ARR for distribution business

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ARR and Tariff Petition

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Contents

1 Introduction to ARR and Tariff Petition............................................31.1 Filing based on Multi-Year Tariff (MYT) Principles for Second Control

Period.........................................................................................................3

2 Resource Plan for Distribution business for Control Period..............72.1 Sales Forecast for the Control Period.................................................................72.2 Power Procurement Cost for Current Year Second Half and Ensuing Year....14

Capacity break-up of major generating sources ...................................................15Power purchase tariffs ..........................................................................................24ENERGY REQUIREMENT ................................................................................34SUMMARY OF POWER PURCHASE FOR YEAR 2008-09 AND ENSUING

YEAR 2009-10........................................................................................342.3 Capital Investment Plan...................................................................................352.3.1 Base Capital Expenditure.............................................................................35

2.4 Capex Financial Summary...............................................................................51

3 Analysis of Performance for Previous 3 Year and CorrectionsRequired..................................................................................53

3.1 Introduction......................................................................................................533.2 Operating Performance....................................................................................533.3 Financial Performance.....................................................................................533.4 True-up required...............................................................................................54

4 ARR for Distribution business for the Control Period.....................574.1 Basis for O&M Cost Projections......................................................................574.2 Background .....................................................................................................574.3 Need for Review of the O & M Expenses Projection Methodology followed in

the first control period..............................................................................58

4.4 Proposed Methodology for Projection of O & M Expenses............................594.5 Regulated Rate Base (RRB).............................................................................614.6 Depreciation and Advance Against Depreciation (AAD)................................624.7 Return on Capital Employed. ..........................................................................634.8 Other Expenditures...........................................................................................654.9 Tax on Income:................................................................................................654.10 Special Appropriations: .................................................................................654.11 Wheeling Revenue: .......................................................................................674.12 Non-Tariff Income: .......................................................................................67

5 Revenue Requirement for Retail Supply Business..........................68

5.1 Losses...............................................................................................................68

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5.2 Expenditure Projections...................................................................................695.3 Revenue Projections.........................................................................................715.4 Revenue Gap....................................................................................................76

6 Filing of Proposed Tariffs (FPT) for Distribution business forControl Period.........................................................................77

7 Filing of Proposed Tariffs for Retail Supply business for EnsuingFY 2009-10.............................................................................83

Tariff Schedule...................................................................................85

8 Performance Parameters...................................................................92

1 Introduction .....................................................................................95

2 COST OF SERVICE MODEL FOR APNPDCL.............................96

3 Results............................................................................................104

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Sales Forecast for the Control Period

Distribution Plan (Capital Investment Plan) for the Control Period

Power Procurement Plan for the ensuing half year of FY 2008-09 and FY 2009-10

1.1.1 Segregation of Distribution and Retail Supply businesses

Clause 5 of the Regulation specifies that Till such time as there is a complete segregation of

accounts between Distribution and Retail Supply businesses, the ARR for each business shall be

supported by an Allocation Statement that contains the apportionment of costs and revenues to that

business. The allocation statement shall also contain the methodology that has been used for the

apportionment.

As the Honble Commission has rightly assessed, the present accounts of licensee is at a consolidated

level and the licensee does not have segregated accounts for each of the businesses. However, in line

with the Regulation, the licensee has endeavored to analyze the expenses and incomes attributable to

each business and has followed the following principles of allocating expenses and incomes to the

retail supply business while the rest of the expenses and revenues are allocated to the distribution

business:

Before determining the segregation of costs and revenues for each of the businesses, it is important to

first identify the functions under each of these businesses. These are as follows:

Functions pertaining to Distribution (or Wires) Business

The functions pertaining to Distribution business include:

Management and maintenance of distribution network including substations, lines, transformers

and other network equipment

Capital expenditure on distribution network for network expansion as well as loss reduction

Providing new connections to the distribution network

Meter reading and billing

Financial accounting and management functions pertaining to the distribution business

The functions pertaining to the Retail Supply business include:

Procurement of power from generators

Sale of power to Discoms own consumers

Contracting for transmission and SLDC services

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Based on the above definitions of functions pertaining to each business, the allocation of expenditures

and revenues to the Retail Supply business is as explained in the table below:

Allocation of expenses and income to Retail Supply Business

Income: Expenditure:Revenue from Sale of Power (except wheeling revenue) Power Purchase

Other Income Other Financial Charges

Delayed Payment Charges HT-incentive

ABT related UI Charges / Pool Trade Interest on security deposits

Miscellaneous Charges from Consumers

Recoveries for Theft of Power/Malpractice

Revenue from Inter-State sales (D-trade)

Securitization Scheme Benefits and Rebates

1.1.2 Filing Contents

Filing Contents

The filing is structured in the following way:

Section 2 provides the Resource Plan comprising

- Sales Forecast;

- Power Procurement Plan; and

- Distribution Plan (Capital Investment Plan)

The sales forecast is used to determine the revenue from tariff from retail sale of electricity for the first

year of the control period and the energy input required for meeting the demand. The power

procurement plan is based on the availability of the generation sources during the ensuing year, the

cost (fixed, variable and others) and the merit order dispatch of various sources to meet the demand

expected during various months. The distribution/ investment plan is prepared keeping in view of the

potential to meet the load growth, plans to improve quality of supply and the distribution loss

trajectory that the utilities expect to be achieved during the Control Period.

Section 3 provides a brief analysis of the financial and operational performance of the licensee during

the 2005-06 to 2007-08. Section 3 also provides an analysis on the variations in uncontrollable items

of ARR during the last 3 years followed by the true-up for the same period.

Section 4 provides the ARR for distribution business for each of the year of the Control Period and the

basis of projections of the expense and revenue items.

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Section 5 provides the ARR for the retail supply business for the ensuing year and the combined ARR

for the ensuing year (first year of the Control Period, 2009-10).

Section 6 contains the tariff proposals for distribution business for the ensuing year 2009-10 and

Section 7 contains tariff proposals for retail supply business for the ensuing year 2009-10. Section 8

provides the performance of the licensee on various technical and consumer service related issues

during the previous year and plans for improving the same in the ensuing year.

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2 Resource Plan for Distribution business for Control Period

2.1 Sales Forecast for the Control Period

The licensee has adopted the end-user method and trend methods for forecasting the sales of various

categories. In respect of HT-I and HT-IV category services, end-user method has been adopted and for

rest of the categories, trend method has been adopted.

2.1.1 Trend Method

This method is a non-causal model of demand forecasting which assumes to follow the same trend as

in the past and hence the forecast for electricity is also based on the assumption that the past trend in

consumption of electricity will continue in the future.

Sales forecast for basic categories except agriculture was made for the years 2009-10 to 2013-14 by

considering the following data:

Base Sales Data: category-wise sales for FY 2005-06 to FY 2007-08 and First Half (H1) of FY

2008-09.

Growth rates: Compounded Annual Growth Rate (CAGR) for 3 years (2005-06 to 2007-08)

HT-I Industrial:

This category predominantly comprises two types of industries, Singareni Collieries and Cement

Industry, drawing about 45% and 25% of total HT-I sales.

In respect of Singareni Collieries, consequent on changing their strategies by closing some of its

underground mines, new mines have been started based on opencast. As per historical data, there has

been a downward trend in the consumption due to fewer loads required for opencast mining. In

addition to the above, they have adopted adopting energy conservation measures, which resulted in

reduction in energy consumption. In the last 3 years, sales recorded negative growth rates of -5%,

-1% and -5% and 3 years CAGR -4%. Therefore -4% negative growth is expected for Singareni

services for current year and 2nd control period from 2009-10 to 2013-14.

A significant growth in production in the Cement industry has been witnessed due to increased

consumption of cement by the various State Govt. programs such as Irrigation projects, providing

houses under Indiramma program. The yearly growth rates of power consumption for the past three

years in major cement industries were found to be of 5%, 7% and 11% and followed by 6% in the first

half of the current year 2008-09. It is expected that similar trend will continue for second half of the

current year. Hence growth in this industry is expected to be 8% in current year and 2nd control period

2009-10 to 2013-14.

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Apart from Singareni and Cement industries, the growth in sales under HT-I category is recorded by

35% in year 2007-08. In this growth rate, 2 Nos HT consumers i.e. Sirpur Paper Mill and A.P

RAYONS LTD contribute 24%. The Sirpur Paper Mill has contributed by increasing of their

contracted load by 5 MVA in 2nd half of the year 2007-08. The A.P. Rayons Ltd. is having a third

party supply, in this connection whatever additional consumption recorded in 2007-08 may not be

expected in next control period. Considering all above factors and releasing of new services, growth

rate is expected to be 25% in 2008-09 and 15% for 2nd control period 2009-10 to 2013-14 for the

services other than Singareni and Cement industries under HT-I Category.

(In MU)

HT-I 2007-08 2008-09 2009-10 2010-11 2011-12 2012-13 2013-14

Voltage Actuals Projections

132kV 653.07 716.38 734.29 743.54 755.07 766.77 782.95

33kV 74.95 74.74 73.60 75.15 74.23 73.31 72.64

11kV 177.05 222.00 255.03 292.71 337.14 388.32 452.77

Total 905.07 1,013.11 1,062.92 1,111.40 1,166.43 1,228.40 1,308.36

HT-II Non-Industrial:

In this category, there are 3 services in 33KV and above voltage level having captive generation as

main source, which consume only about 3 MU per annum. Balance services existing in 11KV voltage

have shown an average growth of 7% in the last three years as the new services released in HT-II were

in 11 KV only.

Due to the release of new services, the consumption in 11KV is expected to grow by 10.46% for the

control period 2009-14. Accordingly, the growth rate 10.34% is expected on total sales for the ensuing

control period 2009-14 after considering releasing of new services.

(in MU)

HT-II 2007-08 2008-09 2009-10 2010-11 2011-12 2012-132013-

14


132kV&above 1.89 0.72 0.72 0.72 0.72 0.72 0.72

33kV 0.81 0.94 1.02 1.11 1.22 1.33 1.46

11kV 55.70 65.22 71.61 79.30 87.74 97.08 107.26

Total 58.40 66.88 73.36 81.14 89.69 99.14 109.45

HT-IV Irrigation:

As a part of Jalayagnam program, the state government has proposed various lift irrigation schemes,

which will be operational in the area of licensee as stated below.

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During the fiscal year 2009-10, Devadula phase-II and Sripadasagar Yellampally LI schemes are

expected to be operational. Also Devadula phase-III and Pranahitha Chevella LI schemes are expected

to be operational during the fiscal years 2011-12 and 2012-13 respectively.

Load in MW

Voltage 2009-10 2010-11 2011-12 2012-13 2013-14

132 KV andabove

Devadula phase-II101.30

Devadula phase-III 226.13Pranhitha Chevella

212.50

33KV Devadula phase-II 7.00 Devadula phase-III 32.66Pranhitha Chevella

1.95

11KV

Total 108.30 - 258.79 214.45 -

Accordingly, the estimated consumption for the next control period on account of existing LI schemes

and ensuing LI schemes that are expected to be operational is as follows.

(in MU)

HT-IV 2007-08 2008-09 2009-10 2010-11 2011-12 2012-13 2013-14

Voltage Actuals Projections132kV&above 42.01 373.52 720.72 720.72 1371.97 1983.97 1983.97

33kV 5.20 78.78 219.45 219.45 313.52 319.14 319.14

11kV 49.50 76.45 112.71 112.73 112.75 112.77 112.80

Total 96.71 528.75 1,052.88 1,052.90 1,798.25 2,415.88 2,415.90

HT-V Traction:

Though Railway Traction has shown a growth rate in consumption by 8.28% during 2007-08 and it is

expected that the consumption in this category increase by 8.34% during the current fiscal year 2008-

09. The CAGR 2.5% of past 4 years is considered for the ensuing control period 2009-14 and the

projected sales in this category are as follows.

(in MU)

HT-V 2007-08 2008-09 2009-10 2010-11 2011-12 2012-13 2013-14


132kV&above 333.01 360.77 370.51 380.14 389.27 398.61 408.25

33kV - - - - - - -

11kV - - - - - - -

Total 333.01 360.77 370.51 380.14 389.27 398.61 408.25

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HT-VI Colony Lighting:

The consumption in this category has witnessed a negative growth rate of -11.5 % during the FY

2007-08 due to transfer of 3500 services from HT-VI to LT-I at Mandamarry. Hence no increase in

consumption is expected in this category during the current fiscal year 2008-09. Previously this

category was limited to link services i.e. the HT consumers under HT-I to HT-V can take serviceconnection under HT-VI for colony and township purpose. From the FY 2008-09 onwards, this

category is also applicable to Co-operative group housing societies or any person availing supply for

supply to his employees for domestic purpose also. With this change, 5 new services are expected each

year and a growth rate of 1.56% is expected for the ensuing control period 2009-14.

(in MU)

HT-VI 2007-08 2008-09 2009-10 2010-11 2011-12 2012-13 2013-14


132kV&above 70.40 64.99 64.99 64.99 64.99 64.99 64.99

33kV 42.62 46.28 48.09 49.58 51.17 52.80 54.60

11kV 9.86 11.61 12.18 12.43 12.67 12.93 13.19

Total 122.88 122.88 125.26 126.99 128.83 130.72 132.77

HT-VII RESCO:

The consumption in this category has increased by 18.64% and 9.6% during the FY2006-07 and

FY2007-08 respectively. The consumption in this category is expected to increase by 7.87% during

the current fiscal year 2008-09.

For the next control period 2009-14, an average growth rate 8.36% is adopted for estimating

consumption in this category as this category has a bulk consumer in turn supplying to various LT

category loads.

(in MU)

Resco 2007-08 2008-09 2009-10 2010-11 2011-12 2012-13 2013-14


132kV&above - - - - - - -

33kV - - - - - - -

11kV 428.07 461.76 500.55 544.60 588.71 636.39 689.85

Total 428.07 461.76 500.55 544.60 588.71 636.39 689.85

LT-I Domestic:

The Domestic category sales growth is driven by the following factors.

1. Release of new service connections

2. Increase in specific consumption due to addition of domestic appliances like air conditioners,

water heaters etc.

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For the past 5 years the growth rate in this category has been increasing.

Due to the aforesaid reasons, sales in this category have increased in the first half of FY2008-09 by

12.53%. Hence, the licensee estimates an overall growth rate of 11.87% during current FY 2008-09.

In anticipation of sufficient availability of power, the growth rate is expected to be 10.36% during the

ensuing control period of FY2009-14.

(in MU)

ConsumerCategory

2007-08 2008-09 2009-10 2010-11 2011-12 2012-13 2013-14

Acuals Estimate Projection

Domestic supply -Cat-I

1,346.46 1,506.34 1,661.49 1824.32 2014.05 2223.51 2465.87

LT-II Non Domestic:

In the previous FY 2007-08, the growth rate in sales of LT II category was 12.4% and expected to be

9.77% during the current FY 2008-09.

However considering the 5 years CAGR in this category, the sales for ensuing control period isexpected to increase by 10.32% as stated below.

(in MU)

ConsumerCategory

2007-08 2008-09 2009-10 2010-11 2011-12 2012-13 2013-14


Non-Domestic

supply Category-II

274.1

4 300.92 329.21 364.43 402.70 444.98 491.70

LT-III Industrial:

In the previous FY 2007-08 the growth rate in sales was confined to 6% compared to its preceding

fiscal years i.e.FY2006-07 growth rate 18%. As the sales in this category has witnessed a negative

growth rate of 10.89% during the first half of current FY2008-09 the sales of total FY2008-09 is

expected to decrease by 0.72%. However considering CAGR of last 2 years, the sales in this category

are expected to increase by 10.49 % during ensuing control period 2009-14 as shown below.

(in MU)

ConsumerCategory

2007-08 2008-09 2009-10 2010-11 2011-12 2012-13 2013-14


Industrial supply -Category - III

294.24 292.13 323.68 356.82 393.22 433.33 480.99

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LT-IV Cottage Industries:

In the last FY 2007-08 the growth rate in sales of this category was 7.16% and for FY 2008-09, it is

expected to be 7.77 %. The licensee expects an average growth rate of 9.46% for the ensuing control

period 2009-14.The details of estimated consumption are as follows.(in MU)

ConsumerCategory

2007-08 2008-09 2009-10 2010-11 2011-12 2012-13 2013-14


Cottage Industries- Category - IV

5.30 5.71 6.36 6.94 7.55 8.21 8.98

LT-V Agriculture:

The livelihood of greater part of population in APNPDCLs jurisdiction is earned throughagriculture. However, the farmers are largely dependent on lifting ground water for irrigation

needs due to lack of sufficient water through other sources. As a result, agriculture category

consumers contribute to the majority i.e., more than 45% of sales of NPDCL. Fixing the

meters on LV side of selected DTRs does the computation of electrical energy consumption

of these un-metered agricultural services. This methodology of computing the consumption is

adopted in accordance with the directives of Honble Commission.

The state is consistently experiencing a reasonably good rainfall during the last few years.

Adequate rainfall over the past few years resulted in increase of ground water levels in theState including NPDCL area. The Honble Commission is continually adopting the

consumption of 2909.06 MU in the Tariff Orders from the FY 2005-06 up to 2008-09.

However, the actual consumption is increasing every year mainly due to release of additional

services and increased specific consumption of agricultural services. Therefore there is a need

for revision of the consumption allowed in the Tariff Orders during the previous years from

the FY 2005-06 up to 2008-09 based on actual consumption.

In concordance with the situation explained above there is a significant increase in agriculture

consumption during the year 2007-08 at 3622.14 MU as against 2909.06 MU approved by theHonble commission in the Tariff Order 2007-08. The consumption for the first half of the FY

07-08 is 1542.50MU and the consumption for the second half of the FY 07-08 is 2079.64

MU. Similarly, the consumption during the first half of 2008-09 is 1561.9 MU. The increased

consumption during the first half of 2008-09 compared to the H1 of 2007-08 is due to release

of 29648 new agricultural services in APNPDCL. Conventionally, due to ensuing Khariff

season the agricultural consumption during the second half of is much higher than the first

half. Further, the annual target for release of agriculture services has increased to 43400 for

CY 08-09. Based on the above it is estimated that the agricultural consumption during the

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second half of CY2008-09 at 2237.69 MU. Therefore, the total consumption for CY 2008-09

is estimated to be at 3799.59 MU. It is projected that a total of 43400 services are to be

released during the EY2009-10. Keeping in view of the experience of current year and

previous years and duly considering all the factors as explained above it is anticipated that the

same trend will continue in the agricultural sector for the ensuing FY 2009-10. Accordingly,

3959.18 MU sales are projected for FY 2009-10.

However considering CAGR of last 5 years, the sales in this category are expected to

increase by 4.0 % during ensuing control period 2009-14 also as shown below.

LT-V

Agriculture

2007-08 2007-082008-09

H1

2008-09

H22008-09 2009-10

ActualsTariff

OrderActuals Estimation

Revised

EstimationProjections

Sales(MU)3622.1

42,909.06 1561.9 2237.69 3799.59 3959.18

LT-V

Agriculture2010-11 2011-12 2012-13 2013-14

Sales (MU) 4121.50 4321.81 4531.86 4732.60

LT-VI Public Lighting & PWS Schemes:

In the previous FY 2007-08 the growth rate in sales was 3.88%. Since the consumption in the first half

of current fiscal year 2008-09 has increased by 16.24%, the overall growth rate for FY 2008-09 is

expected to be 13.54%. Accordingly, the sales in this category are expected to increase by 8.64% for

the ensuing control period 2009-14.

(in MU)

ConsumerCategory

2007-08 2008-09 2009-10 2010-11 2011-12 2012-13 2013-14


Public Lighting -Category - VI

241.20 273.87 304.54 330.04 355.79 383.54 414.61

LT-VII General Purpose:

In the previous FY 2007-08 the growth rate in sales was 20.37%, which is expected to be 18.09% for

the current FY 2008-09.It is also expected that the sales in this category be expected to increase by

11.98% for the ensuing control period 2009-14. The details are as follows.

(in MU)

ConsumerCategory

2007-08 2008-09 2009-10 2010-11 2011-12 2012-13 2013-14


General Purpose - 20.2 23.95 26.72 29.87 33.47 37.49 42.17

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Category - VII 8

Category wise Abstract of sales for current fiscal year and ensuing control period is given below:

Consumer Category 2008-09 2009-10 2010-11 2011-12 2012-13 2013-14

Estimate Projection

L T Domestic supply - Cat-I 1,506.34 1,661.49 1824.32 2014.05 2223.51 2465.87

Non-Domestic supply Category-II 300.92 329.21 364.43 402.70 444.98 491.70

Industrial supply - Category - III 292.13 323.68 356.82 393.22 433.33 480.99

Cottage Industries - Category - IV 5.71 6.36 6.94 7.55 8.21 8.98

Irrigation & Agriculture Category - V 3,799.59 3,959.18 4121.50 4321.81 4531.86 4732.60

Public Lighting - Category - VI 273.87 304.54 330.04 355.79 383.54 414.61

General Purpose - Category - VII 23.95 26.72 29.87 33.47 37.49 42.17

Temporary - Category - VIII 0.20 0.20 0.20 0.20 0.20 0.20

Total L.T. 6,202.71 6,611.38 7,034.13 7,528.78 8,063.11 8,637.12

H T

Industrial segegrated - Category - I 1,013.11 1,062.92 1111.40 1166.43 1228.40 1308.36

Industrial Non-segegrated - Category - II 66.88 73.36 81.14 89.69 99.14 109.45Irrigation & Agriculture - Category - IV 528.75 1,052.88 1052.90 1798.25 2415.88 2415.90

Railway Traction 360.77 370.51 380.14 389.27 398.61 408.25

Townships & Residential colones - Cat-VI 122.88 125.26 126.99 128.83 130.72 132.77

Electricity Co-operative societies - Cat.VII 461.76 500.55 544.60 588.71 636.39 689.85

Temporary - Category - VIII - - - - - -

HT TOTAL : 2,554.16 3,185.47 3,297.17 4,161.17 4,909.14 5,064.58

LT+HT TOTAL 8,756.87 9,796.85 10,331.31 11,689.94 12,972.26 13,701.70

2.2 Power Procurement Cost for Current Year Second Half and

Ensuing Year

Basis of estimating the quantity and cost of Power Purchased

This section discusses the methodology and assumptions used for estimating the quantum and

corresponding cost of power purchase of the Licensee for the second half of the financial year ending

March 31, 2009 and for the financial year ending March 31, 2010.

With the implementation of Multi-Buyer Model (MBM) in the state from June 9, 2005, each DISCOM

has been allocated a certain share of the generating stations contracted by APTransco. Non-

conventional Energy sources have been allocated to the DISCOMs based on their locations while the

two mini-power plants LVS and Sri Vathsasa have been allocated to EPDCL. The allocation

percentages for the different DISCOMs are as follows:

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S.No. Name of the Distribution

Company

Allocation Percentage

1 EPDCL 15.8 %

2 SPDCL 22.27 %

3 CPDCL 46.06 %

4 NPDCL 15.87 %

In the following paragraphs the capacities and availabilities of all the generating sources have been

described. The actual energy availability in MU for each DISCOM is simply the total generation

availability for each source (except NCEs and the mini-power plants) multiplied by the percentage

allocation as per MBM. The energy availability of NCEs for each DISCOM has been shown

separately.

Capacity break-up of major generating sources

APGENCO

The table below shows the installed capacities of the Thermal and Hydel generating stations of

APGENCO as on 30-9-2008 including share in the interstate projects. The DISCOMs purchase the

entire generation of APGENCO under the terms of the PPA with the generator.

Source Installed Capacity (MW)

THERMALKothagudem-A 240.0

Kothagudem-B 240.0

Kothagudem-C 240.0

Kothagudem-D 500.0

Ramagundam-B 62.5

VTPS 1,260.0

RTPP-I 420.0

RTPP-II 420.0

TOTAL THERMAL 3382.5

HYDEL

Interstate projects:

Machkund, Orissa (AP share 70%) 84.0

T.B. Station, Karnataka (AP share 80%) 57.6

State projects:

Donkarayi 25.0

Upper Sileru 240.0

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*Note. KAIGA unit-4 is expected to come under commercial operation in Dec08.

IPPs

The following IPPs are under commercial operations in the State:

216MW gas-based plant at Jegurupadu by GVK Industries (GVK);

208MW gas-based plant at Kakinada by Spectrum Power Generation Ltd.,

351.49 MW gas-based plant at Vijayawada by Lanco Kondapalli Power Ltd (Lanco

Kondapalli). .

220 MW gas based plant at Samalkota, East Godavari District by M/s. Reliance PowerLtd. (formerly M/s.BSES).

AP Gas Power Corporation Ltd (APGPCL): Joint Sector

APGPCL is a joint sector gas-based power project. The allocation of power from this project

is in proportion to the equity share capital of participating industries. The total installed

capacity of the project along with the DISCOMs share is as given below:

Source Installed Capacity

(MW)

APDISCOMs

Share (MW)

APDISCOMs

Share (%)

Stage I 100 16 16

Stage II 172 42.8 24.88

Total 272 58.8 21.62

Inter-State purchases

PTC, NTPC V V N L, TPTCL

The Licensee proposes to procure power from Power Trading Corporation, NTPC Vidyut

Vyapara Nigam Ltd., Tata Power Trading Company Ltd, Reliance Energy Trading Ltd.

Adani etc., on need basis.

Non-Conventional Energy (NCE) Sources

The installed capacities of NCE projects in the state for FY 2009 and FY 2010 are as follows:

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Type of Project FY 2009(MW) FY 2010(MW)

Bio Mass Power Projects 192.75 192.75

Bagasse Cogeneration Projects. 182.70 190.70

Wind Power Projects 84.5 284.5

Mini Hydel Power Projects 47.45 51.05

Industrial Waste Based 18 33.66

12.74

TOTAL 505.06 765.40

Mini-Power Plants

APTransco had entered into adhoc agreement with LVS (36.8 MW) for purchase of power as per

the direction of Supreme Court and had a PPA with Srivathsa (17.202 MW) power plant. Thesehave been allocated to EPDCL. Licensee proposes power purchase from CPPs of VSP, NBFAL,

Sponge Iron India Ltd, Heavy Water Plant etc., during the year 2009-10 on need basis at the rates

approved by the Commission.

2.2.1 Expected major capacity additions during FY 2010

S. No. Station Name Type Fuel Capacity (MW)

1 *GVK Extension Project IPP Gas 176

2 *Vemagiri Power Generation IPP Gas 296

3 *Konaseema EPS Oakwell PowerLtd

IPP Gas 356

4 *Gautami IPP Gas 371.2

5 VTPS-IV APGENCO Coal 500

6 Jurala APGENCO Hydel 5x39

7 RTPP-III APGENCO Coal 210

8 KAKATIYA-I APGENCO Coal 500

The licensee expects new capacity additions of about 1199 MW from new IPPs subject to the supply

of gas by GAIL.

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As an alternative, in absence of Gas in Jan-09, Generation of 200 to 230 MW is expected from Jan09

to May09 from Vemagiri Power Generation by utilization of diverted gas from LANCO, Kondaplli.

Similarly,Generation of 150 MW is expected from Jan09 to March09 from GVK Extn. by

utilization of diverted gas from GVK Phase-I.

BASIS OF ESTIMATION OF POWER AVAILABILITY FOR FY 2009 H2 AND FY 2010

APGENCO

Thermal:

The power availability for the second half of FY 2009 has been estimated by the Licensee based on

actual performance for the first half of FY 2009 and the expected plant performance and

maintenance schedules of APGENCO for the remaining six months of FY 2009.

APGENCO Thermal ( Energy Availability- MUs)

Sl No Station Name FY 2009 H2 FY 2010

1 VTPS- I 1543 2965

2 VTPS- II 1442 2907

3 VTPS- III 1503 2896

4 VTPS-IV 250 2998

5 RTPP-I 1560 2961

6 RTPP-II 1493 3005

7 RTPP-III 0 554

8 KTPS-A 800 15769 KTPS-B 737 1549

10 KTPS-C 782 1592

11 KTPS-D 1765 3438

12 RTS-B 220 417

13 KAKATIYA-I 0 1966

Total 12095 28824

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Hydel:

The availability from Hydel plants of APGENCO for the second half of FY 2009 has been estimated

taking into consideration the inflows in to the reservoirs of Srisailam and Nagarjuna Sagar owing to

good rainfall in the Krishna catchment areas during the monsoon.

The projection for ensuing year is based on the expected reservoir levels at end of current year and

the assumption of a normal rainfall in the ensuing year.

The following table shows the projected availability for FY 2009 H2 and FY 2010:

APGENCO Hydel ( Energy Availability-MUs)Sl No Station Name FY 2009 H2 FY 2010

1 MACHKUND PH AP Share 248 220

2 TUNGBHADRA PH AP Share 92 171

3 USL 226 481

4 LSR 579 1156

5 DONKARAYI 72 122

6 SSLM (Right Bank) 542 2006

7 NSPH 980 1953

8 NSRCPH 234 192

9 NSLCPH 108 88

10 POCHAMPAD PH 77 59

11 NIZAMSAGAR PH 19 712 PABM 0 2

13 MINI HYDRO&OTHERS 10 13

14 SINGUR 3 2

15 JURALA 0 146

16 SSLM LCPH 830 2351

Total 4020 8969

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CGS

NTPC- Southern region: The estimate of availability from the CGS of the Southern Region for the

second half of FY 2009 is based on the actual performance for the first half of FY 2009 and the

expected performance for the second half of FY 2009.

The total power availability estimate from CGS for FY 09 H2 and FY 10 is as stated below:

Central Generating Stations ( Energy Availability-MUs )


1 NTPC- (SR) 2761 5687

2 NTPC-(SR) STAGE - III 745 1389

3 NTPC TALCHER-II 1649 3118

4 NTPC- SIMHADRI 3948 7406

5 NLC TS II STAGE- I 370 648

6 NLC TS II STAGE- II 645 1146

7 NPC-MAPS 135 2608 NPC-KAIGA 1 & 2 406 817

9 NPC- KAIGA 3 & 4 378 958

TOTAL 11037 21429

APGPCL

The Licensee has not projected any power available from the unutilized capacity of other

shareholders in APGPCL in the 2nd half of FY 2009 as it is in the nature of infirm power.

As per the agreement with APGPCL, unutilized energy in stage-I has to be purchased by AP

DISCOMs.

APGPCL Allocated Capacity (Energy Availability- MUs )


1 APGPCL I - Allocated capacity 36 65

2 APGPCL II - Allocated capacity 130 269

Total 166 334

IPPs

The availability of power from the generating stations of GVK, Spectrum, Lanco Kondapalli and

Reliance (BSES) has been projected as declared by the IPPs.

IPP's (Energy Availability-MUs )


1 GVK 684 1581

2 Spectrum 708 1608

3 Lanco Kondapalli (Gas) 1502 3042

4 Reliance 683 1683

Total 3577 7914

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The projections for FY 2009 H2 and FY 2010 are based on existing gas supply position.

The availability of power from generating stations of GVK Extension, Vemagiri, Gautami and

Konaseema has been projected based on the availability of expected additional gas for 2009-10.

New IPPs FY 2010 (projected)

All figures in MU

GVK Extension Project1196

Vemagiri Power Generation Ltd2012

Gautami Power Ltd2523

Konaseema EPS Oakwell Power Ltd.2221

Total7952

Availability from stations with DISCOM Specific Allocations

The NCE projects and the two mini power plants are not allocated on pro-rata basis but allocated to

specific DISCOMs based on their locations. The availability from these sources for each DISCOM is

as shown below:

Mini Power Plants:

Mini-Power Plants Allocated to EPDCL ( Energy Availability-MUs)

Sl No Station Name FY 2009 H2 2009-101 Srivathsa 47 111

2 LVS 0 0

Total 47 111

Non-Conventional Energy (NCE) Sources

Energy availability in MU for FY 2009 H2

22

Sl No Station Name SPDCL NPDCL EPDCL CPDCL

Total

( Type-

wise)

1 NCE - Bio-Mass 319.41 75.9 84.6 129.66 609.57

2 NCE - Bagasse 115.11 128.71 93.69 32.61 370.12

3

NCE - Municipal Waste to

Energy17 0 0 18.26 35.26

4

NCE - Industrial Waste

based power project0 0 45.86 11.07 56.93

5 NCE - Wind Power 1.94 0 0 49.96 51.90

6 NCE - Mini Hydel 23.47 7.07 11.29 30.63 72.46

7 NCE - NCL Energy Ltd 2.2 1.6 1.6 4.6 10

Total Availability

( DISCOM-wise)479.13 213.28 237.04 276.79 1206.24


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Energy availability in MU for FY 2010

Losses external to APTransco system

The losses external to the APTransco system are estimated to be 4.17 %. This is applicable for

procurement of power from Central Generating Stations.

Summary

A summary of the source wise current estimate of availability for FY 2009 H2 and FY 2010 is

presented below.

23

Sl No Station Name SPDCL NPDCL EPDCL CPDCL

Total

( Type-

wise)

1 NCE - Bio-Mass 682.37 153.05 170.59 223.20 1229.21

2 NCE - Bagasse 290.73 259.56 188.94 65.77 805

3

NCE - Municipal Waste to

Energy34.28 0 0 36.83 71.11

4

NCE - Industrial Waste

based power project0 0 98.23 76.41 174.64

5 NCE - Wind Power 94.57 0 0 214.95 309.52

6 NCE - Mini Hydel 47.25 14.26 31.86 61.77 155.14

7 NCE - NCL Energy Ltd 4.5 3.2 3.2 9.3 20.2

Total Availability

( DISCOM-wise)1153.7 430.07 492.82 688.23

2764.82

Summary Energy Availability Table- MUs

Sl No Sector FY 2009 H2 FY 2010

1 APGENCO - Thermal 12095 28824

2 APGENCO - Hydel 4020 8969

3 CGS (SR) 11037 21429

4 APGPCL 166 334

5 IPPs 4218 15867

6 NCE 1206 27657 Mini Power Plants 47 111

8 Bilateral Purchases 2132 378

Total 34921 78675


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Power purchase tariffs

APGENCO

A fixed cost of Rs.3112.12 crores for the existing stations and including RTPP-II, III, VTPS-IV and

Jurala for FY 2010 is considered in the ARR. The station-wise variable rates for APGENCO thermal

plants that have been adopted for second half of FY 2009 and full FY 2010 are as follows

Station Variable rate (Rs./kWh)

VTPS (I, II, III) 1.57

VTPS-IV 1.4

RTPP-I 1.74

RTPP-II 1.74

RTPP-III 1.74

KTPS (A, B, C) 1.28

KTPS- D 1.16

RTS-B 1.36KAKATIYA-I 1.16

VARIABLE COSTS FOR SLBPH

APERC vide orders Dt 16-10-07 in IA No.11/07 in OP No.4/07 directed to pay the SLBPH energy

Charges (Conventional Mode) monthly as per the methodology indicated in Para 475 & 476 of Tariff

order 2004-05 subject to year ending adjustment.

For Srisailam Laft Bank powerhouse (SSLBPH), variable cost of Rs. 0.86/unit is considered.

However, the above rates are for estimation purpose only and the actual payments will be made as

per the methodology specified in paragraphs 475 to 477 of Tariff Order 2004-05 and reiterated in

paragraph 375 of Tariff order 2005-06.

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NTPC-TALCHER -II (2000 MW)

The fixed costs are projected based on CERC order dt.31-01-2008 and revised allocation of 21.49 %

w.e.f. 18-07-2008. Variable charges are projected based on Sep 2008 bill. Total capacity charges of

2000 MW TALCHER STAGE-II per annum = Rs. 863.5 Crs

Capacity charges payable by APDISCOMS per annum for 429.87 MW entitlement = Rs.185.57 Crs.

Variable rate = Rs.0.76/kwh

NTPC (SR) (2100 MW).


w.e.f. 18-07-2008. Variable charges are projected based on Sep 2008 bill. CERC vide order dt.30-07-

2008 approved fixed charges of Rs.470.53 Crs. per annum Total capacity charges of 2100 MW

TALCHER STAGE-II per annum = Rs. 470.53 Crs

Capacity charges payable by APDISCOMS per annum for 735.18 MW entitlement =

Rs.164.73 Crs.

Variable rate = Rs.1.34/kwh

NTPC (SR) STAGE-III (500 MW)


w.e.f. 18-07-2008. Variable charges are projected based on Sep 2008 bill . Total capacity charges of

500 MW NTPC (SR) STAGE-III per annum = Rs. 263.31 Crs.

Capacity charges payable by APDISCOMS per annum for 183.84 MW

entitlement = Rs.96.81 Crs.

Variable rate = Rs.1.28/kwh.

NTPC- SIMHADRI

The fixed costs of NTPC (Simhadri) are projected based on CERC order dt.18-06-2008 and variable

charges based on Sep 2008 bill.

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Fixed cost per annum: Rs. 462.78 Crs

Variable rate : Rs. 1.15/kwh

NLC TS II

The fixed costs are projected based on CERC order dt.04-06-2008. Variable charges are projected

based on Sep 2008 bill .

Stage I

Total capacity charges of 630 MW NLC STAGE-I per annum = Rs. 121.96 Crs

Fixed cost payable by APDISCOMs per annum for 20.13 % entitlement = Rs. 24.55 Crs/year

Variable rate = Rs 1.46/Kwh

Stage II

Total capacity charges of 840 MW NLC STAGE-II per annum = Rs. 175.19Crs

Fixed cost payable by APDISCOMs per annum for 26.09 %MW entitlement = Rs. 45.7 Crs/year

Variable rate = Rs. 1.37/kwh

MADRAS ATOMIC POWER STATION (MAPS) (440 MW):

Government of India, Department of Atomic Energy (Power Section) notified the tariff for supply of

power from MAPS vide Tariff Notification dated 22.09.2006. As per the notification the tariff

effective from 1.4.2006 is fixed at 181.18 Ps/Kwh. The tariff is subject to fuel and Heavy water

adjustment charges. Taking into account the revisions subsequent to 1.4.2006 in insurance and in therates of fuel and Heavy water, the tariff applicable for September 2008 is Rs. 1.8922 /Kwh and the

same has been adopted for arriving at projected costs for H2 of current year and ensuing year. The

share of AP in MAPS was revised to 10.7 % w.e.f. 07.04.2007. Fixed cost is considered at Rs.

0.71/unit and variable cost at Rs. 1.18/unit.

KAIGA ATOMIC POWER STATION 1 &2 (KAPS) (440 MW):

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Government of India, Department of Atomic Energy (Power Section) notified the tariff for supply of

power from KAIGA 1 &2 vide Tariff Notification dated 21.09.2005. As per the notification, the

tariff effective from 1.7.2005 is fixed at 279.5 Ps/Kwh. The tariff is subject to fuel and Heavy water

adjustment charges. Taking into account the revisions subsequent to 1.7.2005 in insurance and in the

rates of fuel and Heavy water, the tariff applicable for September 2008 is Rs. 2.8878/Kwh and the

same has been adopted for arriving at projected costs for H2 of current year and ensuing year. Fixed

cost is considered at Rs. 1.90/unit and variable cost at Rs. 0.99/unit.

KAIGA ATOMIC POWER STATION 3 & 4 (KAPS) (440 MW):

Unit 3 (220 MW) of KAIGA Atomic Power Station was declared under commercial operation w.e.f

06.05.07. Unit 4 (220MW) is expected to come under commercial operation shortly. Pending

finalization of Tariff for KAIGA 3 & 4 by Department of Atomic Energy, rates of KAIGA 1 & 2 are

being adopted for making payments for supply of power from KAIGA 3 & 4. The KAIGA 1 & 2 tariff

applicable for September 2008 has been adopted for arriving at projected costs for H2 of current year

and ensuing year. The share of AP in KAIGA 3 & 4 is 33.17. Fixed cost is considered at Rs. 1.9/unit

and variable cost at Rs. 0.99/unit.

Other Costs for CGS (SR)

The Other Costs for CGS (SR) have been calculated based on the previous years cost that the

Licensees incurred.

CGS (SR) incentive:

Incentives for CGS (SR) for 2008-09 and 2009-10 are arrived at based on CERC notification dt.26-3-

04.

Total Incentive payable :-Incentive shall be payable at a flat rate of 25.0 Ps/kwh for ex-bus

scheduled energy corresponding to scheduled generation in excess of ex-bus energy corresponding to

target PLF (Target PLF for NTPC Stations -80%, for NLC 75 % and for MAPS & KAIGA Stations

there is no incentive).

As per CERC orders, the incentive amount payable to NTPC & NLC is to be shared by the

beneficiaries in the ratio of energy scheduled beyond target PLF.

APGPCL

The costs for purchase from APGPCL are as per projections given by APGPCL:

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Cost component

Demand Charges (Rs./KVA)

Stage-I 75

Stage-II -Stage-IFixed cost (Rs per kWh) 0.28Variable cost (Rs per kWh) 1.18Stage IIFixed cost (Rs per kWh) 0.12Variable cost (Rs per kWh) 0.88

There are no demand charges for Stage II of the generating station under the terms of the

Memorandum of Understanding of April 1997.

IPPs

GVK: - JEGURUPADU POWER PROJECT

The fixed cost is fully recoverable at 68.5% PLF. The variable charge of Rs 1.28 / KWh has been

computed by assuming that 70% of the units will be generated on GAIL gas and 30% of the units

will be generated on Reliance gas..

The capital cost of this plant is Rs.816 crores. The fixed cost is Rs. 114.63 Crores per annum for FY

2009 and Rs.96.0 Crores for FY 2010. The fixed cost includes foreign exchange variations payable by

APDISCOMs to the company as per the provisions of Power Purchase Agreement. The actual fixed

cost as settled by the Licensee may be different from the estimates as presented above on account of

the monthly Foreign Exchange Rate Variation (FERV). The Licensee submits to the Honble

Commission to allow the Licensee to subsequently claim the change in fixed cost on account of FERV

to the DISCOMs.

Deemed/Notional generation claims will be payable to the company up to 85% PLF as per the

incentive formulae provided in the PPA.

Computation of incentive has been carried out based on the formula provided in the PPAs. The PLF

used for estimating incentives is based on the generators projections of plant performance for FY

2010.

Incentive payment = Equity x (PLF - 68.5).x. 0.00525

Equity = Rs 244 .8 Crores

Projected incentive for FY 2010: Rs.21.21 Crs

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SPECTRUM

The fixed cost is fully recoverable at 68.5% PLF. The variable charge of Rs 1.24 / KWh has been



The fixed cost of Rs 138.13 Crores has been adopted for FY 2009 and Rs 100.0 crores for FY 2010.

The fixed cost is inclusive of foreign exchange variations payable by APDISCOMs to the company as

per the provisions of Power Purchase Agreement.

The actual fixed cost as settled by the Licensee may be different from the estimates as presented above

on account of the monthly Foreign Exchange Rate Variation (FERV). The Licensee submits to the

Honble Commission to allow the Licensee to subsequently claim the change in fixed cost on account

of FERV from the DISCOMs.

Deemed/Notional generation claims will be payable to the company up to 85% PLF as per the

incentive formulae provided in the PPA.

Computation of incentive has been carried out based on the formula provided in the PPAs. The PLF

used for estimating incentives is based on the generators projections of plant performance for FY

2010.

Incentive payment = Equity x (PLF-68.5)x0.004 (IF PLF > 68.5 < 80.5)

Incentive payment = Equity x (PLF - 68.5).x. 0.005 (if PLF > 80.5 and < 85.5 )

Incentive payment = Equity x (PLF - 68.5).x. 0.006 (if PLF > 85.5 )

Equity = Rs 117.92 Crores

Projected incentive for FY 2010 : Rs.9.73 Crs.

LANCO KONDAPALLI

The fixed charges are fully recoverable at 80% PLF

The variable charge of Rs 1.34 / KWh has been computed by assuming that 70% of the units will be

generated on GAIL gas and 30% of the units will be generated on Reliance gas..

Estimated fixed cost for of FY 2009 : Rs.310.39 Crs.

Estimated fixed cost for FY 2010 : Rs.312.0 Crs.

RELIANCE INFRASTRUCTURE LTD (BSES)

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The Fixed charge is fully recoverable at 85% PLF. The variable charge of Rs 1.21 / KWh has been



Based on the formula provided in the PPA, the fixed cost works out to Rs. 152.10 Crs. for FY 2009.

The fixed cost for FY2009-10 is calculated as Rs.159.72 Crs.

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GVK EXTENSION POWER PROJECT

During diversion of GVK Phase-I gas to GVK Extn. ,the expected generation from GVK Extn. for the

period from Jan09 to March09 is about 324MU.The energy availability for FY 2009 is based on

expected additional gas availability. The fixed cost per unit is 96 Ps /Kwh considering USD rate at Rs.

48/$ . Based on GCV of Gas at 9600 Kcal/SCM, basic price of reliance gas at US $ 4.2/MMBTU,

Station Heat Rate at 1850 Kcal/Kwh, Auxiliary consumption at 3 %, the variable rate works out to 178

Ps/Kwh.

VEMAGIRI POWER GENERATION LIMITED

Vemagiri Power generation Ltd amended PPA on 2-5-2007 with modification in fuel definition

making fuel as natural gas only. The COD of the project was declared on 16-09-2006. The project is

awaiting for natural gas supply. During diversion of Lanco gas to Vemagiri ,the expected generation

from Vemagiri for the period from Dec08 to March09 is about 668MU. The energy availability for

FY 2009 is based on expected additional gas availability. The fixed cost per unit is 99 Ps /Kwh

considering USD rate at Rs. 48/$. Based on GCV of Gas at 9600 Kcal/SCM, basic price of reliance

gas at US $ 4.2/MMBTU, Station Heat Rate at 1850 Kcal/Kwh, Auxiliary consumption at 3 %, the

variable cost works out to 178 Ps/Kwh.

GAUTAMI POWER PROJECT

The energy availability for FY 2009 is based on expected additional gas availability. The fixed cost

per unit is 99 Ps /Kwh considering USD rate at Rs. 48/$. Based on GCV of Gas at 9600 Kcal/SCM,

basic price of reliance gas at US $ 4.2/MMBTU, Station Heat Rate at 1850 Kcal/Kwh, Auxiliary

consumption at 3 %, the variable rate works out to 178 Ps/Kwh.

KONASEEMA EPS OAKWELL POWER LTD

The energy availability for FY 2009 is based on expected additional gas availability. The fixed cost

per unit is 99 Ps /Kwh considering USD rate at Rs. 48/$. Based on GCV of Gas at 9600 Kcal/SCM,

basic price of reliance gas at US $ 4.2/MMBTU, Station Heat Rate at 1850 Kcal/Kwh, Auxiliary

consumption at 3 %, the variable rate works out to 178Ps/Kwh.

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MINI POWER PLANTS

LVS POWER LTD (36.8 MW)

LVS is a Mini Power Plant originally contemplated for sale of power to third parties. The

Commission directed the developer to sell energy to APTRANSCO.

However the company was directed to back down the plant from 3.4.2003 onwards due to increase in

variable cost. During the back down period fixed charges payable to the company for the FY 2009 is

Rs.27.73 Crs. FY 2010 is 29.77 Crs.

SRIVATHSA POWER PROJECTS LTD (17.202 MW)

It is also a Mini power plant originally contemplated for sale of power to third parties. However, as

directed by the Commission, the developer has agreed to sell the energy to APTRANSCO

withdrawing the court case against APERC order passed in O.P.No.70-A/2001, Dt. 4.5.2001 and after

series of negotiations developer furnished their proposals with a capital cost of Rs.56.88 crores. Fixed

cost for 6th year (2008-09) is Rs.1.119 per unit and Variable cost during 6th year is Rs.1.2 per unit.The fixed cost for 2008-09 is Rs. 13.38 Crores. For the year 2009-10, fixed cost of Rs.1.057 unit and

variable cost of Rs.1.2 unit has been adopted. The annual fixed charges work out to Rs.11.63 Crs for

2009-10.

NON CONVENTIONAL ENERGY (NCE) SOURCES:

The Commission as per its Order in R.P.84/2003 in O.P.-1075/2000 dated March 20, 2004 hasannounced the tariff applicable to NCE projects with effect from 1.4.2004. Subsequently, the

Commission has revised the incentive in these projects for generation above threshold PLF and tariff

for Mini Hydel projects in its orders on review petitions filed by NCE developers/associations against

orders dt.20.3.2004. The NCE developers approached Honble High Court on the Commissions

orders. Honble High Court issued interim directions allowing APTRANSCO to implement the

revised tariff in addition to payment of 50% of the differential amount between the old rate and

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revised tariff. Honble High Court in June 2005 disposed the cases filed by NCE developers, giving

liberty to the Developers to file appeals before Appellate Tribunal for Electricity, New Delhi.

The NCE developers filed appeals before Appellate Tribunal for Electricity .The Appellate Tribunal

vide orders dt. 02.06.06 set aside APERC orders dt. 20.03.04 with a direction to

APTRANSCO/DISCOMS to continue purchase of energy from NCE projects at a Tariff paid prior tothe Commission orders.

APTRANSCO/DISCOMS filed appeals before Honble Supreme Court against the Tribunal order

dt.02.06.06. The Honble Supreme Court passed interim orders in the appeals and directed its office to

issue notice to NCE developers. In the light of Honble Supreme Court orders, the DISCOMS are

continuing payment of 50 % of differential amount in addition to revised Tariff to NCE developers.

The GOAP filed an implead petition before Honble Supreme Court to clarify its stand in the case. TheHonble Supreme Court has permitted the implead petition. The appeals are yet to be heard.

Bilateral Purchases

Month-wise shortfall has been estimated based on the availability and requirement. This deficit will be

met from external sources such as UI, running existing IPPs on Naphtha, power traders and power

exchange.

D-D Purchases

Month-wise availability of each Discom has been calculated based on PPA allocation and the

requirement of each Discom has been calculated to arrive at Transco periphery, which has been

calculated by grossing up the sales with losses. The D-D purchases /sales for each Discom have been

estimated. The D-D pool price has been calculated based on the average fixed cost and the highest

marginal cost station. The D-D price has been estimated to be Rs. 2.42/kwh.

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FY 09-10 Projection (Ensuing Year)

Station

Power

PurchaseFixed Cost Variable Cost Other Costs Total Costs

MUs Rs. Crs. Rs. Crs. Rs. Crs. Rs. Crs.

APGENCO - Thermal 25,294 3112 3633 62 6807

APGENCO - Hydel 8,969 201 - 201

CGS 14,023 865 1637 162 2664

NTPC Simhadri 7,406 463 852 23 1338

NTPC - ER - - - - -

IPPs15,867

1473 2426 60 4021

APGPCL 334 5 31 - 36

Others 2,87541 1168 - 1209

Total 75146 5959 9948 307 16,215

2.3 Capital Investment Plan

The licensee hereby submits to the Honble Commission the procedure adopted for CapitalExpenditure (Capex) estimation for the control period. The total Capex estimated comprises of two

components namely, Base Capex and Other Capex. The estimation of each of the components of total

Capex is as mentioned below.

2.3.1 Base Capital Expenditure

The Base Capex is planned to cater the load growth and network strengthening. The following

methodology has been adopted for the estimation of the Base Capex:

Methodology

Sub-division Details

The following data has been gathered for all the sub-divisions in a DISCOM:

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Sales Forecast

Projection of sub-division wise sales for the control period has been carried out on the basis of the

actuals of the last three years. The sales projections were done for LT, HT 11 kV, total HT sales and

the total sales for the DISCOM for each year in the control period. The growth-rates were calculated

for each sub-division for each year in the control period.

Sub-division Classification

The classification of sub-divisions as Urban, Semi-urban and Rural was done on the basis of load

factor at PTR level of the sub-division. The load factor of the sub-division is calculated using sum of

the HT 11 kV and LT sales; and the total installed capacity of the sub-division (which is the sum of the

installed capacities of all the PTRs in all sub-stations in a sub-division). All those sub-divisions

having load factor 20% more than the average load factor of the DISCOM are classified as Urban sub-

divisions, and those having load factor 20% less than the average load factor of the DISCOM are

classified as Rural sub-divisions. The remaining sub-divisions have been classified as Sub-Urban. All

the sub-stations in a sub-division have been assumed to have the same classification as that of the sub-

division.

2.3.1.1 Substation Details

Power Transformer Details

The power transformer (PTR) capacities installed in a substation were gathered along with the peak

loading details of PTRs. The data used for analysis is the year end values of 2007-08 and is as

received from the field to ensure that the model captures and reflects the real situation as in the fields.

The peak loading details as received from the field was validated to limit the peak loading on the

PTRs based on certain criteria and also to ensure that the equivalent secondary current of the PTRs

in a substation is less than the total feeder currents in a substation by a certain margin.

Feeder Details

The details captured for analysis are the total number of feeders installed in a substation and the peakcurrents flowing through the same. This data too is as received from the field and correspond to the

2007-08 end year values. The peak current data in feeders of a sub-station have been validated to

ensure that the total currents in the feeders in a substation is higher than the equivalent secondary

current of the PTRs in a substation by a certain margin and also not exceeding certain limits which

have been set depending upon the classification of the substation.

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Distribution Transformer Details

The total number of distribution transformers catered by a substation at the end of the year 2007-08

has been considered. The DTR wise peak loading hasnt been considered though the number has been

categorized in various load bands.

2.3.1.2 Trigger Points for Network Additions (Substations; PTRs; Feeders; DTRs)

Substations

The PTR and feeder loadings in a substation have been assumed to grow at the same rate as the year-

on-year sales growth of sum of LT and HT 11 kV sales in that subdivision. The substation capacity

limit has been fixed at 16 MVA for Urban substations, 10 MVA for sub-urban substations, and 5

MVA for rural substations.

A new substation is proposed if all of the following happen:

1 If an additional PTR is required and the substation cannot accommodate any further PTRs based

on the criteria mentioned above.

2 Average loading on PTRs in substation is greater than 80%.

A certain loading of the PTRs in the present substation is transferred to the new substation. The PTR

capacity to be installed in the new substation is a factor of the PTR utilization of the present

substation, and can be either of 5 MVA; 8 MVA; 10 (5 + 5) MVA or 13 (8 + 5) MVA. The loadtransfer from a present substation to a new substation has been factored in such a way that in most

situations the average loading on PTRs in the present substation after the load transfer doesnt exceed

80% in any of the years in the control period. The load transfer from a present substation to a new

substation in the later years in the control period has been increased to ensure that total network is well

balanced at the end of the control period.

The number of feeders proposed for a new substation is a factor of the new capacity installed in that

substation, the average new substation loading, and a maximum feeder current limit of 60 Amps.

For year 2008-09, as the projects have already started for new substations installation, and a few of

them proposed for this year are already operational, the difference in the additions as proposed by the

model and the projections as per the projects wing for 2008-09 has been carried forward to the

subsequent years in the control period. This has been done so to ensure that the network is

strengthened to cater to the load growth expected during the control period.

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Power Transformers

A new PTR is proposed if all of the following happen:

1 If the peak loading of any of the PTRs installed exceeds 80% of its capacity and if the substation

can accommodate a new PTR.

The PTR capacity proposed is either 5 MVA or 8 MVA, depending on substation capacity.

The final loading on the PTRs after a new PTR is proposed is such that the distribution of peak loads

on all PTRs is the same. This shall ensure that all the PTRs are loaded equally unlike the scenario of

peak loading on one of them being very high.

A similar carry forward approach has been adopted for the PTR additions as done for substations.

FeedersThe total number of feeders in a substation has been restricted to 16. New feeders are proposed if all of

the following happen:

1 Peak feeder current exceeds more than 100 Amps;

2 If no new substation addition is being proposed;

3 If additional feeder can be accommodated in the substation.

The peak currents in the feeders are distributed equally among the ones over loaded and the newfeeders proposed.

A similar carry forward approach has been adopted for the feeder additions as done above for

substations and PTRs.

Distribution Transformers

The number of DTRs has been categorized in various load bands as can be seen in the table below:

Name of Sub-Station

DTR Loading Information ( Beginning of the Year )

No. of DTRs' 100%

SS - 1 192 0 21 123 48 0

SS - 2 225 0 115 65 45 0

SS - 3 365 0 166 53 146 0

SS - 4 153 0 59 18 76 0

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2.3.1.3 Network Cost Details

The following approach has been considered to estimate the Network cost details which is important

to convert the network additions to Base Capex:

1 Substation Unit Cost (Rs. / substation): For calculating the cost of a substation added we have

considered the following to be a part of a substation unit:

33 kV line of 6 Kms;

132/33 kV tapping bay;

33 kV VCB;

Substation unit cost excludes the PTRs, 11 kV bay and AB switches;

It includes all the relevant material cost, construction cost and labor charges.

The substation unit cost arrived above is the value pertaining to 2008-09. Considering the possible

increase in material and labor costs, the substation cost has been escalated by a certain percentage

year-on-year. The number of substation additions each year has been multiplied by the substation unit

cost for that year to arrive at the total cost of installing all new substations in that year.

2 PTR Unit Cost (Rs. / MVA): For calculating the cost of installing a PTR in a substation we have

considered the following for the year 2008-09:

PTR of 5 MVA capacity;

HV Breaker;

LV Breaker;

Associated Equipment and labor cost.

The cost incurred for installing a 5 MVA PTR as above is divided with the PTR size to arrive at the

PTR unit cost. The total MVA addition in a year, which includes the additions in existing and new

substations, is multiplied with the PTR unit cost for that year to arrive at the total cost of installing all

the PTRs. On similar lines as the substation unit cost, the PTR unit cost of 2008-09 has been escalated

by a certain percentage year-on-year to get the PTR unit cost for subsequent years of the control

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period. This has been done to account for the possible increase in the material and labor cost during

the 2nd control period.

3 Feeder Unit Cost (Rs. / feeder): For calculating the cost of a installing a feeder in a substation we

have considered the following for the year 2008-09:

Feeder breaker and metering set (including CT/PT);

Bay extension;

11 kV line;

Poles;


The total feeder addition in a year, which includes the additions in existing and new substations, is

multiplied with the feeder unit cost for that year to arrive at the total cost of installing all the feeders.

The feeder unit cost of 2008-09 has been escalated by a certain percentage year-on-year to get the

feeder unit cost for subsequent years of the control period.

4 DTR Unit Cost (Rs. / kVA): For calculating the cost of a installing a DTR we have considered the

following for the year 2008-09:

100 kVA DTR cost;

AB switches;

DTR structure;

0.3 km of LT line;

0.4 km of 11 kV line;


The cost incurred for installing a 100 kVA DTR as above is divided with the DTR size to arrive at the

DTR unit cost. The total kVA addition in a year is multiplied with the DTR unit cost for that year to

arrive at the total cost of installing all the DTRs. The DTR unit cost of 2008-09 on similar lines as

others above has been escalated by a certain percentage year-on-year to get the DTR unit cost for

subsequent years of the control period.

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5 Escalation Factor: The escalation parameter that has been considered on the unit costs of 2008-09

to arrive at the unit costs for 2nd control period is as mentioned below in the table:

2008-09 2009-10 2010-11 2011-12 2012-13 2013-14

3% 3% 7% 7% 7%

2.3.2 Network Additions SummaryIn this section, the details of the network additions of all the DISCOMs are provided for the 2nd control

period. In the network additions, the substation additions, PTR capacity additions, Feeder additions,

and DTR additions has been captured.

2.3.2.1 NPDCL

The network to be added in the 2nd control period in NPDCL is as mentioned below in the table:

NPDCL UnitFY 08-

09 FY 09-10FY 10-

11FY 11-

12FY 12-

13FY 13-

14Total (FY 09-10

to FY 13-14)

SubstationAdditions Nos. 65 78 64 86 64 62 354

PTR Additions MVA 625 697 636 721 437 385 2,876

Feeder Additions Nos. 520 721 399 454 229 232 2,035

DTR Additions kVA598,000

1,155,722

895,932

885,674

161,322

163,300

3,261,950

2.3.3 Other Capital Expenditure

Apart from the base capital expenditure projected based on the load growth and

existing load on the net work, it is proposed to invest and amount of Rs.2, 754.00

crores for loss trajectory, technology up gradation and system improvement of

existing net work. The expenditure is basically divided into following heads:

1. AT&C loss reduction

2. Reliability Improvement & Contingency Schemes

3. Renovation & Modernisation

4. Technology Upgradation

5. New Consumer Capex

6 Civil Infrastructure Development

Loss Reduction: The licensee proposes to invest in the following areas under lossreduction schemes

1 Meter replacement: In order to reduce commercial losses, the licensee proposes to replace

467960 nos existing electromechanical meters with high quality type during current fiscal year

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and ensuing control period of 5 years which is expected to incur an expenditure of Rs 25

Crores

2 HVDS Conversion: The NPDCL has a predominant agricultural consumer base of an

approximately 8 lakh consumers which contribute more than 45% of total sales. Hence, the

licensee feels essential to reduce technical losses by converting existing LT distribution

network to 11KV, laying LT cables and by erecting small capacity of DTRs 16/25 KVA in

place of existing 100/63 KVA DTRs. Accordingly, the licensee proposes to take up HVDS

works during the current fiscal year and ensuing control period which would incur about Rs.

741 Crores.

3 MRI instruments: The licensee intends to increase the accuracy in metering by taking all the

electronic meter readings through Meter Reading Instruments only. These MRIs not only

prevent disputes between consumers and the licensee over meter readings but also avoid

erroneous readings when taken manually. The licensee estimates an expenditure of

Rs0.81Crores during current fiscal year and ensuing control period.

4 Replacement of existing 34sqmm conductor with 55sqmm conductor: Asa step to reduce

the technical losses, thelicensee proposes to replace existing worn out 35sqmm conductor of

about 11500KM 11KV line with 55sqmm conductor and accordingly the licensee expects to

incur an expenditure of Rs26Crores during current fiscal year and ensuing control period.

Network Additions

Sl.No.

Investment AreaUnit

s2008-09 2009-10 2010-11 2011-12 2012-13 2013-14

AT & C Loss Reduction

1.Meter Replacement ( Installation of HighQuality meters)

Nos. 96860 95600 87500 73000 60000 55000

2. HVDS Conversion

- Existing DTR capacity on the networkproposed for conversion

KVA 192000 192000 192000 128000 120000 120000

- Projected DTR capacity on the proposedHVDS network

KVA 240000 240000 240000 160000 150000 150000

-Difference in DTR capacity KVA 240000 240000 240000 160000 150000 150000

( Average DTR capacity assumed for

HVDS network) KVA 20 20 20 20 20 20- No of new DTRs required for HVDSnetwork

Nos. 12000 12000 12000 8000 7500 7500

3. Laying of AB cables Kms. 2400 2400 2400 1600 1500 1500

4. MRI instruments Nos. 55 50 50 55 50 55

5.Replacement of existing 34 sqmmconductor with 55 sqmm conductor

Kms. 1921 1673 1323 1222 1120 952

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Financial Summary

(in Rs)

Sl.No.

Investment Area 2008-09 2009-10 2010-11 2011-12 2012-13 2013-14

AT & C Loss Reduction

1

Meter Replacement( Installation of High

Quality meters) in 48430000 49234000 46414375 41433449.5 36438732.3 35740323.26

2 HVDS ConversionCost of New DTR(additional capacity) 1117800000 1151334000 1185874020 845923467.6 848566978.4 907966666.9

3 Laying of AB cables 249360000 256840800 264546024 188709497.1 189299214.3 202550159.3

4 MRI instruments 1265000 1184500 1220035 1435981.195 1396818.072 1644054.87

5

Replacement of existing 35sqmm conductor with 55sqmm conductor 55901100 50144829 40843907.37 40366623.31 39587038.77 36004411.76

SUB TOTAL ( In Rs Crores 147.28 150.87 153.89 111.79 111.53 118.39

Reliability improvement and Contingency Schemes

The licensee intends to improve its reliability in power supply by reducing interruptions and

improving the existing system by implementing the following schemes.

1 Reliability Improvement schemes

a) Providing sectionalizers: The licensee proposes 3000nos AB switches as

sectionalizers in 11KV lines to sectionalize the faulty line from the system in the

event of break downs and line clears/ maintenance thereby restoring supply to theconsumers as much as possible. This scheme is expected to commence in the current

fiscal year and complete by the end of ensuing control period. Accordingly, an

amount of Rs2.31crores approximately is estimated to be incurred during the above

period.

b) Reconductoring of lines: The licensee also proposes to replace the damaged

conductor of existing lines with the similar size of conductor to prevent accidents and

to avoid interruptions to the power supply to the consumers. Accordingly it is

expected to carry out reconductoring work for 300KM of existing 11KV lines, which

would incur an amount of Rs0.15Crores during the current fiscal year and ensuing

control period.

c) Replacing OH line with UG cables (at road crossings etc): The licensee aims at

avoiding electrical accidents with power lines at road crossings and highly congested

and densely populated locations due to low ground clearances as a result of escalation

of road and other reasons. During the current fiscal year and for ensuing control

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period, the licensee estimated to replace 40 KM of overhead line with XLPE UG cable

at required locations which would incur an expenditure of Rs15.27Crores during the

current fiscal year and ensuing control period.

2 Contingency schemes

- Provision of alternate supply at 33KV level: Under this scheme the licensee aims at providing

alternate 33KV supply to 100Nos substations, which have a single source of 33KV supply. It is

estimated that this scheme requires 500KM of new 33KV line and 200Nos new 33KV bays. To this

end, the implementation of scheme would incur Rs25.38Crores during current fiscal year and ensuing

control period.

Provision of alternate supply at 11KV level: The licensee intends to erect 300KM 11KV line to

provide alternate 11KV supply for improving reliability in power supply by providing supply to a partof feeder in the event of break downs, line clears etc. Accordingly, an amount of Rs 8.36Crores

approximately is expected to be incurring during the present fiscal year and ensuing control period.

Provision of alternate supply for LT consumers: In the event of a distribution transformer failure, it

is necessary to have an alternate LT supply from adjacent DTRs to the existing LT lines. Hence

262KM of LT line is proposed for above purpose, which would incur an amount of Rs 4.62Crores

during the current fiscal year and ensuing control period.

Network Additions

Sl.No.

Unit2008-

092009-

102010-

112011-

122012-

132013-

14

Reliability Improvement &Contingency Schemes

1 Reliability Improvement

Auto-reclosers Nos 0 0 0 0 0 0

Sectionalisers Nos 700 600 475 450 400 375

Reconductoring of lines Kms 70 65 55 45 35 30

Replacing OH line with UGcables ( at road crossings etc)

Kms 10 8 7 5 5 5

Others ( Pls Specify)2 Contingency Schemes

- Provision of alternate supply at33KV SS/ Consumers

- Addition of 33KV lines Kms 90 85 85 85 85 70

- No. of Bays Nos 36 34 34 34 34 28

3-Provision of alternate supply

at 11KV Consumer

- Addition of 11KV line Kms 70 60 50 45 40 35

- No. of Bays Nos 3.5 3 2.5 2.25 2 1.75

4-Provision of alternate supply

for LT consumers

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- Addition of LT line ( for ringfencing etc)

Kms 50 50 45 42 40 35

Financial Summary

(in Rs)

Sl.No.

Investment Area 2008-09 2009-10 2010-11 2011-12 2012-13 2013-14

1ReliabilityImprovement

Auto-reclosures 0 0 0 0 0 0

Sectionalisers 4900000 4326000 3527492.5 3575763.45 3400948.348 3411576.31

Reconductoring of lines 315000 301275 262572.75 229870.508 191303.3446 175452.496

Replacing OH line withUG cables

34780000 28658720 25828671.4 19740484.6 21122318.49 22600880.8

Others ( Pls Specify)

SUB TOTAL ( In Rscrores)

3.9995 3.3285995 2.961873665 2.35461185 2.471457018 2.61879096

2 Contingency Schemes- Provision of alternatesupply at 33KV level

- Addition of 33KV lines 31338000 30484910 31399457.3 33597419.3 35949238.66 31677623.2

- Bays -33 kV 9561240 9300961.8 9579990.654 10250590 10968131.3 9664859.23


4.089924 3.97858718 4.097944795 4.38480093 4.691736996 4.13424825

3-Provision of alternatesupply at 11KV level

- Addition of 11KV line 17101000 15097740 12958893.5 12479414.4 11869309.73 11112641.2

- Bays -11 kV 600670 530305.8 455179.145 438337.517 416907.6825 390329.818


1.770167 1.56280458 1.341407265 1.2917752 1.228621742 1.15029711

4 -Provision of alternatesupply LT voltage

- Addition of LT line 7935000 8173050 7576417.35 7566315.46 7710435.755 7218895.48

Renovation and Modernization.

Under Renovation and Modernization scheme the licensee proposes to replace the following

existing assets due to ageing of equipments. In order maintain the system in healthy condition and

to provide uninterrupted power supply to the consumers, the licensee proposes to procure 300 Nos

VCBs, 31292Nos Dtrs, and erection of 3210KM of lines during current fiscal year and ensuing

control period of 5 years which is expected to incur an expenditure of Rs 73.09Crores.

Network Additions

Sl.No.

Investment Area Unit2008-09 2009-10 2010-11 2011-12 2012-13 2013-14

1Proposed Retirement ofexisting assets

- 33/11KV SS Nos

- VCBs in existing SS Nos 50 50 50 50 50 50

- 33KV line Kms 5 5 5 5 5 5

- 11KV line Kms 30 30 30 30 30 30

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- DTR KVA 7792 7500 6000 5000 4000 1000

- LT line Kms 500 500 500 500 500 500

Financial Summary (in Rs)

Sl.No.


1

ProposedRetirement ofexisting assets

- 33/11KV SS

- VCBs in existing SS 12375000 12746250 13128638 14047642 15030977 16083145

- 33KV line 1741000 1793230 1847026.9 1976319 2114661 2262687

- 11KV line 7329000 7548870 7775336.1 8319610 8901982 9525121

- DTR 11904430 11802069 9724905.2 8671374 7422696 1985571

- LT line 79350000 81730500 84182415 90075184 96380447 103127078

Technology up gradation

For proper identification of consumers and linking them with input source for the purpose of

having complete database, e-procurement, billing, effective functioning of AMRs, the

licensee proposes to implement the following projects during current fiscal year and ensuing

control period of 5 years which is expected to incur an expenditure of Rs 198.85Crores.

GIS Mapping:

The primary objective of this project is to enhance the efficiency of distribution system in terms ofquality of power supply and increased revenue earning by reducing T&D losses (both Technical &

Commercial) , outage and to merge the faction of independent offices into the main stream operational

hierarchy with the help of organization wide network.

WAN:

The Discom offices are spread across five Northern districts of A.P. The company has established

connectivity i.e. WAN, between various offices through BSNL Leased Lines. Presently the

connectivity is provided to Circles, Divisions, EROs and District Stores mainly for SAP

implementation. There are some more offices, which require connectivity to meet upcoming IT

applications under APDRP XI Plan.

AMR Solution:

This is an Automated Meter Reading solution for remotely reading various energy meters installed

in the field. This will facilitate to eliminate meter reading irregularities, online monitoring of the

consumer meters, online analysis of the industries, load monitoring, feeder energy auditing etc. Under

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this scheme, AMRs will be installed on HT services, LT High value services, Distribution

Transformers, Sample AGL, DTR meters etc.

Automation of Substations:

Under this the company will be taking initiatives required at Substations to make them compatible to

integrate with the upcoming IT applications. Basically this may require providing Intelligent

Automatic Meter Reading devices (IAMR), WAN points, PCs, communication equipment etc. In

addition the Town outdoor Substations will be planned to convert into Indoor Substations.

SCADA:

The company is planning to take up Supervisory Control And Data Acquisition (SCADA) in the

Towns of the Discom. Basically SCADA refers to a system that collects data from various sensors at

substation or in other remote locations and then sends this data to a central computer, which then

manages, and controls the data. This offers following advantages

Load Monitoring and Alarm

Voltage Monitoring and Alarm

Outage Monitoring

Power Quality Monitoring and Alarm

Reliability Assessment

System Performance Analysis

Loss Analysis

Regulatory Reporting

ERP/IT Applications:

To improve and automate the Finance & Accounts (F&A), the company has implemented SAPwith the following modules.

FI/CO

MM

AM

IM

The main advantages envisaged by automation of F&A function are:

Standardization of the methods and accounting throught the Discom.

To done way with manual posting, writing of ledgers, cash book etc.

Completion of Annual Accounts and book closures within the statutory due dates.

To comply with the requirements of the Companies Act and Govt. of AP and APERCdirectives quickly as database would be readily available on line.

Saving in expenditure in communication with its unit offices as all the informationwould be available in Corporate Office.

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The company is presently using SAP R/3 4.7 Enterprise. Recently company has decided to upgrade

the current version to higher version i.e. ECC 6.0. This version has lot of improvements and additional

modules, which will enable the Discom to map some of the business process in to SAP.

Network Additions

Sl.No.

Investment Area Unit2008-09 2009-10 2010-11 2011-12 2012-13

2013-14

Technology Upgradation

1 Automation of Substations Nos 50 45 45 40 10 10

2 GIS mapping Nos 10 5 4 3 2 2

3 WAN Nos 100 90 80 60 40 30

4 AMR solutions Nos 6000 5000 3730 3000 1000 500

5 SCADA Nos 10 5 4 3 3

6 ERP/IT applications Nos 1 AMC AMC AMC AMC AMC

Financial Summary (in Rs)

Sl.No.


Technology

UpgradationAutomation ofSubstations 125000000 112500000 112500000 100000000 25000000 25000000

GIS mapping 19230770 9903846.55 8160769.56 6549017.57 4671632.53 4998646.81

WAN 50000000 45000000 40000000 30000000 20000000 15000000

AMR solutions 78000000 65000000 48490000 39000000 13000000 6500000

SCADA 100000000 50000000 40000000 30000000 30000000ERP/ITapplications 350000000 77000000 77000000 77000000 77000000 77000000

New consumer Capex

Presently in NPDCL for every new consumer, the service is released with a tamper proof energy meter

and service wire (XLPE) at 33 KV level and for voltages from 11 KV and below, only meter will be

supplied by the Discom. It is estimated that an average 65000 nos of LT meters and 12 nos of 33 KV

services are released per annum. The projected expenditure for releasing these services for the current

ARR for distribution business

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