CONTENTS
ChapterTitle
1.Introduction
2.True-up for the year 2004-05
3.Review for the year 2005-06
4.Commission’s Analysis & Decisions on Revenue Requirement for the year 2006-07
5.Determination of Tariff and Related Issues
6.Annexures


PUNJAB STATE ELECTRICITY REGULATORY COMMISSION
SCO 220-221, SECTOR 34-A, CHANDIGARH.

Phone – 0172-2645164-66, Fax – 0172-2664758

E.mail : percchd8@hotmail.com Website : pserc.nic.in




PUNJAB STATE ELECTRICITY REGULATORY COMMISSION
SCO 220-221 SECTOR-34-A
CHANDIGARH

PETITION NO. 1 OF 2006

IN THE MATTER OF :

ANNUAL REVENUE REQUIREMENT AND TARIFF APPLICATION
FILED BY THE PUNJAB STATE ELECTRICITY BOARD
FOR THE FINANCIAL YEAR 2006-07.


PRESENT:Mr. Jai Singh Gill, Chairman
Mrs. Baljit Bains, Member
Mr. Satpal Singh Pall, Member
Date of Order : May 10, 2006


ORDER

    The Punjab State Electricity Regulatory Commission, in exercise of the powers vested in it under the Electricity Act, 2003 passes this order determining the Annual Revenue Requirement (ARR) and Tariff for supply of electricity by the Punjab State Electricity Board (the Board) to the consumers of the State of Punjab for the year 2006-07. The ARR and Tariff Application filed by the Board, the facts presented by the Board in its various filings, objections received by the Commission from consumer organizations and individuals, the issues raised by the Public in hearings held at Ludhiana, Bathinda, Amritsar and Chandigarh, the responses of the Board to the objections and the observations of the Government of Punjab in this respect have been considered. The State Advisory Committee constituted by the Commission under Section 87 of The Electricity Act, 2003 has also been consulted and all other relevant facts and material on record have been perused before passing this Order.



1.1    BACKGROUND

    Four Tariff Orders have already been passed by the Commission, determining tariff with reference to the ARRs and Tariff Applications submitted by the Board for the years 2002-03, 2003-04, 2004-05 and 2005-06.

    Tariff Orders of the Commission for the years 2002-03 and 2003-04 were challenged in the Punjab & Haryana High Court (High Court) by some consumers. The Tariff Order for the year 2002-03 was set aside by the High Court. The order of the High Court has, however, been stayed by the Hon'ble Supreme Court in SLPs pending before it for final decision. The appeals filed in respect of Tariff Order for the year 2003-04 have been disposed of by the High Court and the parties have been directed to appear before the Appellate Tribunal on July 4, 2006. For the year 2004-05, the Tariff Order of the Commission was challenged by way of writ petitions both by some consumers as well as the Board but the writ petitions were withdrawn. Appeals have, thereafter, been filed by the Board and consumers against the orders passed by the Commission for the years 2004-05 and 2005-06 before the recently constituted Appellate Tribunal at New Delhi. Arguments in these appeals have been concluded by the ! concerned parties and judgment has been reserved by the Tribunal.



1.2    ARR AND TARIFF APPLICATION FOR THE YEAR 2006-07

    The Board filed the ARR and Tariff Application for the year 2006-07 on November 30, 2005 and worked out a cumulative revenue gap of Rs.2390 crore for the year 2006-07. In the Tariff Application, the Board proposed to capture Rs.1335 crores out of total revenue gap of Rs.2390 crores for the year 2006-07 through tariff increase and the remaining gap of Rs.1055 crores was proposed to be carried forward as a Regulatory Asset subject to the approval of the Commission.

    On scrutiny of the ARR and Tariff Application it was observed that there were a number of deficiencies which required substantive changes to be incorporated in the Tariff Application before the same could be put up for Public Notice. The ARR and Tariff Application was returned to the Board by letter dated December 6, 2005 requiring the Board to revise the Tariff Application bringing it in line with the Electricity Act, 2003 and the Tariff Regulations, 2005. The Board responded to the letter of the Commission stating in its letter dated December 13, 2005 that it has initiated the process of compilation of information required for responding to the deficiencies pointed out by the Commission and that the same shall be filed with the Commission in a week's time. It was also requested therein that ARR and Tariff Application may be taken on record. This letter was considered by the Commission in its meeting held on December 15, 2005 wherein the Commission observed that the Tarif! f Application of the Board was not in accordance with the Tariff Regulations, 2005 and that the Application was deficient. Another letter dated December 16, 2005 was written to the Board providing an opportunity to present its case in the hearing scheduled to be held on December 22, 2005. The Board was heard on this date, whereafter it filed the revised ARR and Tariff Application on December 29, 2005. Since the revised ARR and Tariff Application substantively complied with the deficiencies pointed out by the Commission and the Board made request for waivers for the remaining deficiencies, the Commission in its order dated January 2, 2006 decided to take the ARR and Tariff Application on record and to put it to public notice for inviting objections.



1.3    INVITATION OF OBJECTIONS AND PUBLIC HEARINGS

    Public Notice was issued in The Tribune, Hindustan Times, Ajit (Punjabi) and Punjab Kesri (Hindi) on January 5, 6 & 7, 2006 inviting objections from the general public.

    Copies of the ARR and Tariff Application were made available in the offices of the Chief Engineer, Commercial, PSEB, Patiala, Liaison Officer, PSEB Guest House, # 248, Sector 19-A, Chandigarh and also in the offices of all Chief Engineers (Operation) and all Superintending Engineers-in-charge of Operation Circles of the Board. As per this public notice, objectors were advised to file 7 copies of their objections with the Secretary of the Commission by February 6, 2006, with an advance copy to the Board. It was specifically stated in the notice that after perusing the objections received in response to the notification, the Commission will conduct public hearings on the dates which would be subsequently notified.

    The Commission received 32 written objections within the due date expressing concern over the proposed increase in tariffs. Another 21 additional written objections were received after the due date and upto March 31, 2006 during the public hearings and in the office of the Commission. The Commission decided to consider all these objections. Out of a total of 53 objections so received and taken on record, 22 are on affidavits and the remaining without them. However all these objections have been considered and taken into account by the Commission.

    Categorywise number of objections received from consumers, individuals, consumer groups/ organizations and others in response to the public notice are detailed below :
    SI. No.CategoryNo. of Objections
    1.Chambers of Commerce5
    2.Industrial Associations16
    3Industry6
    4Railways1
    5PSEB Engineers/Employees Association2
    6Consumer protection and Grievances Redressal Forum2
    7Trade unions2
    8Social Welfare Trusts/Committees5
    9BSNL1
    10MES2
    11Colonizers1
    12Individuals10
    Total 53


    The list of objectors is contained in Annexure- I to this Tariff Order. The Board submitted its replies to all the written objections raised by different consumers/ consumer organizations, copies of which were supplied to respective objectors.

    The Commission decided to hold public hearings at Ludhiana, Bathinda, Amritsar and Chandigarh. Public notice was issued on March 1, 2006 in The Tribune, Indian Express, Punjab Kesri, Jagbani and Punjabi Tribune informing objectors, consumers and the general public about the holding of public hearings at the following places on the dates shown against each:
    VenueDate & time of public hearingCategory of consumers to be heard.
    LUDHIANA
    Bachat Bhawan,
    Mini Secretariat,
    Jagraon Road,
    Ludhiana
    March 7, 2006
    11 AM to 1.30 PM
    (To be continued in the afternoon, if necessary.
    All consumers/ organisations of the area.
    BATHINDA
    Circuit House, Civil Lines,
    Near D.C.Residence,
    Bhatinda.
    March 10, 2006
    11 AM to 1.30 PM
    (To be continued in the afternoon, if necessary)
    All consumers/ organizations of the area.
    CHANDIGARH
    Commission Office
    i.e. SCO No.220-221,
    Sector 34-A,
    Chandigarh.
    March 13, 2006
    10.30 AM to 1.30 PM
    (To be continued in the afternoon, if necessary)
    All consumers except Industry, Agricultural consumers and staff unions of the Board.
    March 14, 2006
    10.30 AM to1.30 PM
    Industry
    March 14, 20063 PM onwardsStaff unions of Board and other organizations.
    AMRITSAR
    Bachat Bhawan
    (Guest House),
    B-Block,
    Ranjit Avenue,
    Amritsar.
    March 17, 2006
    11 AM to 1.30 PM
    (To be continued in the afternoon, if necessary.
    All consumers/ organizations of the area.
    CHANDIGARH
    Commission Office
    i.e. SCO No.220-221,
    Sector 34-A,
    Chandigarh.
    March 20, 2006
    10.30 AM to1.30PM.
    Agricultural consumers and their Unions.
    March 20, 2006
    3 PM onwards
    Open for all


    Through the same public notice, it was also intimated that the Commission will conduct a public hearing at Chandigarh on March 27, 2006 in which the Board will reply to all the objections raised by the public in writing and during public hearings and make a presentation of its case.

    The public hearings were held as per schedule and the objectors, general public and the Board were heard by the Commission. A gist of the issues raised, responses of the Board and views of the Commission are part of Annexure I of this Tariff Order.

1.4    VIEWS OF THE GOVERNMENT

    The Government of Punjab (GOP) was approached by the Commission through letter dated March 14, 2006 to give its views on the ARR and Tariff Application and the overall level of subsidy which the Government proposed to provide and allocation of this subsidy to different categories of consumers. The State Government conveyed its observations on the ARR and Tariff Application in its letter of April 8, 2006 which have been taken note of by the Commission. The subsidy level has also been intimated by the Government vide its letter dated May 03, 2006 and the same has been incorporated while determining tariff.

1.5    STATE ADVISORY COMMITTEE

    The constitution of the State Advisory Committee under Section 87 of the Electricity Act, 2003 was published in the Punjab Government Gazette of January 20, 2006. The ARR and the Tariff Application were discussed in a meeting of the State Advisory Committee convened for this purpose on March 22, 2006. The minutes of meeting are enclosed as Annexure -II to this Tariff Order.

    The Commission has thus ensured that the due process as contemplated under The Electricity Act, 2003 and the Regulations framed by the Commission was followed at every step and adequate opportunity was provided to all concerned to present their points of view.

1.6    Summary of ARR & Tariff Application of the Board for the year 2006-07.

1.6.1    Annual Revenue Requirement

    The Board filed its ARR and Tariff Application for the year 2006-07 as a vertically integrated utility projecting aggregate revenue requirement of Rs. 9820 crores. The expected revenue projected at current tariffs including subsidy from GoP is Rs. 8124 crores and non-tariff income is projected at Rs.360 crores. The revenue gap for the year 2006-07 accordingly works out to Rs.1336 crores. After adding revenue gap for the years 2003-04, 2004-05 and 2005-06 and after adjustment of excess subsidy received from GoP, the Board has projected total revenue gap of Rs.2595 crores. The Board has proposed to cover this gap by additional revenue from proposed tariffs (Rs.1383 crores) and creation of a Regulatory Asset (Rs.1212 crores). A summary of ARR as filed by the Board is given below in Table 1.1.

    Table - 1.1

    Annual Revenue Requirement for the year 2006-07 (Rs. Crores)
    Sl. No.ItemProjected by the Board in ARR 06-07
    123
    1.Cost of Fuel2316
    2.Power Purchase Expenses3256
    3.Employee Cost*1803
    4.Interest Charges*1036
    5.Repair & Maintenance Expenses*290
    6.A&G Expenses *58
    7.Depreciation Charges649
    8.Net Expenditure9408
    9Add: Reasonable Return412
    10.Total Revenue Requirement9820
    11.Less Non-tariff Income360
    12.Net Revenue Requirement9460
    13.Less Revenue at Existing Tariff including Subsidy from Government of Punjab8124
    14.Net Revenue Gap1336
    15.Adjustment of excess subsidy received from Govt.of Punjab200
    16.Gap for 2003-04, 2004-05 and 2005-061059
    17.Total Gap2595
    18.Covered by
    i) Additional Revenue from Proposed Tariff.
    ii) Regulatory Asset.
    iii)Total

    1383
    1212
    2595
    * Net of capitalization.

    The major items of expenses are Fuel cost (25%), power purchase cost (35%), employees cost (19%) and interest charges (11%).


1.6.2    Energy Projections

    The Board in its ARR has projected energy sales and energy availability within the State for the year 2006-07 as given below in Tables 1.2 and 1.3.

    Table - 1.2
    Energy Sales for 2006-07 (MU)
    Sl.No.Category of ConsumersProjected Energy Sales
    123
    1.Domestic5713
    2.Non-Residential Supply (NRS)1616
    3.Small Power750
    4.Medium Supply1532
    5.Large Supply7337
    6.Agriculture7115
    7.Public Lighting129
    8.Bulk Supply and Railway Traction682
    9.Total Sales in the State24874


    Table - 1.3
    Energy Availability for 2006-07
    Sr. No.ParticularsProjected Energy Availability
    123
    1.Generation 
     (i)Thermal Generation 
     - Gross generation13990
     - Auxiliary consumption 1310
      - Net generation 12680
     (ii) Own Hydel Generation  
     - Gross generation 3740
     - Auxiliary consumption 12
     - Transformation losses55
     - Net generation 3673
     (iii) Share from BBMB (including 302 MU as share of common pool consumers) - Net4248
     Total generation (net)20601
    2.Power purchase (net)12724
    3.Total energy availability33325
    4.Lessi) Common pool sales. ii) Outside state sales302718
    5.Energy available for sale within the State (3-4)32305
    6.T&D loss at 23%7431
    7.Estimated energy sales in the State (5-6)24874
1.6.3    Proposed Tariffs
    a) Existing and Proposed Tariffs

    The Board has filed proposals for revising tariff to meet the Revenue requirement for the year 2006-07. The existing and proposed tariffs are given in Annexure-III to this Tariff Order.

    b) Salient Features of the Proposed Tariff

    1. Two Part Tariff structure has been proposed for Large Supply consumers and Railway Traction. Fixed charges are proposed on sanctioned contract demand and energy charges on energy consumption. Monthly minimum charges are proposed to be discontinued for these categories.

    2. For all categories of consumers except Railway Traction, connected at 33 KV and above voltage, a rebate is proposed on energy charge at the following rate :-
      a)Consumers connected at 33/66 KV2.5%
      b)Consumers connected at 132/220 KV4.0%

    3. Presently a rebate of 7.5% is being allowed to all Domestic Supply/Non-Residential Supply consumers getting supply at 11 KV irrespective of their connected load. The Board has proposed to allow the rebate to only those consumers in the DS/NRS category connected at 11 KV where connected load is less than 100 KW.

    4. Surcharge is proposed to be levied on consumers availing connection at a supply voltage lower than the prescribed voltage as per PSEB norms.

    5. The Board has proposed to increase the existing tariff applicable to temporary connections of all consumers by 15%.

    6. The Seasonal industry/Cold-storage/Ice factories under Large Supply category shall pay the fixed charges for the whole year during the defined seasonal period for which the industry actually runs i.e. per month fixed charges to be recovered shall be adjusted accordingly on pro-rata basis and if any seasonal industry runs beyond seasonal period, only energy charges will be required to be paid during the off-season period.

    7. The Board has also proposed to retain all other charges presently being charged from various categories of consumers for the year 2006-07.

    c) Revenue from Existing and Proposed Tariffs

      The projected revenue from various consumer categories with reference to the existing and proposed tariffs is as given below in Table 1.4.

    Table 1.4
    Revenue from Existing and Proposed Tariff Rates
    Sr. No.Consumer categoryAnnual consumption (MU)Revenue from (Rs. Crores)
    Existing TariffProposed Tariff
    12345
    1.Domestic571316121894
    2.NRS1616741872
    3.Small power750268316
    4.Medium supply1532606710
    5.Large supply733727753268
    6.Public lighting*1295463
    7.Bulk supply, MES and Traction.682270318
    8.Agriculture711515231791
    9.Common pool3025959
    10.Outside State718216216
    11.Total2589481249507

    *In the ARR, revenue from existing and proposed tariff rates has been shown as Rs.55 crores and Rs.64 crores respectively. However, to balance the totals with respect to discussion in the ARR, these have been modified to Rs.54 crores and Rs.63 crores respectively.

1.6.4    2005-06 Review

    The Board has submitted revised estimates for Aggregate Revenue Requirement and Revenue for the year 2005-06 and has worked out revenue gap of Rs.292 crores with the proposal to carry this amount as Regulatory Asset. Revised Revenue Requirement for the year 2005-06 is analyzed in Chapter-3 of this Tariff Order. During its presentation on 27.03.2006, the Board has supplied Latest Estimates (L.E.). These have also been discussed in the relevant paras in Chapter-3.

1.6.5    2004-05 True Up

    The Board has intimated actual Aggregate Revenue Requirement and Revenue for the year 2004-05 and has indicated a revenue gap of Rs. 804 crore. The Board has proposed to carry this amount as a Regulatory Asset. True up for the year 2004-05 based on actuals as reflected in annual statement of accounts is discussed in Chapter-2 of this Tariff Order.

1.6.6    Compliance of Directives

    In its last order the Commission had issued certain directives to the Board in public interest as a part of the Tariff Order. A summary of directives issued, level of compliance by the Board alongwith comments of the Commission are given in Annexure-IV to this Tariff Order.

Chapter-2
True-up for the year 2004-05

    2.1    The Commission had approved the Annual Revenue Requirement and the Tariff for the year 2004-05 in its Tariff Order dated November 30, 2004. These approvals were based on the estimates presented by the Board for costs to be incurred and revenues likely to be generated by the Board during the year. In its ARR and Tariff Application for the next year, 2005-06, the Board furnished revised estimates for the year 2004-05. There were major differences in certain items of costs as well as revenues between the approvals granted by the Commission and the revised estimates furnished by the Board. The Commission in its Tariff Order for the year 2005-06 reviewed the approvals granted by it earlier and re-determined the approvals with reference to the revised estimates made available by the Board. Alongwith its application for determining the ARR for the year 2006-07, the Board has furnished actual audited figures for the year 2004-! 05 which vary as compared to the figures earlier taken into account by the Commission in its review for the year 2004-05 in the Tariff Order of 2005-06. This chapter contains a final true-up for the year 2004-05, based on the audited annual statement of accounts but without altering the principles and the norms approved earlier.

A.    ENERGY DEMAND (SALES), AVAILABILITY AND BALANCE

2.2    ENERGY DEMAND (SALES)

    2.2.1    The sales projected by the Board in the ARR for the year 2004-05, sales approved by the Commission in the Tariff Order of 2004-05, revised estimates in the ARR of 2005-06, re-revised estimates (R.R.E.) furnished during the course of issue of Tariff Order for that year, sales accepted by the Commission in the Tariff Order 2005-06 and actual sales figures now given by the Board in the ARR for the year 2006-07 are given in Table 2.1.

    The Board in its ARR for 2006-07 has furnished actual sales at 23502 MU for the year 2004-05. The sales as per annual statement of accounts for the year 2004-05 are 23501 MU including theft of energy at 179 MU. The sales as per ARR 2006-07 and annual statement of accounts for the year 2004-05 are almost same. However, in the annual statement of accounts theft of energy has not been apportioned to different consumer categories. In Table 2.1 the category-wise sales for the year 2004-05 have, therefore, been shown on the basis of figures given in the ARR for the year 2006-07.

    Table - 2.1
    Energy Sales for 2004-05
    Sr. No.CategoryProposed by PSEB in ARR 04-05Approved by the Commission in T.O. 04-05Revised Estimate by PSEB in ARR 05-06R.R.E. by PSEB during the course of T.O. 05-06Approved by the Commission in T.O. 05-06Actuals furnished by PSEB in ARR 06-07Now approved by the Commission(MU)
    123456789
    1.Domestic5553564456595150515051825182
    2.Non-Residential1344140614361306130613571357
    3.Small Power738738675703703709709
    4.Medium Supply1500158817041447144714781478
    5.Large Supply6902689067066979697969236923
    6.Public Lighting117114115111111112112
    7.Bulk Supply & Grid513540479554554547547
    8.Metered sales (within State)16667169201677416250162501630816308
    9.Agriculture6472621368536593656364726472
    10.Total sales within the State23139231332362722843228132278022780
    11.Common pool381381381381381362362
    12.Outside State sales426426553360360360307
    13.Total (10+11+12)23946239402456123584235542350223449
2.2.2    Metered Sales

    The Commission accepts the metered sales within the State at 16308 MU and common pool sales at 362 MU as per actuals furnished in ARR for the year 2006-07. Actual outside state sales now supplied by the Board is 360 MU. The Board has intimated that HP royalty in Shanan (53 MU) and HP share from RSD (53 MU) forms a part of outside state sales. However, HP share in RSD is free of cost and as such is required to be excluded from such outside sales. After excluding HP share in RSD, the outside state sales come to 307 MU. The Commission, therefore, accepts outside state sales at 307 MU. HP share in RSD will be incorporated in computing net energy availability from hydel power plants.

    The metered sales now approved by the Commission are as shown in Table 2.1.

2.2.3    Agriculture Consumption

    The Commission in its Tariff Order of 2004-05 fixed a consumption norm of 1700 kwh/kw/year for the year 2004-05 and approved AP consumption at 6213 MU. It was also observed in the Tariff Order that the actual AP consumption can be reviewed at the end of the year if more authentic information is made available.

    The Board in its ARR for the year 2005-06 stated that the revised AP consumption during 2004-05 was 6853 MU. For review of AP consumption for the year 2004-05, the Commission discussed the matter in detail in its Tariff Order of 2005-06 and decided to accept sample meter readings in the year 2004-05. On this basis, the Commission in its Tariff Order for the year 2005-06, approved revised AP consumption to 6563 MU for the year 2004-05.

    The Board in its ARR for the year 2006-07 has furnished actual AP consumption during 2004-05 at 6472 MU as per sample meter readings.

    The Commission accepts and approves agriculture consumption at 6472 MU for the year 2004-05 as per actuals based on sample meter readings.

2.3    PSEB’S OWN GENERATION
2.3.1    Thermal Generation

    The station-wise generation projected by the Board in the ARR of 2004-05, generation approved by the Commission in the Tariff Order for the same year, revised estimates furnished in the ARR of 2005-06, generation accepted by the Commission in the Tariff Order for that year and actuals now furnished in the ARR of 2006-07 are given below in Table 2.2.

    Table – 2.2
    Thermal Generation 2004-05
    S . N.StationProjected by PSEB in ARR 04-05Approved by the Commission T.O. 04-05Revised Estimates by PSEB in ARR 05-06Approved by the Commission T.O. 05-06Actuals by PSEB in ARR 06-07Now accepted by the Commission (MU)
      GrossNetGrossNetGrossNetGrossNetGrossNetGrossNet
    1234567891011121314
    1GNDTP210018691982179320231772202318301992174919921802
    2GGSTP850077068895815490008159908383269082830390828325
    3GHTP312028203179289631972890319729123309299233093014
     Total137201239514056128431422012821143031306814383130441438313141

    Actual gross thermal generation for 2004-05 as per ARR of 2006-07 is 14383 MU which is almost the same as actual thermal generation pegged at 14384 MU as per annual statement of accounts of 2004-05. However, plant-wise generation is not available in the annual statement of accounts and as such the values given in the ARR have been taken into account by the Commission. The Commission, therefore, accepts the generation at 14383 MU.
    The position of auxiliary consumption is given in Table 2.3.

    Table - 2.3
    Auxiliary Consumption 2004-05
    S. No.StationApproved by the Commission in T.O.04-05Revised estimates by PSEB in ARR 05-06Approved by the Commission in T.O. 05-06Actuals by PSEB in ARR 06-07Now accepted by the Commission
    1234567
    1.GNDTP9.54%12.40%9.54%12.23%9.54%
    2.GGSTP8.33%9.34%8.33%8.57%8.33%
    3.GHTP8.91%9.61%8.91%9.58%8.91%

    It is observed that the actual auxiliary consumption now furnished by the Board is higher than the approved level. The Commission sees no justification for allowing increase in auxiliary consumption. The Commission, therefore, retains the auxiliary consumption as approved in the Tariff Order for the year 2004-05 i.e 9.54% for GNDTP, 8.33% for GGSTP and 8.91% for GHTP. The net thermal generation on this basis works out to 13141 MU as shown in Table 2.2.

    The Commission observes that the Board has over-achieved in thermal generation by 327 MU gross and 298 MU net as compared to the approvals in the Tariff Order for the year 2004-05.

    The Commission accordingly approves incentive for higher thermal generation and consequential less power purchase on this account. This is discussed further in para 2.9.

2.3.2    Hydel Generation

    The station-wise generation projected in the ARR of 2004-05, generation approved by the Commission in its Tariff Order for that year, revised estimates furnished in the ARR of 2005-06, R.R.E furnished by the Board in the process of consideration of the Tariff Order for 2005-06 and accepted by the Commission and actuals furnished in the ARR of 2006-07 are given below in Table 2.4.

    Table 2.4
    Hydel Generation 2004-05
    Sr. No.StationProjected by PSEB in ARR 04-05Approved by Commission in T.O. 04-05Revised Estimates by PSEB in ARR 05-06R.R.E by PSEB and accepted by Commission in T.O. 05-06Actuals by PSEB in ARR 06-07Now accepted by the Commission
    12345678
    1.Shanan502434460 515515
    2.UBDC380328380 380380
    3.RSD130611901020 11441144
    4.MHP990791830 812812
    5.ASHP691628528 388388
    6.Micro Hydel10810 44
    7.Total Own Hydro      
    a)Gross387933793228 32433243
    b)Net13756232633320531814318753168
    8.Share from BBMB including share of common pool consumers (Net)4374
    (common pool = 381)
    3469
    (common pool = 381)
    3743
    (common pool = 381)
    3669
    (common pool = 381)
    3669
    (common pool = 362)
    3669
    (common pool = 362)
    9.Total hydro (Net)813067326948685068566837
    Notes :
    1.Net of auxiliary consumption, royalty of HP in Shanan and share of HP in RSD.
    2.Net of HP royalty in Shanan (53 MU), HP share (free) from RSD @ 4.60% (55 MU) and auxiliary consumption (8 MU).
    3.Net of auxiliary consumption ( 7 MU) and transformation losses (16 MU).
    4.Net of auxiliary consumption (7 MU) and transformation losses (49 MU).
    5.Net of HP share in RSD (free) @ 4.6% (53 MU), auxiliary consumption @ 0.2% (6 MU) and transformation losses @ 0.5% (16 MU).


    Actual hydel generation for the year 2004-05 is 3243 MU gross from the Board’s own hydel stations and the Commission accepts the same. For calculating the net generation, the Board has not deducted the HP share (free) in RSD. The Commission has worked out net hydel generation by deducting this as well, from gross generation. The net hydel generation for the year 2004-05 thus works out to 3168 MU. Actual net availability from BBMB is 3669 MU and the Commission accepts the same.

    The Commission, therefore, approves the hydel generation for the year 2004-05 at 3168 MU net from own hydel stations and 3669 MU net as share from BBMB as shown in Table 2.4.

2.4    POWER PURCHASE

    To meet the energy demand, the Commission in its Tariff Order of 2004-05, approved power purchase for that year at 11372 MU net. In the ARR for the year 2005-06, the Board furnished revised estimates for power purchase at 12457 MU net. During consideration of the Tariff Order 2005-06, the Board furnished R.R.E for power purchase at 10915 MU net and the Commission accepted the same in its Order. In the ARR of 2006-07, the Board has submitted that actual purchases during 2004-05 are 10900 MU net which is the same as given in the annual statement of accounts for 2004-05. The matter has been further discussed in para 2.8.

2.5    TRANSMISSION & DISTRIBUTION LOSSES (T&D LOSSES)

    The Commission in its Tariff Order of 2004-05, fixed T&D losses at 23.25% for that year. In the ARR for the year 2005-06, the Board stated that T&D losses in 2004-05 would be 24.50%. However, the Commission in its Tariff Order of 2005-06 retained the T&D losses for 2004-05 at 23.25%. In the ARR for the year 2006-07, the Board has intimated that losses during the year 2004-05 are 24.27%. The Commission sees no reason for accepting T&D losses in excess of the approved norm.

    The Commission, therefore, retains the T&D losses at 23.25% as approved in the Tariff Order for the year 2004-05.

2.6    ENERGY BALANCE

    The details of energy requirement and availability approved by the Commission in Tariff Order of 2005-06, actuals furnished in the ARR for the year 2006-07 and now approved by the Commission are given in Table 2.5 below. Energy balance and T&D losses with sales and availability now approved by the Commission is shown in column 6 of Table 2.5.

    Table – 2.5
    Energy Balance 2004-05
    S. No..ParticularsApproved by the Commission in T.O. 05-06Actuals furnished by PSEB in ARR 06-07Now approved by the CommissionT&D losses with sales and availability now approved
    123456
    A) Energy Requirement
    1.Metered Sales16250163081630816308
    2.Sales to Agriculture6563647264726472
    3.Total Sales within the State22813227802278022780
    4.Loss percentage23.25%24.27%23.25%24.59%
    5.T&D losses6911*729869017429
    6.Sales to Common pool consumers381362362362
    7.Sales outside State360360307307
    8.Total requirement30465308003035030878
    B) Energy Available
    9.Own generation (Ex-bus)    
    10.Thermal13068130441314113141
    11.Hydro3181318731683168
    12.Share from BBMB (incl.share of common pool consumers3669
    (common pool = 381)
    3669
    (common pool = 362)
    3669
    (common pool = 362)
    3669
    (common pool = 362)
    13.Purchase net10915109001090010900
    14.Total Available30833308003087830878

    Note : In the ARR 06-07, PSEB has indicated T&D losses as 7300 MU but for balancing energy requirement and energy availability, the losses have been shown as 7298 MU.

    The total energy requirement now approved by the Commission is 30350 MU (net) whereas total energy availability now approved is 30878 MU (net). The difference of 528 MU (net) between energy requirement and energy availability is owing to the underachievement of T&D loss target as discussed in para 2.5 and depicted in columns 5&6 of Table 2.5. The higher T&D loss above the level approved by the Commission has resulted in increased power purchase to the extent of 528 (7429-6901) MU net. The matter is discussed further in para 2.9.

B.    EXPENSES
2.7    FUEL COST

    In its Tariff Order of 2004-05, the Commission approved the fuel cost at Rs.2072.95 crores for a gross thermal generation of 14056 MU. Keeping in view the increase in coal freight w.e.f. November 27, 2004, the Commission in its Tariff Order for the year 2005-06, approved the revised fuel cost for 2004-05 to Rs.2137.50 crores for the then revised approved generation of 14303 MU. The approved fuel cost is given below in Table 2.6.

    Table-2.6
    Approved Fuel Cost for the year 2004-05
    Sr.NoStationAs per T.O. 04-05As per T.O. 05-06
    Gross generation (MU)Fuel Cost (Rs.crores)Gross generation (MU)Fuel Cost (Rs.crores)
    123456
    1.GNDTP1982342.792023354.17
    2.GGSTP88951290.6990831335.53
    3.GHTP3179439.473197447.80
     Total140562072.95143032137.50

    In the ARR of 2006-07 the Board has indicated actual fuel cost for 2004-05 at Rs.2127 crores. As per annual statement of accounts for 2004-05, the total generation expenses for 2004-05 are Rs.2149.82 crores. This comprises of Rs.2048.80 crores for consumption of coal and oil, Rs.14.61 crores for other fuel related costs which include octroi, contract handling charges, railway staff charges, siding charges etc. for coal and oil, Rs.69.19 crores towards fuel related losses which include transit losses, loss on railway claim for coal etc. and Rs.17.22 crores for other operating expenses which include cost of water, lubricants, consumable stores and station supplies. Out of these, the expenses of Rs. 17.22 crores towards other operating expenses do not form part of the fuel cost and have been considered under repair and maintenance expenses in para 2.11. Thus the fuel cost as per annual Statement of accounts is Rs.2132.60 crores (2149.82-17.22).

    In the ARR for the year 2006-07, the actual calorific value of coal, price of coal and coal transit loss for the year 2004-05 are as given below in Table 2.7.

    Table-2.7
    Actual Calorific Value, Price and Transit Loss of Coal for the year 2004-05
    Sr.NoStationCalorific value of coal (kCal/Kg)Price of coal includingTransit loss (Rs./MT)Transit loss Price of coal excluding Transit loss (calculated) (Rs./MT)
    123456
    1.GNDTP389222974.08%2203.28
    2.GGSTP382521401.89%2099.55
    3.GHTP397724685.65%2328.56

    In order to work out fuel cost for the true-up of 2004-05, the Commission decides to consider the price and calorific value of both coal and oil as actually obtained during the year.

    The fuel cost for the year 2004-05 for different stations corresponding to actual generation has been worked out based on parameters adopted by the Commission in its Tariff Orders for the years 2004-05/2005-06, and considering price and calorific value of coal and oil as actually obtained in 2004-05. The fuel cost is given below in Table 2.8.

    Table -2.8
    Fuel cost (Coal and Oil) now approved for 2004-05
    S.N.ItemDerivationUnitApproved for 2004-05
    GNDTPGGSTPGHTPTotal
    12345678
    1.GenerationAMU19929082330914383
    2.Heat RateBk.cal/kWh Generated283725002402 
    3.Specific oil consumptionCMilli litre/kwh1.650.910.32 
    4.Calorific value of oilDk.cal/litre10000100009400 
    5.Calorific value of coalEk.cal/kg389238253977 
    6.Overall heatF = (A*B)G.cal5651304227050007948218 
    7.Heat from oilG = (A*C*D)/1000G.cal32868826469953 
    8.Heat from coalH = (F-G)G.cal5618436226223547938265 
    9.Oil consumption I=G*1000/D=A*CKL328782651059 
    10.Transit loss of coalT(%)2.002.002.00 
    11.Coal consumption including transit loss.J=(H*1000/E) /(I-T/100)MT147304760350422036779 
    12.Cost of oil per KLKRs./KL140711227614686 
    13.Cost of coal per MTLRs./MT220321002329 
    14.Total cost of oilM=K*I/10**7Rs.crores4.6310.151.5616.34
    15.Total cost of coalN=J*L/10**7Rs.crores324.511267.36474.372066.24
    16.Total Fuel CostS=M+NRs.crores329.141277.51475.932082.58
    * indicates multiplication and ** indicates raised to the power

    The Commission, thus, approves the fuel cost at Rs. 2082.58 crores for generation of 14383 MU for the year 2004-05.

    The difference in fuel cost now approved by the Commission (Rs.2082.52 crores) as compared to cost as per annual statement of accounts (Rs.2132.60 crores) is because of difference in operating parameters approved by the Commission and actuals reported by the Board.

2.8    POWER PURCHASE COST

    The Commission, in its Tariff Order of 2004-05, approved a cost of Rs.2171.22 crores for power purchase of 11746 MU (gross). In Tariff Order for 2005-06, the Commission approved revised power purchase cost at Rs.2267.24 crores for power purchase quantum of 10915 MU (net) for 2004-05. The actual gross power purchase for the year 2004-05 now furnished in the ARR of 2006-07 is 11332 MU including unscheduled interchange (UI) of 580 MU. Net power purchase corresponding to 11332 MU gross power purchase is 10900 MU as discussed in para 2.4 while power purchase cost as per annual statement of accounts for 2004-05 is Rs.2281.01 crores.

    The Commission approves the cost of power purchase at Rs.2281.01 crores incurred for power purchase of 10900 MU net (11332 MU gross).

2.9    INCENTIVE APPROVED/EXPENSES DISAPPROVED BY THE COMMISSION
2.9.1    Incentive approved due to higher Thermal Generation

    As discussed in para 2.3.1, the Commission has approved incentive for higher thermal generation to the tune of 327 MU gross (298 MU net) and consequent less power purchase on this account. The station-wise increase in gross generation is 10 MU for GNDTP (1992-1982), 187 MU for GGSTP (9082-8895) and 130 MU for GHTP (3309-3179). The increase in fuel cost for different stations corresponding to this higher generation based on cost now approved by the Commission works out to be Rs.46.65 crores as given in Table 2.9 below:-

    Table 2.9
    Increase in Fuel Cost due to higher Thermal Generation during 2004-05
    Sr. No.StationNow approved by the CommissionIncrease due to higher generation
    Generation (MU)Fuel Cost
    (Rs. Crores)
    Increase in generation (MU)Increase in Fuel Cost
    (Rs. Crores)
    123456
    1.GNDTP1992329.14101.65
    2.GGSTP90821277.5118726.30
    3.GHTP3309475.9313018.70
     Total143832082.5832746.65

    The decrease in power purchase on account of higher thermal generation is 298 MU net. The prorata cost of 298 MU (net) on the basis of power purchase cost approved as per para 2.8 works out to Rs.62.36 crores (i.e.2281.01x298/10900). Hence the net saving on account of higher thermal Generation is Rs.15.71 crores (i.e 62.36-46.65).

    The Commission, therefore, approves an amount of Rs.15.71 crores as incentive on account of higher thermal generation.

    The effect of this is reflected at Sr.No.11 of Table 2.10.

2.9.2    Expenses disapproved due to higher T&D Losses

    As discussed in para 2.5, the Board has underachieved the T&D loss target approved by the Commission. In the Tariff Order for the year 2005-06, the Commission had decided that the financial burden as measured by the consequential additional power purchase on this account may not be passed on to the consumers but borne by the Board. As brought out in para 2.6, T&D loss level higher than that approved by the Commission has resulted in increased power purchase to the extent of 528 MU (net). Pro-rata cost of this 528 MU (net) on the basis of power purchase cost approved under para 2.8 works out to Rs.110.49 crores (2281.01x528/10900).

    The Commission, thus, disapproves expenses of Rs.110.49 crores on account of higher T&D losses.

    The effect of this is reflected at Sr.No.11 of Table 2.10.

2.10    EMPLOYEE COST

    The Commission, in the Tariff Order of 2004-05, had approved an employee cost of Rs.1274.66 crores for the year 2002-03 on actual basis. The Commission had noted that the Board did not take effective steps to contain excess cost on this account and as such, this cost for the years 2003-04 and 2004-05 was also approved at Rs.1274.66 crores by capping it to the level of actual expenditure for the year 2002-03. In the ARR for the year 2006-07, the Board has revised the net employee cost to Rs.1541.24 crores (on actual basis) excluding capitalization of Rs.97.95 crores and prior period expenses of Rs.12.63 crores which are dealt with separately. Since the Commission had decided to cap the employee cost for the year 2004-05 at Rs.1274.66 crores in its earlier Tariff Orders, it has no reason for allowing any further increase in this expenditure now.

    The Commission, therefore, retains the employee cost at Rs.1274.66 crores for the year 2004-05 as approved earlier.

2.11    REPAIRS & MAINTENANCE EXPENSES

    The Commission had approved R&M expenses of Rs.197.10 crores in the Tariff Order of 2004-05 which was revised to Rs.224 crores in the subsequent Tariff Order. In the ARR for 2006-07, the Board has claimed net R&M expenses of Rs.224 crores excluding prior period expenses of Rs.1 crore on actual basis for 2004-05. As per annual statement of accounts of 2004-05, R&M expenses are Rs.206.97 crores net of capitalization of Rs.2.10 crores. After adding other operating expenses of Rs.17.22 crores related to generation as per schedule-7 of the annual statement of accounts, total amount of R&M expenses comes to Rs.224.19 crores which is almost the same as Rs.224 crores as claimed in the ARR of 2006-07.

    In view of this, R&M expenses of Rs.224.19 crores are approved for the year 2004-05.

2.12    ADMINISTRATION AND GENERAL EXPENSES

    The Commission had approved A&G expenses of Rs.43.23 crores in the Tariff Order of 2004-05 which was revised to Rs.47.91 crores in the Tariff Order for 2005-06. In the ARR for 2006-07, net A&G expenses have been claimed at Rs.52.30 crores exclusive of prior period expenses of Rs.13.40 crores. As per annual statement of accounts of 2004-05 also, the net A&G expenses work out to Rs.52.30 crores.

    Therefore, the Commission approves administration and general expenses at Rs.52.30 crores for the year 2004-05.

2.13    DEPRECIATION

    The Commission had approved depreciation of Rs.576.12 crores in the Tariff Order of 2004-05 which was revised to Rs.591.25 crores in the Tariff Order for 2005-06. In the ARR of 2006-07, the Board has claimed depreciation of Rs.583 crores on actual basis for 2004-05. This amount includes prior period depreciation charges of Rs.8 crores which is being excluded as the same is being allowed separately along with other prior period income/expenses. Thus, depreciation charges for the year 2004-05 work out to Rs.575 crores which are almost the same as Rs.574.73 crores given in the annual statement of accounts.

    The Commission, therefore, approves depreciation charges of Rs.574.73 crores for the year 2004-05.

2.14    INTEREST AND FINANCE CHARGES

    The Commission had approved interest and finance charges of Rs.875.62 crores in the Tariff Order of 2004-05 which was revised to Rs.879.75 crores in the Tariff Order for 2005-06 after disallowing Rs.100 crores interest related to diversion of capital funds for revenue purposes. In the ARR of 2006-07, the Board has claimed net amount of interest and finance charges of Rs.997.90 crores excluding prior period expenses and capitalization. As per annual statement of accounts of 2004-05, the net interest and finance charges are of Rs.992.84 crores. As decided earlier by the Commission in the Tariff Orders for the years 2003-04, 2004-05 and 2005-06, the Commission retains disallowance of interest of Rs.100 crores related to diversion of capital funds for revenue purposes by the Board.

    The Commission, therefore, approves Rs.892.84 crores as net amount of interest and finance charges for the year 2004-05. 0

2.15    NET FIXED ASSETS AND RETURN

    The Commission had approved a return of Rs.213.70 crores in the Tariff Order of 2004-05 which was revised to Rs.212.20 crores in the following year. In the ARR of 2006-07, the Board has claimed a return of Rs.213 crores on a capital base of Rs.7090 crores. The return @ 3% on a capital base of Rs.7090 crores actually works out to Rs.212.70 crores.

    Therefore, the Commission approves Rs.212.70 crores as reasonable return on actual basis for the year 2004-05.

C.    MISCELLANEOUS REVENUE (NON TARIFF INCOME)

    The Commission had approved non tariff income of Rs.362 crores in the Tariff Order for the year 2004-05 which was revised to Rs.331 crores in the subsequent Tariff Order. In the ARR of 2006-07, the Board has depicted non tariff income of Rs.331 crores excluding prior period income of Rs.34.70 crores. As per annual statement of accounts of 2004-05, other income of the Board is Rs.181.40 crores besides non tariff income of Rs.149.60 crores which is included in the sale of power. Thus, the total non tariff income of the Board as per annual statement of accounts works out to Rs.331 crores which is the same as depicted by the Board in the ARR of 2006-07.

    As such, the Commission approves non-tariff income of Rs.331 crores on actual basis for the year 2004-05.

2.16    SUBSIDY FROM GOVERNMENT OF PUNJAB

    As per annual statement of accounts for the year 2004-05, total subsidy of Rs.923.61 crores (Rs.873.61 crores AP subsidy + Rs.50 crores SC Domestic subsidy) has been paid by the GoP to the Board. The Commission has now re-determined AP consumption at 6472 MU i.e., 4328 MU + 2144 MU on actual basis on which revenue @ 200 paise and @ 194 paise respectively works out to Rs.1281.54 crores. Of this, farmers have been billed for Rs.391.80 crores and the balance of Rs.889.74 crores is payable by the GoP as AP subsidy as against Rs.873.61 crores already paid to the Board. The GoP has further agreed to pay balance subsidy of Rs.16.13 crores (Rs.889.74 – Rs.873.61) during the current year (refer Table 5.5).

    Besides, subsidy of Rs.8.20 crores for SC Domestic consumers is also payable by the GoP as against Rs.50 crores already paid. The adjustment on account of excess subsidy paid on this account is made in para 4.14 (refer Table 4.24).

2.17    REVENUE FROM SALE OF POWER

    As per annual statement of accounts for the year 2004-05, revenue from sale of power is Rs.6062.51 crores excluding GoP subsidy. This revenue includes non tariff income of Rs.149.60 crores on account of meter rent/service rent, recoveries from theft of power, wheeling charges and partly miscellaneous charges (Rs.114.42 crores, Rs.14.03 crores, Rs1.39 crores and Rs.19.76 crores respectively) which have already been taken into account in non tariff income. Excluding the above from the revenue from sale of power, net revenue on this account works out to Rs.5912.91 crores. After adding GoP subsidy of Rs.923.61 crores, the total revenue from sale of power comes to Rs.6836.52 crores which is almost the same as Rs.6837 crores as given in the ARR.

    Therefore, the Commission approves the revenue from sale of power at Rs.6836.52 crores for the year 2004-05.

D.    PRIOR PERIOD CREDITS/CHARGES

    The Board has claimed prior period income/expenses under different heads of expenditure which have been excluded while approving actual income/ expenditure under those heads. As per schedule-18 of the annual statement of accounts for the year 2004-05, the net effect of prior period credits/charges is Rs.47.74 crores which actually works out to Rs.52.15 crores (income) after taking into account the comments of audit. This includes Rs.12.63 crores being prior period charges of employee cost. These expenses are being allowed assuming that these relate to the period prior to the capping of this cost.

    The Commission, therefore, approves net prior period receipts of Rs.52.15 crores for the year 2004-05.

E.    REVENUE REQUIREMENT

    In view of above analysis the revised revenue requirement for the year 2004-05 would be as per details given in Table 2.10 below:

    Table – 2.10
    Revenue Requirement for the year 2004-05
    Sr. No.Item of expenseApproved by Commission in T. O. for 04-05Approved by Commission in T. O. for 05-06Actuals as per accounts for 04-05Final approval by Commission
    123456
    1.Cost of fuel2072.952137.502132.602082.58
    2.Cost of power purchase2171.222267.242281.012281.01
    3.Employee cost1274.661274.661541.241274.66
    4.R&M expenses197.10224.00224.19224.19
    5.Administration and general expenses43.2347.9152.3052.30
    6.Depreciation576.12591.25574.73574.73
    7.Interest charges875.62879.75992.84892.84
    8.Return on NFA213.70212.20213.00212.70
    9.Less: Prior period receipts (net)--(-)47.74(-)52.15
    10.Total revenue requirement7424.607634.517964.177542.86
    11.i) Add incentive for higher thermal generation
    ii) Less expenses disapproved due to higher T&D loss
    -



    -
    (+)9.40



    (-)76.44
    -(+)15.71



    (-)110.49
    12.Revenue requirement (10-11)7424.607567.477964.177448.08
    13.Less: non tariff income 362.00331.00331.00331.00
    14.Net revenue requirement (12-13)7062.607236.477633.177117.08
    15.Revenue from tariff7333.136931.236836.526836.52
    16.Gap (14-15) (-)270.53305.24796.65280.56
    17.Add concessions94.67---
    18.Net gap(-) 175.86305.24796.65280.56
    19.Gap for the year 2003-04(-) 262.43(-)36.66 (-)36.66
    20.Total gap (18+19)(-) 438.29268.58 243.90
    21.Energy sales (MU)23940235542350123449

    Thus, from the truing up for the year 2004-05, it is noted that there is deficit of Rs.243.90 crores against deficit of Rs.268.58 crores earlier determined by the Commission in the Tariff Order dated June 14, 2005. This deficit is being carried forward to next year for adjustment.

    Chapter-3
    Review for the year 2005-06

    3.1    The Commission had approved the ARR and Tariff for 2005-06 in its tariff order dated June 14, 2005. The Tariff Order of the Commission contained its approvals on various issues concerning the ARR and Tariff Proposals of the Board for the year 2005-06. These approvals were based on estimates presented by the Board for different items of cost to be incurred and revenues likely to be earned by the Board during the year. In the ARR for 2006-07, the Board has furnished revised estimates for the earlier year including a revenue gap of Rs.292 crores for that year. The Board has proposed that this revenue gap may be carried forward as a Regulatory Asset. The Board has thus petitioned to the Commission to revise its ARR for the year 2005-06 as well.

    There are major differences in certain items of cost as well as revenues between the approvals granted by the Commission and the revised estimates furnished by the Board. The Commission, therefore, considers it appropriate and fair to re-look the approvals granted by it earlier and to review these with reference to the revised estimates made available by the Board and taking into account other relevant factors but without altering the principles and the norms approved earlier. The issues involved are discussed in the following paragraphs.

A.    ENERGY DEMAND (SALES), AVAILABILITY AND BALANCE

3.2    ENERGY DEMAND (SALES) FOR THE YEAR 2005-06
    3.2.1    The sales projected in the ARR for 2005-06, sales approved by the Commission in its Tariff Order for that year and revised estimates furnished in the ARR of 2006-07 are given below in Table 3.1.
    Table- 3.1
    Energy Sales for 2005-06
    Sr.No.CategoryProposed by PSEB in ARR 05-06Approved by the Commission in T.O.05-06Revised Estimate by PSEB in ARR 06-07Now approved by the Commission(MU)
    123456
    1.Domestic6075552854415402
    2.Non-Residential1587144414811454
    3.Small Power678707730699
    4.Medium Supply1862158115051456
    5.Large Supply6706697971277543
    6.Public Lighting127123120120
    7.Bulk Supply & Grid504583611567
    8.Metered sales(Within State)17539169451701517241
    9.Agriculture7364700067767000
    10.Total sales within the State24903239452379124241
    11.Common pool381381302302
    12.Outside State sales553360516593
    13.Total (10+11+12)25837246862460925136

3.2.2    Metered Sales

    In the ARR for 2006-07, the Board has stated that energy sales to metered categories in 2005-06 and 2006-07 have been projected based on cumulative annual growth rate (CAGR) of the past three years i.e. FY 01-02 to FY 04-05, except for sales to other states, which have been projected on the premise that J&K would be drawing its 20% share from RSD project w.e.f. November 1, 2005. Besides, share in common pool sale from BBMB is based on the details as provided by it. Further, the Board asserts that growth in total metered sales for the first six months of 2005-06 is broadly in line with the past 3 years CAGR (FY 01-02-FY04-05).

    The Board in its presentation on March 27, 2006 has given Latest Estimates (L.E.) for total metered sales within the State as 17241 MU but category-wise sales were not given. Subsequently, the Board also supplied details of L.E. for category-wise metered sales within the State. The Commission accepts the L.E. of metered sales within the State at 17241 MU. The Board in its presentation has not given L.E. for sales to common pool and outside state sales separately but given a combined L.E. of 988 MU on that account. Out of this, the Commission approves sales to common pool at 302 MU as per Revised Estimates in the ARR for 2006-07. The L.E. for outside state sales thus work out to 686 (988-302) MU. The Board in its ARR, has intimated that HP royalty in Shanan and HP share from RSD forms part of outside state sales. However, HP share in RSD is free of cost and as such is required to be excluded from outside state sales. After excluding HP share (93 MU) in RSD (refer pa! ra 3.5.2), the revised estimates for outside state sales come to 593 MU. The Commission, therefore, accepts outside state sales at 593 MU. HP share in RSD will be incorporated in computing net energy availability from hydel power plants.

    The metered sales now approved by the Commission are as shown in Table 3.1.

3.2.3    Agriculture Consumption

    The Commission in its Tariff Order for 2005-06 approved AP consumption for that year at 7000 MU after allowing reasonable increase over the then approved consumption on this account for the year 2004-05 at 6563 MU based on sample meter readings. It was also observed in the Tariff Order that AP consumption approved will be reviewed at the end of the year based on sample meter readings and other relevant factors.

    The Board in its ARR for the year 2006-07 has furnished revised estimates for AP consumption for 2005-06 at 6776 MU based on the actual consumption for April to September, 2005 as per readings of sample meters and projected consumption for the remaining part of the year.

    The Board, during its presentation submitted L.E. for AP consumption at 7259 MU. The Board has intimated that increase in AP consumption from R.E. of 6776 MU is owing to failure of winter rains. Actual consumption data upto February, 2006 based on sample meter readings was obtained from the Board. Assuming AP consumption for March, 2006 at the level of AP consumption during March, 2005, the total estimated AP consumption during 2005-06 is as given below in Table 3.2.

    Table 3.2
    AP Consumption for 2005-06 as per Sample Meters
    MonthConsumption (kwh)
    12
    April, 2005301,394,576
    May, 2005376,271,030
    June, 2005607,428,196
    July, 2005971,894,007
    August, 20051063,883,821
    September, 20051023,623,030
    October, 2005697,128,092
    November, 2005491,568,051
    December, 2005459,234,160
    January, 2006383,433,802
    February, 2006416,380,486
    March, 2006 (Assumed equal to AP consumption of March, 2005)224,996,276
    Total7017,235,527

    Thus, the total AP consumption now estimated as per sample meter readings is 7017 MU for the year 2005-06. These estimates are very close to AP consumption of 7000 MU approved by the Commission in the Tariff Order of 2005-06. As these are still estimates, the Commission retains AP consumption as approved in the Tariff Order for 2005-06.

    The Commission, thus, retains agriculture consumption for the year 2005-06 at 7000 MU.

3.3    TRANSMISSION & DISTRIBUTION (T&D) LOSSES

    For the reasons discussed in Tariff Order for the year 2005-06, the Commission retains target T&D loss level at 22.00% for the year 2005-06.

3.4    ENERGY REQUIREMENT (INPUT)

    The total energy requirement to meet the demand of the system would be the sum of estimated energy sales including common pool and outside state sales and T&D losses. The total energy requirement for the year 2005-06 projected in the ARR for 2005-06, approved by the Commission in its Tariff Order of 2005-06, revised estimates furnished in the ARR for 2006-07 and now approved by the Commission are given below in Table 3.3.

    Table 3.3
    Energy Requirement for the year 2005-06
    Sr.NoParticularsProjected by PSEB in ARR 05-06Approved by the Commission in T.O. 05-06Revised Estimates by PSEB in ARR 06-07Now approved by the Commission
    123456
    1.Metered Sales within the State17539169451701517241
    2.Agriculture Consumption7364700067767000
    3.Total sales within State (1+2)24903239452379124241
    4.Common pool sales381381302302
    5.Outside state sales553360516593
    6.Total sales25837246862460925136
    7.T&D Losses on item (3)(24%) 7864(22%) 6754(24%) 7513*(22%) 6837
    8.Total energy input required33701314403212231973

  1. In the ARR 06-07, PSEB has indicated T&D losses as 7514 MU but to balance the energy requirement with the revised estimates of energy availability discussed in subsequent paragraphs, these have been shown as 7513 MU.

    The revised energy requirement for the year 2005-06 thus is 31973 MU which has to be met from own generation of the Board (Thermal & Hydel) including share from BBMB, purchases from Central Generating Stations and other sources.

3.5    PSEB’s OWN GENERATION
3.5.1    Thermal Generation

    The station-wise generation projected by the Board in the ARR of 2005-06, generation approved by the Commission in its Tariff Order for that year, revised estimates in the ARR for 2006-07 and L.E. now supplied by the Board are given in Table 3.4 below.

    Table-3.4
    Thermal Generation 2005-06
    S NStationProjected by PSEB in ARR 05-06Approved by the Commission T.O.05-06Revised Estimates by PSEB in ARR 06-07Latest Estimates by PSEB during course of T.O. 06-07Now approved by the Commission
    GrossNet (Aux Cons)GrossNet (Aux. Cons)GrossNet (Aux Cons)GrossNet (Aux Cons)GrossNet (Aux Cons)
    123456789101112
    1GNDTP21001840
    (12.40%)
    22201976
    (11.00%)
    21001840
    (12.40%)
    2358-23582099
    (11.00%)
    2GGSTP86507842
    (9.34%)
    86387904
    (8.50%)
    86507903
    (8.64%)
    9320-93208528
    (8.50%)
    3GHTP31202820
    (9.60%)
    30892811
    (9.00%)
    31202828
    (9.35%)
    3134-31342852
    (9.00%)
     Total13870125021394712691138701257114812134461481213479

    The Board in its ARR for 2006-07 has furnished Revised Estimates for gross thermal generation for the year 2005-06 at 13870 MU. In its presentation in March, 2006, the Board has given L.E. of net thermal generation in 2005-06 at 13446 MU, wherein gross generation for different plants has not been separately depicted. Subsequently, the Board also furnished details of L.E. for gross generation of different thermal plants as 2358 MU, 9320 MU and 3134 MU for GNDTP, GGSTP and GHTP respectively. Thus, L.E. for total gross generation of thermal plants is 14812 MU.

    Accordingly, the Commission approves gross thermal generation for the year 2005-06 at 14812 MU as per L.E.

    Auxiliary Consumption & Net Generation.

    The Commission, in its Tariff Order for 2005-06 approved auxiliary consumption for GGSTP and GHTP at 8.50% and 9.00% respectively as per CERC norms. The Commission allowed auxiliary consumption for GNDTP at 11.00% in line with CERC norm for Tanda station of NTPC which like GNDTP has 4 units of 110 MW each. In the ARR of 2006-07, the Board has revised the estimates of auxiliary consumption which are higher than the approved levels as depicted in Table 3.4. The Commission sees no justification for allowing increase in auxiliary consumption levels as per revised estimates of the Board.

    The Commission, thus, retains the auxiliary consumption levels as approved in the Tariff Order for 2005-06. The net thermal generation on this basis works out to 13479 MU as shown in Table 3.4.

3.5.2    Hydel Generation

    The station-wise generation projected by the Board in the ARR for 2005-06, generation approved by the Commission in its Tariff Order for that year and revised estimates in the ARR of 2006-07 are given below in Table 3.5.

    Table 3.5
    Hydel Generation 2005-06
    Sr. No.StationProjected by PSEB in ARR 05-06Approved by the Commission in T.O. 05-06Revised Estimates by PSEB in ARR 06-07Now approved by the Commission
    123456
    1.Shanan460502514509
    2.UBDC380380451531
    3.RSD1020130918022013
    4.MHP83099710301237
    5.ASHP528696744709
    6.Micro Hydel1010106
    7.Total own Hydel
      Gross3228389445515005
     Net13205237543448644877
    8.Share from BBMB including share of common pool consumers(Net)3743
    (Common Pool-381)

    4507
    (Common Pool-381)
    4773
    (Common Pool-302)
    54778
    (Common Pool-302)
    9.Total Hydro (Net)6948826192599655
    1.Net of auxiliary consumption (7 MU) and transformation losses (16 MU)
    2.Net of HP royalty in Shanan (53 MU), HP share (free) in RSD @4.6% (60MU), auxiliary consumption @ 0.2% (8MU) and transformation losses @0.5% (19 MU).
    3.Net of auxiliary consumption (11 MU) and transformation losses (54 MU). In the ARR, net hydel generation from own hydel stations has been indicated as 4487 MU whereas it works out to 4486 MU.
    4.Net of HP share (free) in RSD @ 4.6%(93 MU), auxiliary consumption @0.2% (10MU) and transformation losses @ 0.5% (25 MU).
    5.Net of NREB transmission losses @ 3.76% (187 MU) from gross availability of 4965 (4663+302) MU from BBMB.

    The Board in its ARR for 2006-07 has given revised estimates for hydel generation in 2005-06 as 4551 MU gross and 4486 MU net from its own stations and 4773 MU net as its share from BBMB. The Board has stated that energy availability from own hydel stations and BBMB during the year 2005-06 is higher mainly owing to a good monsoon.

    The Board in its presentation in March, 2006 has given Latest Estimates (L.E.) for hydel generation including BBMB share, for 2005-06 as 9879 MU (net) wherein gross generation from each of the hydel stations of PSEB and BBMB share has not been given separately. Subsequently, the Board supplied L.E. for gross generation of own hydel stations and share from BBMB. The Commission accepts the L.E. furnished by the Board but has worked out net hydel generation by deducting HP share (free) @ 4.6% in RSD.

    The Commission, thus, approves the revised hydel generation for the year 2005-06 at 4877 MU net from own hydel stations and 4778 MU net as share from BBMB as shown in Table 3.5.

3.6    POWER PURCHASE

    To meet the energy demand, the Board, in its ARR for 2005-06 projected power purchase at 14251 MU net. The Commission in its Tariff Order for that year approved power purchase at 10488 MU net. In the ARR of 2006-07, the Board has given revised estimates of power purchase for 2005-06 at 10292 MU net. The now approved total energy (input to the system) to meet the demand of the State during 2005-06 including common pool and outside state sales and T&D losses is 31973 MU as discussed in para 3.4. The energy available from own generating stations of the Board including its share from BBMB is 23134 (13479+4877+4778) MU as approved in para 3.5. The balance energy requirement of 8839 MU (net) has to be met through purchases from central generating stations and other sources.

    The Commission, accordingly, approves the revised power purchase at 8839 MU net for the year 2005-06.

3.7    ENERGY BALANCE

    The details of energy requirement and energy availability projected in the ARR for 2005-06, approved by the Commission in its Tariff Order of that year, revised estimates in the ARR of 2006-07 and now approved by the Commission are given in Table 3.6.

    Table 3.6
    Energy Balance 2005-06
    Sr.No.ParticularsAs per PSEB in ARR 05-06Approved by the Commission in T.O. 05-06Revised estimates by PSEB in ARR 06-07Now approved by the Commission
    123456
    (A) Energy Requirement
    1Metered Sales within the State17539169451701517241
    2Sales to Agriculture7364700067767000
    3Total Sales within the State24903239452379124241
    4Loss percentage24%22%24%22%
    5T&D losses7864675475136837
    6Sales to Common pool381381302302
    7Sale outside State553360516593
    8Total requirement33701314403212231973
    (B) Energy Available
    9Own generation (Ex-bus)
    10Thermal12502126911257113479
    11Hydro3205375444864877
    12Share from BBMB (inc.share of common pool consumers)3743(Common pool-381)4507(Common pool-381)4773(Common pool-302)4778(Common pool-302)
    13Purchase net1425110488102928839
    14Total Available33701314403212231973

B.    EXPENSES
3.8    FUEL COST

    The Commission in its Tariff Order of 2005-06 approved fuel cost at Rs.2176.19 crores for a gross thermal generation of 13947 MU. In the ARR for 2006-07, the Board has given revised estimates of fuel cost at Rs.2182 crores for gross thermal generation of 13870 MU. The Commission has now approved revised gross thermal generation at 2358 MU for GNDTP, 9320 MU for GGSTP and 3134 MU for GHTP as discussed in para 3.5. The prorata fuel cost for different stations corresponding to generation now approved has been worked out, based on the parameters approved by the Commission in its Tariff Order of 2005-06 and the same is given below in Table 3.7.

    Table - 3.7
    Approved Fuel Cost for the year 2005-06
    Sr.No.StationApproved by the Commission T.O. 05-06Now approved by the Commission
    Gross Generation (MU)Fuel Cost (Rs.Crore)Gross Generation (MU)Fuel Cost (Rs.Crore)
    123456
    1GNDTP2220391.272358415.59
    2GGSTP86381317.0793201421.06
    3GHTP3089467.853134474.67
     Total139472176.19148122311.32

    The Commission, therefore, approves the revised fuel cost at Rs.2311.32 crores for the now approved generation of 14812 MU.

3.9    COST OF POWER PURCHASE

    The Commission in its Tariff Order for 2005-06 approved a cost of Rs.2259.66 crores for purchase of 10916 MU gross. In the ARR of 2006-07, the Board has given revised estimates for such cost at Rs. 2445 crores for purchase of 10695 MU gross in the year 2005-06.

    As discussed in para 3.6, the requirement of 8839 MU net has to be met through purchases from central generating stations and other sources. The transmission loss external to the PSEB system has to be added to arrive at the quantum of gross energy to be obtained from various sources. The Commission in its Tariff Order of 2005-06 had determined the external losses at 3.92% as per actuals in the Northern region upto December, 2004. In its ARR of 2006-07, the Board has stated that external losses on power purchase in 2005-06 are estimated to be 3.76%. For arriving at the revised gross energy to be purchased, the Commission has considered the losses at 3.76% as per latest estimates. After adding these losses, the gross energy required to be purchased works out to 9184 MU (8839 MU + external losses 345 MU). On the basis of the power purchase cost approved by the Commission in its Tariff Order for 2005-06, the prorata cost of 9184 MU works out to Rs.1901.13 crores (2259.66! x9184/10916).

    The Commission, therefore, approves a revised cost of Rs.1901.13 crores for the now determined power purchase requirement of 9184 MU.

3.10    FUEL COST ADJUSTMENT (FCA) AMOUNT

    The Commission’s Tariff Order of 2005-06 mentioned that any change in fuel cost from the level approved by the Commission would be passed on to the consumers as Fuel Cost Adjustment (FCA). PSEB filed Petition (No.10 of 2005) for approval of FCA for the second quarter of 2005-06 which was decided by the Commission in its Order dated January 31, 2006 approving an Adjustment Amount of Rs.11.91 crores cumulative for the first two quarters. It was also provided in the Order that the adjustment amount shall be allowed along with Tariff Order for 2006-07. Further, the Board filed Petition (No.7 of 2006) for approval of FCA for the third quarter of 2005-06. The Commission has decided on the Petition and approved Adjustment Amount of minus Rs.11.43 crores. The total Adjustment Amount on account of FCA for first three quarters thus comes to Rs.0.48 crores.

    The Commission, therefore, approves Fuel Cost Adjustment amount of Rs.0.48 crores.

    The effect of this item is reflected at Sr.No.14 of Table 3.13.

3.11    EMPLOYEE COST

    In the ARR for 2006-07, the Board has claimed net employee cost of Rs.1710.52 crores for the year 2005-06. The Commission has consistently observed that the employee cost of the Board was one of the highest in the country and had recommended that the Board needs to take effective steps to contain the same. This issue has already been dealt with in detail in the Tariff Orders from 2002-03 to 2005-06. For 2005-06, the Commission had approved employee cost of Rs.1473.63 crores based on increase of 15.61% in the Wholesale Price Index from March 2002 to January 2005 (the then available WPI). Now, the WPI upto March, 2005 has become available and the increase from March 2002 to March 2005 works out to 16.11%. Accordingly, employee cost for the year 2005-06 is revised to Rs.1480.01 crores.

    The Commission, therefore, approves employee cost of Rs.1480.01 crores in the year 2005-06.

3.12    REPAIR AND MAINTENANCE EXPENSES

    In the ARR for 2005-06, the Board had projected R&M expenses at Rs.265 crores in that year which were approved by the Commission. Now, the Board has revised its estimtates to Rs.250 crores in its presentation of March, 2006. The details of expenditure as given in the ARR indicate that the Board intended to utilize this amount on R&M of plant and machinery, lines, cables and network to ensure reliable and un-interrupted energy supply. The claim for expenditure on R&M is, therefore, justifiable.

    The Commission, as such, approves R&M expenses at Rs.250 crores for the year 2005-06.

3.13    ADMINISTRATION AND GENERAL EXPENSES

    The Commission, in its Tariff Order for 2005-06 had approved A&G expenses of Rs.50.31 crores by allowing increase of 5% over the actual expenditure in 2003-04, keeping in mind a 5% expansion in business of the Board. Actuals for 2004-05 have now become available. Accordingly, the Commission allows increase of 5% over the actuals of Rs.52.30 crores for the year 2004-05 against the Board’s revised claim of Rs. 55 crores.

    The Commission, therefore, approves administration and general expenses of Rs.54.91 crores in 2005-06.

3.14    DEPRECIATION

    The Commission had approved Rs.621.77 crores as depreciation charges in the Tariff Order for 2005-06. In the ARR of 2006-07, the Board has revised its claim to Rs.609 crores in 2005-06 as given in Table 3.8. Table 3.8 Depreciation Charges (Rs. in crores)
    Sr. no.ItemAssets as on April 1, 2004Amount of Depreciation for 2004-05 % RateAssets as on April 1, 2005Amount of Depreciation for 2005-06 % Rate
    1.2.3.4.5.6.7.8.
    1.Thermal28681485.1729221515.17
    2.Hydro56331422.5256571422.52
    3.Internal combustion3--3--
    4.Transmission1486835.581627915.58
    5.Distribution32812006.1036552236.10
    6.Others13721.3413721.34
    7.Total13407575 14001609 

    >From the above, it is evident that the percentage of depreciation charges for 2005-06 is the same as was approved by the Commission in 2004-05.

    The Commission, therefore, approves depreciation charges of Rs.609 crores for the year 2005-06.

3.15    INTEREST AND FINANCE CHARGES

    The Commission had approved net interest and finance charges of Rs.811.41 crores in the Tariff Order for 2005-06. In the ARR of 2006-07, the Board has claimed net interest and finance charges of Rs.1023.60 crores in 2005-06.

3.15.1    Investment Plan

    In the revised estimates for 2005-06, the Board has proposed an investment of Rs.1281 crores against approved investment of Rs.1200 crores by the Commission in the Tariff Order of 2005-06. Against the proposed investment, actual capital expenditure in 2005-06 upto January, 2006 is Rs.991.48 crores as per annexure-A-4 of the Board’s presentation of March, 2006. This level of spending shows that the total expenditure during the year is unlikely to exceed Rs.1200 crores already approved by the Commission. Therefore, the Commission retains its earlier approval of Rs.1200 crores on this account.

3.15.2    Working Capital

    Working capital requirement of the Board based on revised expenditure approved under different heads by the Commission is worked out in Table 3.9 below:

    Table – 3.9 Working Capital Requirement
    One month fuel cost192.61(Rs. in crores)
    One month power purchase158.43
    One month cash requirement (employee cost and A&G expenses)127.91
    One month cost of R &M 20.83
    Total requirement for working capital499.78

    The Board has claimed Rs.66.10 crores as interest on working capital loan of Rs.930.93 crores. The Commission approves interest of Rs.35.49 crores on working capital loan of Rs.499.78 crores on proportionate basis.

3.15.3    Finance Charges

    The Board has claimed these charges @1.56% of fresh borrowings against the rate of 1.5% approved in the Tariff Orders for 2004-05 and 2005-06. The Commission sees no reason for enhancing the rate of finance charges. However, the Commission approves finance charges of Rs.14.75 crores @ 1.5% of net investment of Rs.983 crores for 2005-06 after adjustment of consumer contribution of Rs.217 crores assumed at previous year’s level.

3.15.4    Interest on Government Loans

    With the conversion of Rs.140 crores of State Government loans into equity, the balance of Government loans work out to Rs.4397.53 crores. The Commission allows interest of Rs.465.90 crores (in place of Rs.480.73 crores allowed earlier on loans of Rs.4537.53 crores) for the year 2005-06 on proportionate basis.

3.15.5    Interest on Diversion of Funds0

    In view of the detailed discussion in the previous Tariff Orders for the years 2003-04, 2004-05 and 2005-06 on this issue, the Commission retains disallowance of interest of Rs.100 crores related to diversion of capital funds for revenue purposes.

3.15.6    Capitalization of Interest

    As already decided in earlier Tariff Orders, the Commission allows capitalization of interest excluding interest charges on working capital in the ratio of net works in progress to total expenditure.

    Accordingly, the interest and finance charges for the year 2005-06 are revised as per Table 3.10 below.

    Table-3.10
    Interest Charges approved for the year 2005-06

    (Rs. in crores)

    Sl. No.ParticularsLoans o/s as on 31.3.05Receipt of loansRepayment of loansLoans o/s as on 31.3.06Amount of interest
    1234567
    1.As per ARR (other than WCL & Govt. loans)3998.761134.00872.594260.17535.46
    2.Approved by Commission (other than WCL & Govt. loans)3998.76*983.00872.594109.17525.67
    3.Government loans4537.53--**4397.53465.90
    4.Total (2+3)8536.29983.00872.598506.70991.57
    5.Interest on working capital----35.49
    6.Total interest----1027.06
    7.Add finance charges----14.75
    8.Grand total----1041.81
    9.Less capitalization     72.75
    10.Net interest & finance charges----969.06
    *Receipt of loan Rs.983 crores = Approved investment of Rs.1200 crores – consumer contribution of Rs.217 crores.
    ** Govt. loans of Rs.140 crores converted into equity.

    The net interest and finance charges work out to Rs.869.06 crores for 2005-06 after disallowing Rs.100 crores of interest related to diversion of capital fund for revenue purposes.

    Therefore, the Commission approves interest and finance charges of Rs.869.06 for the year 2005-06.

3.16    SUBSIDY FROM GOVERNMENT OF PUNJAB

    The Commission has retained AP consumption at 7000 MU for the year 2005-06. Estimated revenue from Agriculture Sector at the existing tariff of 214 paise per unit works out to Rs.1498 crores. Out of this, revenue receipts from farmers were Rs.432.82 crores as determined by the Commission in the Tariff Order 2005-06. Thus, the Government subsidy for the AP sector was worked out at Rs.1065.18 crores. In view of the decision of the Government to provide free electricity to all farmers from September 1, 2005, an additional subsidy of Rs.252.48 (432.82 x 7/12) crores has also become due from the Government. Besides, the Board in its communication of November 14, 2005 has intimated that because of free supply to agricultural sector, it would not be possible to recover the service charges and meter rentals from farmers as they would not be coming for payment of bills. The Board has estimated revenue loss of Rs.7 crores per annum on this account. The Government subsidy on account of! these charges and rentals for seven months of 2005-06 will, therefore, be Rs.4.08 crores (7x7/12) on proportionate basis. This amount of Rs.4.08 crores would, therefore, need to be reimbursed from Government through subsidy. The total subsidy for AP sector would accordingly be of Rs.1321.74 crores for the year 2005-06. Besides, the Board has claimed subsidy of Rs.10.50 crores for Domestic (SC) Consumers on account of free energy supply upto 50 units per month. However, the limit of free supply has been enhanced to 200 units per month from September 1, 2005. The Board has not submitted its revised claim on account of this enhancement. Therefore, the Commission retains the approval for the GoP subsidy of Rs.50 crores as originally determined in 2005-06. This will be adjusted in the True-up exercise for 2005-06 on the basis of actual expenditure.

3.17    NET FIXED ASSETS AND RETURN

    The Commission had approved Rs.205.57 crores as return on net fixed assets of Rs.6852.45 crores in the Tariff Order for 2005-06. In the ARR of 2006-07 as also in its presentation of March 27, 2006, the Board has revised its claim to Rs.208 crores for 2005-06 owing to a change in net fixed assets. The actual amount of return @3% has been worked out in Table 3.11 below:

    Table - 3.11
    Reasonable Return

    (Rs. in crores)

    Item05-06 (RE)
    12
    Gross block14001
    Accumulated depreciation5492
    Net block8509
    Less consumer contribution1587
    Net fixed assets6922
    Reasonable return @3%207.66

    The Commission, therefore, approves Rs.207.66 crores as return on net fixed assets for the year 2005-06.

C.    MISCELLANEOUS REVENUE (NON TARIFF INCOME)

    In the Tariff Order for 2005-06, the Commission had approved non tariff income of Rs.340 crores as estimated by the Board. Now, in the ARR of 2006-07, the Board has revised the estimates of non tariff income to Rs.352.80 crores for 2005-06. The actuals of 2005-06 are not yet available.

    The Commission, therefore, approves Rs.352.80 crores as miscellaneous revenue (non tariff income) of the Board for the year 2005-06.

3.18    REVENUE FROM EXISTING TARIFF

    In the ARR for 2006-07, the Board has revised the estimates of revenue from existing tariff (after tariff hike of 2005-06) to Rs.7853 crores in 2005-06. However, the Commission has assessed revenue from existing tariff at Rs.7959.91 crores as given in Table 3.12.

    Table - 3.12
    Revenue from Existing Tariff
    Sr. No.Category of consumersEnergy sales (MU)Tariff rates (paise/unit)Revenue (Rs. in crores)
    12345
    1. Domestic
    a)Up to 100 units2971221656.59
    b)101-300 units1351368497.17
    c)Above 300 units1080389420.12
     Total (a+b+c)5402 1573.88
    2.NRS1454423615.04
    3.Public lighting12042350.76
    4.
    a)SP699337235.56
    b)MS1456372541.63
    c)LS75433722806.00
     Total (a+b+c)9698 3583.19
    5.Bulk supply454394178.88
    6.Railway traction11344350.06
    7.Common pool302-59.74
    8.Outside state593-147.36
    9.Total (1 to 8)18136-6258.91
    10.AP consumption70002141498.00
    11.Total (9+10)25136-7756.91
    12.Add MMC and Other charges--203.00
    13.Grand Total--7959.91


    The Commission, therefore, approves the revenue from existing tariff at Rs.7959.91 crores for the year 2005-06.

D.    REVENUE REQUIREMENT

    The summary of the review for 2005-06 as analyzed in the preceding paragraphs is given in Table 3.13 below: Table – 3.13 Revenue Requirement for the year 2005-06 (Rs. in crores)
    Sr. No.Item of expenseApproved by Commission in T.O. for 05-06Revised by the Board in ARR for 06-07Latest estimates as per presentationFinal approval by Commission
    123456
    1.Cost of fuel2176.192182.002334.002311.32
    2.Cost of power purchase2259.662445.002358.001901.13
    3.Employee cost1473.631711.001711.001480.01
    4.R&M expenses265.00265.00250.00250.00
    5.Administration and general expenses50.3155.0055.0054.91
    6.Depreciation621.77609.00609.00609.00
    7.Interest charges811.411024.001024.00869.06
    8.Return on NFA205.57208.00208.00207.66
    9.Total revenue requirement7863.548499.008548.007683.09
    10.Less: non tariff income 340.00353.00354.00352.80
    11.Net revenue requirement (9-10)7523.548145.008194.007330.29
    12.Revenue from tariff7023.477853.007935.007959.91
    13.Gap (11-12)500.07292.00259.00(-)629.62
    14.Fuel cost adjustment---0.48
    15.Net gap (13+14)--259.00(-)629.14
    16.Gap for 2004-05268.58-767.00243.90
    17.Total gap (15+16)768.65-1027.00(-)385.24
    18.Energy sales (MU)24686246092548725136

    Thus, from the review of the year 2005-06, it is noted that there is gap (surplus) of Rs.629.14 crores. The net gap (surplus) for the year 2005-06 after adjustment of deficit of Rs.243.90 crores for the year 2004-05 works out to Rs.385.24 crores against deficit of Rs.768.65 crores determined earlier by the Commission in the Tariff Order dated June14, 2005. This gap (surplus) of Rs.385.24 crores is being carried forward to the next year for adjustment.

Chapter-4
Commission’s Analysis and Decisions
on Revenue Requirement
for the year 2006-07

A.    CATEGORYWISE ENERGY DEMAND (SALES)/T&D LOSSES AND TOTAL ENERGY REQUIREMENT

4.1     ENERGY DEMAND (SALES) FOR THE YEAR 2006-07

4.1.1    Metered Energy Sales

    Category-wise actual sales for 2001-02, 2002-03 , 2003-04 and 2004-05, Cumulative Annual Growth Rate (CAGR) for 3 years i.e. 2001-02 to 2004-05, Revised Estimates (R.E.) of sales for 2005-06 and projected sales in 2006-07 as per ARR for that year are given below in Table 4.1.

    Table - 4.1
    Energy Sales to Metered Categories as per ARR 2006-07

    (MU)

    MeteredActual for 01-02Actual for 02-03Actual for 03-04 Actual for 04-053yr.CAGR for 01- 02 to 04-05RE for 05-06Projection for 06-07
    12345678
    Domestic44764913527151825.00%54415713
    Non-residential10441204129913579.12%14811616
    Small Power6516426717092.88%730750
    Medium Supply14001474155914781.82%15051532
    Large Supply63446405670669232.92%71277337
    Public Lighting91891041127.32%120129
    Bulk supply, MES & Traction39441845454711.54%611682
    Common Pool113105381362 302302
    Outside State633589553360 516718
    Total Sales15146158381699917029 17833*18779**
    *In the ARR 06-07, total has been indicated as 17832 MU.
    **In the ARR 06-07, total has been indicated as 18780 MU.

    In the ARR for 2006-07, the Board has projected aggregate metered sales at 18779 MU in 2006-07 of which metered sales within the State are 17759 MU. The Board has arrived at the category-wise sales to metered categories for 2005-06 (R.E) and 2006-07 (projections) based on 3-years CAGR for the years 2001-02 to 2004-05, except for sales to other states which has been projected on the premise that J&K would be drawing its 20% share from RSD project w.e.f. November 1,2005. Share in common pool sales from BBMB has been based by the Board as per details provided by BBMB. The Board has stated that the growth in total metered sales for the first six months of the year 2005-06 is broadly in line with the past 3 years CAGR (i.e.FY 01-02 to FY 04- 05).

    The Commission has estimated category-wise sales within the State for 2006-07 by applying 3 years CAGR i.e. 2001-02 to 2004-05, on the sales for the year 2005-06 now approved in Chapter-3. The actual sales for the years 2001-02 and 2004-05, 3 year CAGR for 2001-02 to 2004-05 as calculated by the Commission, sales now approved for 2005-06 and estimated sales in 2006-07 for different metered categories within the state are given below in Table 4.2.

    Table - 4.2
    Three Year Cumulative Annual Growth & Estimated Metered Sales within the State

    (MU)

    Sr.NoCategory01-02 (Actuals)04-05 (Actuals)3 year CAGR (01-02 to 04-05)
    (%)
    Sales now approved for 05-06Estimated sales for 06-07 by applying CAGR to 05-06 sales
    1234567
    1.Domestic447651825.0054025672
    2.Non-residential104413579.1314541587
    3.Small Power6517092.89699719
    4.Medium Supply140014781.8214561482
    5.Large Supply634469232.9575437766
    6.Public Lighting911127.17120129
    7.Bulk & Grid supply including Rly. Traction39454711.56567633
    8.Total within the State.1440016308 1724117988

    These estimated metered energy sales within the State at 17988 MU for the year 2006-07 are approved by the Commission. The Commission also approves sales to common pool at 302 MU as projected by the Board. The Board has indicated outside state sales at 718 MU. The Board has intimated that HP royalty in Shanan and HP share from RSD have been included in outside state sales. After excluding free HP share (59 MU) in RSD (refer para 4.4.2), the projected outside state sales come to 659 MU. The Commission, therefore, approves outside state sales at 659 MU. HP share in RSD will be incorporated in computing net energy availability from hydel power plants.

    The estimated metered sales for the year 2006-07 projected by the Board and as approved by the Commission are given below in Table 4.3.

    Table - 4.3
    Energy Sales 2006-07 (Metered)

    (MU)

    Sr. NoCategoryProjected by Board in ARR 06-07Approved by the Commission
    1234
    1.Domestic57135672
    2.Non-Residential16161587
    3.Small Power750719
    4.Medium Supply15321482
    5.Large Supply73377766
    6.Public Lighting 129129
    7.Bulk & Grid Supply including Rly Traction682633
    8.Total within the State1775917988
    9.Sales to Common Pool302302
    10.Outside State Sales718659
    11.Total Metered Sales1877918949

    The Commission, thus, approves the metered sales at 18949 MU against 18779 MU projected by the Board for the year 2006-07.

4.1.2    Agriculture Consumption

    The Board in its ARR for the year 2006-07 has projected the AP consumption at 7115 MU. The Board has submitted that :-

    1. Agricultural consumption for the year 2006-07 is projected at 7,115 MU assuming 5% growth on revised estimates of AP consumption for the year 2005-06 at 6776 MU.

    2. Agriculture Consumption is being assessed on the basis of more than 50000 sample meters installed on tubewell connections all over the State on representative basis. As on September 30, 2005 total size of sample meters was 52900 which was 5.81% of the total 910312 AP connections as against Commission’s directive for a sample size of at least 2% of the total number of pumpsets.

    3. A lower assessment of agricultural consumption allowed by the Commission would result in corresponding increase in T & D losses and the consequent disallowance of power purchase cost would put extra financial burden on the Board.

    4. In compliance with the Commission’s directive, PSEB has received the final report from the Punjab Agricultural University in respect of various issues pertaining to agricultural consumption wherein PAU has based its findings on data for five years. The findings of PAU given in its Final Report are as under:-

      1. Electricity consumption norm increased by 51.99 units per KW of AP load for every one metre decline in water table for rice areas.

      2. For annual drop of 0.144 metre in water table, there would be 0.43% annual rise in the total consumption norm at Punjab level.

      3. There is good scope to reduce the losses in electricity consumption by installing efficient agricultural pumping systems.

      4. State level total average energy consumption norm was observed as 1981.07 units per KW of AP Load.

    5. PSEB is in the process of implementing the suggestions given by PAU in its Final Report in terms of redistribution of sample meters (Reference- Para 4 of Chapter 5 of PAU Final Report). This would result in a more scientific assessment of the agricultural consumption in future. This data may be used by the Commission for assessing the agricultural consumption while truing up the ARR for 2006-07.

    6. Any disallowance in AP Consumption may force the Board to reduce supply of power to agriculture, especially during paddy season (June-October), which would adversely affect the agricultural output of the State and as a result the economy of the State.

    The matter of estimating the energy consumption by agricultural pumpsets during the year 2002-03 and subsequent years was deliberated in detail by the Commission in its Tariff Orders for the years 2002-03, 2003-04, 2004-05 and 2005-06. After considering various factors as discussed in para 3.2.3, of Tariff Order of 2005-06 relating to revised ARR for 2004-05, the Commission had decided to assess the AP consumption/consumption norm in 2004-05 and 2005-06 based on sample meter readings. It was also decided that the AP consumption will be reviewed at the end of the year based on sample meter readings and other relevant factors.

    Final Report submitted by Punjab Agricultural University (PAU) was discussed with the representatives of PAU and PSEB. During the meeting, Director, School of Energy Studies for Agriculture, PAU intimated that basic objective of the study was to develop a methodology for estimation of AP consumption. PAU has developed a software for estimation of energy norm starting at feeder level and then moving on to sub-division, division and circle levels and then the whole of Punjab. Provision has also been made in the software to get the results for different types of agricultural pumpsets and three broad soil categories. He further brought out that State level total average annual energy consumption norm (i.e. 1981.07 kwh/kw/year) mentioned in the Report is based on a one year survey data of 300 sample meters only which was used only to validate and demonstrate the working of software and is not meant for estimating the AP consumption. He opined that the data of the sample! meters the number of which has now gone to about 50,000 sample meters, will give better results by adopting this methodology. This will minimize the error on account of variation in factors such as rainfall, water table etc. He was of the view that it is preferable to work out the AP consumption first at feeder level instead of direct at division level as is being done presently by PSEB. This will lead to more accurate results as there will be less variation of parameters such as water table depth, rainfall etc. along a feeder as compared to their variation at division level.

    The Commission has already approved revised AP consumption for 2005-06 at 7000 MU. The Commission is constrained to observe that there has, so far, been no accurate and entirely reliable methodology for determining AP consumption in the State. Even the Commission’s own decisions, with regard to how AP consumption is to be ascertained, have been subject to change and it has now been decided to go as per PSEB readings of the installed sample meters. Even this methodology can not be taken as entirely fool proof and ways have to be found to ensure that sample meters which now have been reported to be installed in adequate numbers are functional and reliable and that the readings taken therefrom are cross checked possibly through an independent agency. The Commission also observes that much of the speculation concerning levels of AP consumption would be put to rest if 100% metering is done on the Distribution Transformers serving the rural areas. The Commission is happy ! to observe that PSEB has given an unequivocal assurance for completing metering of Distribution Transformers in the current year. Admittedly, the above method would still not be entirely accurate as line losses, both technical and commercial, from Distribution Transformers onwards would tend to inflate the figure of AP consumption. However, the figures so obtained and cross checked with better data emanating from sample meters would perhaps place the question of determining levels of AP consumption beyond controversy. The Commission strongly recommends that metering of all Distribution Transformers be completed in the shortest possible time. In the absence of an entirely reliable methodology to ascertain AP consumption, the Commission would tentatively like to go along with the Board’s own projections of anticipated consumption for 2006-07 as 7115 MU.

    The Commission, thus, approves agriculture consumption for the year 2006-07 at 7115 MU as projected by the Board.

    The AP consumption for the year 2006-07 is, however, approved subject to the following conditions :-

    1. The AP consumption approved will be reviewed at the end of the year based on sample meter readings and other relevant factors.

    2. The Board will send monthly consumption data based on sample meter readings.

    3. The Board will co-relate the results of energy audit of 11 KV feeders exclusively feeding AP consumers with the results of sample meter readings.

    4. The consumption recorded by meters installed on distribution transformers will be compared by PSEB with the consumption as per sample meter readings to ensure accuracy of the sample meter study.

    5. The Board will get the accuracy of all sample meters checked and take remedial action to get the same re-calibrated or replaced wherever and whenever required. A report on further action taken in this respect should be forwarded to the Commission on a quarterly basis.

4.1.3    Total Energy Demand (Sales)

    The category-wise sales projected by the Board and as approved by the Commission are given below in Table 4.4.

    Table - 4.4
    Total Energy Sales for 2006-07

    (MU)

    Sr.NoCategoryProjected by PSEB in ARR 06-07Approved by the Commission
    1234
    1.Total metered sales within the state1775917988
    2.Agriculture71157115
    3.Total sales within the state (1+2)2487425103
    4.Sales to common pool302302
    5.Outside state sales718659
    6.Total Sales (3+4+5)2589426064

    The Commission, thus, approves energy sales to various categories of consumers at 26064 MU including common pool and outside state sales against 25894 MU projected by the Board in the ARR for the year 2006-07.

4.2    TRANSMISSION AND DISTRIBUTION (T&D) LOSSES

    The Board in its ARR for the year 2006-07 has projected T&D losses at 23.00% for the year 2006-07 with AP consumption at 7115 MU. The Board has brought out that T&D losses are determined by deducting the assessed/ estimated AP consumption from energy available within the state after meeting the energy sales to the metered categories. In the ARR, the Board has submitted that if the Commission reduces the level of supply to the agricultural pumpsets proposed by the Board, then there would be a corresponding increase in T&D losses. In the case of PSEB where losses have already reached 24.27%, further reduction of losses even by 1% is a difficult task which requires significant effort and resources. Moreover, the quantum of energy handled by the system has increased over a period of time which also marginally adversely affects the loss reduction trajectory.

    Accurate estimation of T&D losses is crucial not only for working out energy requirement but also for determining the ARR to be allowed to the Board. In fact T&D loss level is perhaps the most important performance parameter for any power utility. A number of consumers have highlighted the need for reducing T&D losses of the Board to enhance power availability and bring down tariff to a reasonable level.

    The Commission has deliberated in detail on the issue of T&D losses from 2002-03 and subsequent years in its Tariff Orders for the earlier years. In the first year of the tariff determination exercise (2002-03), the Commission undertook an assessment of the existing T&D losses for the year 2001-02. The Commission made its own assessment of AP consumption and recalibrated T&D losses for the year 2001-02 at 27.52%. Taking this as base level, every year the Commission has been determining T&D loss targets to be achieved by the Board. A reduction target of 2% was set by the Commission for the year 2002-03 and thus approved T&D losses at 25.52% for the year 2002-03. For the subsequent year, the Commission fixed the T&D loss target of 24.50% which involved a reduction of only 1.02% over the target fixed for the year 2002-03. Further, the Commission in its Tariff Order for 2004-05 fixed the target at 23.25% for that year which was a further reduction of 1.25% over the leve! l fixed for the previous year. The Commission also proposed to continue with this modest reduction target of 1.25% for each of the next four years starting with 2004-05. In line with this, the Commission in its Tariff Order of 2005-06 fixed T&D losses for that year at 22%.

    All the legitimate revenue requirements of the Board including investment needs are being fully met through the Tariff Orders of the Commission. However, capital expenditure incurred by the Board in the previous years is usually less than the investment levels approved. The Commission is also unable to discern any overall strategy that the Board has adopted to tackle the crucial issue of reducing T&D losses. This would include a medium and long term plan for strengthening the Transmission and Distribution system as well as covering the main operations of the Board by energy audit with related follow up and fixation of responsibility where necessary. In the absence of credible evidence that the Board has taken serious steps on the above lines, it is difficult to agree that the annual reduction of T&D losses along the trajectory set by the Commission is not feasible. Such a conclusion is evident also from the wide dispa evident also from the wide disparity of T&D losse! s in different Circles of the Board. Data on T&D losses for the period April to September, 2005 for instance shows losses as low as 11.14%, 11.64% and 13.92% for Khanna, East Ludhiana and Ropar respectively, whereas in other Circles such as Ferozepur, Muktsar and Amritsar these are as high as 42.13%, 39.39% and 32.72 to 37.33% respectively. In fact, more than 60% of the 20 Circles incur T&D losses in excess of 25%. Clearly, the Board is in a position to target T&D losses at micro level which could significantly reduce the overall quantum of losses. In these circumstances, the Commission is unable to agree with the submissions of the Board for its inability to achieve the reduction targets of T&D losses determined by the Commission.

    The Commission, therefore, decides to fix the target of T&D losses at 20.75% for the year 2006-07 i.e. a reduction of 1.25% over the loss level fixed for the year 2005-06.

4.3    ENERGY REQUIREMENT (INPUT)

    The total energy requirement to meet the demand of the system would be the sum of estimated energy sales including common pool and outside state sales and T&D losses. The estimated energy sales, T&D losses and estimated energy requirement projected by the Board and as approved by the Commission for the year 2006-07 are given in Table 4.5.

    Table - 4.5
    Energy Requirement for 2006-07

    (MU)

    Sr.NoParticularsAs projected by the Board in ARR 06-07As approved by the Commission
    1234
    1.Metered Sales within State1775917988
    2.Agriculture consumption71157115
    3.Total sales within state (1+2)2487425103
    4.Common pool sales302302
    5.Outside state sales718659
    6.Total sales2589426064
    7.T&D losses on item (3)(23%) 7431(20.75%) 6573
    8.Total energy input required3332532637

    Note:- In the ARR 06-07, totals of projected figures have some discrepancies and as such totals have been slightly adjusted.

    The overall energy requirement projected by the Board and approved by the Commission differs by 688 MU. This is mainly due to difference in T&D losses allowed and variation in metered sales projected by the Board and allowed by the Commission.

    The energy requirement thus works out to 32637 MU which has to be met from own generation of the Board (Thermal & Hydel) including share from BBMB and purchases from central generating stations and other sources.

4.4    OWN GENERATION OF THE BOARD
4.4.1    Thermal Generation

    The Board in its ARR for the year 2006-07 has projected generation for the year 2006-07 at 2220 MU, 8650 MU and 3120 MU for GNDTP, GGSTP and GHTP respectively.

    The Board has submitted that units installed at GNDTP are over 25 years old and it is necessary to renovate and overhaul them to bring sustained improvement in operational efficiency. The combined outage of the 4 generating units of 110 MW each would be 287 machine days (6888 machine hours) during the year 2006-07.

    Generating units 1, 2, 3, 4, 5 & 6 at GGSTP, Ropar are proposed to be taken out for statutory inspection of boiler, annual overhaul etc. for a total period of 152 machine days (3648 machine hours) during the year 2006-07.

    The unit 1 & 2 at GHTP, Lehra Mohabbat are also being taken out for annual maintenance for 60 machine days (1440 machine hours) during the year 2006-07.

    Based on the maintenance schedules, the availability of GNDTP, GGSTP and GHTP in 2006-07 works out to be 80.34%, 93.06% and 91.78% respectively. Against this, the Board has indicated that availability for GNDTP will be 74% while availability for GGSTP and GHTP will be in the range of 88-91%. The difference in availability worked out from maintenance schedules and that indicated by the Board is because the Board has considered forced outage also while estimating the availability of the plants.

    The Commission has considered the last three years average (i.e 2002-03, 2003-04 and 2004-05) of duration of maintenance and generation for each of the stations and details of the availability of each station during 2006-07 as worked out from the maintenance schedules are given in Table 4.6.

    Table – 4.6
    Availability, Generation and Plant Load Factor of Thermal Plants
    Sr.NoStationThree year average availability (%)Three year average generation (MU)Assessed by the Commission for 06-07
    Availability as per mtc. Schedules for 06-07 (%)Generation
    4x5
    3(MU)PLF
    (Calculated) (%)
    1234567
    1.GNDTP82.65234780.34228159.18
    2.GGSTP91.36854493.06870378.85
    3.GHTP93.52319891.78313885.29

    The Commission approves the thermal generation as assessed in Table 4.6 above, for each of the stations.

    CERC Norms
    CERC in its notification No.L-7/25(5)/2003-CERC dated 26.3.2004 has made regulations for determining terms and conditions for electricity tariff for the five year period beginning April 1, 2004. In these regulations, CERC has laid down norms of operation for thermal plants. In its Tariff Order for the year 2005-06 the Commission adopted CERC norms wherever specified. For the year 2006-07 also, the Commission has decided to follow the CERC norms wherever specified. CERC has not specified any norms for 110 MW units installed at GNDTP. However, CERC has specified norms for Tanda station of NTPC which like GNDTP, has 4 units of 110 MW each, commissioned between 1987-88 and 1997-98 i.e. later than commissioning of GNDTP units which were commissioned between 1974-75 and 1979-80. In case of GNDTP, the Commission has, thus, decided to follow CERC norms specified for Tanda station.

    Auxiliary Consumption & Net Generation.


    In the ARR for 2006-07, the auxiliary consumption projected by the Board for GNDTP, GGSTP and GHTP is 12.20%, 8.64% and 9.35% respectively.

    The Board has submitted that the projected auxiliary consumption includes excitation and step-up transformation losses of around 0.5% which have not been considered in the past years. It has also been urged that even though the auxiliary consumption of PSEB stations is slightly higher than CERC norms for normal thermal stations, yet it is much lower than the CERC norms for similarly aged Tanda and Talcher stations. Further, it has been submitted that auxiliary consumption is specific to a particular plant depending on the kind of auxiliary equipments installed at the plant and the percentage of auxiliary consumption varies depending on the total generation. The Board has also stated that nothing much can be done to reduce the auxiliary consumption without major renovation and modernisation.

    The Commission in its Tariff Order for 2005-06 decided to adopt the CERC norms for auxiliary consumption for that year. The CERC norm of auxiliary consumption applicable for GGSTP is 8.50% and for GHTP it is 9.00%. CERC has not specified any norm for 110 MW units installed at GNDTP but has specified norm of 11.00% for Tanda station of NTPC.

    There are no strong reasons for not following the CERC norms for determining auxiliary consumption in this year also. Therefore, the Commission decides to fix auxiliary consumption for the year 2006-07 as per CERC norms and allows auxiliary consumption at 8.50% for GGSTP and 9.00% for GHTP. CERC has not specified any norm for units installed at GNDTP. The Commission, however, allows auxiliary consumption for GNDTP at 11.00% at par with Tanda station of NTPC.

    Auxiliary consumption and net generation from the three thermal generating stations as projected by the Board and as approved by the Commission for the year 2006-07 is given in Table 4.7 below.

    Table – 4.7
    Generation and Auxiliary Consumption for 2006-07 for Thermal Plants

    (MU)

    Sr. No PlantProjected by the Board ARR 06-07Approved by the Commission
    Gross GenerationAuxiliary ConsumptionNet GenerationGross GenerationAuxiliary ConsumptionNet Generation
    12345678
    1.GNDTP2220271 (12.20%)19492281251 (11.00%)2030
    2.GGSTP8650747 (8.64%)79038703740 (8.50%)7963
    3.GHTP3120292 (9.35%)28283138282 (9.00%)2856
     Total1399013101268014122127312849

    The net thermal generation thus approved by the Commission is 12849 MU against 12680 MU projected by the Board for the year 2006-07.

4.4.2    Hydel Generation

    In the ARR for 2006-07, the Board has estimated hydel generation for the year 2006-07 based on the average of 3 years (i.e. 2002-03, 2003-04 and 2004-05) in order to capture any variation on account of vagaries of the monsoons.

    For estimating hydel generation from own hydel stations for the year 2006-07, the Commission has also considered the average generation for three years in line with the approach adopted by the Commission in its earlier Tariff Orders. The recent three-year average needs to be considered as it gives more reliable generation figures for the year 2006-07 and as such the actual generation for the years 2002-03, 2003-04 and 2004-05 has been considered. The projected generation by the Board and generation approved by the Commission on the basis of three-year average are given below in Table 4.8.

    Table – 4.8
    Hydel Generation

    (MU)

    Sr.NoStationGeneration projected by the Board in ARR 06-07Actual GenerationGeneration estimated by the Commission (Based on 3 year average
    2002-032003-042004-05
    1234567
    1.Shanan516469564515516
    2.UBDC400394427380400
    3.RSD12811151154811441281
    4.MHP8797951029812879
    5.ASHP656750829388656
    6.Micro Hydel891048
    7.Total own generation (Gross)37403568440732433740

    The Commission approves the above estimated generation from own hydel stations. The Commission also approves PSEB share and common pool share from BBMB as projected by the Board as depicted in Table 4.9 below. The hydel generation projected by the Board from own hydel stations as well as common pool share from BBMB and generation approved by the Commission is given in Table 4.9 below. For calculating net generation, the Board has not deducted HP share (free) in RSD. The Commission has worked out net hydel generation by deducting this as well.

    Table – 4.9
    Hydel Generation for the year 2006-07

    (MU)

    Sr. No.Station/ sourceProjected by the Board in ARR 06-07Approved by the Commission
    1234
    1.Shanan516516
    2.UBDC400400
    3.RSD12811281
    4.MHP879879
    5.ASHP656656
    6.Micro Hydel88
    7.Total own generation (Gross)37403740
    8.Total own generation (Net)*3673**3654
    9.BBMB
    i)PSEB share (Gross)41124112
    ii)Common pool share (Gross)302302
    iii)Total (Gross)44144414
    iv)External losses on BBMB166166
    v)Availability (Net)42484248
    10.Total hydel generation (Net)79217902


    *Net of auxiliary consumption (12 MU) and transformation losses (55 MU).In the ARR, net generation has been indicated as 3672 MU which has been corrected to 3673 MU.
    **Net of HP share (free) in RSD @ 4.6% (59 MU), auxiliary consumption @ 0.2% (8MU) and transformation losses @ 0.5%(19 MU) as per CERC Norms.

    The Commission, thus, approves net hydel generation of 7902 MU for the year 2006-07 against 7921 MU projected by the Board in ARR for the year 2006-07.

4.4.3    Total Availability from own Stations of the Board and BBMB

    The approved net generation from own Thermal and Hydel stations of the Board and share from BBMB is given below in Table 4.10.

    Table – 4.10
    Net Generation for 2006-07

    (MU)

    Sr.NoSourceEnergy available (ex-bus)
    123
    1.Thermal Stations12849
    2.Hydel Stations (Own)3654
    3.Share from BBMB (including 302 MU share of common pool consumers)4248
    4.Total own Availability20751

    The total energy available (ex-bus) from own generating stations of the Board including share from BBMB approved by the Commission is thus 20751 MU.

4.5    PURCHASE OF POWER

    The total energy required (input to the system) to meet the demand of the State during 2006-07 including common pool and outside state sales is 32637 MU as discussed in para 4.3. The energy available from own generating stations of the Board including its share from BBMB is 20751 MU as approved in para 4.4. The balance requirement of 11886 MU (net) has to be met through purchases from central generating stations and other sources. This is against requirement of 12724 MU (net) projected by the Board in its ARR for the year 2006-07.

4.6    ENERGY BALANCE

    To sum up, the energy balance which takes into account the approved energy sales to different categories of consumers, T&D losses, energy requirement and energy available is as given in Table 4.11 below.

    Table – 4.11
    Energy Balance for 2006-07

    (MU)

    Sr.No.ParticularsProjected by the Board in ARR 06-07Approved by the Commission
    1234
    A.Energy Requirement  
    1.Metered Sales within state.1775917988
    2.Sales to Agriculture. 71157115
    3.Total sales within state.2487425103
    4.T&D Losses 7431
    (23%)
    6573
    (20.75%)
    5.Common pool302302
    6.Outside state sales718659
    7.Total Requirement3332532637
    B.Energy Availability  
    1.Own generation (ex-bus)  
    a)Thermal1268012849
    b)Hydro36733654
    2.Share from BBMB (including share of common pool consumers)4248
    (Common Pool=302)
    4248
    (Common Pool=302)
    3.Purchase (Net)1272411886
    4.Total Availability3332532637

    Note: In the ARR 06-07, totals of the projected figures have some discrepancies and the same have been slightly adjusted.

B.    EXPENSES
4.7    FUEL COST
4.7.1    Fuel Cost Projected by the Board

    In the ARR, the Board has projected a fuel cost of Rs.2316.00 crores for a total generation of 13990 MU during the year 2006-07 as detailed below in Table 4.12.

    Table – 4.12
    Fuel Costs projected by the Board for 2006-07
    Sr.NoStationGross Generation (MU)Cost of Fuel (Coal & Oil ) (Rs.crores)
    1234
    1.GNDTP2220400
    2.GGSTP86501398
    3.GHTP3120518
     Total139902316

    The Board has submitted that as per directives from the Government of India, the Board proposes to import 5.04 lakh tonnes of coal during 2006-07. As the coal blending facility is available only at GHTP and GGSTP, imported coal is likely to be utilized in these 2 stations in the proportion of 1:1.625 respectively. The additional impact on cost of coal has been given at Rs.35.00 crores during 2006-07 and the projected cost of fuel is inclusive of this impact. In this regard, copy of letter dated November 17, 2004 from the Government of India has been supplied in the ARR in which it is mentioned that the Board was agreeable to import coal to the tune of 7.2 lakh tonnes. Copy of letter dated June 6, 2005 from Ministry of Power, Government of India has also been supplied in ARR in which the quantity of coal for import has been revised to 5 lakh tonnes.

    The Board has arrived at the above fuel costs based on the following parameters.
    Sr.NoStationPLF (%)Heat Rate (kcal/kwh)Transit loss of coal (%)Indian Coal Price including transit loss (Rs/MT)Calofic value of Indian coal (kcal/kg) Price of Oil (Rs/KL)Specific oil consumption (ml/kwh)Calorific Value of oil (kcal/litre)Price ofimported coal (Rs/MT)Calorific value of imported coal (Kcal/Kg)
    123456789101112
    1.GNDTP57.6028113.972499.453922163091.0410000--
    2.GGSTP78.3725492.372380.003825138220.891034048986800
    3.GHTP84.8024222.732758.004065171630.46940047816800


    The Board has submitted that the performance parameters and coal transit loss of all the three stations as submitted by the Board may be approved without any disallowance considering the following:-

    1. PSEB stations except for GHTP are vintage in nature, which naturally results in deterioration of performance over the years, inspite of regular maintenance, renovation & overhauls.

    2. Performance of GNDTP should be compared with CERC norms fixed for similar aged Tanda and Talcher stations, instead of CERC norms for new stations.

    3. PSEB stations are fully depreciated with minimal capital cost being recovered from consumers, as against new stations and IPPs, whose fixed costs are relatively high in comparison to low cost stations of the Board. Thus, the unit cost of power generated by these stations is much less than new thermal stations.

    4. PSEB stations are performing better as seen with reference to CERC norms on PLF and specific oil consumption thereby resulting in lower cost of generation to that extent.

    5. The Board does not have much control in reducing coal transit loss beyond certain level as there are many uncontrollable external factors. Norms specified by CERC are based on actual transit and handling losses for the NTPC coal based stations.

    6. The Board has stated that CERC vide letter No.20/5(102)/2003-CERC dated July 22,2005 has clarified that section 61 (a) of the Electricity Act, 2003 provides that the appropriate Commission shall be guided by the principles and methodologies specified by the Central Commission for determination of tariff applicable to generating companies and transmission licensees. The State Regulatory Commissions are not barred from adopting their own norms after going into the merits of specific cases and relevant factors specific to the state generating stations.

4.7.2    Fuel Cost approved by the Commission
    Gross Generation

    The gross generation of thermal plants for the year 2006-07 has been discussed in para 4.4.1 and summarized in Table 4.7.

    Station Heat Rate
    CERC has laid down norms of gross station heat rate for coal based thermal power generating stations as given below in Table 4.13.

    Table – 4.13
    CERC Norms for Gross Station Heat Rate
    S NUnit size / PlantSHR during stabilization period (kcal/kwh)SHR subsequent to stabilization period (kcal/kwh)
    1234
    1.200/210/250 MW sets26002500
    2.500 MW and above sets25002450
    3.Talcher Thermal Power Station 3100
    4.Tanda Thermal Power Station 3000
    Note: -1.

    In respect of 500 MW and above units where the boiler feed pumps are electrically operated, the gross station heat shall be 40 kcal/kwh lower than the station heat rate indicated above.

     2.

    For generating stations having combination, of 200/210/250 MW sets and 500 MW and above sets, the normative gross station heat rate shall be the weighted average station heat rate.

    On the above basis, the Commission approves SHR at 2500 kcal/kwh for GGSTP and GHTP in accordance with CERC norms. CERC has not specified any norm for units installed at GNDTP. The Commission, however, allows SHR for GNDTP at 3000 kcal/kwh i.e. at par with Tanda Thermal Station of NTPC as has been followed in the case of auxiliary consumption.

    Coal Transit Loss

    The Board in its ARR has projected transit loss of coal for 2006-07 at 3.97%, 2.37% and 2.73% for GNDTP, GGSTP and GHTP respectively.

    Section 61(a) of the Electricity Act, 2003 dealing with tariff regulations provides that the appropriate Commission shall be guided by the principles and methodologies specified by the Central Commission for determination of the tariff applicable to generating companies and transmission licensees. CERC has laid down norms for transit and handling losses as percentage of the quantity of coal dispatched by the coal supply company. These are as given below :-

    Pit head generating stations0.3%
    Non-pit head generating stations0.8%


    CERC vide letter No.20/5(102)2003-CERC dated July 7, 2005 addressed to Chairman, PSEB has intimated that CERC has fixed the norms based on actual transit and handling losses for the NTPC coal based stations. CERC has also expressed the opinion that State Commissions are not barred from adopting their own norms after going into the merits of the case and relevant factors specific to the State generating stations.

    The actual transit loss of coal reported by the Board for different thermal stations in the earlier years is given below :-
    Sr. No.PlantYear
    01-0202-0303-0404-05
    1.GNDTP5.657.126.084.08
    2.GGSTP4.694.721.611.89
    3.GHTP3.550.782.725.65


    The Commission has specifically addressed the question of coal transit losses in its Tariff Orders 2002-03, 2004-05 and 2005-06. It began by fixing transit losses at 3% in 2002-03 which were reduced to 2% in 2004-05. In March, 2004, CERC prescribed transit loss norms as 0.3% for Pit Head generating stations and 0.8% for stations away from the Pit Head and on that basis, a norm of 0.8% was prescribed in the Tariff Order of 2005-06. The Commission observes that there is force in the Board’s contention that application of CERC norms would not be fair as even the non pit head central generating stations are, on the whole, located far closer to the coal mines than is the case of Stations located in Punjab. CERC has clarified that its norms are based on actual losses of the NTPC coal based stations but that State Commissions are free to adopt their own norms by taking local factors into account. The Commission observes that the Board can at best play a limited role in curtailin! g transit losses as it can exercise little control over the coal loading end and the Railways. The Commission accordingly feels that it would be more realistic to adopt a norm which is capable of being achieved as per past performance indicators. It observes that on several occasions, in the past, different generating stations have been able to keep transit losses below 2%. On that basis, the Commission is of the considered view that a more appropriate benchmark for coal transit loss would be 2% as had earlier been determined by the Tariff Order of 2004-05. Accordingly, the Commission approves a transit loss of 2% for Indian coal in respect of all the three Thermal Stations during the year 2006-07. In the case of imported coal, the prices are FOR destination and as such coal transit loss has been taken as nil.

    Price and Calorific Value of Coal

    Indian Coal

    The Board in its ARR for the year 2006-07, has supplied actual prices of Indian coal prevailing during first half of the year 2005-06 at Rs.2380/MT, Rs.2266/MT and Rs.2627/MT for GNDTP, GGSTP and GHTP respectively. Fuel cost being a major item of expense, the actual calorific value, price and transit loss of Indian coal for the first half of 2005-06 were verified. These were found to be as per Revised Estimates for the year 2005-06 given by the Board in its ARR for the year 2006-07 and are as given below in Table 4.14.

    Table 4.14
    Actual Calorific Value, Price and Transit Loss of Indian Coal during 1st half of 2005-06
    S. NoStationCalorific value of coal (kcal/kg)Price of coal including transit loss (Rs/MT)Transit LossPrice of coal excluding transit loss (calculated) (Rs./MT)
    1.GNDTP392223803.97%2285.51
    2.GGSTP382522662.37%2212.30
    3.GHTP406526272.73%2555.28

    In working out cost of Indian Coal for the year 2006-07, the Commission has decided to consider the price and calorific value of Indian Coal as actually obtained during first half of the year 2005-06.

    Imported Coal
    As per letter dated June 6, 2005 from Ministry of Power, Government of India, the Board is to import 5.0 lakh MT of coal. The Board has intimated that imported coal is likely to be utilized at GHTP and GGSTP in the proportion of 1:1.625 respectively. The Commission has thus considered quantity of imported coal to be utilized at GHTP and GGSTP as 190476 MT and 309524 MT respectively. The Board has intimated the F.O.R. destination price of imported coal as Rs. 4898/MT for GGSTP and Rs. 4781/MT for GHTP and calorific value of imported coal as 6800 kcal/kg. The Commission accepts these prices and calorific value of imported coal.

    Specific Oil Consumption, Calorific Value and Price of Oil

    The Board in its ARR of 2006-07 has projected oil consumption for 2006-07 at 1.04 ml/kwh, 0.89 ml/kwh and 0.46 ml/kwh for GNDTP, GGSTP and GHTP respectively. The Commission has, however, decided to adopt CERC norms for oil consumption as in the case of other performance parameters for thermal plants. The Commission, thus, approves oil consumption of 2.0 ml/kwh for GGSTP and GHTP for the year 2006-07. For GNDTP, the Commission, however, allows oil consumption at 3.5 ml/kwh i.e. at par with Tanda station of NTPC. The Commission has considered calorific value of oil and oil price as projected by the Board for the year 2006-07.

    Based on the generation and operational parameters, approved by the Commission above, the cost of fuel for the year 2006-07 works out to Rs.2258.15 crores as detailed below in Table 4.15.

    Table – 4.15
    Fuel cost (Coal and Oil) for 2006-07
    S NItemDerivationUnitApproved for 2006-07
    GNDTPGGSTPGHTPTotal
    12345678
    1GenerationAMU22818703313814122
    2Heat RateBk.cal/kWh Generated300025002500
    3Specific oil consumptionCMilli litre/kwh3.502.002.00
    4Calorific value of oilDk.cal/litre10000103409400
    5Calorific value of Indian coalEk.cal/kg392238254065
    6Calorific value of imported CoalFk.cal/kg--68006800
    7Overall heatG = (A*B)G.cal6843000217575007845000
    8Heat from oilH = (A*C*D)/1000G.cal7983517997858994
    9Heat from coalI = (G-H)G.cal6763165215775227786006
    10Oil consumption J=H*1000/D=A*CKL7984174066276
    11Quantity of imported CoalKMT--309524190476
    12Heat from imported CoalL= F*K/1000G.Cal--21047631295237
    13Heat from Indian CoalM= (I-L)G.Cal6763165194727596490769
    14Transit loss of coalT(%)2.02.02.0
    15Consumption of Indian Coal including transit loss.N= (M*1000/E) / (I-T/100)MT175961051948141629332
    16Cost of oil per KLORs./KL163091382217163
    17Cost of Indian coal per MTPRs./MT228622122555
    18Cost of imported coal per MTQRs./MT--48984781
    19Total cost of oilR=O*J/10**7Rs.crores13.0224.0610.7747.85
    20Cost of Indian CoalS=N*P/10**7Rs.crores402.251149.09416.291967.63
    21Cost of Imported CoalU=K*Q/10**7Rs.crores--151.6091.07242.67
    22Total cost of coalV=S+URs.crores402.251300.69507.362210.30
    23Total Fuel costW=R+VRs.crores415.271324.75518.132258.15


    * indicates multiplication and ** indicates raised to the power.

    Any change in the price of coal and/or railway freight and oil indicated above, would be passed on to the consumers as Fuel Cost Adjustment.

    On the above basis, the Commission approves the Fuel Cost at Rs.2258.15 crores for gross generation of 14122 MU against Rs.2316 crores projected by the Board for generation of 13990 MU.

    Fuel Cost Adjustment (FCA) Formula
    Any change in the fuel cost from the level approved by the Commission is to be passed on to the consumers as FCA. Punjab State Electricity Regulatory Commission (Conduct of Business) Regulations, 2005 contain the FCA formula according to which any change in fuel cost would be passed on to the consumers with prior approval of the Commission.

4.8    POWER PURCHASE
4.8.1    Projection by the Board.

    The Board in its ARR for the year 2006-07, has projected a cost of Rs.3256 crores for purchase of 13225 MU for the year 2006-07. In doing so, the Board has taken the following into account :-

    1. The Board’s share in Dulhasti and Tehri will be available to it during 2006-07.

    2. Power purchase from NHPC stations in 2006-07 has been estimated by the Board on the basis of past 3 years (2002-03 to 2004-05) average purchase from these stations.

    3. Power purchase from NTPC and NPC stations during 2006-07 has been estimated by the Board by considering average of allocated and unallocated share received by the Board during 2002-03 to 2004-05. The Board has projected external transmission losses at 3.76% for the year 2006-07.

    4. Petitions for determination of tariff for Central Generating stations namely, Anta, Auraiya, Dadri, Singrauli, Rihand and Unchahar Stage-I and II for the years 2004-05 and 2005-06 are under consideration.

    5. The Commission may issue appropriate Power Purchase Cost Adjustment formula to ensure regular recovery from consumers of any increase in average purchase price of individual stations as well as any change in procurement mix.

4.8.2    Requirement of Energy through Purchase

    As discussed in para 4.5, the requirement of 11886 MU (net) has to be met through purchases from central generating stations and other sources. The transmission loss external to the PSEB system has to be added to arrive at the quantum of energy to be purchased from various sources.

4.8.3    Transmission Losses External to PSEB System

    For the year 2006-07, the Board has projected the gross power purchase at 13225 MU and losses external to PSEB system at 3.76%.

    The Commission has considered the external losses at 3.76% as projected by the Board. The gross energy to be purchased, thus, works out to 12350 MU (11886 MU & external loss 464 MU).

4.8.4    Entitlement from Central Generating Stations

    For estimation of energy entitlement of PSEB from different Central Generating Stations (CGSs), the Commission has considered the average of the actual energy purchased by the Board for three years (2002-03, 2003-04 and 2004-05). The recent three year average is taken as it gives a more realistic estimation. Similarly, for estimating share allocation to PSEB from CGSs, the Commission has considered the average of the actual share allocation to PSEB for three years (2002-03, 2003-04 and 2004-05). Based on the above, the energy entitlement of the Board from NTPC, NHPC and NPC stations works out as 4990 MU, 1830 MU and 1030 MU respectively. The details are given below in Tables 4.16 to 4.18.

    Table – 4.16
    PSEB’s Entitlement from NTPC stations for 2006-07
    Sr. NoStationCapacity (MW)Firm AllocationEnergy entitlement based on 3 year average (MU)Share allocation based on 3 year average (%)
    %MW
    1234567
    1.Anta41911.694933212.36
    2.Auraiya66312.528354913.04
    3.Dadri Gas83015.9013280416.32
    4.Singrauli200010.00200164410.67
    5.Rihand-I100011.0011090211.67
    6.Unchahar-I4208.57362968.91
    7.Unchahar-II42014.286046314.95
     Total   4990 


    Table – 4.17
    PSEB’s Entitlement from NHPC stations for 2006-07
    Sl.NoStationCapacity (MW)Firm AllocationEnergy entitlement based on 3 year average (MU)Share allocation based on 3 year average (%)
    %MW
    1234567
    1.Salal69026.6018488226.62
    2.Bairasul18046.508430846.60
    3.Tanakpura9417.93177218.09
    4.Chamera-I54010.205522910.20
    5.Uri48013.756633913.75
     Total    1830 


    Table – 4.18
    PSEB’s Entitlement from NPC stations for 2006-07
    Sl.NoStationCapacity (MW)Firm AllocationEnergy entitlement based on 3 year average (MU) Share allocation based on 3 year average (%)
    %MW
    1234567
    1.NAPP44011.595134012.43
    2.RAPP44022.73100690*-
     Total   1030 

    * For RAPP, energy entitlement has been taken as projected by PSEB in view of recent increase in share of PSEB in the plant.

    In addition to the existing central generating stations, the Commission has considered purchase of energy from Rihand-II, Chamera-II, Dulhasti, Nathpa Jhakri, Tehri and Dhauli Ganga as projected by the Board i.e. 805 MU, 150 MU, 100 MU, 695 MU, 330 MU and 111 MU respectively.

4.8.5    Cost of Power Purchase
    (a) Central Generating Stations (CGS)

    CERC has issued regulations laying down terms & conditions for electricity tariff for the five year period beginning April 1, 2004. The Board has intimated that for individual CGSs, Tariff Orders for the year 2005-06 are under process and have not yet been finalised by CERC.

    NTPC Stations

    Fixed Cost
    As per the prevalent mechanism the fixed cost is payable in proportion to the share allocation in respect of central generating stations and the Commission has accordingly arrived at the fixed charges.

    Since Tariff Orders for individual central generating stations, have not been issued by CERC, the annual fixed charges in respect of NTPC stations have been considered as per NTPC bills for September, 2005 which would be subject to revision based on the CERC orders.

    Variable Cost
    In the absence of CERC orders as per CERC tariff regulations applicable from April 1, 2004, the Commission approves variable cost for 2006-07 as per NTPC bills for September, 2005 for different central generating stations. Change in the variable cost from these levels is admissible to be passed on to the consumers as FCA with prior approval of the Commission.

    Incentive and Other Charges
    The incentive and other charges are approved as projected by the Board in its ARR for the year 2006-07.

    NHPC Stations
    The actual rate for primary energy in respect of purchases from NHPC stations as per September, 2005 bills is 73.79 Ps/kwh. As per CERC regulations effective from April 1, 2004, recovery through primary energy charge shall not be more than the annual capacity charge. Accordingly, the Commission approves the variable cost in respect of NHPC stations at 74 Ps/kwh but limited to annual capacity charge.

    The incentive and other charges including income tax, foreign exchange rate variation etc. are considered as projected by the Board.

    NPC Stations
    The tariff for NAPP and RAPP stations has been considered by the Commission as per bills for September, 2005. The other charges are considered as projected by the Board.

    (b) Power Purchase Tariff for New Stations
    The Board has assumed power purchase rate from NJPC as Rs.2.45/kwh. However, CERC has approved provisional rate of Rs.2.35/kwh for NJPC and the Commission approves this rate. The Board has projected power purchase rates from Tehri, Dulhasti and Dhauli Ganga stations at Rs.3.60/kwh, Rs.4.00/kwh and Rs.2.80/kwh respectively and the Commission approves these rates. These rates are subject to final rates to be approved by CERC.

    (c) Power Purchase Rates for Banking from Other States
    Power purchase rates for Banking from HPSEB, J&K and UPCL have been projected by the Board at Rs.2.46/kwh, Rs.2.86/kwh and Rs.3.50/kwh respectively.

    The above rates are applicable for the purchase of power during summer and sale of power during winter. The Commission provisionally approves these rates for estimating the cost.

    (d) Power Purchase from PTC/Other Traders
    The Board in its ARR has stated that power purchased from Power Trading Corporation (PTC) varies in the range of Rs. 2.05/kwh to Rs. 3.64/kwh depending on the price bids received by PTC. Further, the Board has intimated that rate of power purchased from NTPC Vidyut Vyapar Nigam Limited (NVVNL) varies in the range of Rs.2.30/kwh to Rs. 2.77/kwh.

    For estimating cost of additional power purchase from PTC/NVVNL, the Board has assumed average cost of power purchase from these sources as Rs.3.50/unit. The actual average rate of power purchase from traders during 2004-05 is Rs.2.49/kwh. Data regarding actual power purchased from traders upto December, 2005 contained in PSEB petitions relating to FCA for first three quarters of 2005-06 gives an average rate of Rs.2.97/kwh. The Commission, therefore, considers that the rate of Rs.3.50/kwh projected by the Board is reasonable and provisionally approves this rate for estimating the cost.

    (e) Transmission Charges
    The Board has projected the transmission charges to PGCIL at Rs.165 crores for the year 2006-07. The Commission approves these charges as projected by the Board.

    Based on the above, the cost of power purchase for the year 2006-07 works out to Rs.2813.34 crores as detailed below in Table 4.19.

    Table – 4.19
    Power Purchase Cost 2006-07
    Sr. No.SourcePurchase (MU)AFC (Rs. Crore)PSEB share (%) VC (Ps/ Unit)FC (Rs. crores)VC (Rs.crore)Others (Rs.crore)Total (Rs.crore)
    12345678910
    INTPC
    1.Anta33281.0212.3615610.0151.793.0064.80
    2.Auraiya549145.8813.0419419.02106.517.00132.53
    3.Dadri Gas804207.8216.3220333.92163.2110.00207.13
    4.Singrauli1644349.9610.678937.34146.3211.00194.66
    5.Rihand-I902499.2511.678658.2677.5718.00153.83
    6.Unchahar-I296190.218.9111616.9534.344.0055.29
    7.Unchahar-II463210.9014.9511531.5353.252.0086.78
    8.Rihand-II80559.0410.20986.0278.89-84.91
    IINHPC
    9.Salal882178.2526.6254-47.458.0055.45
    10.Bairasuil30846.8646.6071-21.844.0025.84
    11.Tanakpur7245.3418.09742.875.331.009.20
    12.Chamera-I229210.2310.20744.4916.955.0026.44
    13.Chamera-II150-10.00228-34.201.0035.20
    14.Uri339516.0213.757445.8625.097.0077.95
    15Dulhasti100--400-40.00-40.00
    16.Dhauli Ganga111-10.00280-31.08-31.08
    IIINPC
    17.NAPP340-12.43233-79.22-79.22
    18.RAPP690-22.73291-200.75-200.75
    IVOther Sources
    19.Co-gen. including Jalkheri203--385-78.16-78.16
    20.Banking
    a)HPSEB72--246-17.71-17.71
    b)J&K41--286-11.73-11.73
    c)UPCL87--350-30.45-30.45
    21.NJPC695-7.60235-163.33-163.33
    22.Tehri330--360-118.80-118.80
    23.PTC/Other1906--350-667.10-667.10
    VOther Charges
    24.PGCIL -  -165.00 165.00
    25.ULDC -  -- -
    26.NRLDC -  -- -
     Total12350   266.272466.0781.002813.34

    The Commission approves power purchase cost at Rs.2813.34 crores for power purchase of 12350 MU against Rs.3256 crores projected by the Board for power purchase of 13225 MU.

    However, the Commission is of the opinion that the cost of power purchase including purchase under UI is not entirely within the control of the Board in a shortage scenario. In view of this, if at the end of year, there is any increase in the quantum of power purchase, the Commission will consider allowing the same subject to (a) intimation to the Commission and (b) the power is purchased in a judicious and economic manner.

4.9    EMPLOYEE COST

    In the ARR for the year 2006-07, the Board has projected net employee cost at Rs.1803 crores for the year 2006-07. The actual net employee cost for the years 2002-03, 2003-04 and 2004-05, revised estimates of the Board for 2005-06 and approved by the Commission along with the projections by the Board for 2006-07 are given in Table 4.20 below:

    Table-4.20

    (Rs. in crores)

    YearNet employee cost as per the BoardEmployee cost approved by the Commission
    123
    2002-031274.66(Actual)1274.66
    2003-041378.83(Actual)1274.66
    2004-051541.24(Actual)1274.66
    2005-061710.52(Revised)1480.01
    2006-071803.00(Projections)-

    It is evident from above that the employee cost is increasing year after year despite Commission’s clear directions to the Board to contain this cost as it is one of the highest in the country. This issue has already been discussed in detail in the Tariff Orders for the years 2002-03 to 2005-06 issued by the Commission. The Board has shown its helplessness stating that any increase in dearness allowance and on account of grant of annual increments to its employees has to be at par with the State Government employees owing to the service conditions of the Board’s employees. Further, the Board has stated that the measures like downsizing are not possible due to prevalent labour policies in the country. Introduction of VRS in the Board is also ruled out as it does not have resources to fund the same. The Board has also asserted that the maximum it could do in this direction was to impose a ban on new recruitment. However, the Commission notes that the Board ! has not tried to fix higher targets of productivity for its employees with a view to provide better quality services to the consumers which could justify granting additional emoluments to its employees.

    The Commission appreciates the constraints of the Board in reducing employee costs on account of the compulsion of having to pay normal increments as well as adopt increase of DA etc. as allowed by the State Govt. to its employees. The Commission also notes that the Board has, by and large, restrained from effecting any recruitment for the past several years. However, while such a policy has effected some savings, this can not be a prescription which can be adopted in the long run. The Commission observes that the Board has taken no steps whatsoever, towards rationalizing its staff strength even in the long run. This implies undertaking professional work studies to assess man power requirements and adopting productivity performance indicators. The Commission observes that the Public Expenditure Reforms Commission, Punjab Public Sector Disinvestment Commission and the Expert Group on Power Sector Reforms have all made recommendations in this respect which need to be s! eriously considered. During Tariff Order 2004-05, the Commission had suggested a group of six performance indicators which could be used by the Board for devising a formula for determining staff costs each year incorporating improving levels of efficiency. However, no such proposal was received from the Board and the Commission was left with little option but to determine the costs next year with reference to increase in the Wholesale Price Index.

    According to the provisions contained in the Punjab State Electricity Regulatory Commission (Terms and Conditions for Determination of Tariff) Regulations, 2005, O&M expenses including employee cost approved by the Commission for the year 2005-06 are to be the base expenses for determination of O&M expenses for the year 2006-07. These expenses are to be adjusted according to the annual variation in the rate of WPI relevant to All Commodities to determine the O&M expenses for the subsequent year, where WPI is the Wholesale Price Index (WPI) on April 1 of the relevant year. The increase in WPI from April 1, 2005 to March 31, 2006 is not available as yet. The increase in WPI from April 1, 2004 to March 31, 2005 is 5.34% which is being taken as basis for allowing increase in employee cost for the year 2006-07. As such, after allowing this increase over the approved employee cost of Rs.1480.01 crores for the year 2005-06, the employee cost for the year 2006-07 work out to! Rs.1559.04 crores.

    The Commission, therefore, approves Rs.1559.04 crores as employee cost for the year 2006-07.

4.10    REPAIR AND MAINTENANCE EXPENSES

    In the ARR for 2006-07, the Board has projected R&M expenses for that year at Rs.290 crores. The Board has justified this expenditure saying that it has vintage thermal power stations and T&D network which need to be maintained properly to ensure reasonable availability, reliability and quality of supply to the consumers. The Commission takes cognizance of the massive efforts required to be taken in this direction. The Punjab State Electricity Regulatory Commission (Terms and Conditions for Determination of Tariff) Regulations, 2005 provide for allowing annual increase based on increase in WPI over the O&M expenses approved by the Commission for the year 2005-06. The increase in WPI from April 1, 2004 to March 31, 2005 which is 5.34% is being allowed to determine the R&M expenses for 2006-07. As such, the R&M expenses for 2006-07 work out to Rs.263.35 crores against Rs.250 crores approved in 2005-06.

    The Commission, therefore, approves Rs.263.35 crores as repair and maintenance expenses for the year 2006-07.

4.11    ADMINISTRATION AND GENERAL EXPENSES

    In the ARR for the year 2006-07, the Board has projected administration and general expenses at Rs.58 crores for the year 2006-07.

    According to the provisions contained in the Punjab State Electricity Regulatory Commission (Terms and Conditions for Determination of Tariff) Regulations, 2005, annual increase based on increase in WPI over the A&G expenses approved by the Commission for the year 2005-06 is to be allowed. The increase of 5.34% in WPI from April 1, 2004 to March 31, 2005 is being allowed for the year 2006-07. As such, the A&G expenses for the year 2006-07 work out to Rs.57.84 crores after allowing this increase over the approved A&G expenses of Rs.54.91 crores in 2005-06.

    The Commission, therefore, approves Rs.57.84 crores as administration and general expenses for the year 2006-07.

4.12    DEPRECIATION

    In the ARR for 2006-07, the Board has revised depreciation charges to Rs.609 crores for the year 2005-06 and has projected these charges at Rs.649 crores in 2006-07. The depreciation charges for 2006-07 have been worked out on the basis of same function wise depreciation rates as for the year 2005-06 as given below in Table 4.21.

    Table-4.21
    Depreciation Charges approved for the year 2006-07

    (Rs. in crores)

    Item2005-062006-07
    Assets as on 1.4.05 as per balance sheetRate %Depreciation for 05-06Assets as On 1.4.06Rate %Depreciation for 06-07
    1234567
    Thermal29225.1715129255.17151
    Hydro56572.5214256852.52143
    Internal Combustion3--3--
    Transmission16275.589118855.58105
    Distribution36556.1022340626.10248
    Others1371.3421371.342
    Total14001 60914695 649

    In view of above, the Commission allows and approves depreciation charges of Rs.649 crores for the year 2006-07 as claimed by the Board.

4.13    INTEREST AND FINANCE CHARGES0

    In the ARR for the year 2006-07, the Board has claimed interest and finance charges of Rs.1063.30 crores for the year 2006-07 as per details discussed below:

4.13.1    Investment Plan

    The Board has proposed an ambitious investment plan of Rs.2509 crores for the year 2006-07. Actual capital expenditure in previous years is, however, on lower side as compared to the approved investments. Judging by actual expenditure incurred during previous years, it can be assumed that the capital expenditure during the year 2006-07 is unlikely to come up to the level of Rs.2509 crores as estimated by the Board in the investment plan. The Commission, therefore, estimates that the capital expenditure of the Board during the year 2006-07 would not exceed Rs.1500 crores. The Commission, therefore, approves an Investment Plan of Rs.1500 crores against approved investment of Rs.1200 crores for the year 2005-06.

4.13.2    Working Capital

    The Board has projected working capital requirement of Rs.1042.50 crores for which interest charges of Rs.86.60 crores have been claimed. Against this, the Commission determines the working capital requirement of Rs.579.31 crores for the year 2006-07 in accordance with the provisions contained in the Regulations as per details in Table 4.22 below:

    Table-4.22
    Working Capital Requirement

    (Rs. in crores)

    Fuel cost (one month)188.18
    Power purchase cost (one month)234.44
    Employee cost (one month)129.92
    Administration and General expenses (one month)4.82
    R&M expenses (one month)21.95
    Total requirement for working capital579.31

    The Commission, therefore, proportionately decreases interest on this account to Rs.48.12 crores against the claim of Rs.86.60 crores by the Board.

4.13.3    Finance Charges

    The Board has estimated these charges at Rs.25 crores which work out to1% of the proposed investment of Rs.2509 crores. After adjustment of consumer contribution of Rs.217 crores assumed at previous year’s level from the approved investment of Rs.1500 crores, the amount of balance investment works out to Rs.1283 crores in 2006-07. As such, the finance charges work out to Rs.12.83 crores on proportionately reduced basis which are approved by the Commission.

4.13.4    Capitalization of Interest

    In the Tariff Orders issued previously, the Commission had allowed capitalization of interest excluding the interest charges on working capital in the ratio of net works in progress to total expenditure. For the year 2006-07 also, capitalization of interest is allowed on the same principle. In view of this, the amount of capitalization of interest charges works out to Rs.105.32 crores for the year 2006-07.

4.13.5    Interest on Government Loans

    The Board has proposed neither any new Government loans nor any payment of earlier loans for the year 2006-07. The Commission allows the same amount of interest of Rs.465.90 crores on Government loans of Rs.4397.53 crores as approved for the year 2005-06.

4.13.6    Interest on Diversion of Funds

    The issue of diversion of capital funds for revenue purposes by the Board has been discussed in detail in the Tariff Orders for the years 2003-04, 2004-05 and 2005-06. The Commission had decided to disallow interest of Rs.100 crores related to diversion of capital funds. The Commission retains the decision of disallowance of Rs.100 crores from the interest charges payable for the year 2006-07 also.

    On the basis of above decisions, the Commission approves interest and finance charges as given in Table 4.23 below:

    Table – 4.23
    Interest Charges approved for the year 2006-07

    (Rs. in crores)

    Sl. No.ParticularsLoans o/s as on 31.3.06Receipt of loansRepayment of loansLoans o/s as on 31.3.07Amount of interest
    1234567
    1.As per ARR (other than WCL & Govt. loans)4260.172301.00611.535949.64616.92
    2.Approved by Commission (other than WCL & Govt. loans)4109.17*1283.00611.534780.64537.16
    3.Government loans4397.53--4397.53465.90
    4.Total (2+3)8506.701283.00611.539178.171003.06
    5.Interest on working capital----48.12
    6.Total interest----1051.18
    7.Add finance charges ----12.83
    8.Grand total----1064.01
    9.Less capitalization----105.32
    10.Net interest & finance charges----958.69

    * Receipt of loans of Rs.1283 crores = Approved investment of Rs.1500 crores –consumer contribution of Rs.217 crores

    Thus, net interest and finance charges work out to Rs.958.69 crores for the year 2006-07. Out of this, Rs.100 crores is to be disallowed on account of diversion of capital funds for revenue purposes. As such, net interest and finance charges come to Rs.858.69 crores for the year 2006-07.

    The Commission, therefore, approves net interest and finance charges of Rs.858.69 crores.

4.14    SUBSIDY FROM GOVERNMENT OF PUNJAB

    The Commission has approved AP consumption of 7115 MU for the year 2006-07. Revenue at existing rate of 214 paise per unit will work out to Rs.1522.61 crores which is to be paid by the Government to the Board as AP subsidy. An additional subsidy of Rs.7 crores on account of service charges and meter rentals in respect of AP consumers is also payable by the Government of Punjab. Besides, the Board has claimed subsidy of Rs.12 crores for Domestic (SC) Consumers on account of free energy supply. This claim was based on the earlier limit of 50 units of free supply which has now been raised to 200 units per month from September 1, 2005. The Board has not submitted its revised claim on account of this enhancement in the ARR for 2006-07. However, the Commission will allow the enhanced claim of subsidy at Rs.50 crores which will be adjusted in the review exercise for 2006-07.

    The Government of Punjab in its letter dated October 18, 2005 has stated that it had paid excess subsidy of Rs.152.50 crores for the years from 2002-03 to 2005-06 on account of subsidy for SC Domestic Consumers as per details given in Table 4.24 below.

    Table -4.24
    Government Subsidy for SC Domestic Consumers

    (Rs. in crores)

    Sr. No.YearAmount paidAmount dueExcess paid
    12345
    1.2002-0350.0020.6929.31
    2.2003-0450.008.1141.89
    3.2004-0550.008.2041.80
    4.Sub-total150.0037.00113.00
    5.2005-0650.0010.5039.50
    6.Total200.0047.50152.50

    The truing up exercise of the accounts of the Board has been done by the Commission for the years 2002-03, 2003-04 and 2004-05 in which subsidy of Rs.50 crores related to DS (SC) consumers paid by the Government for each year has been taken into account. As such, the excess subsidy received by the Board for the years 2002-03, 2003-04 and 2004-05 works out to Rs.113 crores is adjusted in the ARR for the year 2006-07. As discussed in para 3.16, the adjustment of excess subsidy paid for 2005-06 is not being made and will be considered on the basis of actuals at the time of true-up exercise for 2005-06.

4.15    RETURN ON EQUITY

    According to the provisions contained in Regulation 25 of the Punjab State Electricity Regulatory Commission (Terms and Conditions for Determination of Tariff) Regulations, 2005, Return on Equity shall be computed on the paid up equity capital determined in accordance with Regulation 24 and shall be guided by the Central Electricity Regulatory Commission (Terms and Conditions of Tariff) Regulations, 2004 as amended by CERC from time to time. Keeping this in view, Return on Equity is admissible @14% p.a. on equity capital as on 1st April, 2006.

    No doubt, the Board is running into losses but still its net worth in terms of fixed assets is more than the amount of equity. Also even if a utility is running into losses, return on equity cannot be denied to it. Else, having once gone into losses it can never become financially viable and sustainable. In other words, denial of ROE to a loss making utility will further push it into losses rather than retrieving it from that situation. If a profit making utility is entitled to ROE, the loss making utility cannot be denied of this genuine charge on its consumers. It is important to remember that inefficiencies of a utility are already penalized by restricting them to normative costs under relevant heads. The denial of ROE will, therefore, result in doubly penalizing the inefficiencies of the utility.

    As such, the Board is entitled to get return on equity as provided in the Regulations. The amount of approved loans and the equity in the Board is Rs.8506.70 crores and Rs.2946.11 crores respectively as on April 1, 2006. The equity in the debt equity ratio works out to 25.72% which is within the maximum limit of 30% as per CERC Regulations. The Board has claimed Rs.412.46 crores as return @ 14% on equity of Rs.2946.11 crores which is conforming to the provisions in the regulations.

    The Commission, therefore, approves Return on Equity of Rs.412.46 crores for the year 2006-07.

C.    MISCELLANEOUS REVENUE (NON TARIFF INCOME)

    In the ARR of 2006-07, the Board has projected non tariff income of Rs.360 crores for the year 2006-07. The Commission has decided to reduce the meter rentals with effect from April 1, 2006 which will result in reduction in non tariff income by Rs.40 crores. Thus, the non tariff income of the Board for the year 2006-07 is estimated to be Rs.320 crores.

    The Commission, therefore, approves Rs.320 crores as non tariff income for the year 2006-07.

4.16    REVENUE FROM EXISTING TARIFF

    Revenue from existing tariff as projected by the Board for the year 2006-07 is Rs.8124 crores. However, the expected revenue from existing tariff on the basis of sales approved by the Commission will work out to Rs.8270.82 crores as given below in Table 4.25.



    Table – 4.25
    Revenue from Existing Tariff
    Sr. No.Category of consumersEnergy sales
    (MU)
    Tariff rates
    (p/unit)
    Revenue (Rs. in crores)
    12345
    1.Domestic
    a)Up to 100 units3120221689.52
    b)101-300 units1418368521.82
    c)Above 300 units1134389441.13
     Total (a+b+c)5672 1652.47
    2.NRS1587423671.30
    3.Public lighting12942354.57
    4.Industrial
    a)SP719337242.30
    b)MS1482372551.30
    c)LS77663722888.95
     Total (a+b+c)9967 3682.55
    5.Bulk supply502394197.79
    6.Railway traction13144358.03
    7.Common pool302 59.74
    8.Outside state659 163.76
    9.Total18949 6540.21
    10.AP consumption71152141522.61
    11.Total26064-8062.82
    12.Add MMC and Other charges--208.00
    13.Grand Total--8270.82

    The Commission, as such, approves revenue from existing tariff at Rs.8270.82 crores for the year 2006-07.

D.    REVENUE REQUIREMENT

    The summary of the revenue requirement of the Board for the year 2006-07 as analyzed in the preceding paragraphs is given below in the Table 4.26.

    Table – 4.26
    Revenue Requirement for the year 2006-07

    (Rs. in crores)

    Sr. No.Item of expenseProposed by the Board Approved by The Commission
    1234
    1.Cost of fuel2316.002258.15
    2.Cost of power purchase3256.002813.34
    3.Employee cost1803.001559.04
    4.R&M expenses290.00263.35
    5.Administration and general expenses58.0057.84
    6.Depreciation649.00649.00
    7.Interest charges1036.00858.69
    8.Return on Equity412.00412.46
    9.Total revenue requirement9820.008871.87
    10.Less: non tariff income 360.00320.00
    11.Net revenue requirement (9-10)9460.008551.87
    12.Revenue from tariff8124.008270.82
    13.Gap for 2006-07 (11-12)1336.00281.05
    14.Gap for 2005-061059.00(-)385.24
    15.Total Gap (13+14)2395.00(-)104.19
    16.Adj. of excess subsidy for SC Domestic consumers153.00113.00
    17.Adj. of subsidy for AP consumers48.00-
    18.Gap after adjustment of excess subsidy2595.008.81
    19.Additional revenue from proposed tariff1383.00-
    20.Regulatory asset1212.008.81
    21.Energy sales(MU)2589426064

    >From the above, it is evident that there will be a revenue gap (deficit) of Rs.281.05 crores for the year 2006-07. After taking into account the revenue surplus of Rs.385.24 crores for the year 2005-06 and adjustment of excess subsidy of Rs.113 crores, the Board will be left with a revenue gap of Rs.8.81 crores at the end of March, 2007.

    Annual Revenue Requirement for the year 2006-07 is assessed at Rs.8871.87 crores with energy sales of 26064 MU. The average cost of supply with this revenue requirement comes out to 340.39 paise per unit say 340 paise per unit.The corresponding figure of average cost of supply per unit for the year 2005-06, as worked out by the Commission was 319 paise as per Tariff Order dated June14, 2005. However, the combined average cost of supply (which is the average cost of supply after taking into account past years’ gap) works out to 329.94 paise per unit against 329.42 paise per unit worked out last year. This combined average cost of supply is being considered for determination of tariff.

Chapter-5
Determination of Tariff
and Related Issues

5.1    DETERMINATION OF TARIFFd
5.1.1    Annual Revenue Requirement

    The ARR and Tariff Application of 2006-07 filed by the Board includes truing up for the year 2004-05 and review of 2005-06. The Board has projected a revenue deficit of Rs.1336 crores for the current year and additional deficit of Rs.1059 crores for the years 2004-05 and 2005-06. The Commission has determined the ARR for the current year at Rs.8871.87 crores. After making adjustment on account of non-tariff income and revenue from tariff at existing level, the revenue gap assessed by the Commission for the current year is a deficit of Rs.281.05 crores. The Commission has simultaneously undertaken an exercise of truing up for the year 2004-05 consequent to the availability of audited Annual Statement of Accounts. As a result of this truing up, net revenue deficit of the Board for the year 2004-05 has finally been worked out as Rs.243.90 crores against the deficit of Rs.268.58 crores determined earlier. The Commission has also taken up the review of its Tariff Order of 2005-06! , as a result of which the gap of 2005-06 has been revised to a surplus of Rs.629.14 crores against a surplus of Rs.271.75 crores originally determined by the Commission. Combined impact of the three exercises is that at prevalent level of tariff, the Board is surplus by Rs.104.19 crores as compared to its total revenue requirement. Out of this, an amount of Rs.113 crores received from the Government as excess subsidy is to be adjusted during 2006-07 leaving a net deficit of Rs.8.81 crores only (Table 4.26).

5.1.2    Cost of Supply and Cross Subsidy

    As per mandate of the Electricity Act, 2003 (the Act) the issue of ‘cost of supply’ is fundamental to the determination of tariff. Section 61 of the Act lays down different guiding factors to be kept in view by the Commission in this respect. Sub section (d) provides that the consumers’ interests are to be safeguarded while at the same time recovery of the cost of electricity in a reasonable manner is to be ensured. Further sub section (g) enjoins that tariffs should progressively reflect the cost of supply of electricity and also the reduction and elimination of cross subsidies. It is clear that cost of supply is the ultimate goal towards which tariffs of different categories of consumers have to move over a period of time. However, the Act does not define the term ‘cost of supply’ i.e. whether it is category-wise cost of supply or average cost of supply. The Commission has for the next 10 years taken ‘cost of supply’ to mean average cost of supply.

    The Commission has also defined cross subsidy in PSERC (Determination of Tariff) Regulations, 2005. As per this definition, Cross-subsidy for a consumer category in the first phase means the difference between the average realization per unit from that category and the combined average cost of supply per unit expressed in percentage terms as a proportion of the combined average cost of supply. In the second phase it means the difference between the average realization per unit from that category and the combined per unit cost of supply for that category expressed in percentage terms as a proportion of the combined cost of supply of that category. Further, it is provided in the Regulations that the Commission shall determine the tariff to progressively reflect the cost of supply of electricity and also reduce and eliminate cross subsidies within a reasonable period. In the first phase the Commission shall determine tariff so that it progressively reflects combined average uni! t cost of supply and the cross subsidy as defined above is eliminated over a period of 10 years from the date of issue of these Regulations. In the second phase, the Commission shall consider moving towards the category-wise cost of supply as a basis for determination of tariff.

5.1.3    Tariff Proposal of the Board

    The tariff proposal of the Board is contained in Chapter 1 of this Order. The detailed tariff schedule proposed by the Board is contained in Annexure-III. Salient features of the proposal are also narrated in para 1.6.3 of that Chapter. One of the basic changes proposed by the Board in the tariff structure this year is the shift from Single Part Tariff to Two Part Tariff for LS & Railway Traction consumers. This structure involves charging of tariff in two parts - one for the energy consumed at the rates determined for the purpose and second, a fixed charge to be borne by the consumer with reference to the sanctioned load/contract demand but irrespective of the actual energy consumed. While recommending levy of fixed charges, the Board proposes to abolish Monthly Minimum Charges simultaneously. Other features of the proposal include restructuring of the penalty for exceeding the contract demand and reduction in rebate for high voltage supply. There is also a provision for re! covery of various charges from consumers availing Open Access as per PSERC (Open Access) Regulations, 2005.

    The Act enjoins separation of transmission and system operation activities of the licensee separately and distinct from generation or trading business. The present extension allowed by the Govt. of India authorizes the Board to function as an integrated utility and perform the functions of State Transmission Utility (STU) upto June 9, 2006 only. However, the Board has not provided cost of various activities separately for the year 2006-07. Apparently, the Board is not foreseeing its unbundling into separate entities during the current year. The Commission accepts this position and has determined only combined costs for the current year. The detailed discussion on various issues related to tariff is contained in para 5.2 of this Chapter.

5.1.4    Determination of Tariff

    For determination of tariff, the Commission is guided by the principles enshrined in Section 61 of the Electricity Act, 2003. Further, the Commission has also notified in the official gazette Regulations laying down terms & conditions for determination of tariff. These Regulations incorporate guidelines for determination of the Annual Revenue Requirement of a power utility and the tariff for various categories of consumers. The National Electricity Policy and the National Tariff Policy have also been notified by the Government of India in Notifications dated February 12, 2005 and January 6, 2006 respectively. The Commission has been guided by the provisions of the Act, its Regulations, National Tariff Policy, the principles adopted by it in its earlier four Tariff Orders and has also kept genuine grievances of the consumers in view.

    While determining tariff for various categories of consumers, the Commission has arrived at a revenue gap of Rs.281.05 crores for the current year as worked out in Table 4.26 of this Order. After adding adjustments made for the earlier years and the excess provision of GOP subsidy in earlier years, total deficit works out to Rs.8.81 crores as given in Table 4.26.

    The Commission observes that this gap is insignificant being only about 0.1% of the total revenue requirement of the Board for the year 2006-07. The Commission further observes that the cross subsidy levels prevalent in the system have already been reduced substantially consequent to the last four Tariff Orders of the Commission. The reduction in cross subsidy level by the Commission has been achieved in two ways - one by introduction of agricultural tariff at about Rs.2 per unit on agricultural consumers as against free supply to this sector earlier. The recovery from agricultural sector at the existing tariff is over 65% and is one of the highest in India. Secondly, the tariff of other categories of consumers has also been consciously brought nearer to average cost of supply continuously over the last four years. The Commission is conscious of the requirement of reduction and final elimination of cross subsidy level as per Section 61(g) of the Act and also the requ! irement of the National Tariff Policy to move the tariffs in such a way that tariff for each category of consumers is brought down to a maximum of ± 20% of average cost of supply by the year 2010-11 at a linear rate. The Commission notes that it has already moved substantially in this direction and in view of the fact that there is effectively no change in the average cost of supply, it decides to continue with the existing level of tariffs for all categories of consumers in the current year.

5.1.5    Effect of Tariff Revision on Cross Subsidy

    As indicated in para above, the Commission has decided to continue with existing level of tariffs for all categories for the year 2006-07. The Commission, however, considers it worthwhile to assess the effect of revised tariff on the cross subsidy level in the system.

    Keeping in view the definition of cross subsidy in Tariff Regulations, 2005 the total quantum of cross subsidy generated and utilized in the system as per existing tariff has been worked out for the year 2005-06 in Table 5.1.

    Table - 5.1
    Aggregate Quantum of Cross Subsidy for the year 2005-06
    Existing Tariff

    Combined average cost of supply = 329.42 paise/unit

    Sr. NoCategoryEnergy Sales (MU)Existing tariff paise/unitRevenue with existing tariff (Rs. Crores)PLEC + MMC etc. (Rs. Crores)Non tariff income (Rs. Crores)Total Revenue (Rs. Crores) (5+6+7)Expected Revenue with average cost (Rs. crores)Cross Subsidy generated (+) Utilised (-) (8-9)
    12345678910
    1Domestic
    a)Upto 1002971221656.592241.70720.29978.71-258.42
    b)101-3001351368497.17118.96517.13445.0572.08
    c)>300 units1080389420.12015.16435.28355.7779.51
     Total5402&nbs[1573.882375.821672.701779.53-106.83
    2NRS1454423615.045320.41688.45478.98209.47
    3Public Lighting12042350.7601.6852.4439.5312.91
    4Industrial
    a)SP699337235.56159.81260.37230.2630.11
    b)MS1456372541.633420.44596.07479.64116.43
    c)LS75433722806.0078105.872989.872484.82505.05
     Total9698 3583.19127136.123846.313194.72651.59
    5Bulk Supply454394178.8806.37185.25149.5635.69
    6Rly. Traction11344350.0601.5951.6537.2214.43
    7Common Pool302 59.7404.2463.9899.48-35.50
    8Outside State593 147.3608.32155.68195.35-39.67
    9AP70002141498.00098.251596.252305.94-709.69
     Total25136 7756.91203352.808312.718280.301075.68
    -1043.28
    This means that Rs.1075.68 crores of cross subsidy is generated at the existing levels of tariff whereas Rs.1043.28 crores is required resulting in a surplus of Rs.32.40 crores. This is mainly on account of change in sales, sales mix and non- tariff income.

    The position indicating cross subsidy levels in the system with revised tariffs approved by the Commission for the year 2006-07 is given in Table 5.2.
    Table - 5.2
    Aggregate Quantum of Cross Subsidy for the year 2006-07
    Revised Tariff

    Combined average cost of supply = 329.94 paise/unit

    Sr. NoCategoryEnergy Sales (MU)Revised tariff paise/ unitRevenue with Revised tariff (Rs. Crores)PLEC+MMC etc. (Rs. Crores)Non tariff income (Rs. Crores)Total Revenue (Rs. Crores) (5+6+7)Expected Revenue with average cost (Rs. crores)Cross Subsidy generated (+) Utilised (-) (8-9)
    12345678910
    1Domestic
    a)Upto 1003120221689.522438.31751.831029.41-277.58
    b)101-3001418368521.82117.41540.23467.8572.38
    c)>300 units1134389441.13013.92455.05374.1580.90
     Total5672 1652.472569.641747.111871.42-124.31
    2NRS1587423671.305719.48747.79523.61224.18
    3Public Lighting12942354.5701.5856.1542.5613.59
    4Industrial
    a)SP719337242.30158.83266.13237.2328.90
    b)MS1482372551.303418.20603.50488.97114.53
    c)LS77663722888.957495.353058.302562.31495.99
     Total99673682.56123122.373927.933288.51639.42
    5Bulk Supply502394197.7936.16206.95165.6341.32
    6Rly. Traction13144358.0301.6159.6443.2216.42
    7Common Pool302 59.7403.7163.4599.64-36.19
    8Outside State659 163.7608.09171.85217.43-45.58
    9AP71152141522.61087.351609.962347.52-737.56
     Total26064 8062.83208320.008590.838599.561088.21
    - 1096.91

    Accordingly, Rs.1088.21 crores subsidy shall be generated at the revised level of tariff against which Rs.1096.91 crores cross subsidy shall be utilized leaving a marginal deficit of Rs.8.70 crores only.

    Utilising the figures of aggregate quantum of cross subsidy in each consumer category under the existing and revised tariffs as worked out in Table 5.1 and 5.2 above, the gross quantum of cross subsidy from each category for the years 2005-06 and 2006-07 after tariff determination through this Order is given in Table 5.3:

    Table – 5.3
    Aggregate Quantum of Cross Subsidy
    Comparison of Existing and Revised Tariffs
    Existing average cost of supply 329.42 paise/unit
    Revised average cost of supply 329.94 paise/unit
      Quantum of Cross Subsidy in absolute terms
    Sr. No.CategoryExisting for the year 2005-06Revised for the year 2006-07
    Energy Sale
    Mus
    Cross Subsidy
    (Rs. Crores)
    Energy Sale
    Mus
    Cross Subsidy
    (Rs. Crores)
    123456
    1Domestic
    a)Upto 1002971-258.423120-277.58
    b)101-300135172.08141872.38
    c)>300 units108079.51113480.90
     Total5402-106.835672-124.31
    2NRS1454209.471587224.18
    3Public Lighting12012.9112913.59
    4Industrial
    a)SP69930.1171928.90
    b)MS1456116.431482114.53
    c)LS7543505.057766495.99
     Total9698651.599967639.42
    5Bulk Supply45435.6950241.32
    6Rly. Traction11314.4313116.42
    7Common Pool302-35.5302-36.19
    8Outside State593-39.67659-45.58
    9AP7000-709.697115-737.56
     Total251361075.68
    - 1043.28
    260641088.21
    - 1096.91

    Further, the cross subsidy levels as per existing tariff and revised tariffs are as given in Table 5.4.

    Table – 5.4
    Cross Subsidy Levels
    Sr. NoCategoryExisting Tariff
    Combined average cost of supply
    = 329.42 paise/unit
    Revised Tariff
    Combined average cost of supply
    = 329.94 paise/unit
    Energy Sales (MU)Total Revenue (Rs. Crores)Realisation per unit paise/unitCross Subsidy %Energy Sales (MU)Total Revenue (Rs. Crores)Realisation per unit paise/unitCross Subsidy %
    12345678910
    1Domestic
    a)Upto 1002971720.29242.44-26.43120751.83240.97-27
    b)101-3001351517.13382.7816.21418540.23380.9815.5
    c)>300 units1080435.28403.0422.31134455.05401.2821.6
     Total54021672.70309.64-656721747.11308.02-6.6
    2NRS1454688.45473.4943.71587747.79471.242.8
    3Public Lighting12052.4443732.712956.15435.2731.9
    4Industrial
    a)SP699260.37372.4913.1719266.13370.1412.2
    b)MS1456596.07409.3924.31482603.50407.2223.4
    c)LS75432989.87396.3820.377663058.30393.8119.4
     Total96983846.31396.6120.499673927.93394.0919.4
    5Bulk Supply454185.25408.0423.9502206.95412.2524.9
    6Rly. Traction11351.65457.0838.813159.64455.2738
    7Common Pool30263.98211.85-35.730263.45210.1-36.3
    8Outside State593155.68262.53-20.3659171.85260.77-21
    9AP70001596.25228.04-30.871151609.96226.28-31.4
     Total251368312.71330.71 260648590.83329.61 

    It will be seen from the Table above that there are only insignificant changes in the existing level of cross subsidy.

5.1.6    Subsidy from Government of Punjab

    While determining the ARR of the Board and tariff for electricity, the Commission interalia, kept in view all relevant factors including the GOP’s observations on ARR and Tariff Application of the Board. The Commission, thereafter approached the Government to indicate its views regarding its plan to extend subsidy to any consumer or class of consumers under Section 65 of the Electricity Act, 2003 in its D.O. letter No.2538 dated May 1, 2006. A copy of the reference is enclosed at Annexure-V. It was also indicated in the reference that presently, the GOP is subsidizing AP consumers and SC domestic consumers having connected load upto 500 watts and the requirement of subsidy for maintaining the status quo in 2006-07 will be as follows:

    Table 5.5
    Requirement of subsidy to maintain status quo

    (Rs. in Crores)

    (a)AP subsidy for current year for assessed consumption of 7115 MUs1522.61
    (b)Subsidy for free supply to SC domestic consumers for current year50.00
    (c)Adjustment in AP consumption for the year 2004-0516.13
    (d)Adjustment in AP consumption for the year 2005-06Nil
    (e)Loss of revenue on account of meter rentals due to free supply11.08
     Total subsidy requirement1599.82
    (f)Adjustment of excess provision of SC domestic subsidy in earlier years(-)113.00
     Net subsidy required1486.82

    Further, it was indicated that of the total subsidy requirement, Rs.465.90 crores is available for adjustment from interest due from the Board on Government loans during the year 2006-07 and balance subsidy of Rs.1020.92 crores will need to be made good by adjustment of Electricity Duty and other means.

    The Government in its letter dated May 3, 2006 has accorded sanction for subsidy as given in the Table above. A copy of this letter is enclosed at Annexure VI. The Commission accepts the decision of the Government regarding grant of subsidy. The same has been incorporated in the tariff structure for working out the tariffs payable by the consumers subsidized by the Government as indicated in Table 5.7.

5.1.7    Multi Year Tariff Principles

    Section 61 sub-section (f) of the Electricity Act, 2003 states that the Appropriate Commission shall specify the terms & conditions for determination of tariff and in doing so, shall interalia be guided by Multi Year Tariff principles.

    The National Tariff Policy notified by the Ministry of Power, Government of India on January 6, 2006 mandates that the Multi Year Tariff frame-work is to be adopted for any tariff to be determined from April 1, 2006.

    The Commission has framed Tariff Regulations determining the terms and conditions of tariff which have been notified on December 2, 2005 and have come into effect from that date. These Regulations interalia cover most of the principles for determination of tariff under Multi Year Tariff frame-work. The Commission has gone by these Regulations and has thereby followed Multi Year Tariff principles in determination of tariff for the current year.

5.1.8    Open Access Charges

    One of the main objectives of the Electricity Act, 2003 is to promote competition through Open Access. The Act provides for Open Access both on the transmission and distribution system of licensees, thereby allowing non-discriminatory access to these systems by a customer on payment of various charges. Both the Open Access and Tariff Regulations have been finalized and notified in the State Govt. Gazette.

    The Commission had considered the provisions of the Act and the Regulations framed by it while passing a detailed Order dated January 25, 2006 determining the Open Access charges for the year 2005-06. In the Order, it was indicated that as the National Tariff Policy had been received only a few days before the Order, the same could not be taken into consideration. It was decided that implications of National Tariff Policy on the Open Access charges will be considered while deciding charges for Open Access for the year 2006-07. The provisions of the National Tariff Policy are at variance with the Regulations notified by the Commission on issues like determination of surcharge and T&D losses. While the National Tariff Policy defines surcharge as the difference between tariff applicable and the cost of supply for that category of consumers, the Commission has taken surcharge to be the difference between realization and the combined average cost of supply and has allow! ed only 50% of recovery of surcharge from Open Access customers as against full recovery in the National Tariff Policy. Further, the Commission has not gone into class-wise cost of supply on account of inadequate data presently available from the utility. Similarly, the Commission has not determined voltage-wise T&D losses and has gone by the overall average T&D losses of which only 50% would be payable by Open Access customers. As against this, the National Tariff Policy provides for full accountal of T&D loses at the supply voltage level. The Commission is of the view that owing to non-availability of a complete data-base on voltage-wise losses from the power utility and in view of the provisions of Regulations already duly notified after following a transparent procedure as provided in the Act, it would be advisable not to adopt any yardsticks in the current financial year other than those provided in the Regulations. The Commission, therefore, decides to adopt the sam! e methodology for determination of Open Access charges as followed in the Order of the Commission dated January 25, 2006.

    For fixing different charges, the following methodology has been adopted.

    1. For the purpose of calculation of Open Access charges, the costs of the utility be apportioned between generation, transmission and distribution. The Board, being an integrated utility, has not furnished segregated ARRs for these functions. However, the Annual Statement of Accounts of the Board depicts expenditure under these three functions. There are also some common expenses which have not been so apportioned but these expenses are minimal. It has been decided to apportion the common expenses in the proportion of direct costs under each head. The apportionment of total expenditure under various heads and of fixed assets have been worked out taking the audited accounts of 2004-05 as the base.

    2. While apportioning expenditure as above, expenditure on fuel cost and power purchase cost has been excluded as this is directly related to generation and is very substantial and its inclusion for the purpose of apportionment may distort the results.

    3. The ARR for the year 2006-07 approved by the Commission has been apportioned among various functions in the ratio in which actual expenses for the year 2004-05 have been apportioned in Para (a) above.

    4. The total transmission and distribution capacity as intimated by the Board in its letter no. 412 dated April 5, 2006 has been adopted for calculating transmission and wheeling charges.

    The apportionment of costs for the year 2004-05 on the basis of the above principles and audited accounts for that year is worked out in Table 5.6:

    Table – 5.6
    Apportionment of cost among various functions as per
    Board’s Audited Accounts for the year 2004-05

    (Rs. in crores)

    Sr. NoParticuLarsTotalGenerationTransmissionDistributionTotal (Gen.+Trans.+Dist.)Common assets/ExpensesRemarks
    A-ASSETS
    1.Assets14000.71Direct  8581.96
    Apprt.  84.64
    Total  8666.60
    1627.32
    16.05
    1643.37
    3654.69
    36.05
    3690.74
    13863.97
    136.74
    14000.71
    136.74General assets trifurcated in ratio of assets
    B-EXPENSES
    1.Employees cost1639.19


    Capitalisation
    97.95
    Direct  222.71
    Apprt.  54.36
    Total  277.07
    Net of Cap.  260.51
    111.64
    27.25
    138.89

    130.59
    983.24
    239.99
    1223.23

    1150.14
    1317.59
    321.60
    1639.19

    1541.24

    321.60
    General expenses trifurcated in ratio of respective heads
    2.R&M cost17.22
    209.07
    226.29

    Capitalisation
    2.09
    Direct  17.22
    Direct  116.58
    Apprt.  8.33
    Total  142.13
    Net of Cap.  140.82

    27.95
    2.00
    29.95

    29.67

    50.60
    3.61
    54.21

    53.71
    17.22
    195.13
    13.94
    226.29

    224.20

    13.94
    Operating expenses General expenses trifurcated in ratio of respective heads
    3.A&G70.17


    Capitalisation
    17.87
    Direct  8.16
    Apprt.  2.37
    Total  10.53
    Net of Cap.  7.85
    11.47
    3.33
    14.80

    11.03
    34.74
    10.10
    44.84

    33.42
    54.37
    15.80
    70.17

    52.30
    15.80General expenses trifurcated in ratio of respective heads
    4.Depreciation (net)575.64


    Capitalisation.
    0.91
    Direct  289.79
    Apprt.  1.92
    Total  291.71
    Net of Cap.  291.25
    83.53
    0.55
    84.08

    83.95
    198.53
    1.32
    199.85

    199.53
    571.85
    3.79
    575.64

    574.73

    3.79
    -do-
    5.Intt.& Fin. Charges1054.27

    Capitalisation
    61.43
    Direct  707.18
    Apprt.  2.69
    Total  709.87
    Net of Cap.  668.51
    130.79
    0.50
    131.29

    123.64
    212.31
    0.80
    213.11

    200.69
    1050.28
    3.99
    1054.27

    992.84

    3.99
    -do-
    6.Return on NFA212.70Direct  131.6624.9756.07212.70  Trifurcated in the ratio of assets
    7.Total exp. excluding Fuel cost and Power purchase3598.011500.60403.851693.563598.01    

    The total capitalised amount under various heads as per Account of the Board for the year 2004-05 has been apportioned to Generation, Transmission and Distribution in the ratio of their total expenditures.

    The apportionment of costs for the year 2006-07 amongst various functions in the same proportion shall be as follows:
    (Rupees in Crores)
    Total ARR= Rs.8871.87
    Less
    (i)Fuel Cost= Rs.2258.15
    (ii)Power Purchase= Rs.2813.34
    Balance ARR= Rs.3800.38
    Generation= Rs.1585.00
    Transmission= Rs. 426.56
    Distribution= Rs. 1788.82
    Total= Rs.3800.38
    Total transmission capacity= 5870 MW
    Total distribution capacity= 5919 MW

    Various Open Access charges to be paid by customers during the year 2006-07, therefore, shall be as follows:-
    (i)Transmission Charges= 426.56
    5870x365
    = Rs1990.89 /MW/day
    (ii)Wheeling Charges=1788.82
    5919x365
    = Rs.8279.91 /MW/day
    (iii)Transmission + Wheeling Charges
    Chargeable from long term customers
    = 33% of (1990.89+8279.91)
    = Rs.3389 /MW/day
    (iv)Transmission+ Wheeling Charges
    Chargeable from short term customers
    = 25% of (1990.89+8279.91)
    = Rs.2568 /MW/day
    (v)T&D Losses=50% of total T&D losses = 10.375%
    (vi)Surcharge=Realisation per unit – Combined average cost of supply
    Surcharge for Large Supply= 393.81 – 329.94 = 63.87 paise/unit
    Chargeable Surcharge for Large Supply= 50% of 63.87 = 31.94 paise/unit
    (vii)Other charges such as additional surcharge, operation charges, UI charges, reactive energy charges, shall be levied as per the Open Access Regulations/Tariff Regulations notified by the Commission.

5.2    RELATED ISSUES

    Some Tariff related issues have been raised by various Consumers/Consumer Organizations. The Commission has examined all these issues along with responses of the Board thereto. These issues are discussed below:

5.2.1    Two Part Tariff (TPT) for Large Supply & Railway Traction Consumers

    In the Tariff Order for 2005-06, the Commission had directed the Board to introduce two part tariff for Large Supply & Railway Traction consumers from the year 2006-07. The Commission further directed the Board to prepare a detailed and well considered proposal containing all relevant data pertaining to load & contract demand profiles of different types of consumers in these categories. The Board was further directed to go into the reasons for earlier reverting to single part tariff and also bring out the revenue implications for consumers and the Board.

    The Board’s Tariff Application for the year 2006-07 proposes to introduce TPT for Large Supply industrial consumers and Railway Traction. The proposal consists of recovery of tariff in two parts – fixed/ demand charges to be levied on the sanctioned contract demand and energy charges on actual consumption. With introduction of TPT, the Board has proposed to discontinue the recovery of Monthly Minimum Charges. The Board has also proposed that the seasonal industries, cold storages and ice factories under LS categories shall pay the fixed charges for the whole year during the defined seasonal period for which the industry actually runs, per month fixed charges to be recovered shall be adjusted on pro-rata basis and for the period beyond seasonal period, only energy charges would be payable.

    Several Consumers’ Associations have vehemently objected to the proposal of the Board for introduction of TPT. Their main plea is that rate of fixed charges is high and consumers having low consumption/ load factor would be hit hardest with their overall rate increasing substantially. According to them, fixed charges should be levied on actual maximum demand or a predetermined fixed part of sanctioned contract demand. It has further been suggested that the Board should not be allowed to mobilize additional revenue under the garb of TPT and there should be provision for maximum overall rate.

    The Board has responded to the objections of consumers and Industry Associations stating that the tariff is designed in such a way that overall level of revenue recovery through TPT structure would be the same as under single part tariff. Further, fixed charges are leviable for the commitment made by the Board for supply of power irrespective of actual consumption of energy. It has also been stated that maximum overall rate would complicate billing procedure.

    The Commission notes that the Board had TPT for LS & MS consumers upto the year 1989, under which demand charges were based upon higher of actual recorded maximum demand or 75% of sanctioned contract demand or 100 KVA in case of LS consumers and connected load in case of MS consumers. From 1989, all MS consumers and LS consumers with load upto 1MW were brought under single part tariff. However, in 1994, two part tariff was substituted with single part tariff for all consumers. The main argument for reverting to single part tariff was simplification in understanding and billing and avoidance of manipulation of actual maximum demand recorded by electro-mechanical (E/M) meters. While these E/M meters have now been replaced with Electronic meters, the Board has not clearly stated whether risk of manipulation still exists or the extent thereof.

    The Board has supplied statistics in respect of 4059 consumers and information regarding load and contract demand profiles of different types of consumers under Large Supply and Railway Traction categories. The Commission observes that the TPT proposal submitted by the Board would lead to a wide disparity in overall tariff rates for different consumers even of the same category. Representations made by consumers/industrial organizations during the Commission’s hearings had with use of actual billing data and load profiles shown how the rate would vary under the TPT proposal for different LS consumers depending upon load factor/utilization. It is also evident that introduction of TPT on the lines proposed by the Board would result in higher tariffs for a vast majority of consumers, whereas a better dispensation would be available only to a few units with heavy load demand and better load factor. Implementation of the TPT proposal on these lines would, therefore, rais! e serious equity issues besides the likelihood of adversely affecting competitiveness of many units where energy costs are a substantial chunk of the overall cost of production. The liability to pay fixed charges based on sanctioned contract demand might also induce several existing Large Supply units to consider lowering their contract demand in order to avail of more attractive tariff rates. Such a situation, which is not unlikely, would also adversely effect revenue of the Board in the short run. In the light of these observations, the Commission while mindful of National Tariff Policy enjoining early introduction of TPT is nevertheless of the considered view that TPT should be introduced only after efforts are made to build a consensus amongst various stake holders of PSEB through public hearings and by more critically analyzing actual billing data to determine impact on consumers as well as the Board’s revenues. The Commission further observes that ways of giving consu! mers time to make adjustments to address optimal utilization of their contract demand may need to be thought of. Also, such an exercise may necessarily have to be prefaced by simplification in procedure for enhancement/reduction of contract demand.

    In the light of the above, the Commission does not consider it appropriate to introduce Two Part Tariff during the current year but would like to more surely prepare the ground for implementation of this proposal in the next financial year. The Board is advised to furnish a detailed proposal on the above lines which also addresses concerns raised by consumers during tariff hearings of 2006-07 by end September 2006.

5.2.2    High Voltage Rebate

    The Commission in its Tariff Order for 2005-06 had decided to continue the existing high voltage rebate and had also directed the Board to submit a comprehensive proposal bringing out all the aspects of the matter including revenue implications.

    In the ARR and Tariff Application, the Board has proposed to change the quantum of high voltage rebate permissible for all categories of consumers (except Railway Traction) connected at 33KV and above. It has been proposed that consumers connected at 33 KV/66KV be allowed rebate @ 2.5% while those at 132KV/220KV be allowed rebate @ 4.0%. The proposed rebate has been worked out by the Board on the basis of connected load and consumption profile of consumers connected at these voltage levels. The Board has worked out the financial implications of the rebate with respect to T&D losses only which have been taken as 9.55% at 11 KV supply, 4.79% at 33/66 KV and 2.00% for 132/220 KV. The Board has also proposed that the high voltage rebate of 7.5% being allowed to all DS/NRS consumers getting supply at 11 KV irrespective of their connected load, be allowed to those consumers in DS/NRS categories connected at 11 KV whose connected load is less than 100 KW .The Board has not ! indicated the basis for assuming T&D losses at various voltages as well as reasons for change in eligibility for allowing rebate to DS/NRS consumers.

    Some Industrial Consumers’ Associations have objected to the proposal of PSEB on the plea that consumers catered at 33 KV or higher voltage had to spend substantial amounts for creating infrastructure besides bearing losses. They have also pointed out that while working out financial implications, the Board has taken the price of electricity as 167 paise per unit against purchase price of 256 paise per unit. Others have pointed that the Board in its earlier ARR for 2004-05 had proposed enhancement in quantum of rebate and there is no reason for reducing the rebate now. According to them, high voltage rebate as decided by the Commission in its various Tariff Orders should at least be continued till the cost of supply is calculated category-wise and voltage-wise as this would definitely be less for EHT consumers. According to them, there is perhaps a case for enhancement of quantum of rebate as their cost for availing supply at high voltage is much higher as compared t! o the quantum of rebate.

    The present system is as follows:-

    1. Large Supply consumers and consumers of all other categories except Railway Traction supplied at 33KV/66KV are allowed rebate @ 3%. Large Supply consumers and consumers of other categories except Railway Traction, catered at 132KV/220KV are allowed rebate @ 5%. The rebate is admissible on consumption charges including demand charges, if any, or monthly minimum charges.

    2. For Large Supply consumers with contract demand exceeding 2500 KVA and upto 4000 KVA catered at 11 KV, surcharge @ 10% is leviable on consumption charges including demand charges, if any, or monthly minimum charges as compensation for transformation losses, incremental line losses etc. A surcharge of 17.5% is leviable on consumption charges including demand charges, if any, or monthly minimum charges on all Arc Furnace consumers and other Large Supply consumers having contract demand above 4000 KVA and catered at 11 KV.

    3. Medium Supply, Small Power, Domestic Supply and Non-Residential Supply consumers catered at 11 KV are allowed 7.5% rebate on their consumption charges including demand charges, if any, or monthly minimum charges. Also Large Supply consumers catered at LT i.e. 400 volts are levied 20% LT surcharge. Steel rolling mills supplied under LS category but connected at LT are levied steel rolling mill surcharge @ 5% in addition to LT surcharge @ 20%.

    The Commission observes that the Board in its ARR for 2004-05 had itself proposed higher rebate @ 6% for LS consumers getting supply at 33 KV or higher voltage. The Commission had approved high voltage rebate @ 5% for consumers getting supply at 132 KV/220 KV voltage level. Further, in case any Large Supply consumer is connected at voltage lower than 11 KV, he is liable to pay LT surcharge. The Commission observes that where supply is availed at a voltage higher than the base voltage level, the utility is benefited by way of saving of capital and operating costs besides reduction in losses. However, while calculating financial implications of voltage level rebate, only cost of T&D losses has been taken into account and not the cost of capital investment and operational & maintenance costs borne by the consumer. Thus the Board is applying different yardsticks for the methodology adopted by it to work out surcharge for supply at a lower voltage and allowing! rebate for higher voltage supply. Also, the Commission has only recently revised the rates for high voltage rebate and the impact thereof needs to be seen for sometime before considering any changes therein.

    In view of all above, the Commission considers it appropriate to continue with existing provisions for rebates and surcharges for availing supply at different voltages.

5.2.3    KVAH Tariff

    The Commission in its Tariff Order for 2005-06 had directed the Board to carry out a study on the practicability of introducing KVAH tariff for Large Supply, Medium Supply and Railway Traction consumers. The Board instead of carrying out such a study has given reasoning for not proposing introduction of KVAH tariff.

    The Board has opposed introduction of KVAH tariff while admitting at the same time, the importance of KVAH tariff and stating that poor power factor loads at the consumer premises are the source of most reactive power flows in the system. It has further been stated that owing to lack of commercial inducement, consumers are not installing capacitors of requisite capacity. However, according to the Board, KVAH Tariffs are not advisable since the commodity being sold is active energy (KWH) and not apparent energy which in fact is only a derivative. The Board has further stated that energy accounting and energy audit can be carried out only if measurement of KWH consumption is continued and in case KVAH tariff is introduced, it would not be possible to carry out energy audit. The Board has also taken the plea that KVAH drawal by the consumers for the same connected load will vary depending upon the voltage at consumer’s premises which is under the control of the Distrib! ution Licensee and not the consumer.

    A few Industrial Consumer Associations/consumers have stressed that the Board should introduce KVAH tariff instead of KWH tariff so that the consumers having low power factor and drawing more KVAH are penalized suitably. On the other hand, some consumers have supported the present system of levying power factor surcharge and rebate which is said to be working satisfactorily.

    Presently, KVAH tariff is not prevalent in the state. However, Large Supply, Medium Supply industrial consumers and Railway Traction consumers are subjected to levy of power factor surcharge and rebate which is determined on the basis of monthly average power factor which in turn is the ratio of monthly KWH consumption and monthly KVAH consumption. Low power factor surcharge is leviable for all the categories, if the monthly average power factor falls below 0.90. On the other hand, Power factor incentive is allowed if monthly average power factor exceeds 0.90 for LS (general industry) and MS consumers. For LS (PIUs & Arc Furnaces) consumers and Railway Traction, incentive is available if their monthly average power factor exceeds 0.95. The revised threshold limit of power factor and concept of incentive was recently introduced by the Commission in the Tariff Order for 2004-05 and was made effective from July 1, 2005.

    The Commission observes that some of the States such as Delhi, HP and UP have introduced KVAH tariff for one or more categories. The Commission also notes that for introducing KVAH tariff, the provision of reliable KVAH metering is very essential which has been provided by the Board on all Large Supply, Medium Supply and Railway Traction consumers. The Commission further notes that the purpose of introduction of KVAH tariff and low power factor surcharge/high power factor incentive are similar and the concept of allowing incentive for high power factor and new threshold limits for power factor have been made effective very recently from July 1, 2005. The Commission, therefore, considers it prudent to continue the existing position for some time before taking a view on the introduction of KVAH tariff. The Commission further feels that there is a need for carrying out a detailed study so that a holistic view could be taken. The study would need to focus on:

    1. Feasibility of introduction of KVAH tariff;

    2. Impact of introduction of KVAH tariff on the bills of different categories of consumers;

    3. Impact of such introduction on overall revenues of the Board;

    4. Proposed tariff structure for various categories;

    5. Present status of KVAH compatible meters on consumer premises and feasibility of installing such meters on all industrial and railway traction consumers;

    6. Impact of introduction of KVAH tariff in reduction of T&D losses;

    7. The position in this respect in other states;

    8. Feasibility of conducting energy accounting and audit with KVAH tariff.

    The Commission, therefore, decides to continue with the existing system of KWH based tariff and the prevailing practice of levying low power factor surcharge and allowing high power factor incentive for Large Supply, Medium Supply Industrial & Railway Traction consumers. The Commission further directs the Board to examine various issues related to introduction of KVAH tariff and submit its proposals alongwith the next ARR.

5.2.4    Bulk Supply Tariff

    Some consumer associations/consumers have submitted that Bulk Supply Tariff applicable to consumers having mixed load and undertaking distribution of energy to ultimate consumers at their level is very high and needs reduction. It has been brought out that consumers availing Bulk Supply Tariff receive power supply at one point, provide their own distribution system, bear all operation and maintenance costs besides T & D losses while distributing energy bills to residents and collecting payments. The consumer effects full payment for the entire energy received at single point to the Board. Thus, in such cases there is substantial saving to the Board on account of distribution/commercial losses and billing cost. It has been prayed that tariff rates for Bulk Supply category should be fixed in such a way that it is viable for consumers to take bulk supply connection without suffering financial loss on this account. This issue was also raised in the meet! ing of State Advisory Committee held on March 22, 2006.

    In its response the Board has stated that Bulk Supply category is a subsidizing category and the first slab of Domestic Supply category is highly subsidized. As such it is not feasible to reduce the tariff of Bulk Supply category since this would mean putting additional burden on other categories.

    Presently Bulk Supply is available to Hospitals, Railways, CPWD, Departmental Colonies and other similar establishments having general or mixed load where further distribution is done by the institution concerned. The consumers of this category receive supply at one point at the entry of their premises and further distribution is done by them. The major load of these consumers falls under Domestic and NRS categories with a small fraction being of Industrial nature. There is no data available regarding mix of load of various Bulk Supply consumers. The mix of load would depend upon nature of the establishment and would vary from consumer to consumer. The present rate of tariff for Bulk Supply consumers is substantially higher than Domestic Supply but less than NRS rates.

    The Commission observes that there may be saving to the Board/licensee in case of Bulk Supply category as they bear interest, depreciation, operation and maintenance expenses of the distribution system besides billing cost. The commercial losses, if any, in such cases are also borne by the Bulk Supply consumer. The Commission, however, notes that adequate data regarding energy consumption mix of various Bulk Supply consumers is not available to enable calibration of tariff at a suitable level for the category as a whole.

    The Commission, therefore, directs the Board to carry out an assessment of consumption of electricity for domestic, industrial, commercial and street lighting purposes separately which may cover all the bulk supply consumers or may take a representative sample to achieve satisfactory overall results. A report in this regard may be submitted by end of September, 2006.

5.2.5    Parallel Operation Charges

    The issue of recovery of parallel operation charges was considered by the Commission during the processing of ARR for 2005-06 and a decision was taken to continue parallel operation charges to all captive power plants which are run in parallel with the grid of the Board irrespective of whether captive plant owners are consumers of the Board or not. In the meanwhile, the Board was asked to carry out a study to assess the quantum of charges.

    However, no study has been undertaken by the Board. The Commission also notes that generation plants set up/ to be set up for sale of entire power to the Board are/ shall not be required to pay any parallel operation charges.

    The Commission decides that where captive plant feeds captive load while also supplying surplus power to the Board, parallel operation charges shall be leviable proportionately on the total capacity available for feeding the captive load worked out by deducting capacity earmarked for sale of power to the licensee from the total capacity of the captive plant.

5.2.6    Tariff for Dairy Farming

    A Dairy Farmers Association has objected to the present system of the Board for charging commercial/industrial rates for supply of electricity to the dairy farms. It has been brought out that dairy farming is an integral part of agricultural milk production from milch animals by feeding fodder and feed (which primarily consists of grains). It has also been stated that a commercial dairy farm has chaff cutters, small bore tubewell with pump for water, animal cooling units, milking machine and milk chilling units etc. and all these equipments consume about 6/8 HP electricity. It has also been stated that besides individual farmers having milch animals at their places/farm houses, some dairy farmers set up a dairy farm of bigger scale say 20/25 animals or more in a premises away from their houses as an independent dairy farm unit by obtaining a separate electricity connection. These dairy farms would generate employment/additional employment opportunit! ies for the unemployed youth of the State besides helping diversification of crops, as such, dairy farms should be supplied electricity at the rate of 62 paise per unit applicable for AP category.

    The Board in its response has stated that tariff for AP supply is lower than the average cost of supply and this category is cross subsidized by other categories. Subsidized tariff is applicable to consumers engaged in farming activities involving cultivation of land. It has further been stated that dairy farming is a distinct business activity carried on in a organized manner with an objective of making profit by selling milk and other milk products. This does not involve cultivation of land and as such could not be treated at par with agricultural farming. It has further been stated that there are a number of other business activities which get their input raw material from the agricultural sector such as sugar, rubber etc. and all these industries would claim AP tariff on the same logic.

    Dairy Farming is presently being charged relevant industrial/NRS tariff depending upon the nature and category of load. The Commission observes that even though there is a need for diversification in agriculture and promotion of Dairy Farming may be a step in the right direction, yet a separate more beneficial dispensation cannot be thought of for this sector alone. There are, the Commission notes, other similar activities such as Poultry Farming which are also being charged industrial category tariff. Moreover, promotion of diversification in agriculture need not only be through lower energy tariffs as Government usually encourages such activities through a variety of other measures which might prove equally if not more effective.

    The Commission, therefore, decides that Dairy Farming may continue to be covered under the relevant industrial tariff as heretofore.

5.2.7    Receivables

    The position of the Board’s receivables for the last 7 years is as under:
    YearReceivables at the end of the yearTotal revenue of the Board excluding non-tariff income & Govt. subsidyReceivables in equivalent number of days revenueReceivables as percentage of revenue
    1998-9941433964412.2
    1999-0044636544512.2
    2000-013994302349.3
    2001-0249145853910.7
    2002-0357253413910.7
    2003-045986112369.8
    2004-0562760633810.34

    The Commission had in the Tariff Order for the year 2005-06 observed that collection efficiency of the Board was nearly 99% and that receivables had remained at less than 40 days revenue for the last 5 years. However, an area of concern was its dues from the Govt. departments. The Commission had, accordingly, directed the Board to take this up at appropriate level. The Commission had also sought age-wise analysis of receivables along with the next ARR. The Board has now furnished age-wise data on outstanding amounts wherein the arrear position in the case of Govt. departments, court cases, DSC cases, PDCO cases and others has been separately depicted. Details of Receivables as on end September 2005 is reproduced below:
    Sr. No.ParticularsUp to 1 year old1 to 2 years old2 to 3 years oldMore than 3 years oldTotal
    1.Pb. Govt. Departments35.1928.4522.2926.47112.40
    2.Court/DSC cases43.9217.5223.5157.62142.57
    3.PDCO cases31.8216.4414.0331.4893.77
    4.Others96.9911.913.652.90115.45
    5.Total207.9274.3263.48118.47464.19


    In the ARR for 2006-07, the Board has stated that the question of clearing electricity bills by the Govt. departments was taken up with the State Govt. by the Chairman for the issue of suitable instructions to Govt. departments and organizations to liquidate these outstanding bills. Moreover, recovery was being monitored on monthly basis by the Board’s field officers also.

    The Commission observes that over 55% of the outstanding amount is more than one year old and special efforts need to be made for recovery of old arrears. The State Government needs also to be impressed upon to provide adequate contingency in the budgets of departments in arrears, which will not only cater to the requirement of current electricity bills but ensure liquidation of outstandings as well. The Commission also notes that the largest single item of arrears are amounts involved in court or DSC cases. These two categories need to be shown separately and high priority accorded to an early decision and recovery of amounts pending in the DSCs.

5.2.8    General Provident Fund

    The Commission, in the Tariff Order for the year 2005-06, had decided that the Board should take steps to open a separate General Provident Fund Account and all new accretions should be deposited in this fund. In case any money was required by the Board to be utilized for funding capital investment plan, the Board might take interest bearing loan from the General Provident Fund Account.

    In compliance of the above directive, the Board in its letter dated March 28, 2006 has stated that in case of a separate General Provident Fund Account, the total interest to be earned on the G.P. Fund investment would be less than the amount of interest payable to the subscribers. It has further requested the Commission to agree in principle to pass on the difference in interest to the consumers through ARR.

    The Commission observes that interest on GP Fund is already being allowed by the Commission in the ARR as a legitimate expense. It expects an expeditious compliance of the directive of the Commission by the Board.

5.2.9    Power Cuts/Other Power Regulatory Measures

    Petition No.5 of 2006 filed by PSEB under Section 23 of the Electricity Act, 2003 seeking authorization for imposing power cuts and undertaking other power regulatory measures has been disposed of by a separate order.

5.3    TARIFF STRUCTURE

    5.3.1    In view of the foregoing discussions, the Commission approves the tariff for different categories of consumers as given in Table 5.7.

    TABLE – 5.7
    TARIFF STRUCTURE
    EXISTING TARIFF, TARIFF AS PROPOSED BY PSEB
    AND TARIFF AS APPROVED BY THE COMMISSION
    FOR 2006-07 APPLICABLE W.E.F. APRIL 01, 2006
Sl. No.Category of consumersExisting TariffProposed tariff by PSEBTariff approved by the Commission
Energy Rate P/KWHMMC Rs./ KW or part thereofFixed charges Rs. per KVAEnergy charges P / KWHMMC Rs./ KW or part thereofEnergy Rate P/KWHMMC Rs./ KW or part thereof
A) PERMANENT SUPPLY
  1) Domestic supply       
 a) Upto 100 units2213002603522130
 b) 101 to 300 units368043335368
 c) Above 300 units389045835389
 2) Non-Residential4231090For supply ‹= 11 KV 498
For supply › 11 KV 498
128


128
423109
 3) Public lighting423As per 8 hrs/ day0498As per 8 hrs/day423As per 8 hrs/ Day
 4) Irrigation tubewellsi) Without Govt. subsidy 214 Ps / kwh or Rs. 208/ BHP / Month

ii) With Govt. subsidy * 57 Ps / kwh or Rs. 60 / BHP / Month
N.A.i) Without Govt. subsidy



ii) With Govt. subsidy
252 Ps/kwh or Rs.245/BHP/ Month


0
i) Without Govt. subsidy 214 Ps / kwh or Rs. 208/ BHP / Month

ii) With Govt. subsidy     0
N.A.
 5) Industrial supply       
 a) Small power33789039610533789
 b) Medium supply3721190438140372119
 c) Large supply       
 i) General industry372119145/ KVA3720372119
 ii) PIU372328145/ KVA3720372328
 iii) Arc Furnace372312145/ KVA3720372312
 6) Bulk supply       
 HT

LT
382

406

Avg. 394
179 / KVA

179 / KW
0

0
449

478
211/ KVA

211/ KW
382

406

Avv. 394
179/KVA

179/KW
 7) Railway traction443179 / KVA180 per KVA3850443179/KVA
 8) Outside state248N.A.   248N.A.
B) SEASONAL INDUSTRY : COTTON GINNING, PRESSING AND BAILING PLANT, RICE SHELLERS / HULLER MILLS, RICE BRAN STABILIZATION UNITS (WITHOUT T.G. SETS) (SP, MS, LS)
 a) During season
( 1st Sep to 31st May)
next year
SP
MS
LS
337
372
372
328
328
328
0
0
145
396
438
372
386
386
0
From Sept 1 to end Feb. next year
337
372
372
178
238
238
 b) Off season

SP
MS
LS
400
431
428
N.A.
N.A.
N.A.
0
0
145
471
507
372
0
0
0
From March 1 to Aug. 31
337
372
372
45
60
60
C) ICE FACTORY & ICE CANDIES AND COLD STORAGE
 a) Season (April to July)

SP
MS
LS
337
372
372
447
(April to July)
0
0
145
396
438
372
526
526
0
337
372
372
447
(April to July
 b) Off Season

SP
MS
LS
- do -89
89
89
0
0
145
396
438
372
105
105
0
337
372
372
89
89
89
D) GOLDEN TEMPLE, AMRITSAR AND DURGIANA TEMPLE, AMRITSAR
 Golden Temple, Amritsar       
 a) First 2000 unitsFreeN.A. 00FreeN.A.
 b) Beyond 2000 units301N.A. 0354301N.A.
 Durgiana Temple, Amritsar       
 a) First 2000 unitsAs per pattern applicable for Golden Temple, AmritsarAs per pattern applicable for Golden TempleAs per pattern applicable for Golden Temple, Amritsar
 b) Beyond 2000 units
E) TEMPORARY SUPPLY
 i) Domestic663Rs. 551 or Rs. 110 / KW whichever is higherProposed to increase the existing tariff by 15% for all categories663Rs.551 or Rs.110/KW whichever is higher
 ii) NRS663Rs. 1102 or Rs. 276 / KW whichever is higher663Rs.1102 or Rs.276/KW whichever is higher
 iii) Industrial
(SP, MS & LS)
As per tariff approved at A(5) above for permanent supply + 100%Rs. 441 / KW of sanctioned loadAs per tariff approved at A(5) above for permanent supply + 100%Rs.441/KW of sanctioned load
 iv) wheat thrasher-do--do--do--do-
 v) Fairs, exhibition & melas CongregationsBulk supply tariff as at A(6) + 50%Rs. 4411 per serviceBulk supply tariff as at A(6) + 50%Rs.4411 per service
 vi) Touring Cinemas

a) Lights and fans
b) Motive load


663
Rate for Industrial permanent supply as at A(5) + 100%
For (a) and (b) Rs. 1102 or Rs. 276/KW of sanctioned load whichever is higher

663
Rate for Industrial permanent supply as at A(5) + 100%
For (a) and (b) Rs. 1102 or Rs. 276/KW of sanctioned load whichever is higher

* with effect from September 1, 2005, the supply to Irrigation tubewells has been made free.

NOTES
  1. Domestic consumers belonging to SC category with connected load upto 500 watts will be given 200 units of free power per month in view of Govt. subsidy;

  2. AP consumers will not be charged service charges and meter rentals in view of Govt. subsidy;

  3. DS and NRS consumers shall continue to be charged MMC on the basis of actual sanctioned load and no rounding off should be carried out for computing the MMC;

  4. Meter rentals, recoverable costs of meter/metering equipment damaged due to fault/negligence of consumer and rates of security deposit for meter/metering equipment shall be as per revised rates approved separately. All other charges including rentals and deposits which are being collected by the Board as per the “Sales Regulations for Supply of Energy to Consumers”, will be continued at the existing rates;

  5. Classification and billing procedure of seasonal industries shall be as per revised General Conditions of Tariff approved separately;

  6. Checking of load of DS consumers shall continue to be suspended.



5.3.2    Date of Effect

    The Commission notes that the ARR of the Board for the year 2006-07 covers the complete financial year. The recoveries of tariff, therefore, have to be such that total revenue requirement of the Board for the year 2006-07 is recovered during the current financial year. Hence the Tariff Order is required to be made effective from April 1, 2006 to ensure full recovery of the ARR of the Board in this year itself. Further, the Commission notes that there is no change in tariff for all categories of consumers. Therefore, there can be no cause of grievance either for the consumers or for the Board on account of making the Tariff Order applicable from the retrospective date of April 1, 2006.

    The Commission, therefore, decides to make the revised tariff applicable from April 1, 2006.

    This order is signed and issued by the Punjab State Electricity Regulatory Commission on this the 10th day of May, 2006.

    DATE : MAY 10, 2006
    PLACE : CHANDIGARH

    sd/-sd/- sd/-
    (S.S. PALL)(BALJIT BAINS)(JAI SINGH GILL)
    MEMBERMEMBERCHAIRMAN


    CERTIFIED

    sd/-

    AJANTA DAYALAN
    SECRETARY
    PUNJAB STATE ELECTRICITY REGULATORY COMMISSION
    CHANDIGARH



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