on web for direct download and on-line payment

c. Multiple options of payment such as on-line through Billdesk/PayU, HDFC

Bank, ATP machine, Paytm, Branches of Gramin Bank, Vasudha Kendra, e-

wallet, Block Collection Counter, Post offices, Mobile App, Mobile Van, etc.

d. Disconnection drive in case of non-payment

e. Filing Certificate Cases and their disposal promptly

f. Customer Facilitation Centre for rectification of bill/ consumer complain

g. Monthly Bill rectification Camp at all Sub-division/Division

5.5.5. Other measures

a. Strengthening and capacity addition of electricity distribution infrastructure

b. Physical feeder segregation

c. Feeder improvement program for network strengthening

d. DSM and energy efficiency measures

e. Name and shame campaign to control power theft

f. Consumer awareness programs

g. Centralised Customer Call Centre to enhance response time and overall quality

of service

5.5.6. In light of the various measures being undertaken by the State and the existing levels

of T&D losses, the Petitioner has targeted a reduction in AT&C losses and

achieve 15% AT&C loss by FY 2019-20. The T&D loss reduction trajectory that has

been agreed between the Petitioner, the Government of Bihar and the Government of

India, has been as given below.



Table 82: Distribution Loss Trajectory

FY 2017-18 FY 2018-19 FY 2019-20

Distribution loss 30% 22% 15%

5.5.7. Further, in FY 2017-18 and FY 2018-19, a large number of rural consumers have been

added to the Discom’s consumer database. Due to this addition in the number of consumers

at a Low Tension level in rural areas, where the length of feeders are generally longer, the

technical losses are expected to go up. Therefore for the Discom as a whole, it would not

be possible to drastically reduce losses in FY 2018-19. However, for the control period it is

envisaged that the Discom will able to achieve the loss trajectory for FY 2019-20.

5.5.8. It is submitted to the Hon’ble Commission that although the Discoms are making the

best possible efforts to reduce the losses with the introduction of feeder separation

schemes, spot billing etc. and various other IT initiatives, the reduction in losses would

still occur in a phased manner.

5.5.9. Given the fact that the Discoms of Bihar have already entered into an MoU which clearly

lays out a loss reduction target agreed by the Government of Bihar and the Government of

India, this target may be treated as the base for setting the loss reduction trajectory.

5.5.10. Accordingly, it is prayed to the Hon’ble Commission to adopt the trajectory agreed under

UDAY scheme and approve a Distribution loss of 15% for SBPDCL for FY 2019-20 and

retain the same distribution loss for FY 2020-21 and FY 2021-22.

Table 82: Distribution Loss Trajectory

FY 2019-20 FY 2020-21 FY 2021-22

Distribution loss 15% 15% 15%

5.5.11. Initiatives taken by the Company to contain Losses:

The Discoms have been initiated customized strategic techno-social solutions to torpedo

the “herd culture”. Demand analysis, market scanning for available befitting technology,

customer communication for smooth implementation and create social backbone for

sustainable results are key areas, where the Discom tries for “symmetry breaking”

solutions.

A. Technical Solutions:

a. SAP Implementation: With latest upgradation, SAP is under consideration for

implementation across all functions of the Discom, creating a transparent and

effective business environment for the Company as a whole.

b. Metering: The Discom might not be the first but certainly one of the frontrunner in

implementing latest metering technologies. Electronic meters with digital display,

AMR meters then LPR meters, group metering, pre-paid meters and SMART



meters are Discom’s latest offering. Nodal point meters are installed to capture

cluster wise consumption for micro audits. “Photo meter readings” are introduced

in rural areas to ensure monthly visit by the meter readers, accurate meter reading

is taken on monthly basis.

c. Data Analysis Center: The Company has set up data analysis center to analyze

drop in consumption, exception reports, and consumption pattern factoring

seasonal variation on monthly basis to prepare suspect list. Attempts are being

made to take intensive actions in such areas in accordance with law.

d. Creation of new load centers and reinvigorate distribution network: Periodic

load survey and analysis is carried out to contain technical losses due to overload

of transformers and to reduce transformer burnt cases. Based on load survey

report, new sources are created and load is shared thereby reducing the load from

overloading transformers. HVDS, Areal bunch cables and junction boxes are

placed in the network, to restrict pilfering of electricity due to consumer’s easy

access. Also, on pilot basis, underground feeder pillar box has been introduced, to

eliminate un-authorize tapings.

e. Spot Connections: Camps has been organized in rural areas to provide new

connection at the same day to the consumer through spot connection drives.

Address in village is not clear and it becomes difficult to follow up with the

consumer indulging in electricity theft, as not being registered consumer. By this

drive, meter has been provided to them and energized supply on same day.

f. GIS System: The Company has introduced state of the art and latest

Geographical Information System (GIS) application covering the entire area in its

jurisdiction. GIS based system integrated with SAP shall allow users to undertake

complex engineering analysis, identify theft locations in the map form, create

network design, generate bill of materials and manage trouble call at dispatch

center. Premises in villages are difficult to locate due to improper address. But with

GIS tracker, Location of pilferage like consumer premises, pole and distribution

transformer in marked in the map and it helps to identify location and book cases

through LCC drives. Also GIS co-ordinates at the time of LCC booking, shall be

captured in hand held device and updated in the GIS map for future use.

B. Social Initiatives:

Community Awareness: Promotional vans, leaflets distribution and spreading

news through media, are key instruments, the Company uses to sensitise people

for better, effective and “pay as per use” for use of electricity.

5.6. State Transmission Losses



5.6.1. The Commission approved intra-state transmission loss at 3.92% for FY 2018-19 in the last

Tariff Order. Also, for the control period the Petitioner has assumed the intra-state

transmission loss at 3.92%.

5.7. Central Transmission Losses

5.7.1. The Commission approved inter-state transmission loss at 2.26% for FY 2018-19 in the

last Tariff Order. In addition, for the control period the Petitioner has assumed the intra-

state transmission loss at 2.26%.

5.8. Power Purchase

5.8.1. The Discoms rely on allocation from central generating stations and state projects for

procuring power for sale in the state. This power has been proposed to be allocated

between north and south Bihar in the proportion as determined by the board resolution

as detailed below:

5.8.2. Bihar State Power Holding Company Ltd (BSPHCL) issued vide its Resolution No.55-

10 dated 14th July 2017 for approval regarding distribution of power purchase

agreement between NBPDCL and SBPDCL. The notification states that,

“RESOLVED THAT Power Purchase & Transmission charges bills are to be admitted and payment by both Discoms i.e NBPDCL and SBPDCL in the ratio 46:54 respectively w.e.f.1-4-2017subjected to the final reconciliation of actual consumption” RESOLVED FURTHER THAT Chairman cum Managing Director, BSHPCL are here by authorized for deciding the power consumption ratio subsequently as per the actual consumption of both the DISCOMS based on the average consumption of the last 6 months of power drawal of both the discoms i.e. NBPDCL and SBPDCL”

The Board further ratifies the submission made in attached agenda note.

The following were considered by the petitioner during the power purchase projections for FY 2018-19

i. Barh Stage I, Unit II has been considered to be available from January of FY 2021-

22.

ii. Nabinagar Stage I has been considered to be available in February 2019

iii. Nabinagar Railway project has been considered that 25MW from Unit III will be

available in July 2018 and then subsequently 25MW from other Unit will be available

from January 2019.

iv. Mangdhechu HEP has been considered shall be available from February 2018-19

5.8.3. The power purchase (MU) has been calculated month wise month on month from April

2018 to March 2019. The methodology of projecting Power purchase quantum (MU) is

as mentioned below:



i. The above mentioned share allocation has been considered using the latest COD’s of

each unit. Many new plants are expected to start operations in the financial year

2019-20. The increase in the share allocation has grown with the demand and is in

lines allocated generation capacity in the 24x7 Power For All (PFA) agreement.

ii. The Plant Load Factor (PLF) for each plant has been calculated on actual basis and

then Petitioner took normative PLF of the plants load factors for FY 2019-20, FY

2020-21 and FY 2021-22

a. Normative Plant Load Factor Plant (PLF) provided by central Electricity

Regulatory Commission (CERC) for the thermal and hydro plants and the auxiliary

consumptions specified for plants. For the state plants PLF highest among the PLF

norms specified by BERC and the plant wise auxiliary consumption determined by

BERC for thermal, and biomass has been considered. For the solar plants highest

among the CUF of 19%

b. Actual Plant Load Factor (PLF) of the thermal, hydro, biomass and solar plants in the

same month of previous financial year i.e. FY 2018-19.

iii. Considering the PLF as mentioned above and using the power purchase allocation

data mentioned in the above table total number of units purchased were

calculated from every source/ plant for every month separately.

5.8.4. Total Power purchase projections data from April 2019-20 to March FY 2021-22 (MU)

is provided in the below table.

Table 84: Total power purchase (MU) for 3rd Control Period

Name of The Source FY 2019-20 FY 2020-21 FY 2021-22


Units purchase

d (MU)


Units purchase

d (MU)


Units purchase

d (MU)

Central Sector Stations 2,391 13,130 2,512 15,005 2,589 14,687

Talcher – I ( 2 x 500 MW) 223 1,541 223 1,541 223 1,541

Farakka – I & II (1600 MW) 271 1,739 271 1,739 271 1,739

Farakka – III (500 MW) 72 491 72 491 72 491

Kahalgaon – I (840 MW) 190 1,239 190 1,239 190 1,239

Kahalgaon – II (1500 MW) 40 286 40 286 40 286

Barh-II 542 3,735 542 3,735 542 3,735

Korba 14 97 -

Rangit – HEP 11 96 11 96 11 96

Teesta - HEP 59 321 59 321 59 321

Chukha 43 272 43 272 43 272

Tala 140 374 140 374 140 374

Barh Stage-I (3 X 660 MW) - - - 185 -

KBUNL 1 59 309 59 309 59 309





Units purchase

d (MU)


Units purchase

d (MU)


Units purchase

d (MU)

KBUNL 2 143 899 143 899 143 899

Barauni Stage I 119 600 119 734 119 734

Barauni Stage II 135 227 270 1,668 270 1,880

PFC_ Medium Term 108 133 108 530 - -

Talcher-II (2x500) - - -

Arun –III - - -

Mangdechhu, HEP, 135 468 135 468 135 468

Punatsangchhu & - - - - -


- - -

Darlipalli STPS (4 X 800 MW)

87 303 87 303 87 303

TAWANG-I - - - - -

TAWANAG-II - - - - -

TEESTA-IV - - - - -

State Generating Stations 5 3 5 3 5 3

Small Hydro (BSHPCL) 5 3 5 3 5 3

IPP 290 1,719 290 1,719 290 1,719

GMR Kamalanga Energy 128 928 128 928 128 928

JITPL 162 791 162 791 162 791

JV projects 308 1,879 308 1,879 308 1,879

Nabinagar Railway (4 X 250 Mw) 54 141 54 141 54 141

Nabinagar Stage-I (3 X 660 254 1,738 254 1,738 254 1,738


- - - - -

Renewable 340 716 340 716 1,258 2,306

SECI-Solar 5 9 5 9 5 9

SECI-Wind-300 MW 108 224 108 224 216 456

PTC-Wind- 300 MW 108 224 108 224 108 228

SECI-Solar -500 MW - 270 451

NTPC-Nokh - 500 MW - 270 451

NTPC-Solar -500 MW 270 451

ACME Magadh 5 9 5 9 5 9

ACME Nalanda 8 13 8 13 8 13

Sunmark 5 9 5 9 5 9

Avantika 3 3 3 3 3 3

AZURE 5 7 5 7 5 7

Udipta Energy & Equipment Pvt ltd

3 4 3 4 3 4

Glatt 2 3 2 3 2 3

Welspun 2 8 13 8 13 8 13

Welspun 1 5 8 5 8 5 8

Welspun 3 8 13 8 13 8 13





Units purchase

d (MU)


Units purchase

d (MU)


Units purchase

d (MU)

Response Renewable Energy 5 9 5 9 5 9

ALFA INFRAPOP 8 15 8 15 8 15

TIRUPATI SUGAR 5 13 5 13 5 13


4 10 4 10 4 10

Harinagar Sugar Mills,Harinagar 6 33 6 33 6 33


6 27 6 27 6 27

Lauriya Sugar Mill 11 27 11 27 11 27

Sugauli Sugar Mill 11 25 11 25 11 25

Hasanpur Sugar Mills,Samastipur

5 14 5 14 5 14

Riga Sugar Company Ltd,Sitamarhi

2 4 2 4 2 4


1 1 1 1 1 1

BDBPL 2 3 2 3 2 3

Open Market Purchase 368 554 1,536

IEX/PXIL - 368 554 1,536

DB Power -

JAYPEE NIGRIE -

GMR ETL -

TATA ETL -

Manikaran Power -

NEA -

NVVNL - -

PVVNL - -

KSEB- Short Term

Tata Power - Short Term

PTC -Ostro Kutch - Short Term

PTC-Short Term

Adani Short Term

UI - - - -

Solar REC to meet RPO

Non-solar REC to meet RPO

Sub Total Power Purchase 3,334 17,815 3,455 19,876 4,450 22,130

5.8.5. The Petitioner requests the Hon’ble Commission to approve the aforementioned revised

power purchase quantity for the period of 3rd Control Period.

5.9. Energy Balance

5.9.1. Based on above discussed elements such as sales, losses & power availability, the

revised projected energy balance for the 3rd control period is as under –



Table 86: Energy Balancing for ARR for 3rd Control Period

Sl. No. Particulars Unit FY 2019-20 FY 2020-21 FY 2021-22

A Energy sales MU 14,240.66 15,889.09 17,735.58

B Distribution loss % 15% 15% 15%

C Distribution loss (AxB/(1-B) MU 2,513.06 2,803.96 3,129.81

D Energy required at Distribution periphery (A+D)

MU 16,753.72 18,693.05 20,865.39

E State Transmission loss % 3.92% 3.92% 3.92%

F State Transmission loss (DxE/(1-E)

MU 683.54 762.66 851.29

G Energy required at State Transmission periphery (D+F)

MU 17,437.26 19,455.71 21,716.69

5.10. Renewable Power Purchase Obligation

5.10.1. It is submitted that Hon’ble Commission has notified the BERC (Renewable Purchase

Obligation, its Compliance and REC Framework Implementation) Regulations, 2010 and

BERC (Terms and Conditions for Tariff Determination from Solar Energy Sources)

Regulations, 2010. Further, there were amendments in both regulations in September 2012

wherein the Solar RPO was modified.

5.10.2. The Licensees are already taking steps to ensure that they enhance their Renewable

Energy mix and accordingly anticipate addition in Solar power as provided in the

following table; however the PPAs are still to be signed and executed

5.10.3. The details of RPO to be met by the Petitioner for the 3rd control period are given in the

table below –

Table 85: Renewable energy purchase obligation for FY 2019-20

Sl. No. Particulars Units FY 2019-20 FY 2020-21 FY 2021-22

1 Energy consumption excluding Nepal MU 14,241 15,889 17,736

2 % of RPO Obligation % 11.50% 14.25% 17.00%

3 Solar % 4.75% 6.75% 8.00%

4 Non-Solar % 6.75% 7.50% 9.00%

5 MUs required as per RPO for the year MU 1,638 2,264 3,015

6 Solar MU 676 1,073 1,419

7 Non-Solar MU 961 1,192 1,596

8 Solar Energy to be procured during the year

MU 112.91 112.91 1466.32



Sl. No. Particulars Units FY 2019-20 FY 2020-21 FY 2021-22

9 Non-Solar Energy to be procured during the year

MU 606.72 606.72 843.24

10 Balance Solar to be procured MU 564 960 -47

11 Balance Non-Solar to be procured MU 355 585 753

5.10.4. The Petitioner has made plan to achieve target of solar power under RPO. The

Petitioner submits that the shortfall may please be allowed to be met though purchase of

REC.


5.11.1. The power purchase cost mainly comprises of fixed charges and energy charges for

two part tariff stations i.e. NTPC, NHPC & PTC in case of Petitioner. The Petitioner

has considered the actual energy charges and fixed cost for these power stations

based on actual previous 12 months month wise data. Average power purchase cost

as mentioned below.

i. Petitioner has considered the new plants whose COD is in the 3rd control period with

the latest information on COD to ensure projections from realistic point of view.

ii. The power purchase cost projections have been made by taking the average of

fixed costs and fuel costs of the 12 months data of FY 2018-19 which consists 6

months actuals and 6 months projections as mentioned in the APR. Using this

projections of FY 2019-20 have been made and 4% increase is taken on FY 2018-19

PP cost.

Sl.

No.

Particulars Assumption

1 Power Purchase

Quantum

Net Power Purchase Quantum is derived as a product of respective power plants MW capacity, plant load factor (PLF) and Bihar state's share in respective power plant. Further the quantum is approved as per Merit order despatch principles. We have also referred to the actual plant load factor of such stations

for the last 2 years while projecting the PLF for the Control period.

2 Fixed Charges Fixed charges are computed after considering Bihar state's allocated

share in respective power plant as latest available bills of the

generating station. Further the escalation factor has been considered

@ 4%.

3 Variable Charge Variable cost is considered as per the recent energy bills raised for the

period 2018-19. Further, the escalation factor has been considered @

4%.



5.11.2. Summary of assumptions for projecting the Power purchase cost for NTPC plants

5.11.3. Summary of assumptions for projecting the Power purchase cost for NHPC plants

Sl.

No.

Particulars Assumption

1 Power Purchase

Quantum

Net Power Purchase Quantum is derived as a product of respective power plants MW capacity, plant load factor (PLF) and Bihar state's share in respective power plant. Further, the quantum is approved as per Merit order despatch principles. We have also referred to the actual plant load factor of such stations for

the last 2 years while projecting the PLF for the Control period.

2 Fixed Charges Fixed charges are computed after considering Bihar state's allocated

share in respective power plant as latest available bills of the

generating station. Further the escalation factor has been considered

@ 4%.

3 Variable Charge Variable cost is considered as per the recent energy bills raised for the

period 2018-19. Further the escalation factor has been considered @

4%.

5.11.4. Summary of assumptions for projecting the Power purchase cost for IPPs/JVs plants

S. No. Particulars Assumption

1 Power Purchase Quantum

Net Power Purchase Quantum is derived as a product of respective

power plants MW capacity, capacity factor and Bihar state's share in

respective power plant.

2 Tariff (Single part & Two part)

Fixed and Variable Charges have been considered as per the recent

energy bills raised for the period FY 2018-19. Further, the escalation

factor has been considered @ 4%.

5.11.5. Power purchase costs: The table here provides detailed power purchase costs –



Table 87: Detailed power purchase costs for FY 2019-20 (in INR Crore)

Name of The Source Share allocated

(MW)

Units purchased

(MU)

PLF (%)

Fixed Cost

(Rs/kWh)

Fixed charge

(Rs Crs)

Energy Cost

(Rs/kWh)

Energy cost (Rs

Crs)

Misc. cost (Rs

Crs)

Total Cost (Rs Crs)

Average Cost

Central Sector Stations 2,391 13,130 62.53% 1.337 1,756.15 2.612 3,429.07 - 5,185.22 3.95

Talcher – I ( 2 x 500 MW) 223 1,541 78.8% 1.05 161.58 1.86 286.60 448.19 2.91

Farakka – I & II (1600 MW) 271 1,739 73.0% 0.96 167.75 2.49 433.86 601.61 3.46

Farakka – III (500 MW) 72 491 78.1% 1.68 82.65 2.51 123.15 205.80 4.19

Kahalgaon – I (840 MW) 190 1,239 74.3% 1.32 163.44 2.48 307.78 471.22 3.80

Kahalgaon – II (1500 MW) 40 286 80.7% 1.10 31.47 2.41 69.01 100.49 3.52

Barh-II 542 3,735 78.4% 2.00 747.99 2.49 930.73 1,678.71 4.49

Korba 14 97 81.8% 1.37 13.31 1.33 12.93 26.24 2.70

Rangit – HEP 11 96 96.0% 2.01 19.24 2.08 19.87 39.11 4.09

Teesta - HEP 59 321 62.5% 1.07 34.49 1.20 38.62 73.11 2.27

Chukha 43 272 71.7% - - 2.47 67.14 67.14 2.47

Tala 140 374 30.3% - - 2.25 84.04 84.04 2.25

Barh Stage-I (3 X 660 MW) - - - - - - - -

KBUNL 1 59 309 59.2% 1.44 44.36 3.74 115.60 159.96 5.18

KBUNL 2 143 899 71.8% 2.70 242.65 2.92 262.60 505.25 5.62

Barauni Stage I 119 600 85.0% - 4.10 246.15 246.15 4.10

Barauni Stage II 135 227 85.0% - 3.97 90.28 90.28 3.97

PFC_ Medium Term 108 133 14.0% - - 4.24 56.21 56.21 4.24

Talcher-II (2x500) - - - -

Arun –III - - - -

Mangdechhu, HEP, 135 468 40.0% - - 4.00 187.32 - 187.32 4.00

Punatsangchhu & - - - -


- - - -

Darlipalli STPS (4 X 800 MW) 87 303 85.0% 1.56 47.22 3.21 97.16 - 144.37 4.77




(MW)

Units purchased

(MU)

PLF (%)

Fixed Cost

(Rs/kWh)

Fixed charge

(Rs Crs)

Energy Cost

(Rs/kWh)

Energy cost (Rs

Crs)

Misc. cost (Rs

Crs)

Total Cost (Rs Crs)

Average Cost

TAWANG-I - - - -

TAWANAG-II - - - -

TEESTA-IV - - - -

State Generating Stations 5 3 7.1% - - 2.59 0.87 - 0.87 2.59

Small Hydro (BSHPCL) 5 3 7.1% - - 2.59 0.87 - 0.87 2.59

IPP 290 1,719 69% 2.516 432.32 1.11 190.02 72.59 694.93 4.04

GMR Kamalanga Energy 128 928 83% 2.03 188.14 1.07 99.58 72.39 360.11 3.88

JITPL 162 791 17% 3.09 244.19 1.14 90.44 0.20 334.82 4.24

JV projects 308 1,879 71% 2.02 378.89 1.69 316.61 - 695.50 3.70

Nabinagar Railway (4 X 250 Mw) 54 141 30% 2.71 38.27 0.39 5.53 43.81 3.10

Nabinagar Stage-I (3 X 660 254 1,738 85% 1.96 340.62 1.79 311.08 - 651.70 3.75

Nabinagar JV (3 X 660 MW) Stage-II - - - - - - - - -

Renewable 340 716 70.52% - - 3.68 263.57 0.14 263.71 3.68

SECI-Solar 5 9 19% - - 5.50 5.01 0.14 5.15 5.66

SECI-Wind-300 MW 108 224 24% - 2.52 56.36 - 56.36 2.52

PTC-Wind- 300 MW 108 224 24% - 2.52 56.36 - 56.36 2.52

SECI-Solar -500 MW - -

NTPC-Nokh - 500 MW - -

NTPC-Solar -500 MW - -

ACME Magadh 5 9 0.18 - 8.73 7.58 - 7.58 8.73

ACME Nalanda 8 13 0.18 - 8.73 11.07 - 11.07 8.73

Sunmark 5 9 0.18 - 5.67 4.89 - 4.89 5.67

Avantika 3 3 0.13 - 7.69 2.37 - 2.37 7.69

AZURE 5 7 0.15 - 8.39 5.88 - 5.88 8.39

Udipta Energy & Equipment Pvt ltd 3 4 0.16 - 7.98 3.11 - 3.11 7.98

Glatt 2 3 0.19 - 6.11 1.63 - 1.63 6.11




(MW)

Units purchased

(MU)

PLF (%)

Fixed Cost

(Rs/kWh)

Fixed charge

(Rs Crs)

Energy Cost

(Rs/kWh)

Energy cost (Rs

Crs)

Misc. cost (Rs

Crs)

Total Cost (Rs Crs)

Average Cost

Welspun 2 8 13 0.18 - 8.64 10.90 - 10.90 8.64

Welspun 1 5 8 0.18 - 8.70 7.30 - 7.30 8.70

Welspun 3 8 13 0.18 - 8.65 11.08 - 11.08 8.65

Response Renewable Energy 5 9 0.18 - 5.67 4.92 - 4.92 5.67

ALFA INFRAPOP 8 15 0.21 - 4.76 6.99 - 6.99 4.76

TIRUPATI SUGAR 5 13 0.27 - 3.61 4.62 - 4.62 3.61


4 10 0.30 - 3.71 3.76 - 3.76 3.71

Harinagar Sugar Mills,Harinagar 6 33 0.63 - 4.44 14.49 - 14.49 4.44


6 27 0.51 - 4.91 13.13 - 13.13 4.91

Lauriya Sugar Mill 11 27 0.28 - 3.67 9.78 - 9.78 3.67

Sugauli Sugar Mill 11 25 0.27 - 5.34 13.60 - 13.60 5.34

Hasanpur Sugar Mills,Samastipur 5 14 0.30 - 3.79 5.31 - 5.31 3.79

Riga Sugar Company Ltd,Sitamarhi 2 4 0.27 - 3.62 1.39 - 1.39 3.62

Siddhashram Rice Mill Cluster Pvt Ltd 1 1 0.24 - 5.60 0.64 - 0.64 5.60

BDBPL 2 3 0.19 - 5.35 1.42 - 1.42 5.35

Open Market Purchase 368 - - 4.36 160.25 - 160.25 4.36

IEX/PXIL - 368 - - 4.36 160.25 160.25 4.36

DB Power - -

JAYPEE NIGRIE - -

GMR ETL - -

TATA ETL - -

Manikaran Power - -

NEA - -

NVVNL - - - - - - -

PVVNL - - - - - - -




(MW)

Units purchased

(MU)

PLF (%)

Fixed Cost

(Rs/kWh)

Fixed charge

(Rs Crs)

Energy Cost

(Rs/kWh)

Energy cost (Rs

Crs)

Misc. cost (Rs

Crs)

Total Cost (Rs Crs)

Average Cost

KSEB- Short Term -

Tata Power - Short Term -

PTC -Ostro Kutch - Short Term -

PTC-Short Term -

Adani Short Term - - -

UI - - - - - - - - -

Solar REC to meet RPO 1.00 56.41 -

Non-solar REC to meet RPO 1.25 44.35 -

Sub Total Power Purchase 3,334 17,815 1.44 2,567.37 2.45 4,360.38 72.73 7,101.24 3.99





(MW)

Units purchased

(MU)

PLF (%)

Fixed Cost

(Rs/kWh)

Fixed charge

(Rs Crs)

Energy Cost

(Rs/kWh)

Energy cost (Rs

Crs)

Misc. cost (Rs

Crs)

Total Cost (Rs Crs)

Average Cost


Talcher – I ( 2 x 500 MW) 223 1,541 78.8% 1.09 168.05 1.93 298.07 466.12 3.03

Farakka – I & II (1600 MW) 271 1,739 73.0% 1.00 174.46 2.59 451.21 625.68 3.60

Farakka – III (500 MW) 72 491 78.1% 1.75 85.95 2.61 128.08 214.03 4.36

Kahalgaon – I (840 MW) 190 1,239 74.3% 1.37 169.97 2.58 320.09 490.07 3.96

Kahalgaon – II (1500 MW) 40 286 80.7% 1.15 32.73 2.51 71.77 104.51 3.66

Barh-II 542 3,735 78.4% 2.08 777.91 2.59 967.95 1,745.86 4.67

Korba

Rangit – HEP 11 96 96.0% 2.09 20.01 2.16 20.67 40.68 4.25

Teesta - HEP 59 321 62.5% 1.12 35.87 1.25 40.16 76.03 2.37

Chukha 43 272 71.7% - - 2.47 67.14 67.14 2.47

Tala 140 374 30.3% - - 2.25 84.04 84.04 2.25

Barh Stage-I (3 X 660 MW) - - -

KBUNL 1 59 309 59.2% 1.49 46.14 3.89 120.23 166.36 5.38

KBUNL 2 143 899 71.8% 2.81 252.36 3.04 273.10 525.46 5.84

Barauni Stage I 119 734 85.0% - - 3.49 256.00 256.00 3.49

Barauni Stage II 270 1,668 85.0% - - 3.97 662.07 662.07 3.97

PFC_ Medium Term 108 530 55.0% - - 4.24 224.86 224.86 4.24

Talcher-II (2x660) -

Arun –III -

Mangdechhu, HEP, 135 468 40.0% 2.09 97.97 2.16 101.20 199.17 4.25

Punatsangchhu & - - - -


- 85.0% - - - - -





(MW)

Units purchased

(MU)

PLF (%)

Fixed Cost

(Rs/kWh)

Fixed charge

(Rs Crs)

Energy Cost

(Rs/kWh)

Energy cost (Rs

Crs)

Misc. cost (Rs

Crs)

Total Cost (Rs Crs)

Average Cost

TAWANG-I - - - - -

TAWANAG-II - - - - -

TEESTA-IV - - - - -

State Generating Stations 5 3 7.1% - - 2.69 0.90 - 0.90 2.69


IPP 290 1,719 68.65% 2.616 449.62 1.15 197.62 75.49 722.73 4.21

GMR Kamalanga Energy 128 928 0.83 2.11 195.66 1.12 103.56 75.28 374.51 4.04

JITPL 162 791 0.56 3.21 253.95 1.19 94.06 0.20 348.22 4.40

JV projects 308 1,879 70.52% 2.02 380.43 1.69 316.83 - 697.25 3.71

Nabinagar Railway (4 X 250 Mw) 54 141 30% 2.82 39.80 0.41 5.75 - 45.56 3.23

Nabinagar Stage-I (3 X 660) 254 1,738 85% 1.96 340.62 1.79 311.08 - 651.70 3.75


- - - - - - - - - -

Renewable 340 716 24.41% - - 3.68 263.57 0.15 263.72 3.68

SECI 5 9 19.19% - - 5.50 5.01 0.15 5.15 5.66

SECI-Wind-300 108 224 24.00% 2.520 56.36 - 56.36 2.52

PTC-Wind- 108 224 24.00% 2.520 56.36 - 56.36 2.52

SECI-Solar -500 - 2.750 - - - -

NTPC-Nokh - 500 - 2.800 - - - -

NTPC-Solar -500 -

ACME Magadh 5 9 18.3% - - 8.73 7.58 - 7.58 8.73

ACME Nalanda 8 13 17.8% - - 8.73 11.07 - 11.07 8.73

Sunmark 5 9 18.2% - - 5.67 4.89 - 4.89 5.67

Avantika 3 3 13.0% - - 7.69 2.37 - 2.37 7.69

AZURE 5 7 14.8% - - 8.39 5.88 - 5.88 8.39

Udipta Energy & Equipment Pvt ltd 3 4 16.4% - - 7.98 3.11 - 3.11 7.98




(MW)

Units purchased

(MU)

PLF (%)

Fixed Cost

(Rs/kWh)

Fixed charge

(Rs Crs)

Energy Cost

(Rs/kWh)

Energy cost (Rs

Crs)

Misc. cost (Rs

Crs)

Total Cost (Rs Crs)

Average Cost

Glatt 2 3 18.8% - - 6.11 1.63 - 1.63 6.11

Welspun 2 8 13 17.7% - - 8.64 10.90 - 10.90 8.64

Welspun 1 5 8 17.7% - - 8.70 7.30 - 7.30 8.70

Welspun 3 8 13 18.0% - - 8.65 11.08 - 11.08 8.65

Response Renewable Energy 5 9 18.3% - - 5.67 4.92 - 4.92 5.67

ALFA INFRAPOP 8 15 20.6% - - 4.76 6.99 - 6.99 4.76

TIRUPATI SUGAR 5 13 27.0% - - 3.61 4.62 - 4.62 3.61


4 10 30.5% - - 3.71 3.76 - 3.76 3.71

Harinagar Sugar Mills,Harinagar 6 33 62.5% - - 4.44 14.49 - 14.49 4.44


6 27 51.2% - - 4.91 13.13 - 13.13 4.91

Lauriya Sugar Mill 11 27 28.1% - - 3.67 9.78 - 9.78 3.67

Sugauli Sugar Mill 11 25 26.9% - - 5.34 13.60 - 13.60 5.34

Hasanpur Sugar Mills,Samastipur 5 14 29.6% - - 3.79 5.31 - 5.31 3.79

Riga Sugar Company Ltd,Sitamarhi

2 4 27.0% - - 3.62 1.39 - 1.39 3.62


1 1 23.9% - - 5.60 0.64 - 0.64 5.60

BDBPL 2 3 18.7% - - 5.35 1.42 - 1.42 5.35

Open Market Purchase 554 - - 4.36 241.52 - 241.52 4.36

IEX/PXIL 554 - - - 4.36 241.52 241.52 4.36

DB Power -

JAYPEE NIGRIE -

GMR ETL -

TATA ETL -

Manikaran Power -




(MW)

Units purchased

(MU)

PLF (%)

Fixed Cost

(Rs/kWh)

Fixed charge

(Rs Crs)

Energy Cost

(Rs/kWh)

Energy cost (Rs

Crs)

Misc. cost (Rs

Crs)

Total Cost (Rs Crs)

Average Cost

NEA -

NVVNL -

PVVNL -

KSEB- Short Term -



PTC-Short Term -

Adani Short Term -

UI - - - - - - - - - -

Solar REC to meet RPO 1.00 96.06







(MW)

Units purchased

(MU)

PLF (%)

Fixed Cost

(Rs/kWh)

Fixed charge

(Rs Crs)

Energy Cost

(Rs/kWh)

Energy cost (Rs

Crs)

Misc. cost (Rs

Crs)

Total Cost (Rs Crs)

Average Cost


Talcher – I ( 2 x 500 MW) 223 1,541 79.0% 1.13 174.77 2.01 309.99 - 484.76 3.15

Farakka – I & II (1600 MW) 271 1,739 73.2% 1.04 181.44 2.70 469.26 - 650.70 3.74

Farakka – III (500 MW) 72 491 78.3% 1.82 89.39 2.71 133.20 - 222.60 4.53

Kahalgaon – I (840 MW) 190 1,239 74.5% 1.43 176.77 2.69 332.90 - 509.67 4.11

Kahalgaon – II (1500 MW) 40 286 80.9% 1.19 34.04 2.61 74.64 - 108.69 3.80

Barh-II 542 3,735 78.6% 2.17 809.02 2.70 1,006.67 - 1,815.70 4.86

Korba - - - - - - -

Rangit – HEP 11 96 96.3% 2.18 20.81 2.25 21.49 - 42.30 4.42

Teesta - HEP 59 321 62.7% 1.16 37.30 1.30 41.77 - 79.07 2.46

Chukha 43 272 71.9% - - 2.47 67.14 - 67.14 2.47

Tala 140 374 30.4% - - 2.25 84.04 - 84.04 2.25

Barh Stage-I (3 X 660 MW) 185 - 85.0% - - - - -

KBUNL 1 59 309 59.4% 1.79 55.36 4.67 144.27 - 199.64 6.46

KBUNL 2 143 899 72.0% 2.92 262.45 3.16 284.03 - 546.48 6.08

Barauni Stage I 119 734 70.3% - - 3.63 266.24 - 266.24 3.63

Barauni Stage II 270 1,880 85.0% - - 3.66 688.55 - 688.55 3.66

PFC_ Medium Term - - -

Talcher-II (2x660) - - 85.0% - - - - -

Arun –III - - 40.0% - - - - -

Mangdechhu, HEP, 135 468 40.0% 2.18 101.89 2.25 105.24 - 207.13 4.42

Punatsangchhu & - - - - - - -


- - - - -





(MW)

Units purchased

(MU)

PLF (%)

Fixed Cost

(Rs/kWh)

Fixed charge

(Rs Crs)

Energy Cost

(Rs/kWh)

Energy cost (Rs

Crs)

Misc. cost (Rs

Crs)

Total Cost (Rs Crs)

Average Cost

TAWANG-I - - - - - - -

TAWANAG-II - - - - - - -

TEESTA-IV - - - - - - -

State Generating Stations 5 3 7% - - 2.80 0.94 - 0.94 2.80


IPP 290 1,719 67.71% 5.53 467.60 2.40 205.53 78.51 751.64 4.37

GMR Kamalanga Energy 128 928 83% 2.19 203.49 1.16 107.71 78.30 389.49 4.20

JITPL 162 791 56% 3.34 264.11 1.24 97.82 0.21 362.14 4.58

JV projects 308 1,879 7.18% 2.11 395.64 1.75 329.50 - 725.14 3.86

Nabinagar Railway (4 X 250 Mw) 54 141 30% 2.93 41.40 0.42 5.98 - 47.38 3.36

Nabinagar Stage-I (3 X 660) 254 1,738 85% 2.04 354.25 1.86 323.52 - 677.76 3.90

Nabinagar JV (3 X 660 MW) Stage-II - - - - - - - - - -

Renewable 1,258 2,306 21.22% - - 2.99 690.40 0.15 690.55 2.99

SECI 5 9 19.19% - - 5.50 5.01 0.15 5.16 5.67

SECI-Wind-300 216 456 24.00% 2.52 114.88 - 114.88 2.52

PTC-Wind- 108 228 24.00% 2.52 57.44 - 57.44 2.52

SECI-Solar -500 270 451 19.00% 2.75 124.06 - 124.06 2.75

NTPC-Nokh - 500 270 451 19.00% 2.80 126.32 - 126.32 2.80

NTPC-Solar -500 270 451 19.00% 2.59 116.84 - 116.84 2.59

ACME Magadh 5 9 18.30% - - 8.73 7.58 - 7.58 8.73

ACME Nalanda 8 13 17.82% - - 8.73 11.07 - 11.07 8.73

Sunmark 5 9 18.17% - - 5.67 4.89 - 4.89 5.67

Avantika 3 3 12.97% - - 7.69 2.37 - 2.37 7.69

AZURE 5 7 14.76% - - 8.39 5.88 - 5.88 8.39

Udipta Energy & Equipment Pvt ltd 3 4 16.44% - - 7.98 3.11 - 3.11 7.98

Glatt 2 3 18.75% - - 6.11 1.63 - 1.63 6.11




(MW)

Units purchased

(MU)

PLF (%)

Fixed Cost

(Rs/kWh)

Fixed charge

(Rs Crs)

Energy Cost

(Rs/kWh)

Energy cost (Rs

Crs)

Misc. cost (Rs

Crs)

Total Cost (Rs Crs)

Average Cost

Welspun 2 8 13 17.73% - - 8.64 10.90 - 10.90 8.64

Welspun 1 5 8 17.69% - - 8.70 7.30 - 7.30 8.70

Welspun 3 8 13 18.01% - - 8.65 11.08 - 11.08 8.65

Response Renewable Energy 5 9 18.30% - - 5.67 4.92 - 4.92 5.67

ALFA INFRAPOP 8 15 20.64% - - 4.76 6.99 - 6.99 4.76

TIRUPATI SUGAR 5 13 26.98% - - 3.61 4.62 - 4.62 3.61


4 10 30.50% - - 3.71 3.76 - 3.76 3.71

Harinagar Sugar Mills,Harinagar 6 33 62.54% - - 4.44 14.49 - 14.49 4.44


6 27 51.25% - - 4.91 13.13 - 13.13 4.91

Lauriya Sugar Mill 11 27 28.09% - - 3.67 9.78 - 9.78 3.67

Sugauli Sugar Mill 11 25 26.85% - - 5.34 13.60 - 13.60 5.34

Hasanpur Sugar Mills,Samastipur 5 14 29.56% - - 3.79 5.31 - 5.31 3.79

Riga Sugar Company Ltd,Sitamarhi 2 4 26.97% - - 3.62 1.39 - 1.39 3.62

Siddhashram Rice Mill Cluster Pvt Ltd 1 1 23.93% - - 5.60 0.64 - 0.64 5.60

BDBPL 2 3 18.67% - - 5.35 1.42 - 1.42 5.35

Open Market Purchase 1,536 - - 4.36 669.56 - 669.56 4.36

IEX/PXIL 1,536 - - - 4.36 669.56 669.56 4.36

DB Power -

JAYPEE NIGRIE -

GMR ETL -

TATA ETL -

Manikaran Power -

NEA -

NVVNL -




(MW)

Units purchased

(MU)

PLF (%)

Fixed Cost

(Rs/kWh)

Fixed charge

(Rs Crs)

Energy Cost

(Rs/kWh)

Energy cost (Rs

Crs)

Misc. cost (Rs

Crs)

Total Cost (Rs Crs)

Average Cost

PVVNL -

KSEB- Short Term -



PTC-Short Term -

Adani Short Term -

UI -

Solar REC to meet RPO 1.00 -





5.11.6. The Petitioner has made PPA agreements with the new plants according to 24x7 Power

For All MoU but considering the reality, the expected COD from the plants have been

considered reasonably. The average cost of power calculated above is subjected to

change on actual basis since power drawl from open market will be available which is

subjected to Annual performance review and true up process.

5.11.7. We humbly request the Hon’ble Commission to approve the above mentioned

projected power purchase costs for the period the 3rd control period.

5.12. Transmission Charges

5.12.1. It is submitted that the Petitioner has to pay transmission charges to PGCIL for use of

transmission facilities enabling power drawl from eastern region. The calculation of

PGCIL charges is done considering 6 months actuals, 6 months projection and then

adding some growth rate as per the increase in the power purchase.

5.12.2. Further the Petitioner also pays BSPTCL, POSOCO charges and Open Access

charges which are projected in the similar way as projected for PGCIL charges.

5.12.3. We request the Hon’ble Commission to approve the transmission and related

charges for inter-state as well as intra-state transmission transactions for 3rd control period

as per the below table:

Table 88: Transmission charges for ARR (in INR Crore)

S. No. Particulars FY 2019-20 FY 2020-21 FY 2021-22

1 PGCIL Charge 566.69 595.02 624.77

2 POSOCO & SLDC Charges 5.83 6.12 6.42

3 BSPTCL charges 778.80 895.61 1,029.96

4 BGCL 180.12 207.14 238.21

5 Total Transmission Purchase 1,531.43 1,703.89 1,899.36

5.12.4. We humbly request the Hon’ble Commission to approve the aforementioned transmission

charges for the 3rd control period.


5.13.1. The Petitioner has computed the capitalization of investment on the assumption that 80% of

the opening CWIP will get capitalized every year and 20% of the fresh investment is would

capitalize. During FY 2018-19 huge capitalization will be done owing to capitalization in

BRGF schemes, chief Minister’s seven resolution scheme, IPDS, DDUGJY etc.

Table 89: Capitalization in 3rd Control Period(in INR Crore)

S.N Name of scheme FY 2019-20 FY 2020-21 FY 2021-22

Ongoing Schemes



S.N Name of scheme FY 2019-20 FY 2020-21 FY 2021-22

1 BRGF 268.98 29.89 -

2 R-APDRP 108.46 0.00 -

3 NABARD Phase VIII - 0.00 -

4 NABARD Phase XI 16.67 0.00 -

5 MP/CM LAD 1.99 2.24 2.49

6 Deposit Scheme 4.08 4.46 4.89

7 ADB 25.13 20.15 2.24

8 ACA State Plan 15.74 6.29 2.52

9 Burnt DTR State Plan - 0.00 -

10 State Plan 121.08 126.43 131.57

Subtotal(A) 562.12 189.46 143.71

11 Re-conductoring 600.00 420.80 106.20

12 IPDS 646.92 54.14 35.73

Subtotal(B) 1246.92 474.94 141.93

13 RGGVY 379.66 494.77 197.91

Subtotal(c) 379.66 494.77 197.91

New Schemes

14 DDUGJY 1,335.51 333.88 -

15 APL Connection 164.29 0.00 -

Subtotal(D) 1499.79 333.88 0.00

Grand Total (A+B+C+D) 3688.49 1493.05 483.55

16 Own Sources 105.59 81.44 75.70

Total 3794.09 1574.49 559.25

5.13.2. The Petitioner has allocated the investments through various schemes into grant, Loan and

Equity. The said allocation is based on the actual source from which funds were received by

the Petitioner. The Petitioner has provided the detailed capitalization plan to the Hon’ble

Commission as required in the tariff formats.

5.13.3. The Capitalization plan bifurcated into various sources of funds is as follows –

Table 90: Capital works in progress for 3rd Control Period (in INR Crore)

S. No. Particulars Ensuing year (FY 2019-20)

Ensuing year (FY 2020-21)


1 Opening CWIP 1,776.08 949.41 583.35

2 New Investment 2,967.62 1,208.51 278.00

3 Less Capitalization 3,794.29 1,574.57 559.29

(a) CWIP 3,035.43 1,259.66 447.43

(b) New Investment 758.86 314.91 111.86

4 Closing CWIP (1+2-3) 949.41 583.35 302.06

5 Funding

(a) CWIP Capitalization 3,035.43 1,259.66 447.43

(i) Grant 1,321.97 547.84 165.55

(ii) Loan 643.90 148.82 26.20

(iii) Equity 1,069.56 562.99 255.68

(b) New Investment Capitalization 758.86 314.91 111.86

(i) Grant 330.49 136.96 41.39



S. No. Particulars Ensuing year (FY 2019-20)



(ii) Loan 160.98 37.21 6.55

(iii) Equity 267.39 140.75 63.92

6 Total capitalization 3,794.29 1,574.57 559.29

(i) Total Grant 1,652.46 684.80 206.94

(ii) Total Loan 804.88 186.03 32.75

(iii) Equity 1,336.95 703.74 319.60

5.13.4. The Petitioner would like to submit that the sources of funds under each scheme is as per

the sanctioned documents for every scheme.

5.13.5. Therefore, the Petitioner requests the Hon’ble Commission to approve the

Capitalization plan as estimated by the Petitioner.



opening fixed assets, capitalization as per the new schemes in the 3rd Control Period.

5.14.2. In addition to ongoing schemes, various new schemes were introduced like Chief Minister’s

Bijli Yojana, DDUGJY and IPDS etc.

5.14.3. The below table demonstrates the Asset addition planned during the control period and

closing balance of Gross Fixed Assets for 3rd control period –

Table 91: GFA for FY 2019-20 (in INR Crore)

Sl. No.

Assets group Closing balance at the end of

Previous Year

Addition during ensuing year

Closing balance at the end of ensuing

year

1 Land and land rights 2,612.34 879.63 3,491.98 2 Buildings 79.71 26.84 106.55 3 Hydraulic works 0.57 0.19 0.76 4 Other civil works 51.07 17.20 68.27 5 Plant and Machinery 2,236.22 752.98 2,989.20 6 Lines and cable network 6,272.28 2,112.02 8,384.29 7 Vehicles 2.27 0.77 3.04 8 Furniture and Fixtures 5.49 1.85 7.34 9 Office equipment 5.79 1.95 7.75 10 Spare unit/service unit 2.02 0.68 2.71

11

Assets taken over from licensees pending final valuation

0.55 0.19 0.74

Total 11,268.31 3,794.29 15,062.60


Sl. No.


Previous Year



year

1 Land and land rights 3,491.98 365.03 3,857.01



Sl. No.


Previous Year



year

2 Buildings 106.55 11.14 117.68

3 Hydraulic works 0.76 0.08 0.84

4 Other civil works 68.27 7.14 75.40


6 Lines and cable network 8,384.29 876.45 9,260.75

7 Vehicles 3.04 0.32 3.36


9 Office equipment 7.75 0.81 8.56

10 Spare unit/service unit 2.71 0.28 2.99

11


0.74 0.08 0.81

Total 15,062.60 1,574.57 16,637.18


Sl. No.


Previous Year



year

1 Land and land rights 3,857.01 129.66 3,986.67

2 Buildings 117.68 3.96 121.64

3 Hydraulic works 0.84 0.03 0.87

4 Other civil works 75.40 2.53 77.94


6 Lines and cable network 9,260.75 311.32 9,572.06

7 Vehicles 3.36 0.11 3.47


9 Office equipment 8.56 0.29 8.84

10 Spare unit/service unit 2.99 0.10 3.09

11


0.81 0.03 0.84

Total 16,637.18 559.29 17,196.46

5.14.4. The Petitioner would like to submit that asset additions are done as per the

Capitalization plan an as per the approved schemes.

5.14.5. The Hon’ble Commission is requested to approve the GFA as estimated by the Petitioner

for the 3rd Control Period.

5.15. Depreciation on GFA

5.15.1. The depreciation has been computed annually based on straight line method by

applying weighted average rate of depreciation on the average GFA. For this purpose, the

Petitioner has adopted the Regulation 23 of the Bihar Electricity Regulatory Commission

(Multi Year Distribution Tariff) Regulations, 2018. The Petitioner has followed Straight line

depreciation method while calculating depreciation for the 3rd control period.



5.15.2. The rate of depreciations has been taken as per the annual accounts of the True Up year.

The Petitioner has reduced the depreciation on assets created out of Grants from the

gross depreciation to arrive at the net depreciation to be charged. The computation of

depreciation on the assets created out of Grants is based on the actual ratio of ‘Grants’ in

GFA.

5.15.3. Also it is to bring into kind attention of the Hon’ble Commission that the balance of GFA in

the beginning of the year and additions during the year does not include the value of Land

as it is a non-depreciable asset.

5.15.4. The table provided below demonstrates the depreciation projected by the Petitioner for

the 3rd control period –

Table 92: Depreciation on GFA (in INR Crore)


Gross fixed assets of the beginning of the year 8,655.97 11,570.63 12,780.17

Additions during the year 2,914.66 1,209.54 429.63

IDC - - -

Adjustment for assets sold/discarded etc - - -

Closing GFA 11,570.63 12,780.17 13,209.79

Average GFA 10,113.30 12,175.40 12,994.98

Weighted Average Rate of Depreciation 5.30% 4.87% 4.71%

Gross Depreciation at the end of the year 536.32 592.39 612.30

Opening grants 4,155.94 5,808.40 6,493.20

Grants during the year 1,652.46 684.80 206.94

Adjustment for assets sold/discarded etc

Total Grants 5,808.40 6,493.20 6,700.14

Average Grants 4,982.17 6,150.80 6,596.67

Weighted Average rate of Depreciation 4.15% 3.76% 3.62%

Depreciation for GFA on Grants 206.82 231.20 238.57

Net Depreciation of GFA on loans (8-15) 329.51 361.19 373.73

5.15.5. As seen from the above table it is clearly evident that the Petitioner has deducted the

depreciation on those fixed assets which are funded through grants. It is requested to the

Hon’ble Commission to allow the depreciation as provided above.

5.16. Interest on Loans

5.16.1. The Petitioner submits that the calculation of interest on Project loans is as per

Regulation 25 of the BERC Multi-Year Tariff Regulations 2018.

5.16.2. The Petitioner has provided detailed loan schedule depicting the project Loans and their

additions and repayment during the year. Detailed Loan schedule for the 3rd Control

Period is provided in the table below –

Table 93: Detailed loan schedule for FY 2019-20 (in INR Crore)

S. No.

Particulars Opening balance

Rate of interest

Addition during

the year


year

Closing balance

Amount of interest to

be paid

1 REC (RGGVY) Term 82.19 11% - 82.19 9.04



Loan

2 REC (R-APDRP) Term Loan

349.26 10% - 349.26 36.32

3 PFC (R-APDRP) Term Loan

173.56 9% 1.85 171.71 15.54

4 PFC (APDRP) Term Loan

- 9% - - -

5 PFC (BRGF) Term Loan

- 10% - - -

6 REC (BRGF) Term Loan

- 10% - - -

7 State Govt.-Non-Plan Loan

- 13% - - -

8 BSPHCL (ADB) Loan - 13% - - -

9 Canara Bank Term Loan

56.57 10% - 56.57 5.66

10 Working Capital Loan 79.61 10% 79.61 - 3.98

Total 741.19 81.46 659.73 70.54


700.46

Weighted Average Rate of Interest

10.07%


S. No.


Rate of interest

Addition during

the year


year

Closing balance


be paid

1 REC (RGGVY) Term Loan

82.19 11% - 82.19 9.04


349.26 10% - 349.26 36.32


171.71 9% 1.85 169.86 15.37


- 9% - - -


- 10% - - -


- 10% - - -


- 13% - - -



56.57 10% - 56.57

10 Working Capital Loan - 10% - -

Total 603.16 1.85 601.31 60.73


602.24


10.08%




S. No.


Rate of interest

Addition during

the year


year

Closing balance


be paid

1 REC (RGGVY) Term Loan

82.19 11% - 82.19 9.04


349.26 10% - 349.26 36.32


169.86 9% 1.85 168.01 15.20


- 9% - - -


- 10% - - -


- 10% - - -


- 13% - - -



56.57 10% - 56.57 5.66

10 Working Capital Loan - 10% - - -

Total 657.88 1.85 656.03 66.23


659.96


10.08%

5.16.3. The interest on normative debt is calculated on the 70% of the amount of capital assets

reduced by the value of grants and depreciation representing normative repayment.

5.16.4. The below table demonstrates the computation of interest on normative debt for the 3rd

Control Period

Table 95: Interest on normative debt for the 3rd Control Period (in INR Crore)

S.N Particulars FY 2019-20 FY 2020-21 FY 2021-22

1 Amount of total asset at the beginning of the year 7,887.82 10,543.82 11,646.02

2 Less: asset created from grant at beginning 2,909.16 4,065.88 4,545.24

3 Addition during the year 2,656.00 1,102.20 391.50

4 Less: asset created from grant during the year 1,156.72 479.36 144.86

5 Net asset 6,477.94 7,100.78 7,347.43

6 Less: Normative repayment 329.51 361.19 373.73

7 Amount of debt(loan) 6,148.44 6,739.59 6,973.69

8 Average debt 5,563.55 6,608.77 7,037.24

9 Amount eligible for return 5,563.55 6,608.77 7,037.24

10 Actual Weighted Average Rate of Interest 10.07% 10.08% 10.08%

Amount of Interest on Loan 560.27 666.49 709.40

5.16.5. It is requested to the Hon’ble Commission to approve INR 642.69 Crore towards interest

on normative debt.

5.17. Other Financial Charges



5.17.1. The Petitioner is incurring other Finance charges i.e. Discount to consumers for timely

payment of bills, power factor rebate, interest to suppliers/contractors etc. The

Petitioner is claiming other Finance charges by escalating the charges estimated for FY

2018-19 by 10% for FY 2019-20 and so on.

Table 96: Other finance charges (in INR Crore)

Sl. No

Particulars Projections for FY 2019-20

Projections for FY 2020-21

Projections for FY 2021-22

1 Expenses estimated in previous year 44.63 49.09 54

2 Inflationary index 10% 10% 10%

3 Finance charges estimated 49.09 54.00 59.40

5.17.2. Therefore, the Petitioner requests the Hon’ble Commission to allow the aforementioned

Finance charges for the 3rd control period.

5.18. Operation & Maintenance (O&M) Expenses

5.18.1. O&M expenses are detailed in this section comprising of Repair and maintenance

expenses, Administrative & General expenses and employee expenses. The O&M

expenses are estimated as per regulation 22 of BERC Multi-Year Tariff Regulations, 2018

as provided below:

“22.1 Employee Cost Employee cost shall be computed as per the approved norm escalated by consumer price index (CPI), adjusted by provisions for expenses beyond the control of the Distribution Licensee and one time expected expenses, such as recovery/adjustment of terminal benefits, implications of pay commission, arrears and Interim Relief, governed by the following formula: EMPn = (EMPb * CPI inflation) + Provision Where: EMPn : Employee expense for the year n EMPb : Employee expense as per the norm CPI inflation : is the average increase in the Consumer Price Index (CPI) for immediately preceding three years Provision: Provision for expenses beyond control of the Distribution Licensee and expected one-time expenses as specified above. Till the norms are specified by the Commission the employee cost shall be determined on the basis of actual historical cost.”

5.18.2. Employee cost: While estimating for employee cost the Petitioner has considered the

Regulation 22.1 of the BERC Multi-Year Tariff Regulations, 2018. The CPI inflation index

as considered for FY 2018-19 has been used for projection of employee cost of the 3rd

control period.

5.18.3. The employee expenses projected by the Petitioner for the 3rd control period is

demonstrated as below.



Table 98: Employee expenses for the 3rd Control Period (in INR Crore)

S.N Particulars FY 19-20 (Projection)

FY 20-21 (Projection)


1 Employee Cost of the Previous Year 397.08 406.59 416.33

2 Inflationary Index 2.40% 2.40% 2.40%

3 Inflationary Increase 9.51 9.74 9.97

4 Employee Cost 406.59 416.33 426.30

5 Less: Capitalization 0.00 0.00 0.00

6 Total Employee Cost 406.59 416.33 426.30

5.18.4. In the light of the above explanation the Petitioner would request the Commission to allow

the employee expenses as mentioned above.

5.18.5. Repair and maintenance expenses: The R&M expenses primarily includes expenses

incurred by the Petitioner related to repair of different class of fixed assets etc. Regulation


Regulations, 2018 provides methodology for calculation of Employee Cost as follows:

“22.2 Repairs and Maintenance (R&M) Expense Repairs and Maintenance expense shall be calculated as percentage (as per the norm determined) of Opening Gross Fixed Assets for the year governed by following formula: R&Mn = Kb * GFAn Where: R&Mn : Repairs & Maintenance expense for nth year GFAn : Opening Gross Fixed Assets for nth year Kb : Percentage point as per the norm”

5.18.5.1. The Petitioner has accordingly computed the ‘K’ factor (i.e. R&M norm) based on

previous 2 (two) years as provided below.

Table 99: Calculation of “K” Factor & R&M Expense for 3rd Control Period

Particulars FY 17-18 FY 18-19 FY 19-20 FY 20-21 FY 21-22

Opening GFA (in INR Crore) 5,667.06 6,626.28 11,268.31 15,062.60 16,637.18

R&M Cost (in INR Crore) 98.71 116.08 201.74 266.28 294.85

% of R&M Cost on Opening GFA 1.74% 1.75% 1.79% 1.77% 1.77%

K Factor considered 1.75% 1.79% 1.77% 1.77% 1.78%

5.18.6. In light of the above calculations it is prayed to the Hon’ble Commission to allow the

expenses for R&M.

5.18.7. Administration and General Expenses: As per Regulation 22.3, of BERC MYT Tariff

Regulations, 2018 A&G expense shall be computed as per the norm escalated by

wholesale price index (WPI), adjusted by provisions for confirmed initiatives (IT and

other initiatives as proposed by the Distribution Licensee and validated by the



Commission) or other expected one-time expense. The relevant Regulation has been

extracted below:

“22.3 Administrative and General (A&G) Expense A&G expense shall be computed as per the norm escalated by wholesale price index (WPI) and adjusted by provisions for confirmed initiatives (IT etc. initiatives as proposed by the Distribution Licensee and validated by the Commission) or other expected one-time expenses, and shall be governed by following formula: A&Gn = (A&Gb * WPI inflation) + Provision Where: A&Gn: A&G expense for the year n A&Gb: A&G expense as per the norm WPI inflation: is the average increase in the Wholesale Price Index (WPI) for immediately preceding three years Provision: Cost for initiatives or other one-time expenses as proposed by the Distribution Licensee and validated by the Commission. Till the norms of A&G expenses is specified by the Commission, the actual historical cost will be considered for determination of A&G expenses.”

5.18.8. As there are no norms yet specified for the projection of A&G expenses, therefore the

Petitioner has considered the escalation index as used for projection of A&G expense

for FY 2018-19 and has increased it in same proportion for the 3rd control period.

5.18.9. Below is the projection for FY 2018-19 for A&G expenses:-

Table 101: A&G expenses for ARR (in INR Crore)

S.N Particulars FY 19-20 (Projection)



1 A&G Expense for previous year 74.56 75.71 76.87

2 WPI Inflationary Index (%) 1.54% 1.54% 1.54%

3 Inflationary increase (1*2) 1.15 1.17 1.19

4 A&G expenses (1+3) 75.71 76.87 78.06

5.18.10. The Petitioner therefore requests the Hon’ble Commission to approve the A&G

expense as provided above for the control period.

5.18.11. Allocation of Holding Company cost: The Petitioner is claiming the holding company

expenses by escalating the expenses projected for FY 2018-19 in Annual performance

review by 10%.

5.18.12. The below table represents the allocation of Holding Company cost towards Petitioner

for FY 2018-19:-

Table 102: Holding company cost for 3rd Control Period (in INR Crore)

Sl. No Particulars FY 2019-20 (FY 2018-19)

FY 2020-21 FY 2021-22

1 Previous year expenses 11.75 12.92 14.22

2 Inflation rate considered 10% 10% 10%

3 Inflationary increase (1*2) 1.17 1.29 1.42

7 Total 12.92 14.22 15.64



5.18.13. The Petitioner requests the Hon’ble Commission to approve the above Holding

Company cost.

5.19. Return on Equity

5.19.1. The Petitioner has projected Return on Equity as per Regulation 27 of the BERC Multi

Year Distribution Tariff Regulations 2018 as extracted below:.

“(a) Return on equity shall be computed on 30% of the capital base or actual equity, whichever is lower.

Provided that assets funded by consumer contribution, capital subsidies/ grants and corresponding depreciation shall not form part of the capital base. Actual equity invested in the Distribution Licensee as per book value shall be considered as perpetual and shall be used for computation in this Regulation.

Provided further that the premium if any raised by the Licensee while issuing share capital and investment of internal resources created out of its free reserves, for the funding of the Scheme, shall be reckoned as paid up capital for the purpose of computing return on equity, provided such premium amount and internal resources are actually utilized for meeting the capital expenditure of the distribution system, and are within the ceiling of 30% of capital cost approved by the Commission.

(b) The return on the equity invested shall be allowed from the date of start of commercial operation after put to use.

(c) Return on equity shall be computed at the rate of 15.5% for the project which is commissioned w.e.f. 01.04.2016 and further incentive equivalent to 0.5% will be allowed in the form of RoE, if the project is completed within original schedule period. However, Return on Equity for the project commissioned prior to 01.04.2016 shall be allowed at the rate of 14%.”

5.19.2. Further, Regulation 29 of the BERC Multi Year Distribution Tariff Regulations 2018

provides for tax on Return on Equity on pre-tax basis as extracted below:

“29.1 The base rate of return on equity as allowed by the Commission under Regulation 27 shall be grossed up with the effective tax rate of the respective financial year. For this purpose, the effective tax rate shall be considered on the basis of actual tax paid in the respect of the financial year in line with the provisions of the relevant Finance Acts by the concerned the Distribution Licensee, as the case may be. The actual tax on income from other business including deferred tax liability (i.e. income on business other than business of distribution, as the case may be) shall not be considered for the calculation of effective tax rate. 29.2 Rate of return on equity shall be rounded off to two decimal places and shall be computed as per the formula given below: Rate of pre-tax return on equity = Base rate / (1-t) Where “t” is the effective tax rate in accordance with Clause (1) of this regulation and shall be calculated at the beginning of every financial year based on the estimated profit and tax to be paid estimated in line with the provisions of the relevant Finance Act applicable for that financial year to the company on pro-rata basis by excluding the income of non-generation or non-transmission business,



as the case may be, and the corresponding tax thereon. In case of licensee paying Minimum Alternate Tax (MAT), “t” shall be considered as MAT rate including surcharge and cess.

5.19.3. The return on equity is calculated on 30% of the fixed assets reduced by the amount of

grants. The table below demonstrates the detailed calculation for return on equity:-

Table 103: Return on equity for ARR (in INR Crore)


1 Closing equity to end of 31.03.2016 574.36 574.36 574.36

2 Rate of return on equity % 14.00% 14.00% 14.00%

MAT Rate for FY 2017-18 20.961% 20.96% 20.96%

Rate of Return on Equity (On Pre-tax Basis)

17.713% 17.713% 17.713%

3 Return on Equity 101.73 101.73 101.73


4 Opening equity 1,513.47 2,156.02 2,422.95

5 Equity Addition during the year 642.55 266.93 105.71

6 Closing Equity 2,156.02 2,422.95 2,528.66

7 Average Equity 1,834.74 2,289.48 2,475.80


15.50% 15.50% 15.50%

MAT Rate for FY 2017-18 20.96% 20.96% 20.96%

Rate of Return on Equity (On Pre-tax Basis)

19.611% 19.611% 19.611%

9 Return on Equity 359.80 448.98 485.52


5.19.4. It is requested to the Hon’ble Commission to consider the amount of equity as

calculated above.


5.20.1. The Petitioner submits that Interest on Security Deposit amount has been claimed as

per the Regulation 26 of the Multi-Year tariff regulations 2018 which specifies that

“Provided further that interest shall be allowed on consumer security deposits and security deposits from Distribution System users held during the year at the Bank Rate as of the date on which petition for determination is filed. The interest allowed shall be subject to true up at weighted average Bank Rate of the concern Financial Year.”

5.20.2. The below table demonstrates the calculation of interest on consumer security deposits

projected for the 3rd Control Period:-

Table 104: Interest on consumer security deposits (in INR Crore)









5 RBI Bank Rate 6.25% 6.25% 6.25%


5.20.3. The Petitioner has taken closing balance for FY 2018-19 as opening balance for FY

2019-20. The additions are assumed as per the audited financial statement for FY

2017-18 i.e. INR 94.74 Crore. The interest on consumer security deposits is calculated

at the rate of 6.25% which is the RBI bank rate as on 1st April, 2018.

5.20.4. Therefore, it is requested to the Hon’ble Commission to approve the above mentioned

amount towards interest on consumer security deposit for the next control period.

5.21. Interest on Working Capital

5.21.1. The Petitioner has estimated the amount towards interest on Working capital for the 3rd

Control Period as per the Regulation 26 of the Bihar Electricity Regulatory Commission

(Multi Year Distribution Tariff) Regulations, 2018, as extracted below:

" The Distribution Licensee shall be allowed interest on estimated level of working capital for the financial year, computed as follows: a) Two months equivalent of expected revenue. b) Maintenance spares@40% of R&M expenses for one month: Less: (i) Power purchase cost, transmission charges and load dispatch charges for one month. (ii) Depreciation, return on equity and contribution to contingency reserves equivalent to two months. (iii) Amount of security deposits from consumers, if any, held during the year. Provided that the interest on working capital shall be on normative basis and rate of interest shall be equal to the State Bank one-year Marginal Cost of Funds-based Lending Rate (‘MCLR’) as of the date on which petition for determination of tariff is filed plus 150 basis points. The rate of interest for the purpose of Truing-up shall be the weighted average MCLR of the concern Financial Year plus 150 basis points. Provided further that interest shall be allowed on consumer security deposits and security deposits from Distribution System users held during the year at the Bank Rate as of the date on which petition for determination is filed. The interest allowed shall be subject to true up at weighted average Bank Rate of the concern Financial Year. Provided also that if the State Government is providing resource gap grant and/or direct subsidy to consumers, the working capital shall be reduced by two months equivalent of that amount."

5.21.2. The Petitioner has considered two months equivalent expected revenue and 40% of

one month of R&M expense as specified in the above Regulation which was further

deducted by Power Purchase cost along with transmission charges for one month,

depreciation, ROE, contingency reserve for 2 month, consumer security deposit.



5.21.3. It is pertinent to note that the Petitioner has determined the ARR for FY 2018-19 taking

UDAY scheme loss trajectory into consideration. Therefore in the absence of any

difference in the loss trajectory of UDAY scheme and the approved trajectory by the

Hon’ble commission. Therefore there will be no state government fund allocated

towards disallowance of power purchase cost. In the light of the above explanation the

Petitioner has not deducted any amount towards disallowed power purchase from

working capital requirement.

5.21.4. The interest on working capital is calculated @ 8.15%, which is SBI one year MCLR on

which 150 basis point is further added as per the prevailing Regulations to reach at a

rate of 9.65%. The detailed working for the interest on working capital requirement is

provided in the table below:

Table 105: Interest on working capital for the 3rd Control Period (in INR Crore)

S.N Particulars FY 2019-20 FY 2020-21 FY 2021-22

1 Two months equivalent of expected revenue 1,755.06 2,016.69 2,213.33


6.72 8.88 9.83

3 Less:

(i) Power purchase cost, Load despatch charges and transmission charges for one month.

719.39 824.79 913.35

(ii) Depreciation, ROE, and contribution to contingency reserve equivalent to two months.

141.23 164.54 174.03

(iii) Amount of security deposits from consumers, if any, held during the year

607.72 702.47 797.21

(iv) Grant received from the State Govt. for power purchase and other O&M expenses etc equivalent to two months.

0 0 0

4 Net working capital 293.44 333.78 338.56

5 Interest rate 9.65% 9.65% 9.65%


5.21.5. The Petitioner requests the Hon’ble Commission to approve the interest of working

capital as provided above for the next control period.

5.22. Non-Tariff Income

5.22.1. The Petitioner has projected the Non-Tariff income taking the amount estimated in

Annual performance review of FY 2017-18 and then escalating the same by 10%. The

below table demonstrates the other non-tariff income for FY 2018-19:

Table 106: Non-tariff income for ARR (in INR Crore)

Sl. No.

Particulars FY 2019-20 (Projection)



1 Base Non-tariff Income 376.30 413.93 455.32



Sl. No.

Particulars FY 2019-20 (Projection)



2 Rate of Increase 10.00% 10.00% 10.00%

3 Increase in Non-tariff Income 37.63 41.39 45.53

4 Sub-total 413.93 455.32 500.86

Interest on funding of DPS (@9.65% i.e. SBI MCLR+150 Basis Point)

88.67 97.54 107.29

6 Total non-tariff income 325.26 357.79 393.56

5.22.2. The Petitioner requests the Hon’ble Commission to approve the above mentioned

amount towards non-tariff income for the next control period.


5.23.1. Revenue from Sale of Power at Existing Tariff for the Petitioner is given in table below-

Table 107: Revenue from sale of power at existing tariff for FY 2019-20 (in INR Crore)

Category Sales (MU) Total Revenue

(INR Crore) Domestic

Kutir Jyoti

Unmetered 43 20.03

Metered (0-50) 1,101 699.45

Total - KJ 1,145 719.48

DS-I (Rural) -

Unmetered 51 22.19

Metered -

First 50 Units 2,077 1327.34

51 - 100 Units 576 370.73

Above 100 Units 676 448.95

Total 3,379 2169.21


1-100 U/Month 647 440.92

101 - 200 U/Month 1,408 991.88

201 -300 U/Month 1,370 1000.11

above 300 U/Month 380 292.15

Total 3,804 2725.06

Total - Domestic 8,328 5613.74

NDS-I (Rural) -

Unmetered - 0.00

Metered -

1-100 U/Month 10 7.38

101 - 200 U/Month 34 22.97

above 200 U/Month 15 10.11

Total 59 40.46


Contract Demand < 0.5 kW 7 4.87


First 100 Units 766 643.36

101 - 200 Units 463 405.31

Above 200 Units 64 55.40

Total 1,300 1108.94



Category Sales (MU) Total Revenue

(INR Crore) Total - NDS 1,359 1149.39


SS-I (Metered) 16 13.78

SS-II (Unmetered) 26 15.82

Total - Street Light 42 29.60

IAS-I (Pvt Tubewell) -

Unmetered 261 141.96

Metered 174 109.88

Total 435 251.85

IAS-II (State Tubewell) -

Unmetered - 0.00

Metered 142 112.37

Total 142 112.37

Total - IAS 577 364.22


Public Water Works 177 188.65

Har Ghar Nal 63 0.00

Total PWW 240 188.65

LTIS -

LTIS-I (Contract Demand < 19 kW) 612 559

LTIS-II (Contract Demand 19-74 kW)) 337 304

Total - LTIS 949 863.02

HTS-I (11 kV) 736 679.05

HTS-II (33 kV) 426 391.39

HTS-III (132 kV) 215 214.28

HTSS (33 / 11 kV) 790 475.45

RTS (132 kV) 579 491.21

Nepal - 0.00


5.23.2. The Petitioner requests the Hon’ble Commission to approve revenue from existing Tariff

as INR 10,460 Crore for FY 2019-20.

5.24. Annual Revenue Requirement for FY 2019-20 to FY 2021-22

5.24.1. The Annual Revenue Requirement for FY 2019-20, FY 2020-21 and FY 2021-22 is given in

the table below-

Table 108: Net ARR for FY 2018-19, FY 2020-21 and FY 2021-22 (in INR Crore)

Sl. No. Particulars FY 2019-20 FY 2020-21 FY 2021-22 1 Power purchase cost 7,101.24 8,193.57 9,060.88

2 PGCIL & other transmission charges 572.51 601.14 631.19 3 State Transmission charges 958.92 1,102.76 1,268.17

4 O&M Expenses

i) Employee Cost 406.59 416.33 426.30

ii) R&M expenses 201.74 266.28 294.85

iii) A&G expenses 75.71 76.87 78.06

5 Share of Holding Company expenses

12.92 14.22 15.64



Sl. No. Particulars FY 2019-20 FY 2020-21 FY 2021-22 6 Depreciation 329.51 361.19 373.73

7 Interest and Finance charges 609.36 720.49 768.80 8 Interest on working capital 28.32 32.21 32.67

9 Return on equity 461.54 550.72 587.25

10 Income Tax 0 0 0


12 Bad debts (if any) 0 0 0

13 Contingency reserves (if any) 56.34 75.31 83.19 Deposit for RPO Obligation

14 Total Revenue Requirement 10,855.63 12,457.94 13,673.53 15 Less: Non-tariff income 325.26 357.79 393.56

16 Aggregate Revenue Requirement 10,530.37 12,100.15 13,279.97

5.25. Net Gap at Existing Tariff

5.25.1. The petitioner requests the Hon’ble commission to approve unrecovered gap for FY 2017-18

as calculated in the table below.

Table 75: Unrecovered Gap for FY 2017-18 along with carrying cost (in INR Crore)

Particulars Amount (INR Crore)

Revenue gap in True up for FY 2017-18 3518.44

Interest for FY 2017-18 (SBI PLR @ 13.75%) for 6 months 241.89



Total Carrying Cost 1039.89

Total unrecovered gap for FY 2017-18 4,558.83

5.25.2. The petitioner has not considered unrecovered gap for APR of FY 2018-19 while computing

net revenue gap for FY 2019-10. The net revenue gap at existing tariff for FY 2019-20 is as

below.

Table 110: Net revenue gap at existing tariff for FY 2019-20

S. No.

Particulars Amount (INR

Crore)

1 Aggregate Revenue Requirement (ARR) 10,530.37

2 Less : Revenue from Existing Tariff 10,460.02

3 Gap / (Surplus) 70.36

Table 110: Net revenue gap at existing tariff for FY 2019-20 and FY 2017-18

S. No.


Crore)

1 Aggregate Revenue Requirement (ARR) for FY 2019-20 10,530.37

True Up gap for FY 2017-18 3518.44

Carrying Cost 1039.89

2 Less : Revenue from Existing Tariff 10,460.02




5.25.3. It can be observed that a high tariff hike is required for meeting the shortfall for FY 2019-20

along with the revenue gap for FY 2017-18. Therefore, the Petitioner proposes to recover a part

of the gap i.e. INR 3,949.58 Crore through regulatory surcharge to avoid tariff shock and rest of

INR 679.10 Crore to be recovered from a hike in tariff applicable to various categories of

consumers.

5.26. Revenue from Sale of Power at Proposed Tariff

5.26.1. Revenue from sale of power at proposed tariff for FY 2019-20 is given in table below

Table 111: Total revenue from sale of power at proposed tariff for FY 2019-20

Category Sales ( MU) Revenue (INR Crore)

Domestic

Kutir Jyoti

Unmetered 43 20

Metered (0-50) 1,101 735

Total - KJ 1,145 755

DS-I (Rural) -

Unmetered 51 22

Metered -

First 50 Units 2,077 1,417

51 - 100 Units 576 391

Above 100 Units 676 479

Total 3,379 2,309


1-100 U/Month 647 471

101 - 200 U/Month 1,408 1,051

201 -300 U/Month 1,370 1,040

above 300 U/Month 380 302

Total 3,804 2,864

DS-III

Total - Domestic 8,328 5,928

NDS-I (Rural) -

Unmetered - -

Metered -

1-100 U/Month 10 8

101 - 200 U/Month 34 25

above 200 U/Month 15 11

Total 59 44


Contract Demand < 0.5 kW 7 5


First 100 Units 766 675

101 - 200 Units 463 426

Above 200 Units 64 58

Total 1,300 1,164

Total - NDS 1,359 1,207


SS-I (Metered) 16 14

Rural 2 1

Urban 14 13



5.27. Revenue gap for FY 2019-20 at proposed tariff

5.27.1. The Petitioner is estimating Annual Revenue Requirement for FY 2019-20 on 100% cost coverage basis.

Table 112: The revenue gap at proposed tariff for FY 2019-20

S. No.


Crore)

1 Aggregate Revenue Requirement (ARR) for FY 2019-20 10,530.37

2 True Up gap for FY 2017-18 3518.44

3 Carrying Cost 1039.89

4 Less: Revenue Gap to be recovered as Regulatory Surcharge 3,949.58

5 Less : Revenue from Proposed Tariff 11,139.12


The Petitioner requests the Hon’ble commission to consider the above presented for

determination of Tariff for the 3rd control period.

5.27.2. It is suggested that the amount recoverable for past period gap / (surplus) by the Discom and

a part of the gap as mentioned in the above paragraph, be created into a Regulatory Asset

and not passed on to consumer tariffs for the ensuing year in order to avoid tariff shock. This

amount may be allowed to be recovered by the Petitioner as Regulatory Surcharge at a rate

as allowed by the Hon’ble Commission in the subsequent years.

SS-II (Unmetered) 26 17

Rural 3 2

Urban 24 15

Total - Street Light 42 31

New IAS

Unmetered 261 142

Metered 316 311

Total 577 453


Public Water Works 177 189

Har Ghar Nal 63 44

Total PWW 240 233

LTIS 949 919

HTS-I (11 kV) 736 709

HTS-II (33 kV) 426 409

HTS-III (132 kV) 215 225

HTSS (33 / 11 kV) 790 515

Total - HTS & HTSS 2,167 1,857

RTS (132 kV) 579 511




6. Voltage-wise cost of supply

6.1. Preamble

6.1.1. This section deals with the voltage wise cost of service by the Petitioner for the 3rd Control

Period.

6.2. Background

6.2.1. The Commission had determined the Multi Year Aggregate Revenue Requirement (ARR)

for the second control period FY 2016-17 to FY 2018-19 in the order dated 21st March,

2016.

6.2.2. The Petitioner has considered distribution losses in line with UDAY distribution loss

trajectory. The Petitioner has computed Voltage-wise cost of supply separately for SBPDCL

and NBPDCL.

6.3. Methodology adopted for Computation of Voltage wise Cost of Supply

6.3.1. The Hon’ble APTEL has proposed a simple methodology to functionalize use of Cost of

Supply model. The APTEL notes that identical consumers connected at different nodes of

distribution system need not to be differentiated. In addition, it is adequate to determine

voltage-wise cost of supply taking into account the major cost elements which would be

applicable to all the categories of the consumers connected at the same voltage level at

different locations in the distribution system.

6.3.2. In the method suggested by the Hon’ble APTEL, there are five major components to arrive

at the voltage wise cost of supply. These elements are:

Technical losses at each voltage level of the network: This value of the technical

losses is found by the field studies. Sampling of the feeders which are representative

of the consumers in the system will help in identifying the technical losses at each

voltage levels. The APTEL recognizes the difficulty in collecting data for technical loss

at 11 kV and LT level, hence the suggestion to compute losses using maximum

possible representative feeders for various consumer categories at respective voltage

levels.

Commercial losses at each voltage level of the network: The commercial loss of

the system is the difference between approved loss in the ARR and the total technical

loss computed from system study. This difference is to be apportioned according to

the sales in each voltage level to arrive at the commercial loss at each voltage level.

Voltage wise sales: The energy sale at a particular voltage level is the sum of energy

sold for all the categories of consumers connected at the said voltage level. Due to its



share of sales in total sales, the consumers of the 132/220 kV network will be

apportioned a share of the commercial losses. The Hon’ble APTEL recognizes that in

reality, there may be minimal technical losses at that level and very low probability of

commercial losses. However, the APTEL is of the opinion that the consumers at

132/220 kV, being a part of the distribution system will bear these apportioned losses.

Power Purchase Cost: The power purchase cost is the cost of energy purchased for

sustaining the energy sales at each voltage level. This power purchase units for each

voltage level is arrived by finding the energy input at each voltage level and adding the

losses (technical and commercial) for the same voltage level and upstream. The

energy input at each voltage level is the sum of the sales at the voltage level and the

losses for the corresponding voltage level.

Network Cost: The network costs are the costs like O&M, interest and finance

charges, depreciation, return on equity etc. These costs are a part of the ARR which in

turn provides the average cost of supply. Thus, the network cost is essentially the

difference between the ARR value and the power purchase cost. The APTEL has

suggested apportioning these costs according to the sales volume in each of the

voltage level.

6.3.3. The above elements will help to establish the voltage wise Cost of Supply. Due to the

methodology applied to apportion losses in the various voltage levels, all the consumer

categories at a particular voltage level will have same cost of supply. In this regard, APTEL

has noted that refinements in the methodology may be done when more data becomes

available.

6.4. Determination of Voltage wise Losses

6.4.1. Transmission & Distribution losses in a system are comprised of two separate components -

Technical losses and Commercial losses.

Technical losses occur naturally and consist mainly of power dissipation in electricity

system components such as transmission and distribution lines, and transformers.

Commercial losses are caused by actions external to the power system and consist

primarily of electricity theft, non-payment by customers, and errors in accounting and

record-keeping. Since the rationale behind these two components is quite distinct,

quantifying them separately is imperative for arriving at meaningful conclusions.

6.4.2. At each voltage level, the Technical losses consist of two major components: Transmission

losses which refer to the losses in the current carrying wires; and Transformation losses

which refer the losses incurred during the voltage transformation in the system. Aggregating



the losses in these two elements at each voltage level would give the technical loss at that

level. The losses remaining would be the commercial losses.

6.5. Information required for arriving Voltage Wise Cost of Supply

6.5.1. Following is the list of details required in order to carry out voltage wise cost of supply:

Voltage wise technical losses

Overall T&D losses

Voltage wise energy sales

Power Purchase Cost

Network Costs

6.5.2. It is submitted that the Petitioner has computed voltage wise losses based on certain

assumptions after observing the sample feeder data available with Discoms

6.5.3. The Petitioner has computed voltage wise cost of supply in view of distribution loss

percentage approved by the Hon’ble commission for FY 2019-20 to FY 2021-22.

Table 116: Voltage wise Technical losses considered for the 3rd Control Period

S. No. Voltage Level

Technical loss (%) Cumulative loss (%)

(kV)

1 220/132 3.92% 3.92%

2 33 3.95% 7.72%

3 11 3.98% 11.39%

4 0.4 4.00% 14.93%

6.5.4. The Petitioner has arrived at voltage wise sales considering the projected sale of power for

the 3rd Control Period, across various categories at the respective voltages mentioned in the

table below

Table 117: Classification of Categories on the basis of Voltage of power supply

S. No. Voltage Level Categories

1 220/132 kV HTS-III, Railways, Nepal

2 33 kV HTS-II, HTSS, DF

3 11 kV HTS-I

4 LT Domestic, Non Domestic, Agriculture and Others

6.5.5. The Petitioner further submits that since the voltage wise cost of supply study is based on

the sample data certain parameters such as total loss, energy input etc. may not tally with

the main energy balance projected for FY 2017-18.

6.5.6. Voltage Wise Technical Loss: The Petitioner submits that it has taken suitable assumptions

to arrive at the loss at 220 kV and 132 kV to arrive at the audited loss of BSPTCL.



6.6. Methodology adopted for determination of Cost of Supply

6.6.1. Due to lack of data for segregation of technical and commercial losses, it is not feasible to fix

the technical and commercial loss levels within proposed loss levels.

6.6.2. In order to understand component of technical losses in total T&D loss, technical loss at

each voltage level need to be grossed. Following is the total technical loss at each voltage

level and cumulative losses at subsequent voltage levels.

Table 118: Voltage wise Technical losses considered for the Control Period


Technical loss (%) Cumulative loss (%)

(kV)

1 132 3.92% 3.92%

2 33 3.95% 7.72%

3 11 3.98% 11.39%

4 0.4 4.00% 14.93%

6.6.3. Following is the apportionment of technical losses to the voltage wise sale.

Table 119: Apportionment of technical losses to voltage wise sale for FY 2019-20

S. No.

Voltage Level

Technical losses (%)

Cumulative loss (%)

Energy Sale Energy input (MU)

Technical loss

(kV) (MU) (MU)

1 220/132 3.92% 3.92% 794.09 826.48 32.40

2 33 3.95% 7.72% 1,215.68 1,317.31 101.63

3 11 3.98% 11.39% 735.89 830.47 94.57

4 0.4 4.00% 14.93% 11,495.00 13,512.81 2,017.81

Total 14,240.66 16,487.08 2,246.42




Cumulative loss (%)


Technical loss

(kV) (MU) (MU)

1 220/132 3.92% 3.92% 834.08 868.11 34.03

2 33 3.95% 7.72% 1,261.02 1,366.44 105.42

3 11 3.98% 11.39% 834.91 942.21 107.30

4 0.4 4.00% 14.93% 12,959.09 15,233.90 2,274.81

Total 15,889.09 18,410.66 2,521.57


S. No.

Voltage Level


Cumulative loss (%)


Technical loss

(kV) (MU) (MU)

1 220/132 3.92% 3.92% 881.49 917.46 35.96

2 33 3.95% 7.72% 1,311.17 1,420.79 109.62

3 11 3.98% 11.39% 947.25 1,068.98 121.74

4 0.4 4.00% 14.93% 14,595.67 17,157.76 2,562.10

Total 17,735.58 20,565.00 2,829.41



6.6.4. Commercial losses (difference of total losses and grossed up technical losses) shall be

apportioned pro rata to energy sales at each voltage level.

Table 120: Apportionment of Commercial losses to voltage wise sale for FY 2019-20

S. No.

Voltage Level

Energy sale(MU)

Technical loss(MU)

Sales + Tech Loss (MU)

Commercial Loss (MU)

Energy Input at State Periphery

(kV) (MU)

1 220/132 794.09 32.40 826.48 52.98 879.47

2 33 1,215.68 101.63 1,317.31 81.11 1,398.43

3 11 735.89 94.57 830.47 49.10 879.57

4 0.4 11,495.00 2,017.81 13,512.81 766.98 14,279.79

Total 14,240.66 2,246.42 16,487.08 950.18 17,437.26


S. No.

Voltage Level

Energy sale(MU)

Technical loss(MU)




(kV) (MU)

1 220/132 834.08 34.03 868.11 54.86 922.97 2 33 1,261.02 105.42 1,366.44 82.94 1,449.38 3 11 834.91 107.30 942.21 54.91 997.12 4 0.4 12,959.09 2,274.81 15,233.90 852.34 16,086.25

Total 15,889.09 2,521.57 18,410.66 1,045.06 19,455.71


S. No.

Voltage Level

Energy sale(MU)

Technical loss(MU)




(kV) (MU)

1 220/132 881.49 35.96 917.46 57.24 974.70

2 33 1,311.17 109.62 1,420.79 85.14 1,505.93

3 11 947.25 121.74 1,068.98 61.51 1,130.49

4 0.4 14,595.67 2,562.10 17,157.76 947.79 18,105.56

Total 17,735.58 2,829.41 20,565.00 1,151.69 21,716.69

6.6.5. The Projected Power Purchase Cost (including PGCIL, POSOCO & ERLDC transmission

costs) of the Petitioner for the Control Period is provided below:


Net Power Purchase (MU) 17,437.26 19,455.71 21,716.69

Power Purchase Cost including PGCIL Charges (Rs. Crore) 7,673.75 8,794.71 9,692.08



Average Power purchase Cost (Rs./kWh) 4.40 4.52 4.46

6.6.6. Following is the allocation of power purchase cost to the total energy sales.

Table 121: Allocation of power purchase cost to the energy sales for FY 2019-20

Sl. No.

Voltage Level

kV

Energy Sale (MU)

Energy Input at State

periphery(MU)

Average power

purchase cost

(INR/kWh)

Power Purchase Cost (INR Cr)

Cost of Power per unit sale of

Energy (INR/kWh)

1 220/132 794.09 879.47 4.40 387.03 4.87

2 33 1,215.68 1,398.43 4.40 615.42 5.06

3 11 735.89 879.57 4.40 387.08 5.26

4 0.4 11,495.00 14,279.79 4.40 6,284.22 5.47

Total 14,240.66 17,437.26 7,673.75 5.39


Sl. No.

Voltage Level

kV

Energy Sale (MU)


periphery(MU)

Average power

purchase cost

(INR/kWh)



Energy (INR/kWh)

1 220/132 834.08 922.97 4.52 417.22 5.00

2 33 1,261.02 1,449.38 4.52 655.17 5.20

3 11 834.91 997.12 4.52 450.74 5.40

4 0.4 12,959.09 16,086.25 4.52 7,271.58 5.61

Total 15,889.09 19,455.71 8,794.71 5.54


Sl. No.

Voltage Level

kV

Energy Sale (MU)


periphery(MU)

Average power

purchase cost

(INR/kWh)



Energy (INR/kWh)

1 220/132 881.49 974.70 4.46 435.00 4.93

2 33 1,311.17 1,505.93 4.46 672.09 5.13

3 11 947.25 1,130.49 4.46 504.54 5.33

4 0.4 14,595.67 18,105.56 4.46 8,080.45 5.54

Total 17,735.58 21,716.69 9,692.08 5.46

6.6.7. The details of fixed distribution costs for the control period are provided below, which are

excluding Power Purchase and PGCIL charges.

Table 122: Allocation of Network Cost for the 3rd Control Period

Sl. No.


(INR Cr) (INR Cr) (INR Cr)

1 Employee Cost 406.59 416.33 426.30

2 R&M expenses 201.74 266.28 294.85

3 A&G expenses 75.71 76.87 78.06



Sl. No.


(INR Cr) (INR Cr) (INR Cr)

4 Share of Holding Company expenses 12.92 14.22 15.64

5 Depreciation 329.51 361.19 373.73

6 Interest and Finance charges 609.36 720.49 768.80


8 Return on equity 461.54 550.72 587.25

9 Income Tax 0.00 0.00 0.00


11 Bad debts (if any) 0.00 0.00 0.00

12 Contingency reserves (if any) 56.34 75.31 83.19

13 Deposit for RPO Obligation 0.00 0.00 0.00

14 Total (1 to 7) 2222.97 2560.48 2713.29

15 State Transmission cost 958.917771 1102.755437 1268.168752

16 Total cost 3181.88 3663.23 3981.45

17 Energy Sales (MU) 14,240.66 15,889.09 17,735.58

18 Network Cost per unit sale of energy (Distribution + Transmission) (Rs./kWh)

2.23 2.31 2.24

6.6.8. The Cost of Supply at different voltage levels is given in the table below:

Table 123: Cost of Supply at different Voltage Levels for FY 2019-20

S. No.

Supply Voltage

Cost of power

purchase (INR/kWh)

Network cost

Cost of supply

(INR/kWh) (INR/kWh)

1 220/132 kV 4.87 2.23 7.11

2 33 kV 5.06 2.23 7.30

3 11 kV 5.26 2.23 7.49

4 0.4 kV 5.47 2.23 7.70


S. No.

Supply Voltage

Cost of power

purchase (INR/kWh)

Network cost

Cost of supply

(INR/kWh) (INR/kWh)

1 220/132 kV 5.00 2.31 7.31

2 33 kV 5.20 2.31 7.50

3 11 kV 5.40 2.31 7.70

4 0.4 kV 5.61 2.31 7.92


S. No.

Supply Voltage

Cost of power

purchase (INR/kWh)

Network cost

Cost of supply

(INR/kWh) (INR/kWh)

1 220/132 kV 4.93 2.24 7.18

2 33 kV 5.13 2.24 7.37

3 11 kV 5.33 2.24 7.57

4 0.4 kV 5.54 2.24 7.78



6.6.9. The Hon’ble Commission is requested to approve the Voltage wise cost of supply as

projected by the Petitioner for 3rd Control Period.



7. Miscellaneous and General Charges

7.1. Schedule of Miscellaneous and General Charges

7.2. Meter Rent

7.2.1.1. The Electricity Act, 2003 empowers the Discom to recover its legitimate business

expenses and enlist the charges to be levied on its consumers. Such charges include

fixed charge in addition to the charge for the actual electricity supplied and rent or other

charges in respect of any electric meter or electrical plant provided by the distribution

licensee. The relevant extract from the EA, 2003 is provided as under:

“(3) The charges for electricity supplied by a distribution licensee may include - (a) a fixed charge in addition to the charge for the actual electricity supplied; (b) a rent or other charges in respect of any electric meter or electrical plant provided by the distribution licensee.”

7.2.1.2. Further, Clause 55 of the EA, 2003 also mandates for supply of electricity through

meter. In its endeavor to provide metered connection, the Petitioner has been making

huge investments for procurement of meters for its consumers, which are dynamic in

nature with advanced technology. The technology of meter reading and billing in India is

continuously evolving and has undergone a paradigm shift in recent past. The Petitioner

has moved from the old electromechanical meters to electronic meters for LT

consumers and AMR meter for the consumers connected at higher voltage level. Also,

the Distribution Licensees are planning to install large number of prepaid meters and

also to introduce smart meters among the LT consumers. This shall bring in more

transparency into the system in terms of better energy accounting and less prone to

tampering. The Petitioner has also established facilities for in-house meter testing and

calibration for testing all kinds of meters for its consumers.

7.2.1.3. The cost of meters needs to be recovered from the consumers within a certain

timeframe. Section 8.7 of the Bihar Electricity Supply Code, 2007 provides for recovery

of meter rent from its consumers. The relevant extract of the said provision is provide

below:-

“The licensee shall supply the meter and metering equipment, cut-out/ MCB/ CB/ load limiter to consumers at the time of serving new service connection or at any other time as required. The licensee shall keep the meter in proper working condition and the consumer shall pay the monthly rent, if any, for the meter and metering equipment at the rate approved by the Commission.” [Emphasis Supplied]

7.2.1.4. It is to be noted that the Petitioner’s investment for purchasing meters is a cost incurred

to provide electricity to its consumers and it should be recovered in a timely manner.

However, the BERC (Multi Year Distribution Tariff) Regulation, 2018 considers the



meter rent collection as a source of other income for the Discom. The relevant extract of

the BERC (Multi Year Distribution Tariff) Regulations, 2018 is provided below:

“30. Non-Tariff Income a) All incomes being incidental to electricity business and derived by the Licensee from sources, including but not limited to profit derived from disposal of assets, rents, delayed payment surcharge, meter rent (if any), income from investments other than contingency reserves, miscellaneous receipts from the consumers, other miscellaneous receipts, income to Licensed business from the Other Business of the Distribution Licensee and any other income mentioned in Schedule-5 of The Electricity (Supply)Annual Accounts Rule 1985 shall constitute Non-Tariff Income of the Licensee.”

7.2.1.5. The Petitioner therefore humbly requests the Hon’ble Commission to approve the Meter

rent as approved for FY 2018-19.

Table 128: Proposed Monthly Meter Rent

S. No. Particulars Proposed Rent

(INR/month)

1 KJ 10

2 Single Phase LT Except KJ 20

3 Three Phase LT up to 100 Amps 50

4 LT meter with CT 500

5 11 kV HTS-I

Meter at low Voltage 1,900

Metering at 11kV 1,900

6 33 kV HT metering equipment for HTS-II and HTSS 3,000

7 132 kV EHT metering equipment for HTS-III 15,000

8 25 kV RTS 4,000

9 132 kV RTS 15,000

10 Smart/Prepaid Programmable Meters (GPRS based): Single Phase

90

11 Smart/Prepaid Programmable Meters (GPRS based): Three Phase

120

12 Prepaid Meters: Single Phase 80

13 Prepaid Meters: Three Phase 110

7.3. SLC charges

7.3.1. Application fee for new connection/ reduction of load/ enhancement of load/ request for permanent disconnection/ request for tatkal connection:

7.3.1.1. The following application fees will be charged for requesting a new connection or Tatkal connection or a reduction of load or enhancement of load or permanent disconnection

Table 129: Application fee

S. No. Category / class Rate (INR)

1 Kutir Jyoti 20.00 2 LT Single phase except Kutir Jyoti 75.00

3 LT Three phase 200.00




4 LT Industrial 300.00

5 HT Connection 750.00

6 For tatkal connection Two (2) times the normal rate

7.3.2. Testing / Inspection of consumer’s installation:

7.3.2.1. The following fees will be applicable for testing or inspection of customer’s installation:

Table 130: Meter testing fee


1 Initial Test / Inspection Free of cost

2 Subsequent test and inspection necessitated by

fault in installation or by not complying with

terms and conditions of supply

Rs. 100.00 for single phase connection

Rs. 200.00 for three phase LT connection

Rs. 800 for HT connection.

7.3.3. Meter Testing Fee:

7.3.3.1. The meter testing fee at the following rates will be charged from the consumers opting to

provide their own meters

Table 131: Meter testing fee for own installation


1 Single Phase meter (L.T.) 100.00

2 Three Phase meter (L.T.) 200.00

3 Three Phase meter with CT 300.00

4 Tri-vector and special type meter 1,800.00

5 33 kV or 11 kV metering equipment 5,000.00

6 132 kV/220 kV metering equipment 8,000.00

Note: a. No meter testing fee shall be charged from the consumers if the meter has been provided by the

licensee. b. If the meter is tested at third party testing laboratory at the request of the consumer then the fees

charged by the testing laboratory will be payable by the consumer.

7.3.3.2. Consumer requiring hard copy of the MRI/RMR report of their Energy meter have to pay

an upfront charge of INR 1000 per report. The Petitioner would like to emphasize that

these proposed charges are nominal as compared to INR 5000 plus GST@18% charged

by CPRI.

7.3.4. Removing / Re-fixing / Changing of Meter / Meter Licensee at consumer’s request:

7.3.4.1. The following fees will be charged from the consumers opting to remove or re-fix or

change their meter:

Table 132: Removal/ refixing/ change of meter fee




Cost of material, as required, will be borne by the consumer

1 Single Phase meter 200.00

2 Three Phase meter 400.00

3 Three Phase meter with CT 500.00

4 Trivector and special type meter 600.00

5 High tension metering equipment 1,200.00

7.3.5. Reconnection/ Disconnection Charge:

7.3.5.1. The following reconnection/ disconnection charges will be charged from consumers:

Table 133: Reconnection charges

S. No. Category/class Rate (INR)

1 Single Phase supply, LT 100.00

2 Three Phase supply other than LT industrial 200.00

3 Three Phase LT industrial supply 900.00

4 HT supply 3,000.00

7.3.6. Supervision, Labour and Establishment charge for service connection:

7.3.6.1. The following supervision, labour and establishment fees will be charged from consumers for service connections:

Table 134: Supervision, labour and establishment charges for service connection

S. No. Category/ Class Rate (INR)

1 Single Phase LT 400.00

2 Three Phase LT other than industrial 900.00

3 Three Phase industrial 1,500.00

4 HT As per approved estimate

5 For tatkal connection Two (2) times the normal rate

7.4. Security Deposit

7.4.1. The consumer (except Kutir Jyoti rural and Kutir Jyoti urban) shall pay initial security deposit

equivalent to the estimated energy charges including fixed / demand charges for a period of

two months or as per the provisions of Bihar Electricity Supply Code notified by the

Commission.

7.4.2. All Central Government and State Government departments are exempted from payment of

security deposit. However all public sector undertakings and local bodies shall pay security

deposit, as applicable.

7.4.3. The amount of security deposit obtained from the consumer is liable to be enhanced every

year, in April-May of next year on the basis of consumption during previous years or as

specified in clause 7.15 of Bihar Electricity Supply Code. In default of payment of additional

security deposit, wherever payable after review, the service line may be disconnected on

serving thirty days’ notice and connection thereafter can be restored only if the deposit is



made in full along with the prescribed reconnection charges and surcharge @1.5% per

month or part thereof on the amount of outstanding.

7.5. Interest on Security Deposit

7.5.1. Security deposit made by a consumer shall bear interest as specified in Bihar Electricity

Supply Code, payable at Bank rate notified by RBI from time to time. The interest will be

calculated for full calendar months only and fraction of a month in which the deposit is

received or refunded, shall be ignored. The interest for the period ending 31st March shall be

adjusted and allowed to the consumer in the energy bill for May issued in June and in

subsequent month(s), if not adjusted completely against the bill for the month of May.



8. Proposed Tariff Schedule for FY 2019-20

8.1. Simplification of tariff structures for electricity consumers in Bihar

8.1.1. The two Distribution Licensees in Bihar have taken initiatives in the past couple of years to

undertake tariff related measures, under the guidance of the Hon’ble Commission. Key

measures undertaken have now resulted in the following:

i. Simplification of the tariff structure,

ii. Bringing in a progressive tariff structure that helps promote efficiency, and

iii. Rationalization of electricity tariffs.

8.1.2. For this year as well, the power distribution companies of Bihar have kept the following

objectives in mind while proposing the tariff structure for FY 2019-20.

Ensuring that an adequate balance is maintained between the interest of consumers

and the distribution utility;

Enabling consumers to efficiently and effectively plan their expenditure on electricity;

Ensuring that tariffs progressively reflect the prudent cost of electricity supply to the

consumers, and

Incentivizing the consumer for efficient utilization of electricity.

8.1.3. The Distribution Licensee have followed the given below key guiding principles for proposing

the tariff structure and tariffs which would be applicable for the FY 2019-20.

i. Merging or elimination of category / sub-category has been done based on relevance,

and whether the categorization is still valid in the current scenario;

ii. Ensure that each major tariff category has a maximum of 4 energy slabs, to maintain

simplicity of structure;

iii. Introduction of two part tariff for all metered consumer categories;

iv. Undertaking an action plan with target timelines for phasing out of unmetered

consumers and therefore of the unmetered tariff sub-categories, through large

targeted metering drives over the next twelve to eighteen months;

v. Preserving kVAh based billing for all consumer categories wherever feasible.

8.1.4. Based on the above principles, the following key changes have been proposed in the tariff

structure and schedule for the ensuing year.

i. Merging of LTIS-I and LTIS-II sub-categories, under a single LTIS category.

ii. Merging of IAS-I and IAS-II sub-categories, under a single IAS category.

iii. Under the Mukhya Mantri’s Saat Nischaya Yojana, a key initiative that has been rolled

out has been the ‘Har Ghar Nal Yojana’ for providing drinking water to each

household. As a part of this effort, the two Distribution Licensees are releasing

electricity connections for pumping of ground water for domestic use. For this purpose,

a separate ‘Har Ghar Nal’ sub-category has been introduced. It is anticipated that



under this State Govt. scheme, a total of 1,10,000 water distribution facilities would be

set up in the State. The connections released would be typically of 1, 3 or 5 HP load

pump-sets, based on specific location requirements and depth of the water table at

each site, for pumping of water to the overhead tank which shall then be distributed to

the households.

As per the decision communicated by Panchayatiraj Department, GoB, these

connections would be released on the basis of camps organized by District

Panchayatiraj officers / EEE at all blocks and connections would be released in the

name of Secretary, Ward Implementation and Management Committee. This

Committee would also be responsible for making timely payment of the bills from their

internal resources.

iv. The existing PWW category has been converted into a sub-category and has been

brought together with the Har Ghar Nal sub-cateogory under a new category of ‘Public

Services Connections’. This has been done in order to ensure that the addition of the

new ‘Har Ghar Nal’ sub-category does not lead to an increase in the total no. of

categories.

v. Urban areas, for the applicability of tariffs under the DS-II sub-category, would be as

notified by the Department of Urban Development, Govt. of Bihar from time to time.

vi. NDS-II:-This is applicable for Non-domestic premises situated in urban areas notified

by the Department of Urban Development, Govt. of Bihar from time to time.

vii. All other areas, excluding the ones falling under the Urban category, would fall under

the Rural category.

viii. Kutir Jyoti tariff would be applicable for all huts (Kutir) and dwelling houses of rural and

urban families below the poverty line (BPL), as per the list / notification published by

Rural Development Department, Govt. of Bihar from time to time.

ix. For DS-I sub-category, the load restriction of connected load only upto 2 kW for, has

been removed.

x. For NDS-I sub-category, the load restriction of connected load only upto 2 kW for, has

been removed.

xi. Creation of a new sub-category named as DS-III which will be optional for the group

residential consumers who are willing to avail supply at single point 11 kV for the

purpose of use of electricity in residential, Townships, Registered Societies,

Residential Colonies, multi-storied residential complexes (including lifts, water pumps

and common lighting within the premises).The minimum allowable contract demand

under this category will be 50 kVA and maximum Contract demand will be 1500 kVA

xii. Creation of two sub-categories each for SS-I and SS-II, in view of release of more

number of street lights in village panchayats.



xiii. As a progressive measure and to promote use of EVs in the State, the Distribution

Licensees have proposed that for charging of EVs, consumers getting electricity

supply under regular tariff categories may also use the electricity supply for EV

charging. The respective category tariff would be applicable for the electricity

consumed for charging of the EV as well.

xiv. Phasing out of unmetered sub-categories: The Distribution Licensees are taking

targeted measures for elimination conversion of all unmetered consumers across

various tariff categories. As a larger measure, it has been clearly decided and

accordingly guidelines have been issued, that no new connections under any category

would be released without meters. Further, for the IAS category, the Distribution

Licensee has undertaken an action plan for metering of all existing unmetered

connections and endeavors to complete metering on mission mode. Similarly for KJY,

the action plan is to meter all existing unmetered connections by March 2020.

xv. Rebate for the use of Smart Prepaid Meters: The Bihar Discoms are planning to

undertake installation of smart prepaid meters in the State for the IPDS towns. Such

consumers using smart meters shall be allowed interest of 6% per annum which shall

be adjusted in their future electricity bills.

8.1.5. Overall Based on the above, the following tariff categories and structures have been

proposed for FY 2018-19

8.1.5.1. DOMESTIC: Kutir Jyoti

The BPL consumers in the State are served through the Kutir Jyoti tariff category.

At present, the consumption of Kutir Jyoti consumers is capped at 50 units per

month, with the balance consumption being levied as per DS-I tariffs.

This will be applicable to all dwelling houses of rural and urban families below the

poverty line (BPL) as per the list / notification published by Rural Development

Department, Govt. of Bihar from time to time.

Considering that there are still a significant no. of unmetered consumers in this

category, two sub-categories have been retained.

At present, two part tariff structure is applicable for metered Kutir Jyoti

consumers, with fixed charges to be levied on a-per connection basis per month.

The Distribution Licensees propose to retain the two-part tariff structure for

metered Kutir Jyoti consumers, with fixed charges being levied on a-per KW

connected load basis per month

The tariff structure is proposed below.

Table 135: Proposed tariff structure for KJ category



S.

No.

Consumer

Category

Proposed tariff structure

1 Kutir Jyoti

a K.J. (Unmetered) Only fixed charge (per month per connection)

b K.J. (Metered) Two part tariff (fixed charge per month per connection plus energy

charge per unit)

8.1.5.2. DOMESTIC: Others

The Domestic category, comprising of the existing DS-I and DS-II sub-categories,

had been developed for APL consumers, consuming electricity for household

purposes.

On one hand wherein DS-I consumers are consumers in rural areas, DS-II fall

within urban areas.

Under the new structure, it is proposed to retain DS-I and DS-II in its existing

structure. However, the load for the DS-I and DS-II shall be restricted to the

contract demand of 70 kW and capping of the load of 2 kW for DS-I shall be

removed. Further, considering that there are still significant no. of unmetered

consumers in this category, this differentiation is proposed to be retained till the

time all consumers are completely metered.

DS-II tariff is proposed to be applicable for domestic premises in urban areas

notified by the Department of Urban Development, Govt. of Bihar from time to

time.

A DS-III sub-category has been introduced as discussed above.

The revised tariff structure is proposed below.

Table 136: Proposed tariff structure for DS category

S. No. Consumer Category Proposed tariff structure

1 DS – I

a Unmetered Only fixed charges (per connection per month)

b Metered

First 50 units Two part tariff (Fixed charges on sanctioned load

per month) 51-100 units

101-200 units

Above 200 units

2 DS – II

1-100 units Two part tariff (Fixed charges on maximum demand


201-300 units

Above 300 units

3 DS-III (Optional) Two part tariff (Fixed charges on maximum demand

per month)

8.1.5.3. NON-DOMESTIC



The non-domestic category is for consumers using electricity for commercial

purposes in the State of Bihar. Sub-categories have been created on the basis of

connected load and point of connected load.

There are currently two sub-categories within NDS; NDS-I serving rural

consumers and NDS-II serving loads load up to 70 kW for urban consumers for

commercial uses of electricity under LT category.

Under the new structure, it is proposed to remove the cap of 2kW existing for

NDS-I and retain NDS-I and NDS-II in its existing structure. However, the load for

the NDS-I and NDS-II shall be restricted to the contract demand of 70 kW

Ideally, there should be no provision of billing any consumer on unmetered basis;

however an interim provision may be provided by the Commission for billing all

unmetered consumers of the rural areas, till the time Discoms complete the

metering of all such pending connections.

The NDS-II tariff is proposed to be applicable for Non-domestic premises in urban

areas notified by the Department of Urban Development, Govt. of Bihar from time

to time. NDSI tariff will be applicable to areas where NDS II is not applicable.


Table 137: Proposed tariff structure for NDS category

S.

No.

Consumer Category Proposed tariff structure

1 NDS-I Rural Connected Load Based

1-100 units Two part tariff (Fixed charges on sanctioned load per

month) 101-200 units

Above 200 units

2 NDS-II (Contract demand up

to 0.5 KW)

Two part tariff (fixed charge per month per connection

plus energy charge per unit)

3 NDS-II (Contract demand

above 0.5 KW)

Demand Based

Metered Two part tariff (Fixed charges on maximum demand


101-200 units

Above 200 units

8.1.5.4. IRRIGATION AND AGRICULTURE

Under the Irrigation and Agriculture category, there are currently two separate

sub-categories for private and State owned tube-wells, with differentiated tariffs

for providing benefit of lower tariffs to private consumers.



It is proposed to merge the IAS-I (private tube-wells) and IAS-II (Govt. tube wells

/ pumps) with load up to 100 HP under one category for Irrigation and Agriculture

Services.

Given the existing scenario, it is proposed to retain the unmetered class till the

time all such connections are metered. The Discoms plan to meter all unmetered

IAS connections within 6 months of the ensuing year.

For levying of fixed charges, tariff to be levied on the connected / sanctioned

load in the absence of meters with the feature of capturing Maximum-Demand.

For metered consumers, it is proposed to retain two-part tariff structure


Table 138: Proposed tariff structure for IAS category

Consumer Category Proposed tariff structure

Unmetered Supply Only fixed charge (based on per HP per month)

Metered Supply Two part tariff (Fixed charges on connected load)

8.1.5.5. LOW TENSION INDUSTRIAL

LTIS category includes consumers for small industries bifurcated into single

phase and three phase connection.

LTIS-I is for consumers with contract demand up to 19 kW and LTIS-II is for

three phase connection with a contracted load above 19 kW and up to 74kW.

Further, demand based tariff is mandatory for three phase connection and

optional for single phase connection.

To ensure simplification in tariffs, it is proposed that the existing LTIS-I and

LTIS-II sub-categories be merged.

Further, since all meters have the feature of recording Maximum Demand, it is

proposed to retain levy of fixed charges on Maximum Demand only. Fixed

charges are to be levied for all consumers in the category on per kW basis.

In line with other states and the current structure, it is also proposed to retain

kVAh based billing for this category. This will help introduce efficiency into the

system.


Table 139: Proposed tariff structure for LTIS category

Consumer

Category


LTIS Two part tariff (Fixed charges on maximum demand and

energy charges on kVAh based billing)



8.1.5.6. PUBLIC Service Connections

PWW category which is used for public lift irrigation based connections, owned

by the State Govt. under current tariff structure shall be retained as a separate

sub-category under PWW category.

At present, a two part tariff is in place with fixed charges being levied on per

kVA basis and all energy charges are to be charged on a kVAh basis.

A new sub-category named Har Ghar Nal is proposed for water distribution

facility provided by the Public Health Engineering Department at the village

panchayats and ward levels. This sub-category shall be applicable to

connections released under “Har Ghar Nal” Scheme only.

The tariff for Har Ghar Nal scheme is proposed to be two part with fixed charge

to be made applicable on per HP basis and the energy charge to be levied on

the basis of kWh consumption.


Table 140: Proposed tariff structure for PWW category

S. No. Consumer Category Tariff Structure

1 PWW Two part tariff (Fixed charges on maximum demand basis And energy charges on kVAh basis)

2 Har Ghar Nal Two part tariff (Fixed charges on sanctioned load And energy charges on kWh basis)

8.1.5.7. STREET LIGHT SERVICES

This category is for supply of electricity for street light system with separate

sub-categories for metered and unmetered connections.

Ideally, there should be no provision of billing any consumer on unmetered

basis; however an interim provision has been retained for billing all unmetered

consumers, till the time the Discoms complete the metering of all street lights.

All energy charges are to be charged on a kWh basis and fixed charges are

proposed to be levied on kW basis.

In addition to the above, two sub-categories for rural and urban have been

created.


Table 141: Proposed tariff structure for SS category

S.

No.

Consumer

Category




1 SS Metered

Rural Two part tariff (Fixed charges on kW and energy

charge on kWh basis ) Urban

2 SS Unmetered

Rural Two part tariff (Fixed charges on kW and energy charge on

kWh basis ) Urban

8.1.5.8. HIGH TENSION SUPPLY

No change is proposed in tariff structure of this category, and the following existing

structure would continue.

Table 142: Proposed tariff structure for HT category

S.

No.

Consumer

Category

Tariff Structure

1 HTS-I (11 kV) Two part tariff (Fixed charges on maximum demand and

energy charges on kVAh billing) 2 HTS-II (33 kV)

3 HTS-III (132 kV)

4 HTS-IV (220 kV)

5 HTSS (11 kV/33

kV)

Two part tariff (Fixed charges on contract demand and

energy charges on kVAh billing)

8.1.5.9. RAILWAYS

This category is for supplying power to Railway Traction Services wherein the

connection is to be provided only at 132 kV level.

There is also a provision of rebate/surcharge at 13 paise/kVAh for higher

voltage/lower voltage than 132 kV shall be allowed.

No change is proposed in this category and the following existing structure would

continue.

Table 143: Proposed tariff structure for RTS category

S.

No.

Consumer Category Tariff Structure

1 RTS (132 kV) Two part tariff (Fixed charges on maximum demand and

energy charges on kVAh billing)

8.1.6. The above structure has been proposed for the tariff schedule for FY 2019-20. However, it

is pertinent to mention the following key points on the designing of tariff structure and

rates.

8.1.6.1. Unmetered consumer category: The Petitioner is taking several measures for

completion of metering of all consumers. Larger district wise programs are being

undertaken for both metering of unmetered consumers, as well as replacement of



defective meters. This is an ongoing drive and the Discoms expect to gradually narrow

down the number of unmetered connections. This would only remain in some specific

categories such as KJY, DS-I, IAS and Street Lighting (which is primarily due to technical

issues).

8.1.6.2. No. of energy slabs: In its quest for simplifying the tariff structure, the Discoms have

already removed several sub-categories. However for energy slabs, given the current

standard practice followed across states, the Discoms would want to retain the current no.

of energy slabs within each category / sub-category. Going forward, it is their endeavor to

reduce the number of energy slabs within each sub-category as well. For this, they also

plan to carry out a scientific study to substantiate the rationale behind setting various slab

limits.

8.1.6.3. Existence of special categories: In Bihar, a separate category exists as HTSS for

specifically supplying power to arc furnaces, and in line with their consumption, their tariff

structure provides for a high fixed charge with a low per unit energy charge. The Discom

is planning to undertake a study for assessing the demand and consumption patterns of

the consumers on a sample basis, based on which it will develop a roadmap for merging

this category with relevant HTS category. For the ensuing year however, no revision is

proposed.

8.1.6.4. Levying of fixed charges: The endeavor of the Discoms is to levy the fixed tariff on

consumers based on their maximum demand in the long term, and on their contracted

demand in the short term. However for some specific unmetered consumer categories

and sub-categories, the fixed charge is proposed to be levied on each connection. The

Discoms are taking steps to reconcile the connected load of such consumers especially in

the KJY, DS-I and NDS-I categories, so as to avoid any excessive burden due to

inaccurate load records or limited energy usage.

8.1.6.5. Demand Based tariffs: The Discoms are planning to gradually move to demand based

tariffs for all consumers, and most meters being currently installed, have the feature of

recording the maximum demand.

8.1.6.6. Implementation of flat tariff: In order to simplify the tariff structure further, and also

encourage energy efficiency for consumers especially with higher specific consumption,

the Discoms have been exploring the concept of implementing a flat tariff for each energy

slab. However for the ensuing year, the existing structure has been considered wherein

the benefit of lower tariffs would continue for consumption at lower energy slabs.

8.1.6.7. Classification of consumers under urban and rural sub-category for DS-I/DS-II and

NDS-I/NDS-II: The extension of the electrical network of the Discoms has been done for

many areas, and in several cases, electrical feeders initially emerging from urban areas,

have now been extended to rural areas as well, based on financial viability. Therefore in



order to avoid any ambiguity pertaining to a classification of a consumer as Urban / Rural,

the categorization in the applicable sub-category within Domestic and Non-Domestic

categories, would be done only based on the latest / prevalent notification issued by the

relevant authority, denoting an area to be falling under Urban / Rural areas. No other

methodology would be followed.

8.1.6.8. Recovery of fixed charges: The fixed costs include the establishment and network

costs, as well as the fixed costs payable to the Generators, irrespective whether power is

drawn from them. The variable costs is the energy cost paid to Generators for supply of

energy. On one hand wherein the cost structure of the two Discoms is heavily tilted

towards fixed charges, the recovery of revenue through the existing tariff approved by the

Hon’ble Commission is tilted more towards energy tariffs. Due to this skewed nature of

tariff recovery, the Discoms have limited revenue assurance and therefore face

uncertainty.

8.1.6.9. General and miscellaneous charges: The Discoms have also proposed a revision in

meter rent charges for meter cost realization within the warranty expiration time of the

meters.

8.1.6.10. Therefore accordingly, the Discoms propose the following tariff schedule to be adopted for

the FY 2019-20, w.e.f. 01.04.2019 for 100% cost recovery, without taking the impact of

any subsidy to be provided by the Government of Bihar for tariff relief.

Table 144: Tariff schedule considering ‘Zero’ GoB Subsidy

Category Tariff

Fixed charge

Unit Energy Charges

Unit

Domestic

Kutir Jyoti

Unmetered 350 Per Connection Per Month 0 kWh

Metered (0-50) 16 Per Connection Per Month 6.35 kWh

Total - KJ

DS-I (Rural)

Unmetered 500 Per Connection Per Month 0 kWh

Metered

First 50 Units 35 Per kW Per Month 6.4 kWh

51 - 100 Units 35 Per kW Per Month 6.7 kWh

Above 100 Units 35 Per kW Per Month 7.15 kWh

Total

DS-II (Urban- Demand Based)

1-100 U/Month 50 Per kW Per Month 6.45 kWh

101 - 200 U/Month 50 Per kW Per Month 7.20 kWh

201 -300 U/Month 50 Per kW Per Month 7.90 kWh

above 300 U/Month 50 Per kW Per Month 8.80 kWh

Total

DS-III (Optional- Supply at 11 kV) 50 Per kW Per Month 7.9 kWh

Total - Domestic



Category Tariff

Fixed charge

Unit Energy Charges

Unit

NDS-I (Rural)

Metered

1-100 U/Month 55 Per kW Per Month 6.60 kWh

101 - 200 U/Month 55 Per kW Per Month 7.15 kWh

above 200 U/Month 55 Per kW Per Month 7.70 kWh

Total

NDS-II (Demand Based)

Contract Demand < 0.5 kW 100 Per Connection Per Month 6.60 kWh

Contract Demand > 0.5 kW

First 100 Units 190 Per kW Per Month 6.70 kWh

101 - 200 Units 190 Per kW Per Month 7.30 kWh

Above 200 Units 190 Per kW Per Month 8.10 kWh

Street Light Services

SS-I (Metered)

Rural 50 Per kW Per Month 7.70 kWh

Urban 60 Per kW Per Month 7.75 kWh

SS-II (Unmetered)

Rural 3750 Per kW Per Month 0 kWh

Urban 4000 Per kW Per Month 0 kWh

Total - Street Light

New IAS

Unmetered *800 Per HP per month 0 kWh

Metered *200 Per HP per month *6.65 kWh

Total

Public Service Connections

Public Water Works 315 Per kVA Per Month 8.05 kVAh

Har Ghar Nal 40 Per HP per month 6.75 kWh

Total PWW

LTIS 180 Per kVA Per Month 6.75 kVAh

HTS-I (11 kV) 330 Per kVA Per Month 6.85 kVAh

HTS-II (33 kV) 330 Per kVA Per Month 6.8 kVAh

HTS-III (132 kV) 330 Per kVA Per Month 6.75 kVAh

HTSS- IV (220 kV) 330 Per kVA Per Month 6.70 kVAh

HTSS (33 / 11 kV) 700 Per kVA Per Month 4.6 kVAh

Total - HTS & HTSS

RTS (132 kV) 330 Per kVA Per Month 6.95 kVAh

*The tariff is proposed based on cost of supply. However, the State Govt. has announced subsidized tariff of Rs. 0.75 per unit and Rs. 84 per HP respectively for metered and unmetered agricultural consumers. Therefore, the agricultural consumers will be billed as per subsidized tariff decided by the Govt. i.e. Rs. 0.75 per unit fpr metered and Rs. 84 per HP for unmetered.

Note: The above proposed tariff is based on cost of service incurred by SBPDCL for supplying electricity. However, in accordance with the Govt. decision regarding tariff subsidy, consumers will be billed at subsidized tariff.

8.2. Terms and Conditions of Low Tension Tariff

The foregoing tariffs are subject to the following conditions:

8.2.1. Rebate for prompt payment

The due date for making payment of energy bills or other charges shall be 15 days from the

date of issue of the bill. To motivate consumers to make timely payment of their bills it is



proposed to provide a rebate of 1.5% on the billed amount for timely payment of the bills for

all the consumers served in LT category.

In case a consumer makes full payment after due date but within 10 days after the due date,

no DPS shall be levied for this period but rebate for prompt payment will not be admissible.

8.2.2. Rebate for online payment

To motivate the consumers to make online payment of the bills through online web portal of

the Petitioner it is proposed to provide a rebate of 1% of the billed amount in addition to

rebate @ 1.5% on the billed amount for timely payment of the bills for all the consumers

served in LT category. Payment made through all electronic modes of payment made directly

in the Discom account will be considered as online payment. However, online payment rebate

shall be applicable if the consumer makes the payment within due date in full.



8.2.3. Accounting of Partial Payment

All payment made by consumers in full or part shall be adjusted in the following order of

priority:

a. Statutory taxes and duties on current consumption

b. Arrear of Statutory taxes and duties

c. Delayed payment surcharge

d. Balance of arrears

e. Balance of current bill

8.2.4. Delayed Payment Surcharge (DPS)

In case a consumer does not pay energy bills in full within 10 days grace period after due

date specified in the bill, a delayed payment surcharge of one and half (1.5) percent per

month or part thereof on the outstanding principal amount of bill will be levied from the due

date for payment until the payment is made in full without prejudice to right of the licensee to

disconnect the supply in accordance with Section 56 of the Electricity Act, 2003. The licensee

shall clearly indicate in the bill itself the total amount, including DPS, payable for different

dates after the due date after allowing for the grace period of 10 days. No DPS shall be

charged on DPS arrear. The bill shall indicate the energy charges for the month, arrears of

energy charges and DPS separately.



8.2.5. Duties and Taxes

Other statutory levies like electricity duty or any other taxes, duties etc., imposed by the State

Government / Central Government or any other competent authority, shall be extra and shall

not be part of the tariff as determined under this order.

8.2.6. Defective / Damaged / Burnt Meters Supply

In case of meter being defective / damaged / burnt the licensee or the consumer as the case

may be, shall replace it within the specified period prescribed in “Standards of Performance

for Distribution Licensee”, Regulations issued by the Commission.

Till defective / damaged / burnt meter is replaced, the consumption will be assessed

and billed on an average consumption of last 12 months from the date of meter being

out of order. Such consumption shall be treated as actual consumption for all practical

purposes including calculation of electricity duty until the meter is replaced/ rectified.

In cases of newly installed meter of a consumer becoming defective/ damaged/ burnt

after installation of the meter prior to completion of 12 months since its installation, the

billing for the period for such defective/ damaged/ burnt meter, till it is not replaced,

shall be done on the basis of average monthly consumption of the consumer or the

MMC whichever is higher.

In case of the meter of a consumer becoming defective in the first month of installation

itself, without taking any reading the consumer shall be provisionally billed on the

basis of amount of security collected for one month. However, the provisional bill will

be done for one month only and that will be finalized and adjusted on the basis of

consumption of the second month.

8.2.7. Shunt Capacitor Installation

Every LT consumer including irrigation pump set consumers whose connected load

includes induction motor (s) of capacity 3 HP and above and other low power factor

consuming appliances shall arrange to install low tension shunt capacitors of

appropriate capacity of standard make which meet the Bureau of Indian Standard

Specification at his cost across terminals of his motor (s). The consumer shall ensure

that the capacitors installed by him are properly matched with the actual rating of the

motor so as to ensure power factor of 90%.

All LT consumers having welding transformers will be required to install suitable shunt

capacitor(s) of adequate capacity so as to ensure power factor of not less than 90%.

No new supply to LT installations having low power factor consuming equipment such

as induction motor of 3 HP and above or welding transformers etc., will be released

unless shunt capacitors are installed to the satisfaction of the licensee.



The ratings of shunt capacitor to be installed on the motors of different ratings are

provided in the “Electric Supply Code” notified by the Commission.

Any LT consumer except Domestic category of consumer in whose case, the meter

installed has power factor recording feature and who fails to maintain power factor of

90% in any month shall pay a surcharge of 1% for every fall of 1% below 90% subject

to a maximum of 5% in addition to its normal tariff total current bill amount except

DPS.

8.2.8. Charges to Tatkal Connections (Optional)

If any consumer (other than High Tension and Railway) opts for availing connection under

Tatkal scheme, the licensee shall release the Tatkal connection to such consumer with the

following conditions:

The Tatkal connections shall be released by licensee in half the time limit prescribed

in the Supply code for that consumer category.

Two (2) times of the following charges approved under head miscellaneous and

general charges will be taken from the consumers willing to avail Tatkal connection.

Application fees for new connection, and;

Supervision, labor and establishment charge for service connection

In case licensee fails to release connection within this time limit, licensee will refund

the additional amount claimed to the consumer in the first energy bill.

8.2.9. Contract Demand for billing under Domestic Tariff

For computation of the connected load of a domestic consumer either load of coolers/

fans or room heaters whichever is higher shall be considered. For the premises having

Air conditioner (without heater) and that of geysers, the computation of connected load

shall be as per the provision of Bihar Electricity Supply Code, 2007.

The contract demand of those consumers for the monthly billing purpose in the

premises who have opted for demand based tariff, the recorded demand or the

contract demand, whichever is higher, shall be considered.

Subject to the minimum load of 1 kW, the fraction of the load below 500 W shall be

rounded to its nearest lower level of whole number and 500 W and above shall be

rounded to its nearest higher level of whole number, as specified in the Bihar

Electricity Supply Code, 2007.

In case of demand based tariff, verification of connected load is not required.

8.2.10. Existing provision of demand based tariff being optional for three phase LT consumer should

be made compulsory.



Tri-vector meters are installed in all the three phase consumers, Petitioner proposes to cover

all three phase consumers under demand based tariff.

All the other terms and conditions for the LT supply as has been decided by the Hon’ble

Commission in its tariff order dated 21.03.2018 shall remain applicable for the FY 2019-20

also.

8.3. Terms and Conditions of High Tension Tariff

The foregoing tariffs are subject to the following conditions:

8.3.1. Rebate for prompt payment

The due date for making payment of energy bills or other charges shall be 15 days from the

date of issue of the bill. To motivate the consumers to make timely payment of the bills it is

proposed to provide a rebate of 1.5% on the billed amount for timely payment of the bills for

all the consumers served in HT category.



8.3.2. Rebate for online payment

To motivate the consumers to make online payment of the bills through online web portal of

the Petitioner it is proposed to provide a rebate of 1% of the billed amount in addition to

rebate @ 1.5%. Payment made through all electronic modes of payment made directly in the

Discom account will be considered as online payment. However, online payment rebate shall

be applicable if the consumer makes the payment within due date in full.

8.3.3. Accounting of Partial Payment

All payment made by consumers in full or part shall be adjusted in the following order of

priority:

a. Statutory taxes and duties on current consumption

b. Arrear of Statutory taxes and duties

c. Delayed payment surcharge

d. Balance of arrears

e. Balance of current bill

8.3.4. Delayed Payment Surcharge (DPS)

In case of consumer does not pay energy bills in full within 10 days grace period after due

date specified in the bill, a delayed payment surcharge of one and half (1.5) % per month or

part thereof on the outstanding principal amount of bill will be levied form the original due date

for payment until the payment is made in full without prejudice to right of the licensee to

disconnect the supply in accordance with Section 56 of the Electricity Act, 2003. The licensee



shall clearly indicate in the bill itself the total amount, including DPS, payable for different

dates after the due date after allowing for the grace period of 10 days. No DPS shall be

charged on DPS arrear.

8.3.5. Duties and Taxes

Other statutory levies like electricity duty or any other taxes, duties etc., imposed by the State

Government / Central Government or any other competent authority, shall be extra and shall

not be part of the tariff as determined under this order.

8.3.6. Defective / Damaged / Burnt Meters Supply

In case of meter being defective / damaged / burnt the licensee or the consumer as the case

may be, shall replace it within the specified period prescribed in “Standards of Performance

for Distribution Licensee”, Regulations issued by the Commission.

Till defective / damaged / burnt meter is replaced, the consumption will be assessed

and billed on an average consumption of last 12 months from the date of meter being

out of order. Such consumption shall be treated as actual consumption for all practical

purposes including calculation of electricity duty until the meter is replaced/ rectified.

In cases of newly installed meter of a consumer becoming defective/ damaged/ burnt

after installation of the meter prior to completion of 12 months since its installation, the

billing for the period for such defective/ damaged/ burnt meter, till it is not replaced,

shall be done on the basis of average monthly consumption of the consumer or the

MMC whichever is higher.

In case of the meter of a consumer becoming defective in the first month of installation

itself, without taking any reading the consumer shall be provisionally billed on the

basis of amount of security collected for one month. However, the provisional bill will

be done for one month only and that will be finalized and adjusted on the basis of

consumption of the second month.

8.3.7. Exceeding Contract Demand

If the actual recorded demand of a consumer exceeds 110% consecutively for three months

Licensee may issue a notice and inform the consumer to get additional contract demand

sanctioned or to limit their drawal as per their contract. Otherwise Licensee will take action as

per provisions of the Act/Rules/Regulations.

In case the consumer do not respond to the notice within 30 days of issue of notice, to get

additional demand sanctioned or limit their drawal as per the contract, the Distribution

Licensee may revise and enhance the contracted demand of the consumer to the extent of

highest demand in the past three months of the violation.



8.3.8. Contract Demand for Induction Furnaces

The prevailing practice will continue for determining the contract demand of induction

furnaces in the existing services connections. However, for new connections and where the

furnaces are replaced in existing connections, contract demand shall be based on the total

capacity of the furnace and equipment as per manufacturer technical specifications and in

case of difference of opinion, the provisions of clause No.6.39 and 6.40 of Bihar Electricity

Supply Code shall apply.

8.3.9. Shift to kVAH based Tariff

Understanding that the kVAH based tariff has an inbuilt mechanism for incentivizing the

consumers who maintain better power factor, the Petitioner proposes the Commission to

retain kVAH based tariff in the state for HT consumers. This is bound to encourage HT

consumers to save on their electricity bills.

All the other terms and conditions for the HT supply as has been decided by the Hon’ble

Commission in its tariff order dated 21.03.2018 shall remain applicable for the FY 2019-20

also.

8.3.10. Temporary Supply (LT and HT)

Applicability: This tariff is for connection of temporary in nature for period of less than one

year. The applicability shall be as given in the respective category tariff rate schedule.

Temporary supply cannot be claimed by a prospective consumer as a matter of right but will

normally be arranged by the Licensee when a requisition is made giving due notice subject to

technical feasibility and in accordance with electricity supply code issued by the Commission.

Tariff: Fixed charge and energy charge shall be chargeable at one and half times the normal

tariff as applicable to the corresponding appropriate tariff category.

8.3.11. Terms of Supply

Temporary supply under any category of service may be given for a period not exceeding 30

days in the first instance, the duration of which, however may be extended on month-to-

month basis subject to maximum of one year.

In addition to the charges mentioned above, the consumer shall have to deposit the following

charges before commencement of the temporary supply:

o Estimated cost of erection of temporary service line and dismantling.

o Cost of irretrievable materials which cannot be taken back to service.

o Meter rent for the full period of temporary connection as per appropriate Tariff

Schedule and miscellaneous charges.



o Rental on the cost of materials as per estimate framed but not payable by the

consumer shall be payable at the rate of Rs. 15/- per month on every Rs. 100/-

or part thereof.

o Ten per cent on the total cost of the estimate for the temporary service

connection to cover as security for loss of materials and contingencies. In case

such loss is not noticed, the amount will be refunded.

The applicants for temporary supply shall be required to make a deposit in advance of the

cost as detailed above including the energy consumption charges estimated for full period on

the basis of connected load. This will however, be adjusted against the final bill that will be

rendered on disconnection of supply month to month basis.

If the consumer intends to extend the temporary supply beyond the period originally applied

for, he will have to deposit in advance all charges as detailed above including the estimated

electricity consumption charges, for the period to be extended and final bill for the previous

period, as well.

The temporary supply shall continue as such and be governed by the terms and conditions

specified above until the supply is terminated or converted into permanent supply at the

written request of the consumer. The supply will be governed by the terms and conditions of

permanent supply only after the consumer has duly completed all the formalities like

execution of agreement, deposit of security money, cost of service connection and full

settlement of the account in respect of the temporary supply etc.

8.3.12. Security deposit

The initial security deposit shall be calculated on the basis at a load factor of 30% and power

factor of 90% on contract demand payable at prevailing unit rate for HTS-I category.

For HTS-II category it shall be calculated on the basis at a load factor of 35% and power

factor of 90% on contract demand payable at prevailing unit rate.

For HTS-III and HTS-IV category it shall be calculated on the basis at a load factor of 50%

and power factor of 90% on contract demand payable at prevailing unit rate.

For HTSS consumer the formula for calculation of initial security deposit as below:

(Contract demand * 289 * energy charge per unit)*2 + (Contract demand * Demand Charge per

kVA)*2

8.3.13. Seasonal Supply (LT and HT)

The Petitioner proposes to provide seasonal supply to any consumer on written request to the

Licensee subject to the following conditions.

Table 147: Proposed tariff rate for seasonal supply



Period of Supply Tariff Rate

Upto 3 consecutive months in a year Appropriate tariff plus 30 percent

More than 3 consecutive months and upto 6 consecutive

months in a year

Appropriate tariff plus 20 percent

More than 6 consecutive months and upto 9 consecutive

months in a year

Appropriate tariff plus 15 percent

More than 9 consecutive months but less than one year Appropriate tariff plus 5 percent.

The meter rent and other charges as provided in the appropriate tariff are applicable to

seasonal loads and would be charged extra for the entire period of supply.

The supply would be disconnected after the end of the period unless the consumer wants the

supply to be continued. Any reconnection charges have to be borne by the consumer.

Consumer proposing to avail seasonal supply shall sign an agreement with the Licensee to

avail power supply for a minimum period of 3 years in the case of HT, and 2 years in the case

of LT category of supply.

The consumers must avail supply in terms of whole calendar month continuously.

The consumer is required to apply for seasonal supply and pay initial cost and security

deposit as an applicant for normal electricity supply.

The consumer shall ensure payment of monthly energy bills within 7 days of its receipt. The

supply will be disconnected if payment is not made on due date.

Incremental charges will not be applicable for fixed charge component of the electricity bill in

case of seasonal supply.

8.3.14. Additional terms and conditions of HT tariff

The billing demand shall be the maximum demand recorded during the month or 85% of the

contract demand whichever is higher for HTS –I, HTS-II, HTS-III, RTS and HTS-IV. In HTSS

tariff if the power is availed at 11 KV a surcharge of 5% will be charged extra on demand and

energy charges.

If in any month the recorded maximum demand of the consumer exceeds 110% of contract

demand that portion of the demand in excess of the contract demand will be billed at twice the

normal charges for HTS –I, HTS-II, HTS-III, RTS and HTS-IV. Time of Day (TOD) tariff will

remain same as per tariff order for FY2018-19. In case, the consumer exceeds 110% of the

contract demand, the demand in excess of contract demand shall be billed at twice the

normal tariff applicable for day time i.e. 5:00 a.m. to 5:00 p.m. irrespective of the time of use.



Applicability of different HT categories, its capping of contract demand and character of

service will remain same as per tariff order for FY2018-19 unless otherwise any change is

proposed in the instant Petition.



9. Wheeling and Open Access Charges

9.1. Background

9.1.1. The Petitioner submits that for the purpose of open access on distribution network,

determination of wheeling losses and wheeling charges are essential. Further as the

consumer is deemed to be moving out of system, the revenue loss from such consumers is

recovered through Cross Subsidy Surcharge and Additional Surcharge, as the case may be.

9.2. Wheeling Charges

9.2.1. It is submitted that till date complete segregation of accounts between Wheeling and Retail

Supply function has not yet taken place. Thus, ARR proposals for Wheeling and Retail

Supply function is submitted on the basis of an allocation statement to be prepared by the

Distribution Licensee based on their best judgment and in line with the approach followed by

the Hon’ble Commission in its Previous Tariff Orders.

9.2.2. The Licensee, in the instant Petition, has followed the following allocation for calculating

segregating its wire and supply business and the total costs (net ARR) of both the Discoms

are segregated into wire business and retail supply business.

Table 149: Segregation of Wires and Retail Supply Costs

Sl. No. Particulars Total Fixed Cost

Assumption 33kV 11kV

Wire Business

Retail Supply

Wire business

Retail supply

business

Wire business

Retail supply

business

1 Power purchase cost

13,497 0% 100% - 6,748 - 6,748

Less: 1% Rebate

- - - - -

2 PGCIL & other transmission charges

1,006 0% 100% - 503 - 503

3 State Transmission charges

1,711 0% 100% - 855 - 855

4 O&M Expenses - - - - -

i) Employee Cost 678 60% 40% 203 136 203 136

ii) R&M expenses 412 90% 10% 185 21 185 21

iii) A&G expenses 176 50% 50% 44 44 44 44

5 Share of Holding Company expenses

26 60% 40% 8 5 8 5

6 Depreciation 547 90% 10% 246 27 246 27

7 Interest and Finance

978 90% 10% 440 49 440 49



Sl. No. Particulars Total Fixed Cost

Assumption 33kV 11kV

Wire Business

Retail Supply

Wire business

Retail supply

business

Wire business

Retail supply

business

charges

8 Interest on working capital

69 10% 90% 3 31 3 31

9 Return on equity

840 90% 10% 378 42 378 42

10 Income Tax - 0% 100% - - - -

11 Interest on security deposit

64 0 100% - 32 - 32

12 Bad debts (if any)

- 0% 100% - - - -

13 Contingency reserves (if any)

121 0% 100% - 61 - 61

Deposit for RPO Obligation

- - - - -

14 Total Revenue Requirement

20,124 1,508 8,554 1,508 8,554

15 Less: Non-tariff income

585 10% 90% 29 263 29 263

16 Aggregate Revenue Requirement

19,539 1,479 8,291 1,479 8,291

1.1.4. The wheeling charges have been computed on the basis of projected costs of the Petitioner

for its distribution wire business and the total energy expected to be wheeled through their

distribution network. The average per unit wheeling charge is calculated in the table below

Table 150: Wheeling Charges at 33 kV for 3rd Control Period

Sl. No Particulars Unit FY 2019-20

1 Energy input into 33 kV system MU 31,752.52

2 Total distribution cost Rs. Cr 2,958.14

3 Distribution cost for 33 kV voltage levels (assuming 50% of item 2)

Rs. Cr 1,479.07

4 Wheeling charges for 33 kV voltage level (item 3÷1)

Ps./kWh 46.58

9.2.3. The wheeling cost has been computed for 11 kV level as below

Table 151: Wheeling charges at 11 kV for the 3rd Control Period

Sl. No. Particulars Unit FY 2019-20

1 Energy input into 33 kV system MU 31,752.52

2 Losses in 33 kV (5%) % 3,922.05

3 Energy sales in 33 kV system as approved by the Commission

MU 1,587.63

4 Energy input into 11 kV system [1-(2+3)] MU 26,242.84

5 Total distribution cost Rs. Cr 2,958.14

6 Distribution cost for 11 kV voltage levels (assuming 50% of item 5)

Rs. Cr 1,479.07

7 Wheeling charges for 11 kV voltage Ps/ 56.36



level (item 6÷4) kWh

9.3. Cross Subsidy Surcharge

9.3.1. The open access consumers are liable to pay cross subsidy surcharge to compensate the

distribution utility for any loss of revenue due to shifting of its consumer to the open access

system. The cross subsidy surcharge for open access consumers for the 3rd Control Period

is calculated as per the following recommended formula in the BERC MYT Distribution Tariff

Regulations, 2018.

“S= T – [C/ (1-L/100) + D+ R] Where S is the surcharge T is the tariff payable by the relevant category of consumers, including reflecting the Renewable Purchase Obligation C is the per unit weighted average cost of power purchase by the Licensee, including meeting the Renewable Purchase Obligation D is the aggregate of transmission, distribution and wheeling charge applicable to the relevant voltage level L is the aggregate of transmission, distribution and commercial losses, expressed as a percentage applicable to the relevant voltage level R is the per unit cost of carrying regulatory assets.”

9.3.2. The weighted average cost of power purchase for both Discoms is Rs 4.49/kWh as shown

below:-

Table 152: Power purchase cost for FY 2019-20

Particulars FY 2019-20

Gross power purchase (MU) 17,815.31

Less:-PGCIL loss (MU) 2,229.60

Net power purchase (MU) 20,044.91

Power purchase cost including PGCIL charges 8,854.57

Average power purchase rate 4.42

Table 152: Intra-state Transmission Charge for FY 2019-20

Particulars FY 2019-20

Intra-state Transmission Charge (INR Cr.) 1,710.93

Energy available at State Transmission Periphery (MU)

33,048.00

Transmission Charge (Rs./kWh) 0.52

Calculation of Cross Subsidy Surcharge: -

S = T–[C(1-L)/100)+D+R]

a) For 132 kV consumers =10.33–[(4.42/ (1-3.92%) +0.52+0] = Rs.5.22/kWh



b) For 33kV consumers = 9.48 – [(4.42/ (1-3.92%) x (1-3.95%)+(0.52+0.47)+0] =

Rs.3.71/kWh

c) For 11kV consumers = 9.65–[(4.42/ (1-3.92%) x (1-3.95%)x(1-

3.98%)+(0.52+0.47+0.56)+0] = Rs.3.11/kWh

d) For HTSS consumers = 6.57–[(4.42/ (1-3.92%) x (1-3.95%)+(0.52+0.47)+0] =

Rs.0.99/kWh

9.3.3. The Revised Tariff Policy suggest that the cross subsidy shall not increase 20% of

applicable tariff to the category of consumers seeking Open Access. The cross subsidy

surcharge for 132 kV, 33 kV, 11 kV and HTSS category of the consumers are approved by

the Commission at 20% of applicable tariff of the respective category of consumers seeking

Open Access.

a) The cross subsidy surcharge for FY 2019-20 are:-.

b) For 132 kV consumers :- INR 2.07/kWh

c) For 33kV consumers (other than HTSS) :- INR 1.90/kWh

d) For 11kV consumers (other than HTSS) :- INR 1.93/kWh

e) For HTSS :- INR 0.99/kWh

9.4. Reactive Energy charges

9.4.1. The open access consumers should pay a reactive energy charge to Transmission and

Distribution companies as the case may be for drawl/ injection of reactive energy. Discom

proposes the same reactive charges of 04 Paisa/ kVAR for the 3rd Control Period.

9.4.2. The Hon’ble Commission is requested to approve all the open access charges, Cross

Subsidy Charges and other charges

9.5. Standby Charges

9.5.1. As per BERC open access regulations

“20 A. Standby Power In case of outage of a power plant supplying power to an open access

customer, the licensee will, on request, provide standby supply to meet the requirement of

load catered through open access. Such standby supply will be provided by the licensee at

day ahead request from the open access customer. The open access customer will, for that

supply, be liable to pay charges under tariff for temporary connection to that category of

consumer.”

9.5.2. The Hon’ble Commission is requested to approve the same in line with the regulations

9.6. Roadmap for reduction of Cross Subsidy Surcharge



9.6.1. Section 8.3 (2) of the Tariff Policy 2016 specifies that:

“For achieving the objective that the tariff progressively reflects the cost of supply of electricity,

the Appropriate Commission would notify a roadmap such that tariffs are brought within

±20% of the average cost of supply. The road map would also have intermediate milestones,

based on the approach of a gradual reduction in cross subsidy”.

9.6.2. The Tariff Policy provides that SERCs may notify a roadmap such that tariffs are in ±20% of

ACoS. The First proviso to para 8.5.1 of Tariff Policy 2016 also specifies that Cross Subsidy

Surcharge (CSS) should be capped at 20% of the tariff applicable to the category of the

consumers. The Petitioner aims at gradual reduction of cross subsidy surcharge in line with

National Tariff policy.



Annexure A – Additional Data Submission to BERC

f) Annexure: Government of Bihar notification for capital infusion





g) Annexure: Board Resolution for admittance and payment of Power Purchase & Transmission charges bills between NBPDCL & SBPDCL



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