BEFORE THE UTTAR PRADESH ELECTRICITY REGULATORY COMMISSION

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BEFORE THE UTTAR PRADESH ELECTRICITY REGULATORY COMMISSION, LUCKNOW

In the matter of: Draft “Uttar Pradesh Electricity Regulatory Commission (Terms

and Conditions of supply of power from Captive and Non-conventional Energy

Generating Plants) Regulations, 09” (CNCE Regulations’09).

ORDER

(Dates of hearing – 15.05.09, 25.05.09, 27.05.09 and 27.08.09)

1. BACKGROUND

The existing Uttar Pradesh Electricity Regulatory Commission (Terms and

Conditions for Supply of Power and Fixation of Tariff for sale of power from

Captive Generating Plants, Co-generation Plants, Renewable Sources of Energy

and Other Non-Conventional Sources of Energy based Plants to a Distribution

Licensee) Regulations, 2005 herein referred to as CNCE Regulations’05 was

applicable till July 2010. The present proceeding is for early review of CNCE

Regulations’05. Need for early review emerged from the Order dt.12.3.09 passed

in the matter of Pet.no.583/08, M/s Bajaj Hindustan Ltd. Vs. UPPCL & Ors and Pet.

No.578/08, M/s Bajaj Sugar & Industries Ltd. Vs. UPPCL & Ors wherein the parties

to the petitions had agreed for early review of the said Regulations and

accordingly the Commission decided that these regulations shall be reviewed. The

relevant para of Order dt.12.3.09 passed in above petitions is as below:

“In view of the agreements between the parties, the Commission decides for early

review of CNCE Regulations-05 not limited to bagasse based co-generation but in

respect to all sources of generation covered under the said Regulations.”

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2. CONSULTATIVE PROCESS

The Commission prepared Draft “UPERC (Terms and Conditions for Supply of

Power from Captive and Non–conventional Energy Generating Plants)

Regulations, 09” (in short the Draft Regulations) and a Paper on Draft Regulations

and Approach to Tariff (in short the Paper). The Paper highlighted the major

changes proposed in the Draft Regulations and the issues concerned with

determination of tariff of Captive generating plants, co-generation from bagasse,

generation from bio-mass, small hydro plants, solar PV and thermal, municipal

waste and other non-conventional sources of energy like wind, industrial wastes

(liquid, solid and gaseous) and biogas. CNCE Regulations’05 directs captive, small

hydro, non-conventional and renewable energy source based plants to submit

half yearly returns in Annexure-3 to the Regulations. These plants had failed in

submitting the said returns half-yearly as such all generating plants, in whose case

the Commission had approved power purchase agreements, were also directed in

the said Paper to submit returns for last four years. An association representing

the cause of such plants was also directed to ensure that its members should

submit such report directly to the Commission or through such an association.

A notice dated 26th

March 2009 was published in the daily newspaper Hindustan

Times and Amar Ujala on 27.03.2009 inviting comments on the Draft Regulations

and the issues raised in the Paper from all interested parties and stakeholders

before 22.04.2009 with an advance copy to U.P. Power Corporation Ltd., Kanpur

Electricity Supply Company Ltd. and Noida Power Company Ltd., who are

distribution licensees in the State. The draft Regulations and the Paper were

posted on Commission’s website. The public hearing was scheduled on 15th

May

2009. Subsequent hearings were held on 25.05.09, 27.05.2009 and 27.08.09. A list

of participants appearing before the Commission on above mentioned dates is

attached as Annexure 1.

2.1 Written Submissions

The following parties submitted written comments on or after 22.04.2009:

1. Anil Modi Oil Industries Limited ; vide letter dated 21st April 2009

2. U.P. Sugar Mills Cogen Association; vide letter dated 20th April 2009 and dt.

23.7.09.

3. Mawana Sugars Limited ; vide letter dated 20th April 2009

4. Sukhbir Agro Energy Ltd; vide letter dated 17th April 2009 & 12th May 2009

respectively.

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5. Hindalco Industries Ltd ; vide letter dated on 14th May 2009

6. DCM Shriram Consolidated Ltd ; vide letter dated 22nd May 2009

7. General Electronics (GE) ; vide letter dated 27th April 2009

8. Abhinav Steels Pvt. Ltd ; vide letter dated 20th

April 2009

9. Kanoria Chemical & Industries Ltd ; vide letter dated 19th May 2009

10. Hindalco Industries Ltd ; vide letter dated 14th May 2009

11. U.P. Sugar Mills Cogen Association’s supplementary submission; vide letter dt.

23.7.09, 19.08.09 & 27.08.09.

12. U.P. Power Corporation Limited; vide its affidavit dated 25.08.09

13. NEDA; vide its letter dated 26.08.09

The comments/ suggestions (except at Sr. No 9, 11, 12 and 13) received as above

were uploaded on website of the Commission at www.uperc.org for consideration

of interested parties and stakeholders.

The submissions of above parties in brief are as below:

A. Captive generating plants:

In this category, Abhinav Steels, GE Infrastructure Energy, Hindalco Industries,

Kanoria Chemicals and UPPCL have made submissions.

Abhinav Steels submitted that generally the unit size tariff norms have been set

in the existing Regulations for below 200 MW, 200/210/250 MW sets and 500

MW and above sets and suggested that one more category for units below 50

MW should be included as smaller plants have a different economic feasibility as

compared to higher size plants. It also suggested that the capital cost for such

new capacity may be considered as Rs.6.00 Crs/MW.

Abhinav Steels further suggested that proceeds from carbon credit should not be

subject to sharing because it is for financial benefit of the generating company

which invests to qualify for the carbon credit.

GE Infrastructure Energy submitted that tariff norms should also cover gas based

captive generating stations in addition to the coal and diesel based plants. The

variable charge for gas based captive power plants may be approved by UPERC on

a case-to-case basis based on the location, specific fuel price and technology.

Hindalco Industries submitted that banking should not be limited to 50% of total

energy supplied by captive power plant to UPPCL. Carry over of balance banked

energy at the end of year should be allowed in subsequent years without any

limitation. Continuous process industry like Aluminium must be allowed to carry

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forward banked energy, as suggested above, because they can not vary industrial

load frequently due to nature of operation.

Kanoria Chemicals submitted that the tariff of captive generating plant is much

less as compared to tariff of power generating companies and there should be

uniformity in pricing. Withdrawal of banked energy is not allowed from 17:00 to

20:00 hours which do not suit the nature of plant they have. As such restriction

on withdrawal of banked energy during this period should be removed. Further it

suggested that restriction on banking should be extended up to 75%

U.P. Power Corporation Limited submitted its comments that the capital cost for

coal based captive plants should be around Rs 4.5 Crore/MW and ROE should be

taken as 8% since 50% of the generation is being used by the captive user.

B. Bagasse based co-generation plants:

UP Cogen Association, Mawana Sugars, DCM Sriram Consolidated limited and

UPPCL made written submissions in this category.

UP Cogen Association submitted that due to less production of bagasse during

preceding years, plants had not been able to achieve the target PLF of 60%. The

average crushing period from 2005-06 to 2008-09 is stated as 133 days per

annum which corresponds to annual PLF of about 36%. As such a maximum

annual PLF of 40% could be achieved. The bagasse price is suggested at Rs.

1378/MT, determined as coal equivalent price on the basis of landed cost of coal

as Rs. 2227/MT and GCV as 3898 Kcal/Kg (as per UPERC tariff order dt. 6.3.09) and

GCV of bagasse as 2275/Kcal. The fuel price escalation is suggested at 7% per

annum. It also submitted that the SHR of bagasse based cogeneration should not

be less than 3700 kCal/kWh, O&M expenditure be considered at least as 4% of

the capital cost with 5% annual escalation, the auxiliary consumption be fixed at

10% instead of 8.5% at present and capital cost for new plants be considered as

Rs 4.5 Cr/MW with annual escalation of 6% for subsequent years for tariff

determination. U.P. Cogen association also submitted that the cost of line per km

& bay cost may be determined as per prevailing UPPCL norms/schedule after

providing suitable escalations. It is stated that graded incentive proposed in

concept paper is not workable due to high bagasse price in open market and

therefore it is proposed that competitive bidding be considered during off season.

The Return on Equity of 18% post-tax has been requested for determination of

tariff.

UP Cogen Association further submitted that the meters for recording of

import/export of energy from cogen plant are installed at grid substation of

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UPPCL and since the transmission losses between the cogen plant and grid

substation are not compensated in the tariff therefore average 1% transmission

line & transformer losses should be allowed. It also submitted that the provision

of sharing of carbon credit, as proposed in draft, should be dropped as this will

coincide with Kyoto Protocol period ending after 2012. Interest on working capital

may be considered as average SBI PLR during 2008-09.

It further submitted that the banked energy withdrawal during peak hours be

allowed and only the energy charges be considered for such withdrawal not the

demand charges. Wheeling of power to units under the same company has also

been prayed on payment of wheeling charges. Period of PPA is prayed to be

reduced to 10 years from the present term of 20 years.

Use of other fuels has also been proposed.

In the mean time, vide letter dt. 23.7.09, U.P. Sugar Mills co-gen association

requested to submit supplementary details and prayed for another date of

hearing. The Commission allowed them to make submissions by 20.8.09 vide

UPERC letter dated 31.07.2009 read with Public Notice dated 11.08.09. U.P. Sugar

Mills co-gen Association was also directed to serve a copy of the same on UPPCL.

In reference to the said letter, Co-gen Association, vide its letter dated

dt.19.08.09, has proposed that as against the earlier submission, the O&M

expenditure be reduced from 4% to 3%, Auxiliary consumption – from 10% to 9%

and ROE – from 18% post tax to 16% post tax as per CERC. Data for 33 units were

also submitted by the association.

Mawana Sugars submitted that PLF may be considered at 40%, the cost of

bagasse at market price, O&M expenditure as 5% of the capital cost, 10% auxiliary

consumption and RoE as 18% post tax return.

It also submitted that carbon credit benefits should be retained with the project

developer.

DCM Shriram consolidated limited submitted that there is no surety whether

Kyoto Protocol would be extended beyond the year 2012 and hence there should

not be any consideration of sharing of carbon credits. It also requested to reduce

the term of PPA from 20 years to 10 years and to allow electricity sale in the

market through open access.

U.P.Power Corporation Limited submitted its comments on determination of

tariff of bagasse based co-generation and generation from bio-mass vide its

affidavit dated 25.08.09 which is briefed as below:

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i. The limited review in respect of ROE, escalation factors and cost of fuel in

respect of existing plants should be taken for determination of tariff.

ii. PLF for bagasse based co-generation may be taken as 50% for recovery of

fixed charges by balancing commercial interests of stake holders albeit the

lowering of PLF would increase the tariff for the licensee. Only low

sugarcane production may not be taken as the basis for fixing PLF.

iii. SHR for bagasse based co-generation should not be changed.

iv. Notional cost of bagasse may be taken as Rs. 1370/MT with 6% escalation

in subsequent years.

v. Auxiliary Consumption and O & M expenses should not be changed.

vi. The capital cost for new bagasse based co-generation plants may be taken

as Rs. 4 Crore/MW with 3% escalation per annum and O & M expenses

may be taken as 4% of the capital cost.

vii. Due to non conducive financial situation, it would be extremely difficult to

bear the power purchase cost beyond Rs. 4/Unit. Therefore, the over all

tariff for the year 2009-10 should be restricted below Rs. 4/unit. For

subsequent years the escalation in fuel price may be allowed as per

previous norms.

C. Biomass based generating plants:

Anil Modi Oil Inds Ltd (AMOIL), Suhkbir Agro Energy Ltd (SAEL), Universal Bio-

mass Energy Pvt. Ltd, UPPCL and NEDA have made submissions under this

category.

Anil Modi Oil Inds Ltd (AMOIL) submitted that the milling of the paddy is done

between October/November to March/April and with a month stock of fuel,

working period would be not more than 210 days (7 months), therefore, the PLF

of around 66% may be considered. The auxiliary power consumption for biomass

based plants may be 10% and the capital cost for a new plant Rs. 5.50 Cr/MW

with escalation of 5% per year. The capital cost of transmission line may be

considered at an approx. amount of Rs. 0.40 Cr/km + Cost of bay etc. at the

substation end. It also submitted that ROE be considered at 16%, O & M

expenditure 4% of project cost and the rate of interest being 0.50-1.00 % points

above the SBI PLR. AMOIL further submitted that the average price of biomass for

the seven months of the season comes to approximately Rs. 2700/MT and the

average price for the remaining months is approximately Rs. 3450/MT, therefore

a higher tariff should be provided from June to October. AMOIL further submitted

that carbon credits should not be shared.

Suhkbir Agro Energy Ltd (SAEL) submitted that PLF of 70% may be considered for

determining the tariff for biomass based power plant and incentive be provided

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for achieving higher PLF of 80% and 90%. The auxiliary consumption may be

10.27% and the price of fuel be considered as Rs.2800/- per MT with escalation of

10%. SAEL has further submitted that it has recently completed and

commissioned (Jan 2009) its 15 MW biomass based power plant at a total capital

cost of Rs. 77.66 Crores (i.e. Rs. 5.18 Crores per MW) which might be considered

for tariff determination for biomass based generating plants. It is further

submitted that parameters of biomass co-generation plants are materially

different from bagasse based co-generation plants and therefore tariff of biomass

co-generation plants might be separately fixed for the current control period. In

letter dated 18th

May 2009, the capital cost of Rs 5 Cr/MW or actual capital cost is

suggested

Universal Bio-mass Energy Pvt. Ltd submitted that parameters in case of biomass

based generation plants are materially different from bagasse based co-

generation therefore be treated differently. It has suggested considering capital

cost - Rs. 5.2 Cr/MW, PLF - 65%, fuel price – Rs. 3000/MT, O & M – 5% of the

capital cost with 10% escalation and no sharing of carbon credit.

U.P. Power Corporation Limited submitted that the capital cost and other

parameters for the existing plants in biomass may not be changed. Due to non

conducive financial situation, the over all tariff for the year 2009-10 should be

restricted below Rs. 4/unit.

NEDA (Non-conventional Energy Development Agency) submitted that since cost

on transportation and labour in case of biomass is more than in case of bagasse, it

should be treated separately for tariff determination.

D. Canal based Small hydro generating plants:

No written submissions in this category have been received by the Commission.

E. Solar PV and Solar Thermal

Moserbaer made written submission dt. 22.4.09 for grid connected solar PV

projects other than covered under MNRE, GOI generation based incentive

scheme. It has submitted that the tariff for such projects may be fixed at Rs.

15/kwh for 20 years time frame due to techno commercial reasons. It also

pointed out that since National Solar Energy Mission is coming up, Gujarat, West

Bengal, Rajasthan and Haryana have already declared their State Solar Tariff

which has created a competitive atmosphere and investments have started

flowing in.

F. Other non-conventional energy source generating plants:

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On behalf of other non-conventional energy source generating plants, like

municipal waste, wind, industrial wastes (liquid, solid and gaseous) and biogas

etc., no written submissions in these categories have been received by the

Commission.

G. Comments on Draft Regulations & Model PPA:

U.P. Power Corporation Limited, vide its affidavit dated 25.08.09 submitted

comments on Draft Regulations and Model PPA. UP Cogen Association, vide its

letter dt. 27.8.09 has reacted on submissions of UPPCL. Comments of these

parties are detailed as below:

U.P. Power Corporation Limited

a) The additional power requirement within the scope of regulation 34 should be

limited to utilization/consumption for co-gen plant only and not for the sugar

unit.

b) The requirement of an additional CT/PT for check meter may be specified by

the Commission under regulation 35(2).

c) The rebate and surcharge as specified by CERC may be provided under

regulation 40 and a difference of 1% between cash and Letter of Credit (LC) be

maintained. On cash payment without opening LC, 2% rebate may be

provided.

d) The electricity duty paid on banked energy utilized by the generator should be

levied on generator only and such provision should be incorporated in PPA

under cl. 2.1.

e) Progress report during construction may be included under cl.18 of PPA.

f) Specific events of force majeure conditions may be mentioned under cl. 26.3

of PPA.

g) It is suggested as a new point that provisions for earnest money and

performance guarantee should be incorporated for timely completion and

faithful execution of PPA. There should also be penalty clause for delay in

completion.

UP Cogen Association

Point wise comments are as below:

a) Power plants are not separate entities and as such suggestion of UPPCL is not

acceptable that additional power requirement should be limited for use of co-

gen plant only.

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b) The matter regarding additional CT/PT is already settled by UPPCL and

therefore it does not require consideration.

c) The rebate in case of timely payment of bills other than through LC is 1%

under CNCE, 2005 and CERC also provides the same.

d) The withdrawal banked energy should not be treated as sale and hence no

electricity duty be levied. The generating plants should also be permitted

withdrawal out of banked energy during peak hours.

e) No comments.

f) The extension along with revised tariff based on the actual date of

commissioning should be mandated for protecting interests of co-generators.

g) The provisions for earnest money and performance guarantee would

retrograde the investment environment and would dissuade potential

investors. Any penalty imposed by party not having significant investment

may be termed as unfair as PPA is a mutual agreement and all terms and

conditions should be bilateral and equally applicable.

2.2 Submissions of Parties in the hearing

Draft “UPERC (Terms and Conditions for Supply of Power from Captive and Energy

Generating Plants) Regulations, 09” (in short the Draft Regulations) and a Paper

on Draft Regulations and Approach to Tariff (in short the Paper) were discussed in

the hearing on various dates. The deliberations are summarized as below:

A. Hearing dt. 15.05.09:

1. UPPCL submitted an application during the hearing requesting for extension

of date for one month. Sri D.D. Chopra, Advocate of the U.P. Co-gen

Association submitted that since UPPCL is the major stake holder, it would be

pertinent to allow them some time for submissions. The Commission allowed

UPPCL time up to 22.5.09 in view of the fact that after publication of notice in

the news paper had already provided adequate time of about 50 days for

making submission.

2. The Commission expressed concern over non submission of mandatory six

monthly reports and asked the co-generators to submit the report soon. Many

of the representatives of co-generators, accepting the deficiency, assured to

submit the report within one week but requested that the period of report

should be one year because six monthly data collection was a cumbersome

exercise which might take much more time in preparation. The Commission

directed them to submit the report considering period of report as one year.

Sri Pandey of UPPCL stated that it would be convenient to direct for

submission of only few data which were relevant for the case not the entire

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data as was given in the Regulations. The Commission directed to submit the

relevant data by 20.5.09.

3. The parties present in the hearing were allowed to make oral submissions.

The representatives of UP Co-gen Association, Dalmia Chini Mills, Hindalco,

Mawana Sugar Ltd., Sukhbir Agro Energy Ltd., Anil Modi Oil Ind. Ltd. (AMOIL),

Abhinav Steels Pvt. Ltd. and Bajaj Hindustan Ltd. reiterated their written

submissions.

4. The Commission fixed the next date of hearing for 25.05.09.

B. Hearing dt. 25.05.09:

In compliance to direction issued on 15.5.09, the 16 co-generators submitted the

information/ data.

In the hearing, UPPCL did not appear. UPPCL being main stake holder, the parties

present prayed the Commission for rescheduling of date with a direction to

UPPCL to submit comments to the submission made by them. The Commission

fixed the next date of hearing for 27.5.09 vide order dated 25.05.09.

C. Hearing dt. 27.05. 2009:

During the hearing on 27th

May 2009, the Commission expressed discontent over

insufficiency and inconsistency of data submitted by bagasse based co-generators

for the period 05-06 to 08-09.

UPPCL sought adjournment of the hearing till September 2009 on following

grounds:

i. The retail tariff for consumers for the present year had not been decided

yet.

ii. The average tariff including service cost is about Rs.2.88/unit and to bear

the additional cost arising out of revision of Regulation and tariff of

cogeneration, the retail tariff should be finalised first.

iii. The sugarcane production in the year 08-09 has been exceptionally low

resulting in abnormally low bagasse production. Therefore, year 08-09

should not be considered while finalizing the Regulation.

The Commission found none of the above a reasonable or justified ground for

adjournment till September, 2009 and hence decided to continue with the

process.

D. Hearing dt. 27.08.09:

1. Shri K.N. Ranasaria, Co-Gen. Association, submitted that the representation

made by UPPCL is in-toto acceptable to them except the issue of PLF. As it is

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evident from the submitted data and Government report that the cane

production in preceding years has declined sharply and there is crisis of

bagasse in the market therefore, the Co-generators are not in a position to

maintain PLF more than 40%. Hence the Co-gen association has demanded

40% PLF for fixed cost recovery whereas, UPPCL has demanded 50%.

2. Shri Pankaj Rastogi, Dy. ED., Dalmia Chini Mills, on behalf of Co-Gen.

Association, submitted the following comments on model PPA submitted by

UPPCL:

a) There should not be requirement of an additional CT/PT which is an extra

burden on generator.

b) The rebate in case of timely payment of bills should remain same i.e. 1%.

c) Electricity taken back out of banked energy should not be levied with

electricity duty as it is the energy been generated for self use only.

d) The payment conditions in case of force majeure should be more clear.

e) The proposed conditions of earnest money and performance guarantee

will not be in harmony with the status between generator and the

licensee. It may also hamper the progress in generation of electricity from

non-conventional sources in the State. The restriction for below 5 MW

units should not be incorporated.

3. Shri Durga Prasad, Co-Gen. Association, reiterated the facts and figures

submitted by Co-Gen. Association and said that it would be in the interest of

development of generation of electricity from non-conventional sources to

consider hike in the prices as the generators are not able to recover the cost

on present prices.

4. Shri M. L. Arora, GM, Sukhbir Agro Energy Ltd. prayed that the tariffs was

impractically low resulting in huge losses to them every month since they

started generation. He explained that bio-mass fuel was a voluminous

material and requires huge cost on man power and transportation in

comparison to bagasse. He also stated that till date Sukhbir Agro Energy Ltd.

was the only plant based on bio-mass in the State and since the tariff was so

low no other generator will dare to venture in this field. Therefore, the tariff

for bio-mass generation should be revised to the tune of not less then Rs. 5.0

– Rs.5.50 per unit. On a specific query regarding firm agreement for supply of

rice husk (the fuel) for generation in its plant, Shri Arora informed that their

company had no firm agreement for supply of rice husk with any person. Shri

M. L. Arora further submitted that since the prices in the market were

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changing fast; therefore the control period of the Regulations should not be

more than 2-3 years.

5. Shri Sudhir Kumar, Director, NEDA expressed the view that the generation on

bagasse was fundamentally different from the generation from other bio-

mass. The raw material in case of bagasse was available in the plant itself as it

was a by product of sugar production. Whereas, in case of bio-mass (which

varies in nature and properties commercially and chemically as fuel) the area

for collection of raw material was much larger than bagasse because of that,

the generator had to make more investment in plant so that it could be used

on various biomasses available for generation when it exhausts biomass fuel

exclusively produced in its own process. Therefore, it was required to consider

the tariff of generation on bio-mass and bagasse separately. He also pointed

out that there were many other bio-mass by-products besides rice husk such

as ground nut husk, wheat husk etc. which might be used for generation of

electricity and if the tariff was lucrative then many new generators might take

up generation based on rice husk and other bio-mass bi-products.

6. Shri S.K. Agarwal, Director (Finance), UPPCL, informed that they had a meeting

with Secretary (Sugarcane), UP Government regarding production of

Sugarcane in the State. The Secretary showed concern over declining

production of sugarcane. The co-generators had registered low PLFs in the

preceding years. That might be due to low production of sugarcane as well as

oversized plant capacities. The generators at the stage of conceptualization

might not have correctly estimated the availability of bagasse with them while

deciding higher capacity of plant resulting in low PLFs. Further, Shri Agarwal

made following points:

a) The normative PLF for cost recovery under present Regulations was

considered as 60%. In view of lower production of sugarcane and

concerns of co-generators, UPPCL proposed normative PLF as 50% for

fixed cost recovery.

b) The historical data shows that there was no need to change calorific value

and auxiliary consumption and should remain as was given under present

Regulation.

c) On the issue of payment of bills and rebate, the CERC Regulations should

be followed.

d) The electricity duty was a matter pertaining to the Government and if

there was something to be clarified, it was to be clarified from the Govt.

only.

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He also pointed out that the scope for increase in tariff was limited as the

company was not in very sound financial condition and in such a scenario they

would not be able to purchase electricity from bagasse / bio-mass at more

than Rs. 4.00 per unit.

7. The Commission observed that although UPPCL had addressed most of the

issues raised by the co-generators; yet neither the co-generators nor UPPCL

proposed incentive. Shri S.K. Agarwal stated that the incentive scheme had

not been considered separately since they had the opinion that the incentive

scheme as provided in the previous Regulations should remain unchanged and

was acceptable to them. Shri K.N. Ranasaria stated that incentive should be

given for achieving more than 50% PLF. Shri S.K. Agarwal stated that the lower

PLF is acceptable to them only in view of shortage in agricultural production of

sugarcane. It has nothing to do with the performance level and so, it did not

mean that the reduced level of performance was acceptable. Therefore, he

suggested that the incentive should be allowed only above 60% PLF.

8. As far as bio-mass is concerned, Shri S.K. Agarwal stated that the tariff slightly

higher than Rs. 4.00 might be considered. Shri Sudhir Kumar, Director, NEDA

stated that if the tariff declared for generation from bio-mass other than

bagasse was not competitive and not acceptable to the generators then, they

might desire to export power to consumers in other states at higher rates.

9. The issue of withdrawal of electricity from the banked energy during peak

hours was raised by Representative of Co-gen association to which Shri S.K.

Agarwal replied that U.P. was already facing critical power shortage during

peak hours and in such a situation they were not in a position to release

banked power during peak hours. He further stated that since the issue of

banking was not related to tariff, it might be taken up separately by the

Honourable Commission on a petition exclusively filed by the generators. On

the objection raised by generators that the issue of banking was an integral

part of Regulations and could not be separated, Sri Agarwal replied that the

order made in that regard might be made a part of the Regulations.

Representative of co-generators agreed to the suggestion.

10. Sri S.P. Pandey, E.E., UPPCL, raised the issue of withdrawal of excess power by

the generators beyond that the agreed between the parties under the PPA. As

the power available with the licensee was not sufficient for adequate supply

to the consumers of the area, such huge over drawl would make the situation

worse. He pointed out that on many occasions generators were drawing

power to the tune of almost the contracted capacity for supply. It seemed

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that generators were using this drawl power for sugar process besides running

the necessary auxiliaries. He requested that the generators should be

restricted to take power only for auxiliaries and not for other purposes. Sri

Durga Prasad, Co-Gen. Association, submitted that in some instances , a

generator might have misjudged its power requirement at the time of when

PPA was entered and so it should be given at least one opportunity to revise

its load. Sri Pandey did not agree and stated that any request for the

extension of agreed load under PPA should not be entertained.

In consideration of written and oral submissions made by the parties, the

Commission proceeds to determine tariff and other issues.

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3. LEGAL FRAMEWORK, DEVELOPMENT IN CAPACITY ADDITIONS , COMMON ISSUES ARISING OUT OF

DRAFT REGULATIONS AND MODEL, CERC DRAFT REGULATIOS, PROJECT SPECIFIC TARIFF AND

COMMON FINANCIAL PARAMETERS

3.1 Legal Framework

Section 61 of the Electricity Act, 2003 (in short the Act) provides that the

Appropriate Commission shall, subject to the provisions of this Act, specify the

terms and conditions for the determination of tariff, and in doing so, 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; the generation, transmission, distribution and supply of

electricity are conducted on commercial principles; the factors which would

encourage competition, efficiency, economical use of the resources, good

performance and optimum investments; safeguarding of consumers' interest and

at the same time, recovery of the cost of electricity in a reasonable manner; the

principles rewarding efficiency in performance; multi year tariff principles; that

the tariff progressively reflects the cost of supply of electricity and also, reduces

and eliminates cross-subsidies within the period to be specified by the

Appropriate Commission; the promotion of co-generation and generation of

electricity from renewable sources of energy; the National Electricity Policy and

tariff policy.

Section 86 (1) (a) of the Act provides that the State Commission shall determine

the tariff, among others, of generation.

Further, Section 86(1) (e) of the Act specifically provides for promotion of

cogeneration and generation of electricity from renewable sources of energy by

providing suitable measures for connectivity with the grid and sale of electricity to

any person, and also specify, for purchase of electricity from such sources, a

percentage of the total consumption of electricity in the area of distribution

licensee.

The National Electricity Policy provides under clause 5.12, in respect to Co-

generation and non-conventional energy sources as below:

5.12.1 Non-conventional sources of energy being the most environment friendly

there is an urgent need to promote generation of electricity based on such sources

of energy. For this purpose, efforts need to be made to reduce the capital cost of

projects based on non-conventional and renewable sources of energy. Cost of

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energy can also be reduced by promoting competition within such projects. At the

same time, adequate promotional measures would also have to be taken for

development of technologies and a sustained growth of these sources.

5.12.2 The Electricity Act 2003 provides that co-generation and generation of

electricity from non-conventional sources would be promoted by the SERCs by

providing suitable measures for connectivity with grid and sale of electricity to any

person and also by specifying, for purchase of electricity from such sources, a

percentage of the total consumption of electricity in the area of a distribution

licensee. Such percentage for purchase of power from non-conventional sources

should be made applicable for the tariffs to be determined by the SERCs at the

earliest. Progressively the share of electricity from non-conventional sources

would need to be increased as prescribed by State Electricity Regulatory

Commissions. Such purchase by distribution companies shall be through

competitive bidding process. Considering the fact that it will take some time

before non-conventional technologies compete, in terms of cost, with

conventional sources, the Commission may determine an appropriate differential

in prices to promote these technologies.

5.12.3 Industries in which both process heat and electricity are needed are well

suited for cogeneration of electricity. A significant potential for cogeneration

exists in the country, particularly in the sugar industry. SERCs may promote

arrangements between the co-generator and the concerned distribution licensee

for purchase of surplus power from such plants. Cogeneration system also needs

to be encouraged in the overall interest of energy efficiency and also grid stability.

Clause 6.4 of tariff policy states among other things that it will take some time

before non-conventional technologies can compete with conventional sources in

terms of cost of electricity. Therefore, procurement by distribution companies

shall be done at preferential tariffs determined by the Appropriate Commission.

In the long-term, these technologies would need to compete with other sources

in terms of full costs.

In respect to captive generating plants, National Electricity Policy provides under

clause 5.2.26 that a large number of captive and standby generating stations in

India have surplus capacity that could be supplied to the grid continuously or

during certain time periods. These plants offer a sizeable and potentially

competitive capacity that could be harnessed for meeting demand for power.

Under the Act, captive generators have access to licensees and would get access

to consumers who are allowed open access. Grid inter-connections for captive

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generators shall be facilitated as per section 30 of the Act. This should be done on

priority basis to enable captive generation to become available as distributed

generation along the grid. Towards this end, non-conventional energy sources

including co-generation could also play a role. Appropriate commercial

arrangements would need to be instituted between licensees and the captive

generators for harnessing of spare capacity energy from captive power plants.

The appropriate Regulatory Commission shall exercise regulatory oversight on

such commercial arrangements between captive generators and licensees and

determine tariffs when a licensee is the off-taker of power from captive plant.

The tariff policy under clause 6.3 states, inter-alia, that harnessing captive

generation Captive generation is an important means to making competitive

power available. Appropriate Commission should create an enabling environment

that encourages captive power plants to be connected to the grid and such

captive plants could inject surplus power into the grid subject to the same

regulation as applicable to generating companies. Firm supplies may be bought

from captive plants by distribution licensees using the guidelines issued by the

Central Government under section 63 of the Act and Grid connected captive

plants could also supply power to non-captive users connected to the grid

through available transmission facilities based on negotiated tariffs. Such sale of

electricity would be subject to relevant regulations for open access.

In light of above powers, provisions of National Electricity Policy and Tariff Policy,

the Commission made “Uttar Pradesh Electricity Regulatory Commission ( Terms

and Conditions for Supply of Power and Fixation of Tariff for sale of power from

Captive Generating Plants, Co-generation Plants, Renewable Sources of Energy

and Other Non-Conventional Sources of Energy based Plants to a Distribution

Licensee) Regulations, 2005” which came with effect from 28-07-2005. For

reasons stated above, the said regulations are being reviewed to bring about new

regulations to be called “UPERC (Terms and Conditions of Supply of power from

Captive and Non-conventional Energy Generating Plants) Regulations, 09.” In this

review, the Commissions shall be guided by the said provisions.

3.2 Developments in generation from captive and non-conventional Sources

CNCE Regulation’s 2005 have been enforced for about four years and the

developments during this period may be brought out in the following paragraphs.

The generation from non-conventional and renewable sources of energy in the

state of Uttar Pradesh comprises mainly bagasse based co-generation. At present,

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about 800 MW of electricity is being supplied by the bagasse based generating

plants to the licensees and for about 225 MW projects are under construction.

Only One 15 MW plant based on rice husk has recently started generation and

supplying electricity to the licensee. Other biomass based generating plants like

cane trash, toppings of eucalyptus, groundnut husk etc. have not come up.

Four power purchase agreements have been signed by UPPCL for purchase 350

KW power from solar power plants of NEDA at rate specified by the Commission

in CNCE Regulations. The Commission revised the tariff of solar plants to reap the

benefit of Central Government incentive scheme for promotion of solar

technology. This revised tariff has also undergone several revisions but grid

connected Solar generation at MW level is yet to take off in the State.

Generation from Municipal Solid Waste has not been a success across the

country. In UP, projects, as on 2004, have been identified at Kanpur (21.6 MW),

Meerut (10.8 MW), Bareilly (5.4 MW), Varanasi (10.8 MW), Allahabad (7 MW) and

Agra (12 MW). Asia Bio-energy (I) Ltd., Chennai developed a 5 MW MSW based

plant in Lucknow but could not generate more than 2 MW for want of adequate

fuel. Now this project has been closed due to non availability of fuel. The energy

potential assessment, waste transportation and segregation of fuel from non-

biodegradable waste are critical to the success of such plants. Emphasis is

required in this area where the energy assessment should be based on not less

than 90% of fuel dependability and efficient transportation system with active

participation of Municipal Corporations to help the plant in getting segregated

biodegradable wastes from houses, hotel, restaurants, food industries and fruit &

vegetable mandis etc. Co-ordinated efforts by all concerned have to be made in

development of this source of energy for conservation of conventional fuels and

cleaner environment.

Bio-gas, Industrial waste and Wind based electricity generating plants have not

yet come come-up.

NEDA has identified sites along the UP canal system for generation of about 167

MW. The Commission specified tariff for canal based hydro electric generating

stations, the capacity additions at specified locations is yet to take place.

M/s Hindalco and M/s Kanoria Chemicals & Industries Ltd. are known captive

power plants supplying surplus electricity to distribution licensee. Although CNCE

Reg. makes provision for every captive generating plant in the State, whether

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connected or not connected with the grid and supplying or not supplying

electricity to distribution licensee, to register its presence by submitting

information to the Commission in appropriate format provided with the said

regulations, yet no information has been received from any captive power plant.

The Commission, in view of the said developments, shall endeavour to make

provisions in the new regulations to further promote the said sources of

generation.

3.3 Decisions on common issues arising out of draft Regulations and model PPA

Before decision is taken on the issues relating to determination of tariff, the

Commission decides to settle certain issues which are common in nature.

3.3.1 Control Period:

CNCE Regulations 2009 is proposed to come in force for five years. Some parties

have suggested that this control period should be reduced to two or three years

to capture the market changes especially in respect to cost of fuel. It may be

appreciated that CNCE Regulations 2005 had been in operation for about four

years, as on date, and no difficulty was expressed during this period by any of the

generator that the escalation factors specified for fuel cost escalation had been

inadequate except for stated price rise or unavailability of bio-fuel due to reduced

crop on account of failure of monsoon or for any other reasons. Such

unavailability is not a routine occurrence and can not be made a cause to reduce

the control period as suggested. If, for argument sake, the Commission decides to

reduce the control period to two or three years as suggested, the long

consultative process of about a year in making regulations would keep engage

every stakeholder and interested parties including the Commission in consultation

rather than on focusing on promotion of the non-conventional energy sources.

The object before the Commission is to create an environment of certainty in the

market for promotion of these sources and the short control period would be

detrimental to such an endeavour as such the Commission decides that control

period for new regulations would remain five years.

3.3.2 Period of PPA:

Parties have suggested that term of PPA should be reduced to ten years from

existing twenty years. The Commission in order dated 18.7.2005, passed during

the process of making CNCE Regulations,2005 had held that the front loading of

the depreciation was to enable the developers to repay the loan and the benefit

of lower tariff in subsequent years should be passed on to the consumers and

decided a fixed term of PPA as 20 years. The generators who have PPAs for

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supplying electricity to the distribution licensees have enjoyed the benefit of front

loaded depreciation and would continue to enjoy the same in future also. As for

the new generators, the Commission holds the same view as taken in order dated

18.7.2005 for payment of loans. Reduction in period of PPA would not safeguard

the interest of the consumers and the distribution licensees as they would not be

able to reap the benefit of lower tariff which they otherwise deserve to enjoy

after paying front loaded depreciation. In order to balance the interests of

generators, distribution licensees and the consumers, the Commission is not

impressed to reduce the period of PPA as suggested and is of the view to retain it

as 20 years.

3.3.3 UPPCL has suggested that power purchase by a generating plant from a

distribution licensee under proposed regulation 34 should be for use of co-

generation plant and not for sugar plant. The Commission opines that the said

provisions have been made for ‘own use’ of the plants which means that the

purchased power could be used for sugar process also. The first proviso to the

said regulation provide that such purchase of electricity shall be charged as per

the tariff determined by the Commission under appropriate rate schedule of tariff

under which the total load requirement of the plants belong to. The provisions

made under regulation 34 should not be confused with the provisions of

withdrawal of banked energy made under regulation 39. In view of above no

change in regulation 34 is considered.

3.3.4 UPPCL has requested to include the requirement of additional CT/PT for check

meter under regulation 35(2) whereas; UP Co-gen Association has objected as

saying that the matter has already been resolved by UPPCL. As such no change is

considered in the regulations as suggested by UPPCL.

3.3.5 Issues have been raised as to the rate of rebate and surcharge as said before.

Parties are agreed to CERCs norms. The Commission has made UPERC (Terms and

Conditions of Generation Tariff) Regulation 2009 which provides for a rebate of

2% on payment through LC and through other mode at 1%. Late payment

surcharge is at 1.25% per month for payment delayed beyond the period of two

months. Regulation 40 of draft CNCE Regulations, 2009 shall be modified

accordingly in order to bring uniformity among various regulations relating to

supply of electricity by generating companies.

3.3.6 UP Co-gen Association is pleading that electricity duty on withdrawal of banked

energy should not be levied while UPPCL holds that it is a matter concerned with

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the Government. The electricity duty is levied by the State Government on

consumption of electricity and the withdrawal of banked energy and its

consumption thereof falls under the category of ‘Consumption of Electricity’.

Since this is a matter in the domain of the State Government, aggrieved party may

raise the issue at appropriate forum.

3.3.7 UPPCL wants that the progress report under construction should be submitted by

a generating company with the distribution licensee under clause 18 of PPA. UP

Co-gen Association or any other person has not reacted on this issue. This is an

important report which would enable the Commission to investigate the matter

more effectively, if any issue arises before it regarding delay in commissioning of

the plant and force majeure clause is invoked by the generating company

pleading for hire tariff. Clause 18 of model PPA shall be modified accordingly.

3.3.8 UPPCL suggests specifying the events of force majeure conditions. UP Co-gen

Association is pleading that revised tariff based on extended date of

commissioning should be allowed. The parties must note that the generation

project is planned with all due cares and date of commissioning is fixed

accordingly and it is agreed in PPA by the generating company with the

distribution licensee that the benefit of the plant shall accrue to such distribution

licensee with effect from the agreed date of commissioning. Therefore, the

generating companies must carefully plan the project and its date of

commissioning so that it does not slip from the target date. In view of above no

change is contemplated in clause 26 of model PPA.

3.3.9 UPPCL is suggesting incorporation of new clause of earnest money and

performance guarantee in PPA to which UP Co-gen Association has objected.

Parallels cannot be drawn in case of PPAs entered under the proposed

Regulations with the PPAs signed between the parties in case of competitive

biddings under section 63 of the Act. Adequate measures to safeguard interests

of consumers and distribution licensee from delayed commissioning have been

taken in clause 16 of the model PPA. Therefore, the Commission does not

consider yielding to the suggestion of UPPCL for inserting a new provision to that

effect.

3.3.10 UPPCL has raised the issue of withdrawal of banked energy at MW higher than

declared by co-generators. UP Co-gen Association argues that they be allowed to

revise the declared load because in certain cases some plants have misjudged at

low level at the time of PPA. Provision of banking of energy in case of

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cogeneration, renewable and non-conventional energy sources based plants is for

its withdrawal in the event of emergency or shutdown or maintenance of the

plant. In all such eventualities, the maximum load requirement should not exceed

the load of all auxiliaries and colony load. Auxiliary consumption has been fixed at

8.5%. Therefore, the maximum rate of drawl of banked energy shall not be in

excess of the plant unit capacity(ies), out of which contracted capacity has been

agreed in PPA, multiplied by the factor Auxiliary Consumption plus 0.5% to

(account for colony load) subject to maximum of contracted capacity.

3.3.11 Metering and Transmission line losses:

The Commission recognises that the metering of Non-conventional fuel based

generating plants are at sub-station end and in the process, there is a

transmission loss incurred by the plant which needs to be legitimately

compensated. While determining the tariff, to compensate such losses the

Commission decides as below:

While calculating the energy billed, the meter reading in MWH taken at

substation shall be multiplied by a factor as follows to compensate the

transmission losses (the line losses to be taken as percentage per km/MW).

Multiplying Factor = 100 / (100 - 0.001 x L x C.C.)

L = Length of line in km

C.C. = Contracted Capacity in MW

Loss factor = 0.001/km/MW

Proposed regulation 37 shall be modified accordingly.

3.3.12 UPPCL is praying to specify force majeure events. These are already defined in

detail under clause 26 of model PPA as such no reconsideration is required.

3.3.13 Sharing of Clean Development Mechanism (CDM) Benefits:

Many of the stakeholders during the hearings have proposed that the earnings of

the CDM benefits should be exclusively retained with the generator. The

Commission in UPERC (Terms and Conditions of Generation Tariff) Regulation,

2009 has followed the principles made by the CERC. Therefore, the Commission

decides to follow the same which is as given under:

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a) 100% of the gross proceeds on account of CDM to be retained by the project

developer in the first year after the date of commercial operation of the

generating station;

b) In the second year, the share of the beneficiaries shall be 10% which shall be

progressively increased by 10% every year till it reaches 50%, thereafter the

proceeds shall be shared in equal proportion, by the generating company and

the beneficiaries.

3.3.14 The captive generating Plants and co-generators have pleaded for the withdrawal

of banked energy during peak hours while UPPCL opposed on account of huge

shortage in peak and high cost of power purchase during these hours. The

Commission is convinced with the argument of UPPCL that for commercial

reasons and for obligations of distribution licensees to supply electricity to

consumers, the withdrawal of banked energy can’t be allowed during peak hours.

Thus, these plants are advised to plan their commercial operations accordingly.

3.3.15 Kanoria Chemicals and Industries Ltd is seeking rise in maximum ceiling of banking

from 50% to 75% in view of the nature of their industry. The Commission while

reviewing order dated 18th

July 2005, so far as concerned with banking of power,

had an order dated 12th Jan 2006 (Passed in Review Petition No. 282, 285, 286,

287 , 288 of 2005) whose clause 2.4 states that:

“It is observed in the provisions of banking specified in order dated 15.9.05 that

linking of withdrawal of banked energy with grid frequency may not deliver the

results as the generating plants, which have no control over the frequency, shall

not be in a position to plan the withdrawal of banked energy. Therefore,

Commission decides to do away with the condition of frequency for withdrawal of

energy.

Captive generating plants, setup and operated by industry, are mandatorily

required to consume a minimum of the total 51% of generation for their self use

on an annual basis. The Central Govt. in National Electricity Policy requires the

Regulatory Commission to specify the commercial arrangement between the

captive generating plant and the licensee for harnessing surplus power. Since,

industrial processes are such that they may not require supply of power

continuously at a constant load, therefore captive generating plants connected

with the grid, shall have option of exchange of power with the grid unless they

regulate their own generation. The regulation of generation would not be

desirable, as that would deprive the State of surplus power, which could otherwise

be made available to consumers. We are of the opinion that if the surplus capacity

of generating plant is to be harnessed, it would be imperative that the plants are

allowed to exchange energy with the grid on real time basis and an option also be

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given to captive generator and licensee to agree for supply of power from such

plant and consider a part of such energy as banked energy with the Licensee for

drawing back subject to conditions laid down by the Commission for that purpose.

Therefore, the Commission decides to specify a separate scheme of banking for

captive generating plants as such the provisions of banking as specified for captive

generating plants in order dated 15.9.05 shall not apply on such plants.”

In view of the said decision, the captive plants and distribution licensees

depending on nature of industry may agree to the extent of 75%.

3.3.16 The generating companies have to submit the required information’s as specified

at Annexure 2 & 3 of existing regulations. These reports are to be submitted on

half yearly basis. It has been pointed out by the generators during the hearings

that collection of data on half yearly basis is a cumbersome exercise which could

be avoided by making it a yearly submission. The Commission finds it appropriate

and decides to make it a yearly submission. Necessary amendments shall be made

under Proposed Regulations 13 & 28.

3.3.17 At the time of making CNCE Regulations 2005, no generator producing power

from biomass was present and no data was available from this source to enable

the Commission to determine tariff separate for biomass based plants. Therefore,

the Commission decided to consider the tariff of biomass based generation same

as that of bagasse based co-generation. The Non-conventional Energy

Development Agency (NEDA), the agency responsible for development of non-

conventional energy sources in the state has proposed to consider biomass based

energy as a separate category for the accelerated development of biomass based

generating plants. The Commission agrees to the suggestion of NEDA and decides

to determine tariff for this source separately.

3.3.18 There is only one plant of 15 MW, operated by Sukhbir Agro Energy Ltd., based on

biomass (rice husk) in the state commissioned during FY 2008-09. The

representative of the generating plant has mentioned that in the present tariff

structure, the plant operations are not financially viable. It has also mentioned

that the plant is incurring huge losses due to low tariff. UPPCL has submitted that

capital cost and other parameters for existing plants should not be changed. It

may be recalled that tariff of this source was considered by the Commission with

capital cost and other parameters at par with the bagasse based co-generation

plants. As such it would be unfair not to reconsider them when some data and

representation from this source is available. UPPCL might be objecting on

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economical considerations but it would be in the interest of UPPCL, State and the

consumers that all norms including capital cost of this source be reviewed and

tariff determined separately to encourage capacity addition from biomass other

than bagasse as fuel. Considering the above facts, the Commission decides that

the parameters for fixation of tariff for existing biomass based generating plants

shall be the same as decided for the new plants. The capital cost approved for

new projects for FY 2009-10 shall be de-escalated by the approved rate of capital

cost escalation to arrive at capital cost for FY 2008-09. Accordingly, the tariff for

the plants commissioned in FY 2008-09 shall be fixed for FY 2009-10 to FY 2013-

14.

3.3.19 As far as the development in the category of captive generating plants in the state

is concerned, the picture is dismal. No addition in captive capacity has come to

the knowledge of the Commission as on date. There are few plants that have

completed more than 10 years of operations. In view of above, the Commission

decides that apart from fixing tariff for new & existing captive power projects, it

would also determine tariff for the captive plants that have been commissioned

prior to 2005-06 and have discharged its debt liability.

3.3.20 Under CNCE Regulations 2005, the generation plants and the dedicated

transmission line had been considered as a composite project and accordingly the

sum of capital cost of generating plant & dedicated transmission line was

considered for tariff determination. There had been petitions filed before the

Commission by bagasse based co-generation plants seeking permission to

evacuate power from their plants by solid tapping of nearby 132 KV line of the

transmission company because commissioning of dedicated transmission line had

been delaying for various reasons. In number of cases; the commission allowed

such arrangement to operate during certain period of time. It is noticed that

during the course of time that repeated extensions of time had been sought

compelling the Commission to infer that temporary arrangements are becoming

permanent in nature. The Commission finds that construction of dedicated

transmission line is exclusively a duty of generating company. The cost of

transmission system is built-in the tariff and in case the evacuation through

temporary arrangements is allowed by the Commission, the fixed cost

attributable to line should not be reimbursed by the distribution licensee or for

that matter by the consumers. Therefore, the Commission decides that in case of

evacuation through temporary arrangements, the applicable fixed cost in the

tariff shall be reduced by the proportion of the approved cost of transmission

system. The applicable tariff in such cases shall be decided on case to case basis

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by the Commission. Accordingly, the amendments shall be made in proposed

regulations 35.

3.3.21 The Commission in the order dated 15.9.2005 has mentioned that tariff is fixed

for five (5) years. The relevant para is reproduced as below:

“The tariff determined pursuant to this order shall be effective from 28.7.05 for five

years and shall be applicable on the plants existed as on 27.7.05 and that would be

commissioned during the said five years. The Commission may review tariff of

these plants after expiry of the said five years. Such review shall be limited to

return on equity, escalation factors and cost of fuels to such plants existing at the

end of the said five years.”

Therefore, fixed cost and variable cost of such plants shall be determined with

due consideration of change in ROE, escalation factors, fuel cost and interest on

working capital for new control period as decided by the Commission under this

order.

3.4 CERC Draft Regulations 2009 on Renewable Energy

CERC in exercise of its powers conferred u/s 178 of EA 2003 and all other powers

enabling it in this behalf has issued Draft Regulations 2009 for Tariff

Determination from Renewable Energy Sources for comments from various

stakeholders. Though the regulations are in draft stage, the Commission has

analysed the various parameters and information available for consideration of its

order on NCE sources. The general principles applicable to all NCE sources are

provided in the table below:

Page 27

Table 1: General Principles for Renewable Energy Sources - CERC

Cost Elements Financial Principles

Debt Equity Ratio 70:30%

Loan Tenure 12 years

Interest Rate SBI - LT PLR + 100 basis pts

Depreciation 6% for first 12 yrs

17% pre-tax for first 10 yrs

23% pre-tax 11th yr onwards

Working Capital

(Wind/SHP)

O&M - 1 mth, Receivable - 1.5 mths, Spares -

15% of O&M Exp

Working Capital

(Biomass)

Fuel-4 mths, O&M - 1 mth, Receivable - 1.5

mths, Spares - 15% of O&M Exp

Interest WC Avg SBI - ST PLR for FY0809

O&M Escalation 5.72% p.a.

CDM Benefits 1st yr - 100% to Developer, From 2nd yr -

10% reduction to developer till beneficiary

gets 50% and therafter equal proportion.

CERC Draft Regulations 2009 - NCE

RoE

3.4.1 Specific Parameters for Bagasse based Cogen plants

The specific parameters proposed by CERC for Bagasse based Cogen plants are

outlined in the table below:

Table 2: Specific Parameter for Bagasse Plants - CERC

Cost Elements Parameters

Capital Cost Rs.4.45 Crs/MW linked to Indexation formula

PLF 60% (180 days during crushing season and 60

days during off-season)

Aux Cons 8.50%

SHR 4000 kCal/kWh

O&M Expn Rs.13.35 lakh/ MW

Calorific Value 2250 kCal/kg

Fuel Cost Diff for diff states with 5% escalation p.a. at

the option of developer or index formulae.

Rs.953/ MT for U.P.

CERC Draft Reg 2009 for Bagasse Project (Non fossil)

3.4.2 Specific Parameters for Biomass Power Plants

The specific parameters proposed by CERC for Biomass power plants are outlined

in the table below:

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Table 3: Specific Parameter for Biomass Plants - CERC


Capital Cost Rs.4.50 Crs /MW linked to Indexation formula

PLF During Stab - 60%, During first yr after Stab -

70% and from 2nd yr onwards - 80%

Aux Cons 10.00%

SHR 3650 kCal/kWh


Calorific Value Diff for diff states. 3371 kcal/kg for U.P.

Fuel Cost Diff for diff states with 5% escalation p.a. at

the option of developer or index formulae.

Rs.1428/MT for U.P.

CERC Draft Reg 2009 for Biomass Project

3.4.3 Specific Parameters for Small Hydro Plants

The specific parameters proposed by CERC for Small Hydro Plants are outlined in

the table below:

Table 4: Specific Parameter for Small Hydro Plants – CERC


Capital Cost Rs.5.00 Crs /MW linked to Indexation formula

CUF HP, UK & NE States - 45% and for other states -

30%

Aux Cons 0.50%


CERC - Draft Reg 2009 for Small Hydro Project

CERC has not concluded norms however the Commission would keep the draft

proposal in mind while taking decision on determination of tariff.

3.5 Project Specific Tariff

The tariff for captive, bagasse based cogeneration and biomass based generation

plants shall be sum of fixed cost and variable cost which will be constituted by the

following factors:

I. Fixed cost components

a) Return on equity;

b) Interest on loan capital;

c) Depreciation;

d) Interest on working capital;

e) Operation and maintenance expenses

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II. Variable cost component shall be the fuel cost.

However tariff for Solar, Small hydro, industrial waste, municipal waste and Wind

(if any in the State) energy sources based plants, the tariff shall be single part.

The general financial parameters for captive and Non-conventional energy source

based plants are discussed in the subsequent section.

3.6 Financial Parameters Common for all CNCE Plants

Although, the participants to this proceedings have proposed different

parameters in their written or oral submissions. But, the Commission decides to

follow uniform approach in respect to the parameters concerned with the fixed

cost except ROE and O&M, which shall be decided under specific cases.

3.6.1 Capital Cost Escalation

The Commission shall determine capital cost for each of the CNCE plants in the

subsequent paragraphs. However the capital cost shall be escalated by 3%

(simple) for each of the subsequent years on the base capital cost of FY 2009-10.

3.6.2 Debt Equity Ratio

Debt-Equity Ratio of 70:30 shall be considered for the purpose of tariff

determination.

In case, tariff is determined on case to case basis, above principle will apply

subject to following:

I. If the equity actually deployed is more than 30% of the capital cost, equity

in excess of 30% shall be treated as normative loan.

II. Where equity actually deployed is less than 30% of the capital cost, the

actual equity shall be considered for determination of tariff.

3.6.3 Loan Tenure

For the purpose of determination of tariff, loan tenure of 10 years shall be

considered.

3.6.4 Interest on Loan

The Interest on loan shall be computed on 70% debt component of capital cost.

The Paper has proposed average PLR of SBI during FY 2008-09 with suitable

adjustments for tariff period be considered as normative rate of interest for new

plants. For old plants, no change is proposed. The average Prime Lending Rate

(PLR) of State Bank of India (SBI) during FY 2008-09 has been 12.80% p.a. In view

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of above, Commission hereby approves above rate of interest on Loan for

determination of tariff whereas for existing plants rate of interest shall not

change which was at 10.25% p.a.

3.6.5 Depreciation

The Commission would continue with current practice of allowing 70% of the

depreciation to be recovered in first 10 years and the balance, spread over

remaining useful life of the asset. However the total allowable depreciation would

not be more than 90% of the historical cost of asset. Accordingly depreciation for

first 10 years would be 7% p.a.

3.6.6 Interest on Working Capital

The Working Capital requirement in respect of Captive Power Plants, Bagasse,

Biomass and Small Hydro Power projects shall be computed in accordance with

the norms mentioned below:

I. Captive Power Plants

The working capital norms for captive power plants shall be governed as per

UPERC (Terms and Conditions of Generation Tariff) Regulations 2009 which are

provided below:

Table 5: Specific Parameter for Captive Power Plants

S.N Particulars Norms

1 Cost of Coal (Pit-head) One and Half Months

2 Cost of Coal (Non-pit head) Two Months

3 Cost of Secondary Fuel Two Months

4 Operation and Maintenance Expenses One Month

5 Maintenance Spares 20% of O&M

6 Receivables Two Months or actual;

whichever is lower,

comprising of fixed & variable

charges calculated on target

PLF

II. Bagasse based co-generation, Biomass and Small Hydro generating plants

Page 31

Table 6: Specific Parameters for Bagasse/ Biomass/ Small Hydro Power Plants

S.N Particulars Bagasse Biomass Small Hydro

1 Fuel Cost One Month Two Month -

2 Operation and

Maintenance Expenses

One Month One Month One Month

3 Maintenance Spares 15% of O&M 15% of O&M 15% of O&M

4 Receivables Two Months or

actual; whichever

is lower,

comprising of

fixed & variable

charges

calculated on

target PLF

Two Months or

actual; whichever

is lower,

comprising of fixed

& variable charges

calculated on

target PLF

Two Months or

actual; whichever is

lower, comprising of

fixed & variable

charges calculated on

target PLF

Further, Interest on Working Capital shall be at interest rate equivalent to average

State Bank of India (SBI) short term Prime Lending Rate (PLR) prevalent for the

period 1st April 2008 to 31st March 2009 which is worked out by Commission at

12.80% p.a.

3.6.7 Operation & Maintenance (O&M) Expense Escalation

The existing escalation in O&M expenditure is 4% and the Commission has

decided to revise the escalation rate upwards and in line with CERC Draft

Regulations 2009 on Renewable Energy and UPERC (Terms and Conditions of

Generation Tariff) Regulations,09 at 5.72% per annum with yearly compounding.

Page 32

4. CAPTIVE GENERATING PLANTS

Tariff structure comprising of fixed and variable cost would be applicable for sale

of power by a Coal Based Captive Generating Plant at pit-head location to the

distribution licensee of its area. For non-pit head plants, the transportation cost

shall be separately determined on case to case basis.

The earlier regulation had three different tariff structures for unit size below 200

MW, unit size 200/210/250 MW and unit size above 500 MW. Based on

information available with Commission, no PPA has been signed for above unit

sizes by any distribution licensee under CNCE Regulations 2005 or any captive

capacity comprising of the said unit sizes established by any generating company.

If any PPA or captive capacity appears for consideration of the Commission with

the above unit sizes, the fixed cost and variable cost shall be as determined under

CNCE Regulations 2005 till this order comes into effect.

Since there is no presumed new capacity addition of the said unit sizes,

Commission has decided to determine the tariff for the unit sizes upto 100 MW,

above 100 MW but upto 300 MW and above 300MW.

4.1 Financial parameters common to existing and new coal based captive

generating plants:

UPPCL is proposing reduced ROE while Kanoria Chemicals and Industries Limited

calls for uniform approach for determination of tariff as applied to generating

companies. The Commission considered reduced ROE for tariff determination

under CNCE Regulations 2005. The central government has allowed captive plants

to sell electricity up to 49% of its generation as such the risk which may be

encountered by these plants in operation should be compensated in the similar

way as with other coal based generating station of any generating company.

Therefore Return on Equity 15.5% shall be considered for determination of tariff.

However, no compensation for income tax liabilities are being considered since

these plants are set up primarily for the use of its members and the plant shall be

supplying electricity to distribution licensee only in case of eventual surplus.

Accordingly, the following financial parameter as specified under para 4.4 shall

apply to all existing & new plants:

1. Return on Equity - 15.5% of Equity amount (pre-tax)

2. O&M Expenses Escalation- 5.72% p.a. (compounded basis)

3. Working Capital - As provided in section 3.6.6

4. Interest on WC - 12.80% p.a.

Page 33

4.2 Tariff Methodology for Existing Captive units commissioned prior to FY 2005-06

Since there is no captive capacity addition in the knowledge of the Commission

during FY 05-06 to 08-09, as aforesaid & there are unit sizes below 100 MW

installed at captive generating stations operated by Hindalco Industries and

Kanoria Chemicals & Industries Limited as such one unit size of below 100 MW,

commissioned prior to FY 2005-06, may be considered as one of the categories

for tariff determination.

4.2.1 Determination of Fixed Cost

The Commission has considered for the captive units commissioned prior to FY

2005-06, the parameters other than those discussed in para 4.1 are as under:

1. Interest on Loan - NIL. Assuming full repayment is done

2. Depreciation - 20% of project cost to be shared for balance life

of asset i.e. 2% p.a. on total Project cost

3. O&M Expenditure - 2.50% of Project Cost

4.2.2 Determination of Variable Cost

The Commission has considered the same variable parameters as applicable for

new projects except for the Station Heat Rate (SHR) which is considered on higher

side i.e. 2900 kcal/kWh instead of 2800 kcal/kWh, knowing the fact that these

units/ plants are quite old.

For fixation of variable cost, existing as well as new plants, the commission has

considered Fuel Oil Cost as on 1st April 2009 i.e. Rs 15836/KL (Source:

NCDEX.com).The Commission, in its Tariff Order for FY 2008-09 has approved Rs

1276/MT as average Coal cost for Anpara A , Anpara B, Obra A & Obra B which are

pit-head plants. Therefore, the Commission approves Rs 1276/MT with an

escalation of 6% which comes out as Rs 1352/MT for FY 2009-10. For the purpose

of tariff determination in subsequent years, fuel cost shall be escalated at 6% per

annum.

4.2.3 Tariff

The l tariff for the units commissioned prior to FY 2005-06, for unit size less than

100 MW, shall be as given in the following table:

Page 34

Table 7: Tariff for Captive units commissioned prior to FY 2005-06

Captive - Existing Projects (Prior to FY 2005-06)

Financial Year Fixed Cost (Rs/kWh) Variable Cost

(Rs/kWh)

Total Cost (Rs/kWh)

FY 2009-10 0.62 1.31 1.92

FY 2010-11 0.63 1.39 2.02

FY 2011-12 0.64 1.47 2.11

FY 2012-13 0.66 1.56 2.22

FY 2013-14 0.68 1.65 2.33

4.3 Tariff Methodology for Existing Captive units commissioned during FY 2005-06

to FY 2008-09

Tariff of any unit size upto 100 MW commissioned during FY 2005-06 to FY 2008-

09 is being considered as a separate category

4.3.1 Determination of Fixed Cost

The fixed cost for the units commissioned during FY 2005-06 to FY 2008-09 for

unit size less than 100 MW is being determined on the basis of norms specified

under Para 4.1 & the following:

1. Interest on Loan : 10.25% per annum

2. Depreciation : 7%

3. O&M Expenses : 2.5% of the Project cost

Accordingly, the tariff for the category of existing plant is given in the

Following table:

Table 8: Fixed Cost for CPP (Existing)

Captive - Existing Projects (Fixed Cost: Rs /Kwh)

Year of Commissioning FY 2009-

10

FY 2010-

11

FY 2011-

12

FY 2012-

13

FY 2013-

14

FY 2005-06 1.08 1.06 1.03 1.00 0.97

FY 2006-07 1.16 1.13 1.10 1.07 1.04

FY 2007-08 1.23 1.20 1.17 1.14 1.11

FY 2008-09 1.31 1.28 1.25 1.22 1.19


The Commission has considered the same variable parameters as applicable for

new projects as specified under para 4.4of the order

Page 35

Table 9: Variable Cost for CPP (Existing)

Captive-Existing Projects

Financial Year Variable Cost

(Rs/Kwh)

FY 2009-10 1.26

FY 2010-11 1.34

FY 2011-12 1.42

FY 2012-13 1.50

FY 2013-14 1.60

4.3.3 Effective Tariff

The total tariff for the units commissioned during FY 2005-06 to FY 2008-09 for

unit size less than 100 MW will be as given in the following table:

Table 10: Effective Tariff for Captive units commissioned (Existing)

Captive - Existing Projects (Total Cost: Rs/Kwh)

Year of Commissioning FY 2009-

10

FY 2010-

11

FY 2011-

12

FY 2012-

13

FY 2013-

14

FY 2005-06 2.35 2.39 2.45 2.50 2.57

FY 2006-07 2.42 2.47 2.52 2.57 2.64

FY 2007-08 2.50 2.54 2.59 2.65 2.71

FY 2008-09 2.57 2.62 2.67 2.72 2.78

4.4 Tariff Methodology for Captive units commissioned on or after 1st April 2009

In this control period, the Commission has decided to determine tariff for

following unit sizes:

1. Upto 100 MW

2. Above 100 MW and upto 300 MW

3. Above 300 MW

The Commission has already discussed general financial parameters in earlier

chapter and the other operating parameters applicable for all unit sizes of captive

generating plants for the purpose of determination of tariff are as follows:

Page 36

Table 11: Operating Parameters for Captive unit – New Projects

S.N Parameters Unit 0-100 MW 101-300

MW

Above 300

MW

1 Plant Load Factor % 80% 80% 80%

2 Auxiliary Consumption % 10% 9% 8%

3 SHR Kcal/Kwh 2800 2500 2500

4 GCV-Coal Kcal/Kg 3400 3400 3400

5 GCV-Oil Kcal/Kg 10000 10000 10000

6 Specific Oil Consumption ml/Kwh 1.0 1.0 1.0

The other parameters/ norms considered for determination of tariff are discussed

in detail in subsequent section.

4.4.1 Capital cost

The Commission under CNCE Regulations 2005 , considered the cost of unit sizes

below 200 MW , 200/210/250 MW sets and 500 MW & above sets as Rs 3.5

Cr/Mw for FY 2005-06 escalated at the rate of 3% per year. The cost as on FY

2009-10 comes out to be Rs 3.94 Cr/MW. The Commission decides the capital

cost for plant capacities above 100 MW as Rs 4.5 Cr/MW which is at a higher rate

than prescribed under earlier regulations. For capacities above 100 MW & upto

300 Mw is considered as Rs 4 Cr/ Mw and for plants above 300 MW capacities as

Rs 3.5 Cr/ Mw. The above figures, tabulated as below, shall be applicable for the

projects commissioned in FY 2009-10 and thereafter 3% escalation (simple) shall

be applied for subsequent years:

Table 12: Capital Cost for different units sizes – New Projects

Captive - New Projects

Year of

Commissioning

Capital Cost (Rs.Crs/MW)

CPP (0-100 MW) CPP (101-300) CPP (Above 300 MW)

FY 2009-10 4.50 4.00 3.50

FY 2010-11 4.64 4.12 3.61

FY 2011-12 4.77 4.24 3.71

FY 2012-13 4.91 4.36 3.82

FY 2013-14 5.04 4.48 3.92

4.4.2 Return on Equity

The Commission in its earlier regulation had provided Return on Equity (RoE) at

9% considering the aspect that the captive units are primarily for self-use but the

risk associated was not covered. Considering to cover the risk associated with

Page 37

such projects the Commission intends to provide appropriate compensation and

incentive to encourage investment. CERC also in its Tariff Regulations 2009 has

allowed 15.5% post tax RoE to generating units.

Accordingly, the Commission has decided to allow Return on Equity at the rate of

a maximum of 15.5% (pre-tax) per annum.

4.4.3 Operation & Maintenance Expenditure (O&M)

The earlier regulation had O&M expenditure in terms of 2.50% of project cost

escalated by 4% per annum.

However, the Commission has decided to consider O&M expenses in terms of

Rs.Lakhs/MW calculated as 2.50% of the approved project cost for FY 2009-10.

The O&M expenses for different Unit Sizes shall be as below:

Table 13: O&M Costs for FY 10 for unit-wise Captive Power Plants-New Projects

Unit Size O&M Cost

MW Lakhs/Mw

0-100 11.25

100-300 10.00

Above 300 8.75

Thus, the O&M expense as above shall be escalated by factor 5.72% for

calculation of O&M expenses for subsequent year, the escalation rate specified by

the Commission in UPERC (Terms & Conditions of Generation Tariff Reg. 2009).

4.4.4 Fuel Cost

The Commission in its earlier order dated 18.7.05 had provided cost of coal at

Rs.900/ MT and cost of oil at Rs.13000/KL. The cost of the coal as considered by

Commission in para 4.2.2 for tariff determination for FY 09-10, is Rs. 1352/ MT for

captive plants located at coal pitheads. For non pit head plants, the

transportation cost shall be separately decided by the Commission on case to

case basis.

The cost of oil has been considered at Rs.15836/KL which is retail price prevailing

in the market as on 1st April 2009 and the GCV of 10,000 Kcal/Ltr. Further these

prices will be escalated by 6% p.a.

Page 38

4.4.5 Effective Tariff for Firm Power

Taking into account the technical and financial parameters considered by the

Commission in the preceding paragraphs, the fixed cost tariff for captives to be

commissioned on or after 1st April 2009 would be as under:

Table 14: Fixed Cost of Captive Units – New Projects

Captive - New Projects (Fixed Cost : Rs/ Kwh)

Year of

Commissionin

g

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

Unit Size (0-100 MW)

FY 2009-10 1.71 1.66 1.61 1.56 1.51

FY 2010-11 1.76 1.71 1.66 1.61

FY 2011-12 1.81 1.76 1.71

FY 2012-13 1.86 1.81

FY 2013-14 1.91


FY 2009-10 1.51 1.46 1.42 1.37 1.33

FY 2010-11 1.55 1.50 1.46 1.41

FY 2011-12 1.60 1.55 1.50

FY 2012-13 1.64 1.59

FY 2013-14 1.68

Unit Size (Above 300 MW)

FY 2009-10 1.31 1.27 1.23 1.20 1.16

FY 2010-11 1.35 1.31 1.27 1.23

FY 2011-12 1.39 1.34 1.30

FY 2012-13 1.42 1.38

FY 2013-14 1.46

The variable cost for coal based captive generating plants is estimated to be as under:

Table 15: Variable Cost of Captive Units – New Projects

Variable Cost

Financial Year Rs/Kwh Rs/Kwh Rs/Kwh

0-100 MW 101-300 MW Above 300

MW

FY 2009-10 1.25 1.11 1.09

FY 2010-11 1.33 1.17 1.16

FY 2011-12 1.40 1.24 1.23

FY 2012-13 1.49 1.32 1.30

FY 2013-14 1.58 1.40 1.38

Page 39

The effective tariff for coal based captive generating plants is estimated to be as

under:

Table 16: Effective Tariff for Captive Units – New Projects

Captive - New Projects (Total Cost: Rs/ Kwh)

Year of

Commissioning

FY 2009-

10

FY 2010-

11

FY 2011-12 FY 2012-

13

FY 2013-14

Unit Size (0-100

MW)

FY 2009-10 2.96 2.99 3.02 3.05 3.09

FY 2010-11 3.09 3.12 3.15 3.19

FY 2011-12 3.22 3.25 3.28

FY 2012-13 3.35 3.39

FY 2013-14 3.49


FY 2009-10 2.61 2.63 2.66 2.69 2.73

FY 2010-11 2.72 2.75 2.78 2.81

FY 2011-12 2.84 2.86 2.90

FY 2012-13 2.96 2.99

FY 2013-14 3.08

Unit Size (Above 300 MW)

FY 2009-10 2.40 2.43 2.46 2.50 2.54

FY 2010-11 2.51 2.54 2.57 2.61

FY 2011-12 2.61 2.65 2.68

FY 2012-13 2.73 2.76

FY 2013-14 2.84

4.4.6 Electricity (MW/MU) supplied over and above 80% PLF

The tariff of the captive generating plants has been determined at 80% PLF. It

might be willing to supply at PLF above 80%. For such supply, only incentive and

variable cost shall be paid as below:

1. Variable cost as applicable for new plants or existing plants

2. Incentive @ 35 paisa per unit

Page 40

5. BAGASSE BASED COGENERATION PLANTS

The Commission intends to determine tariff for existing projects (commissioned

before FY 2005-06 and between FY 2005-06 to FY 2008-09) and for the new

projects to be commissioned on or after 1st

April 2009.

The parameters considered for determination of tariff are discussed in detail as

under:

5.1 Parameters for Existing & New Bagasse based Co- Generation Plants

5.1.1 Capital cost

The Commission in the earlier Regulation 2005 had provided capital cost of

Rs.3.25 Crs/MW for the plant and Rs. 0.25 Crs/MW for dedicated transmission

line with an escalation of 3% every year for subsequent years. GE has suggested

for higher capital cost considering the changes in technologies. U.P. Sugar Mills

Cogen Association had proposed capital cost of Rs.4.50 Crs/MW plus cost of

transmission line as per schedule of rates of UPPCL.

Recently, CERC has issued Draft Regulations 2009 on Renewable Energy which

mentions about the different approaches of computing capital cost. The

discussion paper provides average capital cost based on the projects registered

with UNFCCC and based on the information available with IREDA. The capital cost

proposed by CERC for FY 2009-10 is Rs. 4.45 Crs/MW. The capital cost approved

by different regulators for bagasse based projects is given in the table below:

Table 17: Capital Cost approved by various SERCs - Bagasse

Orders of the other Commissions on Capital Cost

Particulars Andhra

Pradesh

Gujarat Haryana Karnataka Tamilnadu

Date of order 31.3.09 &

20.3.04

3.1.2007 15.5.2007 18.1.2005 6.5.2009

Capital Cost (Rs. in Crs

/MW)

3.25 4.00 3.95 3.00 4.67

The Commission after considering above information/ submission has come to

the conclusion that there has been increase in actual capital cost due to rise in

material and equipment cost. The Section 61 of the Electricity Act 2003 calls for

optimum investment and the National Electricity Policy says that effort should be

made to reduce the capital cost of the non-conventional and renewable energy

sources based plants. Accordingly, Commission has considered a capital cost of

Page 41

Rs.4.00 Crs/MW (inclusive of cost of transmission line) for the projects

commissioned in FY 2009-10. This cost shall be escalated, thereafter applying 3%

escalation (simple) to arrive at capital cost for subsequent years.

Return on Equity


16%, in view of the fact that electricity generation by sugar mill is not the core

business whereas, under CERC regulations, post tax ROE is provided for those who

are in core business of electricity generation. U.P. Sugar Mills has proposed RoE of

18% on post tax basis. The Commission feels that the proposal of U.P. Sugar Mills

to claim 18% post-tax RoE is too high for consideration. The RoE approved by

other State Electricity Regulatory Commissions is provided below:

Table 18: Return on Equity approved by various SERCs - Bagasse

Orders of the other Commissions on Return on Equity

Particulars Andhra

Pradesh



20.3.04

3.1.2007 15.5.2007 18.1.2005 6.5.2009

Return on Equity (%) 16% 14% (Post-

tax)

16% 16% 19.85%


16% (pre-tax) per annum. This rate shall also apply on existing plants which were

commissioned during prior to FY 2005-06 or during FY 2005-06 to FY 2008-09.



escalated by 4% per annum. The O&M expenses approved by various SERCs are

tabulated as under:

Table 19: O&M Expenses approved by various SERCs - Bagasse

Orders of the other Commissions on O&M Expenses

Particulars Andhra

Pradesh

Gujarat M.P. Karnataka Tamilnadu


20.3.04

3.1.2007 Sep-08 18.1.2005 6.5.2009

O&M Expenses

(as a % of Project

cost)

3% with 4%

escalation

2.50%

with 5%

escalation

3% with

5%

escalation

3% with

5%

escalation

4.5% with

5%

escalation

Page 42

U.P. Cogen Association has asked for O&M escalated at 4% of project cost and

Mawana Sugar has proposed for 5% of project cost to be escalated by 5%

annually. The Commission decides to consider O&M expenses in terms of

Rs.Lakhs/MW calculated as 3% of project cost of approved for FY 2009-10. Capital

cost for FY 2009-10 is considered at Rs.4.00 Crs/MW for new plants. Therefore,

the O&M expense is approved at Rs.12.00 lakhs/MW for the first year of

operation with an annual escalation of 5.72% on compounded basis. The decision

of Escalation on O&M expenses at 5.72% shall also apply on existing plants which

were commissioned during FY 2005-06 to FY 2008-09 or prior to FY 2005-

06.However, the O&M expenses for existing plants shall be calculated based on

2.5% of the project cost escalated by 4% compounded per annum to reach to the

value in for Rs.Lakhs/MW FY 09-10.

5.1.3 Plant Load Factor (PLF)

The Commission had in its earlier regulation approved PLF of 60%. Mawana

Sugars has suggested that PLF of 40% be approved considering average fuel

availability of 130 days throughout the year. Similarly, U.P. Cogen Association has

also suggested 40% PLF based on average crushing period from FY 2005-06 to FY

2008-09.

The PLF approved by various SERCs for Bagasse based Co-gen projects is provided

in the table below:

Table 20: Plant Load Factor (PLF) approved by various SERCs – Bagasse

Orders of the other Commissions on Plant Load Factor (PLF)

Particulars Andhra

Pradesh



20.3.04

3.1.2007 15.5.2007 18.1.2005 6.5.2009

Plant Load Factor

(%)

55% 80% 80% 60% 55%

U.P. Sugar in its submission at Annexure ‘B’ has provided information related to

average crushing season days. The extract of the same for last 4-5 years is

outlined below:

Table 21: Average Crushing Season days – U.P. Sugar Mills

Average Crushing Season days

Particulars FY 04-05 FY 05-06 FY 06-07 FY 07-08 FY 08-09

Target days 130 137 158 127 102

Actual day 124 125 150 120 95

Page 43

The statement of UPPCL in its submission during public hearing has stated that

the crushing period is abnormally low during FY 2008-09 and the same should not

be considered as base.

The average crushing season from FY 2004-05 to FY 2007-08, as reported in the

statistics of UP Govt. Submitted by the U.P. Cogen Association, is 130 days and

the highest reported during this period is 150 days. Further the data furnished by

generators indicate wide variance in figures.

The Co-generating plants are pleading for lower PLF due to failure of sugarcane

crop last year. UPPCL has partially yielded to the plea of the Co-generating plants

by agreeing on 50% PLF as against 40% demanded by the plants .UPPCL has also

raked up the issue of excess plant capacity ; which does not commensurate to

fair availability of bagasse to sustain the plant operations at the desired level.

Commission considers that the decision on the plant capacity is an important one

and if excess capacity (not backed by fuel arrangement) is installed, the consumer

ends up paying higher cost for unutilized capacity. On the other side, the plant

may lose substantially, if the fuel is not available although the capacity was

planned optimum. The decision on capacity is a controllable factor and attributed

to careful planning. The fuel risks such as reduction in cane collection area, failure

of monsoons and farmers opting for cash crops add to the uncontrollable risk on

fuel availability. These factors have to be addressed in fixing the target PLF for

recovery of the fixed charges. The Commission had earlier fixed target PLF at 60%

for recovery of cost. If the fuel availability risks are affecting PLF, fixed cost loss on

account of reduction in PLF must be compensated because non-availability of

adequate fuel is beyond the control of the generating plants. The methodology

must be devised to take care of the loss to the generator due to risks of fuel. The

PLF fixed earlier had not been bone of contention with any of the plants unless

the issue of low PLF due to unavailability of fuel came up with the commission in

the last year. The demand of Co-gen projects in respect of reduced PLF is

excessive while that of UPPCL is accommodative. The balance may be struck by

advance recovery of fixed cost at a low PLF than 60% and asking the generator to

supply electricity beyond such low PLF at variable cost as he continues to get fuel

(availability unaffected by the above cited risks). This system would operate until

generator achieves 60% PLF. The incentive zone shall commence beyond this

level. In case the plant fails to get fuel, it would not be obliged or for that matter

would not have an opportunity to generate more but would be safe as it had

already recovered the fixed charges. In Otherwise case, the consumer interest is

safe guarded by supplying electricity at variable cost on advance payment of the

Page 44

fixed cost if crop is bumper and plant gets fuel. Having met all the interests, the

Commission decides to fix the recovery of fixed cost at 50% PLF, supply of

electricity above 50% PLF to 60% shall be at variable cost only. The incentive

beyond 60% shall be as specified in this order.

Draft Regulation 25 (1) calls for optimum capacity assessed on the basis of

potential of electricity generation available with the NCE sources. In view of

above proposal, all NCE plants are directed to assess the availability of fuel on the

basis of data of at least 15 years by discounting all risks factors to arrive at a

conservative assessment of fuel to make a decision on fixing the capacity. In case,

the fuel availability is increased in future, plant may take up expansion. This

procedure is important particularly in view of the fact that some of the plants

might have set up higher capacities without firm arrangement of fuel supply.

The Commission further submits that although PLF has been fixed at 50% to

address the situation of low production of bagasse, but in future, whenever the

cane production achieves the desired level, the PLF shall be reviewed accordingly.

The reduced Plant load factor and related matters as decided above shall also

apply on existing plants which were commissioned during FY 2005-06 to FY 2008-

09 and prior to FY 2005-06.

5.1.4 Specific Fuel Consumption and Station Heat Rate

The Commission in its earlier Regulation 2005 had approved SHR of 3300

kcal/kWh and most of the generators have asked for higher SHR of 3600 - 3700

kcal/kWh (Specific consumption of about 1.60 kg/kWh). The Specific fuel

consumption prevailing in other states is tabulated below:

Table 22: Specific Fuel Consumption approved by various SERCs – Bagasse

Orders of the other Commissions on Specific Fuel Consumption

Particulars Andhra

Pradesh



20.3.04

3.1.2007 15.5.2007 18.1.2005 6.5.2009

Specific Fuel

Consumption

(kg/kWh)

1.60 1.64 2.38 1.60 1.67

The Commission allows Station Heat Rate as 3650 Kcal/Kwh for existing plants but

a lower Station Heat Rate as 3100 Kcal/Kwh for new plants considering that the

Page 45

new plants will have higher efficiency due to advanced technology. The specific

fuel consumption for existing plants shall be 1.60 kg/kWh; however, for new

plants specific fuel consumption shall be 1.36 kg/kWh.

5.1.5 Fuel Cost

Fuel cost is a key determinant of the cost of power in a cogeneration plant which

determines the viability of the project. The Commission adopted fuel cost of

Rs.740 / MT in order dated 18.7.2005. The fuel for the Cogeneration plant is

virtually free during the crushing season. However, as a fuel, it must be priced.

U.P. Cogen Association has requested that the cost of bagasse should be

Rs.1378/MT with as escalation of 7%. The price is linked to the landed cost of coal

with GCV of 3898 kcal/kg determined for UPRUVNL for FY 2008-09 for Harduaganj

power station. U.P. Cogen Association has also intimated that the market price of

bagasse as sold by Kishan Shahakari Chini Mills is around Rs.2360/MT ex factory.

Mawana Sugars has suggested that fuel price adjustment may be provided for

bagasse considering fluctuating market prices.

The bagasse price approved by other SERCs is provided in the table below with

fuel price escalation:

Table 23: Fuel Cost approved by various SERCs – Bagasse

.

Orders of the other Commissions on Fuel Cost

Particulars Andhra

Pradesh



20.3.04

3.1.2007 15.5.2007 18.1.2005 6.5.2009

Fuel Cost (Rs/MT) 950/- with

5%

escalation

775/-

with 5%

escalation

900/-

with 5%

escalation

800/-

with 5%

escalation

1000/-

with 5%

escalation

The Commission considers cost of bagasse as fuel on the basis of equivalence of

average cost of coal, for UP’s State thermal plants, allowed by the Commission in

its Tariff Order for FY 2008-09. The Commission has approved average cost of coal

Rs 1731/MT having average GCV as 3544 Kcal/kg. Thus, considering the

parameters approved for bagasse based plants i.e. 2275 Kcal as GCV ; in

equivalence terms of cost of coal , fuel cost for bagasse comes out to be Rs

1178/MT for FY 09-10 (escalated at 6% for arriving at FY 09-10 value from FY 08-

09 value) and stands approved by the Commission. The fuel cost shall be

Page 46

escalated at 6% per annum for subsequent years. The above cost of bagasse as

fuel shall also apply for plants that are commissioned prior to FY 2005-06 or

during FY 205-06 to FY 2008-09.

5.2 Tariff Methodology for Bagasse projects Commissioned prior to FY 2005-06 and

during FY 2005-06 to FY 2008-09

5.2.1 Determinants of Fixed Cost

The Commission in its earlier regulation had determined fixed cost based on

certain fixed parameters which would continue for this control period also and

the parameters which have undergone a change are O&M expenses, Escalation

on O&M expenses, Working Capital norms, Interest on working capital, Fuel cost

and PLF as discussed in para 5.1.

Accordingly, the following shall be considered for determination of tariff of the

said existing plants.

1. Return on Equity - 16% of Equity amount (pre-tax)

2. O&M Expenditure - 3% of escalated approved Project Cost

3. Escalation on O&M expenses - 5.72% p.a.(compounded basis)

4. Working Capital - Fuel cost – 1 month, O&M Expenses – 1

Month, Receivables – 2 months, Spares

cost – 15% of O&M expenses


6. Plant Load Factor - 50%

7. Auxiliary Consumption - 8.5%

8. Station Heat Rate - 3650Kcal/Kwh

9. Specific Fuel Consumption - 1.60kg/kWh

10. Interest on Loan - 10.25% p.a.

Table 24: Fixed Cost for Bagasse Plants - Existing Projects

Bagasse - Existing Projects (Fixed Cost: Rs/Kwh)

Year of

Commissioning

FY 2009-

10

FY 2010-

11

FY 2011-

12

FY 2012-

13

FY 2013-

14

FY 2005-06 or

earlier

1.75 1.70 1.66 1.62 1.58

FY 2006-07 1.86 1.81 1.77 1.72 1.68

FY 2007-08 1.97 1.92 1.87 1.83 1.78

FY 2008-09 2.09 2.04 1.99 1.94 1.89

Page 47


Parameters for calculations of variable cost have been discussed in para 5.1

earlier. Based on these parameters, the variable cost of existing plants as

determined as below:

Table 25: Variable Cost for Bagasse Plants - Existing Projects

Bagasse - Existing Projects


(Rs/kWh)

FY 2009-10 2.07

FY 2010-11 2.19

FY 2011-12 2.32

FY 2012-13 2.46

FY 2013-14 2.61


The total tariff for the existing Bagasse based co-gen projects for the period from

FY 2009-10 to FY 2013-14 on the basis of fixed and variable costs, determined

above, shall be as below:

Table 26: Effective Tariff for Bagasse Plants - Existing Projects

Bagasse - Existing Projects (Total Cost: Rs/Kwh)

Year of

Commissioning

FY

2009-10

FY

2010-11

FY 2011-

12

FY 2012-

13

FY 2013-

14

FY 2005-06 or

earlier

3.81 3.89 3.98 4.08 4.19

FY 2006-07 3.92 4.00 4.09 4.18 4.29

FY 2007-08 4.04 4.11 4.20 4.29 4.39

FY 2008-09 4.15 4.23 4.31 4.40 4.50

5.3 Tariff Methodology for New Bagasse projects commissioned on or after 1st April

2009

The financial parameters for the Bagasse based cogeneration plants for

determination of tariff as discussed in para 5.1 are as below:


2. O&M Expenditure - 3% of escalated approved Project Cost


4. Working Capital - Fuel cost – 1 month, O&M Expenses – 1

Page 48

Month, Receivables – 2 months, Spares

cost – 15% of O&M expenses



7. Auxiliary Consumption - 8.5%

8. Station Heat Rate - 3100Kcal/Kwh

9. Specific Fuel Consumption - 1.36 kg/kWh

10. Interest on Loan - 12.80% p.a

5.3.1 Fixed Cost for new Bagasse Plants


Commission in the preceding paragraphs, the fixed cost for Bagasse based

cogeneration plants to be commissioned on or after 1st

April 2009 would be as

under:

Table 27: Fixed Cost of Bagasse Plants – New Projects

Bagasse - New Projects (Fixed Cost : Rs /Kwh)

Year of Commissioning FY 2009-10 FY 2010-11 FY 2011-12 FY 2012-13 FY 2013-14

FY 2009-10 2.46 2.39 2.32 2.25 2.18

FY 2010-11 2.53 2.46 2.38 2.31

FY 2011-12 2.60 2.52 2.45

FY 2012-13 2.67 2.59

FY 2013-14 2.74

5.3.2 Variable Cost for new Bagasse Plants

Parameters for calculation of variable cost have been discussed in the para 5.1

which is as below. Based on these parameters, the variable cost of new plants is

determined as below:

Page 49

Table 28: Variable Cost of Bagasse Plants – New Projects

Bagasse - New Projects

Financial Year Variable Cost (Rs/kWh)

FY 2009-10 1.75

FY 2010-11 1.86

FY 2011-12 1.97

FY 2012-13 2.09

FY 2013-14 2.21

5.3.3 Effective Tariff for new Bagasse Plants

The effective tariff for new Bagasse based cogeneration plants based on fixed and

variable cost, determined above, shall be as follows:

Table 29: Effective Tariff for Bagasse Plants – New Projects

Bagasse - New Projects (Total Cost: Rs/Kwh)

Year of

Commissioning

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

FY 2009-10 4.21 4.24 4.29 4.34 4.40

FY 2010-11 4.39 4.43 4.47 4.53

FY 2011-12 4.57 4.61 4.67

FY 2012-13 4.76 4.81

FY 2013-14 4.96

5.4 Power above 50% PLF and Incentive for Existing & New Plants

5.4.1 Power above 50%

The Commission has allowed recovery of fixed cost at 50% but these plants might

be running above 50% PLF. Since the full fixed cost has been recovered at 50%

PLF, the additional cost for such supply would only be the fuel cost. For supply

above 50% PLF to 60% PLF, the plant shall be paid Variable cost as applicable for

new plants (Table 28) and existing plants (Table 25).

5.4.2 Incentive

The Commission is of the view that it needs to provide suitable incentive to the

bagasse based generating plants to generate more power. Therefore, the

generator shall be paid incentive as below:

Page 50

Table 30: Incentive Structure for Bagasse Plants

Plant Load Factor Incentive

More than 50% -60% Zero Paise per Kwh

More than 60% -70% 10 Paise per Kwh


More than 80% 25 Paise per Kwh

Besides above incentive, the plants shall also ne paid variable cost as applicable

for new plants (Table 28) and existing plants (Table 25) additionally.

Page 51

6. BIOMASS POWER PLANTS

The tariff for Biomass plants for earlier control period was same as of baqasse due

to lack of availability of data to determine it separately. The Commission has now

decided to determine tariff for existing as well as new projects which shall be

commissioned on or after 1st

April 2009 separate from bagasse, by specifying

parameters for the said purpose.

6.1 Tariff Methodology for Biomass Power plants Commissioned during FY 2005-06

to FY 2008-09

There has been only one generating plant commissioned in FY 2008-09 and

Commission has decided, in foregoing paragraphs, to review its tariff for FY 2008-

09 on revised capital cost & other parameters based on parameters as may be

approved by the Commission for new projects, although such tariff shall be

applicable from the date of this order or date by which CNCE Regulations 2009

takes effect.

6.2 Parameters for Biomass Plants existing during FY 2008-09 and New Plants

commissioned during FY 09-10 to FY 13-14

The operating and financial parameters for the Biomass power plants for

determination of tariff are discussed in detailed as under:

6.2.1 Capital cost

The generators Anil Modi Oil Industries Ltd. and Sukhbir Agro have recommended

for higher capital cost at Rs.5.50 Crs/MW and Rs.5.00 Crs/MW respectively.

Earlier the Commission had approved capital cost of Rs.3.50 Crs/MW.

Recently, CERC has issued Draft Regulations 2009 on Renewable Energy which

mentions about the different approaches of computing capital cost. The

discussion paper provides average capital cost based on the projects registered

with UNFCCC and based on the information available with IREDA. CEA while fixing

up operation norms for Biomass based power plants in September 2005 has taken

capital cost of Rs.4.00 Crs/MW. The normative capital cost proposed by CERC for

FY 2009-10 is Rs.4.50 Crs/MW. The capital cost approved by different regulators

for biomass based projects is given in the table below:

Page 52

Table 31: Capital Cost approved by various SERCs - Biomass


Particulars Andhra

Pradesh



20.3.04

17.8.2007 15.5.2007 18.1.2005 27.4.2009

Capital Cost

(Rs.Crs/MW)

4.00 3.50 4.29 4.00 4.87

The only generator which came in operation in FY 2008-09 has proposed capital

cost at Rs.5.00 Crs/MW. In view of the capital costs considered by various SERC’s,

/CERC and earlier by the Commission, Commission has considered a capital cost

of Rs.4.25 Crs/MW inclusive of cost of dedicated transmission line for the projects

commissioned in FY 2009-10. For capital cost of biomass based generating plants

commissioned in FY 2008-09, Rs 4.25 Cr/Mw capital cost for FY 09-10 is de-

escalated at 3%. The capital cost calculated in such a manner comes as Rs 4.13 Cr

/MW (applicable for FY 2008-09). For subsequent years, capital cost has been

worked out by applying 3% (simple) escalation on per annum basis.



16% same as of Bagasse projects. Anil Modi Oil Inds and Sukhbir Agro has

suggested for 16% RoE.

CERC also in its Tariff Regulations 2009 has allowed 15.5% post tax RoE which

works out to around 17% pre-tax for the period where MAT is applicable. The RoE

approved by other State Electricity Regulatory Commissions is provided below:

Table 32: Return on Equity approved by various SERCs – Biomass


Particulars Andhra

Pradesh



20.3.04

17.8.2007 15.5.2007 18.1.2005 27.4.2009

Return on Equity (%) 16% 14% 16% 16% 19.85%

The Commission has analysed the ROE approved by other SERCs which is around

16%. The concept of post tax return can at best be implemented in conventional

power projects. UPPCL has also requested not to consider any change in ROE.

Considering these aspects, the Commission has decided to retain Return on Equity

Page 53

at the rate of 16% (pre-tax basis) per annum as allowed in bagasse based power

plants.



escalated by 4% per annum. CEA in September 2005 report on operation norms

for biomass have suggested O&M expenses @7% of project cost with the review

after 2-3 years with an effort to reduce the same.

Anil Modi Oil Inds has proposed for 4% of project cost, Sukhbir Agro has

suggested 4% of project cost as O&M expenditure with escalation being sought in

the range of 5-10% p.a.

The O&M expenses approved by various SERCs are tabulated as under:

Table 33: O&M Expenses approved by various SERCs – Biomass


Particulars Andhra

Pradesh

Gujarat Rajasthan Karnataka Tamilnadu


20.3.04

17.8.2007 23.1.2009 18.1.2005 27.4.2009

O&M Expenses

(as a % of Project

cost)

4% with 4%

escalation

7% with

5%

escalation

6.5% with

5.72%

escalation

4% with

5%

escalation

4.5% with

5%

escalation

The Commission after considering diverse factors suggested by CEA & developers

has decided to allow O&M expenses in terms of Rs.Lakhs/MW derived on the

basis of percentage of project cost (4% of project cost Rs. 4.25 Crs/MW for FY

2009-10). The O&M expense is approved at Rs.17 lakhs/MW for the first year of

operation i.e. FY 2009-10 with an annual escalation of 5.72% on compounded

basis.

For existing plants commissioned in FY 2008-09, O&M expense shall be worked

out at 4% of the capital cost of Rs 4.13 Cr/MW. O&M expense of subsequent

years shall be escalated by factor 5.72% p.a. for new plants.

6.2.4 Plant Load Factor (PLF)

The developers have suggested PLF in the range of 60% to 70%. The PLF

approved by various SERCs for Biomass power plants projects is provided in the

table below:

Page 54

Table 34: Plant Load Factor (PLF) approved by various SERCs – Biomass

Orders of the other Commissions on Plant Load Factor (PLF)

Particulars Andhra

Pradesh



20.3.04

17.8.2007 15.5.2007 18.1.2005 27.4.2009

Plant Load Factor

(%)

80% 80% 80% 75% 80%

After considering the suggestions of stakeholders, PLFs approved by the various

Regulatory Commissions, the Commission decides to fix the PLF for biomass

power plants at 80%.

6.2.5 Gross Calorific Value (GCV)

CERC in its draft regulations, 09 has proposed the calorific value of biomass for

the state of Uttar PRADESH AS 3371 Kcal/Kg. The Commission decides to approve

calorific value of biomass as 3200 Kcal/Kg

6.2.6 Specific Fuel Consumption and Station Heat Rate

The Commission in its earlier Regulation 2005 had approved specific fuel

consumption same as of bagasse. Anil Modi Oil Industries Ltd. has proposed for

specific consumption of 1.36 kg/kWh as per Appellate Tribunal order that

expresses to consider 1.36 kg/kWh as specific fuel consumption for biomass.

Sukhbir Agro has also suggested Specific consumption in the range of around 1.30

kg/kWh. The Specific fuel consumption prevailing in other states is tabulated

below:

Table 35: Specific Fuel Consumption approved by various SERCs – Biomass

Orders of the other Commissions on Specific Fuel Consumption

Particulars Andhra

Pradesh



20.3.04

17.8.2007 15.5.2007 18.1.2005 27.4.2009

Specific Fuel

Consumption

(kg/kWh)

1.16 1.30 1.36 1.16 1.20

CEA in its operation norms for biomass based power plants has recommended

specific fuel consumption of 1.36 kg/kWh. Hence, the Commission approves

Page 55

Specific fuel consumption as 1.36 kg/kWh with the given calorific value of biomass

and specific fuel consumption, SHR for biomass projects shall be 4350 Kcal/Kwh

6.2.7 Fuel Cost

Rice Husk is the main fuel being used in biomass power plants besides agriculture

crop residues of wheat/ paddy, wheat/ paddy straw, bamboo wastes etc. Sukhbir

Agro in its submission has estimated fuel price of Rs.2800/MT with GCV of 2800

kcal/Kg considering rice husk as main fuel. Anil Modi Oil Inds has suggested price

of Rs.2700/MT considering average price for 7 months of the husk season.

The biomass price approved by other SERCs is provided in the table below with

fuel price escalation:

Table 36: Fuel Cost approved by various SERCs – Biomass

.

Orders of the other Commissions on Fuel Cost

Particulars Andhra

Pradesh

Gujarat Haryana Rajasthan Tamilnadu


20.3.04

17.8.2007 15.5.2007 23.1.2009 27.4.2009

Fuel Cost (Rs/MT) 2000/-

with 5%

escalation

1000/-

with 5%

escalation

1600/- 1216/-

with 5%

escalation

2000/-

with 5%

escalation

CERC in its draft regulation 2009 on Renewable Energy source has mentioned

price of biomass fuel for State of U.P. at Rs.1428/MT while Rs.2039/MT for

Haryana and Rs.1807/MT for Rajasthan in equivalent terms of coal.

Taking into account above figures and fuel prices approved by other states,

Commission considers fuel cost of biomass on the basis of equivalence of average

coal cost approved by the Commission for UP’s State thermal plants under its

Tariff order for FY 08-09. In this order, the Commission has determined simple

average GCV as 3544 Kcal/kg for all the stations and likewise has considered

average coal cost of Rs 1731/MT for all the stations. Thus, GCV of Biomass as

3200 Kcal; in equivalence terms of coal on pro-rata basis, biomass fuel cost comes

out as Rs 1657/MT (escalated at 6% on FY 08-09 figures to arrive at FY 09-10

figures) and stands approved by the Commission. The fuel price shall be escalated

by 6% per annum on compounded basis for subsequent years.

Page 56

6.2.8 Effective Tariff for Biomass Plants


Commission in the preceding paragraphs, the fixed cost tariff for Biomass power

plants for the period from FY 2008-09 to FY 2013-14 would be as under:

Table 37: Fixed Cost of Biomass Power Plants

Biomass - New Projects (Fixed Cost: Rs/Kwh)

Year of

Commissioning

FY 2009-

10

FY 2010-11 FY 2011-12 FY 2012-13 FY 2013-14

FY 2008-09 1.68 1.65 1.61 1.58 1.55

FY 2009-10 1.77 1.73 1.69 1.66 1.62

FY 2010-11 1.82 1.78 1.74 1.70

FY 2011-12 1.87 1.83 1.79

FY 2012-13 1.91 1.87

FY 2013-14 1.96

The variable cost for Biomass power plants is estimated to be as under:

Table 38: Variable Cost of Biomass Power Plants

Biomass - New Projects


(Rs/kWh)

FY 2009-10 2.61

FY 2010-11 2.77

FY 2011-12 2.93

FY 2012-13 3.11

FY 2013-14 3.29

The effective tariff for Biomass Power plants is estimated to be as under:

Table 39: Effective Tariff for Biomass Power Plants

Biomass - New Projects (Total Cost: Rs/Kwh)

Year of

Commissioning

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

FY 2008-09 4.29 4.41 4.55 4.69 4.84

FY 2009-10 4.38 4.50 4.63 4.77 4.92

FY 2010-11 4.58 4.71 4.85 5.00

FY 2011-12 4.80 4.93 5.08

FY 2012-13 5.02 5.17

FY 2013-14 5.26

Page 57

Note: For plants commissioned during FY 2008-09, the tariff as specified in the

above table shall be effective from the date of this order or the date of CNCE

Regulations’09, as may be decided by the Commission. For the earlier period, tariff

shall be determined under CNCE regulations, 2005.

6.3 Incentive for Existing & New Plants

The Commission appreciates that the plants might be running above 80% PLF.

Since the total fixed cost has been considered for determining tariff for supply of

power upto 80% PLF, the additional cost for such supply would only be the fuel

cost. The Commission is of the view that it needs to provide suitable incentive to

the biomass based generating plants to generate more power. The generator shall

be paid as below:

(a) Variable cost as applicable Table 38; plus

(b) Incentive as given in Table 40

Table 40: Incentive Structure for Biomass Plants

Plant Load Factor Incentive


More than 85% 25 Paise per Kwh

Page 58

7. SMALL HYDRO POWER PLANTS

The Commission in the earlier order dated 18.7.2005 had determined tariff for

small hydro power plants for 20 years. As per the available information with the

Commission, no plant was commissioned during period of CNCE Regulations,

2005. Still the, Commission is determining tariff for existing plants on old norms

except for O&M escalation at 5.72% , revised norms on interest on working

capital and rate of interest on working capital at 12.80%.Further, the Commission

also intends to determine tariff for the new projects to be commissioned on or

after 1st April 2009.

7.1 Tariff Methodology Existing Small Hydro Projects

The Return on Equity, O&M expenses, Escalation on O&M expenses, Working

Capital norms and Interest on working capital etc., for existing plants, for

determination of tariff shall be considered as below:

1. Capital Cost - Rs 4.5 Cr/Mw


3. O&M Expenditure - 2.5% of escalated approved Project Cost

4. Interest on Debt - 10.25% per annum


6. Working Capital - O&M Expenses – 1 Month,

Receivables – 2 months,

Spares cost – 15% of O&M expenses



9. Auxiliary Consumption & - 1%

Transformation Losses


On the basis of above mentioned parameters Commission has determined

following tariff for the Existing Small Hydro Plants.

Table 41: Effective Tariff for Small Hydro Plants – Old Projects (Rs/Kwh)

Year of

Commissioning

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

FY 2005-06 2.89 2.81 2.73 2.65 2.57

FY 2006-07 3.06 2.97 2.89 2.81 2.73

FY 2007-08 3.24 3.15 3.06 2.97 2.89

FY 2008-09 3.42 3.33 3.24 3.15 3.06

Page 59

7.2 Tariff Methodology for New Hydro Projects

7.2.1 Capital Cost

The capital cost is the major factor in Small Hydro Plants and varies largely with

the capacity of the plant. CERC in its Draft Regulation 2009 on Renewable Energy

has proposed a capital cost of Rs.6.30 Crs/MW for Himachal Pradesh,

Uttarakhand and North Eastern States and for other states it is proposed at Rs.

5.00 Crs/MW. The capital cost approved in other states for Small Hydro plants is

given in the table below:

Table 42: Capital Cost approved by various SERCs – Small Hydro


Particulars Andhra Pradesh CSEB Haryana Karnataka Kerala


20.3.04

22.5.2008 15.5.2007 18.1.2005 24.6.2006

Capital Cost

(Rs.Crs/MW)

3.625 Admitted cost

+ 1.5% of

CAPEX as

initial spares

10.25 3.90 4.88

The Commission considered in CNCE Regulations, the capital cost of Rs 4.5 Cr/MW

for plants having PLF 35%. Subsequently, a capital cost of Rs 7.88 Cr/MW was

allowed for plants having PLF more than 70% vide order dated 7-7-08 passed as

Petition No. 492/07. Considering above level of capital costs and plant load

factors, the Commission presumes that capital costs of plant shall vary linearly

with load factors varying above 35% to 70% .Therefore, the capital costs with

different range of PLF’s are decided hereunder:

Table 43: Capital Cost for Small Hydro Plants

PLF Range Capital Cost

Rs Cr/Mw

35%-40% 5.30

More than 40%-45% 5.75

More than 45%-50% 6.20

More than 50%-55% 6.65

More than 55%-60% 7.10

More than 60%-65% 7.55

More than 65%-70% 8.00

The above costs shall be applicable on plants commissioned on or after 1st April

2009. For plants commissioned in subsequent years, these costs shall be escalated

by factor 3% (simple) annually.

Page 60



14%. The Commission has analysed the RoE approved by other SERCs which is

around 16% to 20% on pre-tax basis. CERC also in its Tariff Regulations 2009 has

allowed 15.5% post tax RoE which works out to around 17% pre-tax for period

where MAT is applicable. The RoE approved by other State Electricity Regulatory

Commissions is provided below:

Table 44: Return on Equity approved by various SERCs – Small Hydro


Particulars Andhra

Pradesh

CSEB Haryana Karnataka Kerala


20.3.04

22.5.2008 15.5.2007 18.1.2005 24.6.2006

Return on Equity (%) 16% 16% 16% 16% 14%


16% (pre-tax basis) per annum to promote these sources of generation.

7.2.3 Operation & Maintenance Expenditure

The earlier regulation had O&M expenditure in terms of 2.50% of project cost for

first year escalated by 4% per annum for each subsequent year. The O&M

expenses approved by various SERCs are tabulated as under:

Table 45: O&M Expenses approved by various SERCs – Small Hydro


Particulars Andhra

Pradesh

CSEB M.P. Karnataka Kerala


20.3.04

22.5.2008 Sep-08 18.1.2005 24.6.2006

O&M Expenses

(as a % of Project

cost)

1.50% with

4%

escalation

2.50%

with 5%

escalation

2.50%

with 4%

escalation

1.50%

with 5%

escalation

1.5% with

4%

escalation

The O&M expense is approved at 2.5% of the Capital Cost as given in the Table

below for the first year of operation with an annual escalation of 5.72% on

compounded basis to take care of its O&M expenses

Page 61

Table 46: O&M Expenses approved for Small Hydro Plants

PLF Range O&M Expenses

Rs Lakh/Mw

35%-40% 13.25

More than 40%-45% 14.38

More than 45%-50% 15.50

More than 50%-55% 16.63

More than 55%-60% 17.75

More than 60%-65% 18.88

More than 65%-70% 20.00

7.2.4 Effective Tariff for Small Hydro Projects


Commission in the preceding paragraphs, the fixed cost tariff for Small Hydro

Plants to be commissioned on or after 1st April 2009 would be as under:

Table 47: Effective Tariff for Small Hydro Plants – New Projects

PLF (35% to 40%),Capital Cost (Rs 5.3 Cr /MW)

Year of

Operation

FY 10 FY 11 FY 12 FY 13 FY 14

FY 10 3.83 3.71 3.58 3.46 3.34

FY 11 3.94 3.82 3.69 3.56

FY 12 4.06 3.93 3.80

FY 13 4.17 4.04

FY 14 4.29

PLF (More than 40% to 45%),Capital Cost (Rs 5.75 Cr /MW)

Year of

Operation

FY 10 FY 11 FY 12 FY 13 FY 14

FY 10 3.67 3.55 3.43 3.31 3.20

FY 11 3.78 3.65 3.53 3.41

FY 12 3.89 3.76 3.63

FY 13 4.00 3.87

FY 14 4.11

Page 62


Year of

Operation

FY 10 FY 11 FY 12 FY 13 FY 14

FY 10 3.54 3.42 3.31 3.20 3.08

FY 11 3.64 3.52 3.41 3.29

FY 12 3.75 3.63 3.51

FY 13 3.86 3.73

FY 14 3.96


Year of

Operation

FY 10 FY 11 FY 12 FY 13 FY 14

FY 10 3.43 3.32 3.21 3.10 2.99

FY 11 3.54 3.42 3.31 3.19

FY 12 3.64 3.52 3.40

FY 13 3.74 3.62

FY 14 3.84


Year of

Operation

FY 10 FY 11 FY 12 FY 13 FY 14

FY 10 3.35 3.24 3.13 3.02 2.92

FY 11 3.45 3.33 3.22 3.11

FY 12 3.55 3.43 3.32

FY 13 3.65 3.53

FY 14 3.75


Year of

Operation

FY 10 FY 11 FY 12 FY 13 FY 14

FY 10 3.27 3.17 3.06 2.96 2.85

FY 11 3.37 3.26 3.15 3.05

FY 12 3.47 3.36 3.25

FY 13 3.57 3.45

FY 14 3.67

Page 63


Year of

Operation

FY 10 FY 11 FY 12 FY 13 FY 14

FY 10 3.21 3.11 3.00 2.90 2.80

FY 11 3.31 3.20 3.09 2.99

FY 12 3.40 3.29 3.18

FY 13 3.50 3.39

FY 14 3.60

7.2.5 Incentive

The Tariff indicated above will be applicable for the Power Plants for the different

range of PLF .If PLF of a plant during a year exceeds the range ; it shall be eligible

for an incentive of 35 Paise for every unit delivered at generator terminals i.e.

including captive and auxiliary consumption.

For e.g. A Plant having PLF of 43% shall fall in the range of 40%-45%; then any

production beyond 45 % PLF shall be eligible for incentive of 35 Paise per unit.

Similarly, A Plant having PLF of 59% shall fall in the range of 55%-60%; then any

production beyond 60 % PLF shall be eligible for Incentive of 35 Paise per unit.

Page 64

8. SOLAR POWER PLANTS

MNRE has issued guidelines for generation based incentive, for grid connected

solar power generation projects, to encourage grid quality power generation from

megawatt size solar power plants. The Ministry will provide generation based

incentive up to maximum Rs.12 per Kwh for solar photovoltaic power and Rs. 10

per Kwh for solar thermal power fed to the grid after deducting price under

Power Purchase Agreement (PPA) with the utility from a notional amount of Rs.15

per Kwh. The main features of scheme are as given under:

• MNRE proposes to install an aggregate capacity of 50 MW Solar Power

plants during 11th plan period under incentive scheme.

• Solar power projects with an aggregate capacity maximum of 10 MW in a

State would be considered for incentive. The maximum incentive of Rs 12

for Solar PV & Rs 10 for Solar Thermal may be given to eligible projects

which are commissioned by 31st December 2009.

• Any project that is commissioned after 31st December 2009 would be

eligible for an incentive with a 5% reduction and ceiling of Rs.11.40 per

Kwh for solar photo-voltaic, Rs.9.50 per Kwh for solar thermal.

• Proposal from each project developer with a maximum aggregate capacity

of 5 MW either through a single project or multiple projects of a minimum

capacity of 1 MW each at a single location would be considered for

incentive.

GOI is in process of evolving detailed policy for solar power. The costs of solar

plants are changing drastically with newer technologies. As such in future the

tariff for solar power shall be accordingly determined by an order by the

Commission. Till such time, the tariff orders on Solar Power Plants determined by

Commission dated 27th June 2008 (petition no. 522/2008), 27th November 2008

(petition no. 572/2008) and 18th February 2009 (petition no. 592/2008) shall be

applicable for both the cases/ schemes mentioned below:

8.1 Solar Plants covered under MNRE scheme

For Solar Power Plants covered under MNRE scheme the orders mentioned in

Clause 8 above shall be applicable.

8.2 Solar Plants not covered under MNRE scheme

The tariff for Solar Power Plants not covered under GOI Incentive scheme

commissioned upto 31-12-2011, vide order dated 27-06-08, shall be as given

below:

Page 65

Table 48: Tariff for Solar Power – Not covered under GOI Scheme

Types of Solar Power Plants Rate of Electricity for

20 Years

Solar Photovoltaic Rs.15.00/kWh

Solar Thermal Rs.13.00/kWh

9. OTHER NCE PROJECTS (EXCEPT BAGASSE/BIOMASS/SHP/SOLAR)

For this category, there was no representation from other NCE based generators,

therefore the Commission approves minimum of the tariff from existing and new

plants. As soon as the projects come in the state, the Commission may review the

tariff even on case to case basis.

9.1 Tariff for other NCE sources-Existing Plants

The tariff for other existing NCE plants shall be @ Rs.2.89/kWh with an escalation

of 5.72% p.a.

9.2 Tariff for other NCE sources- New Plants

The tariff for other NCE projects shall be @ Rs.3.21/Kwh with an escalation of

5.72% p.a.

10. SUMMARY OF OPERATIONAL & FINANCIAL PARAMETERS – CNCE SOURCES

The Commission would like to summarise below the operational and financial

parameters used in tariff determination for Captive, Bagasse & Biomass for

commissioning on or after 1st

April 2009.

Page 66

Table 49: Summary of NCE Source Parameters: Existing Projects

UPERC - Parameters for CNCE Regulations 2009 - Existing Projects

PARAMETERS - Fixed Cost Principle CPP Bagasse SHP

Capital Cost (Rs.Crs/MW) 3.50 3.50 4.50

Capital Cost Escalation (%) Simple Escalation (fixed) 3.00% 3.00% 3.00%

Debt-Equity Ratio (%) 70:30 2.33 2.33 2.33

Debt Repayment Period (years) 10 10 10

Interest on debt (%) 10.25% 10.25% 10.25%

ROE (%) 15.5% 16.0% 16.0%

Depreciation (%) 7.00% 7.00% 7.00%

O&M Expenditure %/Rs.Lakhs/MW 2.50% 10.23 Rs

Lakh/MW

2.50%

O&M Escalation (%) Annual Escalation (Rate

as per CERC)

5.72% 5.72% 5.72%

Working Capital computations:

Coal Cost Cost for months 1.5 - -

Oil Cost Cost for months 2.0 - -

Bagasse/Biomass Cost Cost for months - 1.0 -

O&M Expenditure Cost for months 1.0 1.0 1.0

Receivables Cost for months 2.0 2.0 2.0

Spares for O&M (All sources) % of O&M cost 20% 15.0% 15.0%

Interest on WC (%) Avg of FY 2008-09 12.80% 12.80% 12.80%

PARAMETERS - Variable Cost Principle CPP Bagasse SHP

PLF (%) For cost recovery 80% 50% 35%

Aux consumption (%) SHP - Transformation

loss 0.5% + Aux - 0.5%

10% 8.5% 1.0%

Cost of Coal (Rs/MT) 1,352 - -

Cost of Oil (Rs/KL) 15,836 - -

Cost of Bagasse/Biomass (Rs/MT) - 1,178 -

Fuel escalation (%) (Coa/Oil/Bagasse/

Biomass etc)

Annual Escalation

(compounded basis)

6% 6% -

SHR (kcal/kWh) 2800 3650 -

GCV - Coal/Bag/Bio (kcal/kg) 3400 2275 -

Specific Fuel Cons (kg/kWh) 1.60 -

GCV - Oil (kcal/kl) 10000 - -

Specific oil cons (Ml/kWh) 2.00 - -

Page 67

Table 50: Summary of NCE Source Parameters: New Projects

UPERC - Parameters for CNCE Regulations 2009 - New Projects (FY 2009-10)

PARAMETERS - Fixed Cost Principle CPP (0-

100 MW)

CPP

(101-

300)

CPP

(Above

300 MW)

Bagasse Biomass

Capital Cost (Rs.Crs/MW) 4.50 4.00 3.50 4.00 4.25

Capital Cost Escalation (%) Simple Escalation

(fixed)

3.00% 3.00% 3.00% 3.00% 3.00%

Debt-Equity Ratio (%) 70:30 2.33 2.33 2.33 2.33 2.33

Debt Repayment Period

(years)

10 10 10 10 10

Interest on debt (%) 12.80% 12.80% 12.80% 12.80% 12.80%

ROE (%) 15.50% 15.50% 15.50% 16.00% 16.00%

Depreciation (%) 7.00% 7.00% 7.00% 7.00% 7.00%

O&M Expenditure Rs.Lakhs /MW 11.25 10.00 8.75 12.00 17.00

O&M Escalation (%) Annual Escalation

(Rate as per

CERC)

5.72% 5.72% 5.72% 5.72% 5.72%

Working Capital

computations:

Coal Cost Cost for months 1.5 1.5 1.5 - -

Oil Cost Cost for months 2.0 2.0 2.0 - -

Bagasse/Biomass Cost Cost for months - - - 1.0 2.0

O&M Expenditure Cost for months 1.0 1.0 1.0 1.0 1.0

Receivables Cost for months 2.0 2.0 2.0 2.0 2.0

Spares for O&M (All sources) % of O&M cost 20% 20% 20% 15.0% 15.0%

Interest on WC (%) Avg. of FY 2008-

09

12.80% 12.80% 12.80% 12.80% 12.80%

PARAMETERS - Variable Cost Principle CPP

(0-100

MW)

CPP

(101-

300)

CPP

(Above

300 MW)

Bagasse Biomass

PLF (%) For cost recovery 80% 80% 80% 50% 80%

Aux consumption (%) SHP -

Transformation

loss 0.5% + Aux -

0.5%

10% 9% 8% 8.5% 8.5%

Cost of Coal (Rs/MT) 1352 1352 1352 - -

Cost of Oil (Rs/KL) 15,836 15,836 15,836 - -

Cost of Bagasse/Biomass

(Rs/MT)

- 1,178 1,657

Fuel escalation (%)

(Coa/Oil/Bagasse/ Biomass

etc)

Annual Escalation

(compounded

basis)

6% 6% 6% 6% 6%

SHR (kcal/kWh) 2800 2500 2500 3100 4350

GCV - Coal/Bag/Bio (kcal/kg) 3400 3400 3400 2275 3200

Specific Fuel Cons (kg/kWh) 1.36 1.36

GCV - Oil (kcal/kl) 10000 10000 10000 - -

Specific oil cons (Ml/kWh) 1.00 1.00 1.00 - -

Page 68

11. This order shall come into effect from 1.10.2009 .Accordingly, proposed

regulations 1(2) shall be modified to read as below

“These regulations shall come into force with effect from 1.10.2009 and shall

remain in force upto 31.03.2014 unless reviewed earlier or extended by the

Commission”

12. Based on decisions taken above in this Order, Draft Regulations shall be modified.

Any correction or modification incidental to above decisions shall also be carried

out in the draft regulations including the minor correction in language, if any.

Final “Uttar Pradesh Electricity Regulatory Commission (Terms and Conditions of

Supply of Power from Captive and Non-conventional Energy Generating Plants)

Regulations, 2009”, so made, shall be put up for approval of the Commission.

These Regulations shall come in to force from 1st October, 2009. The Secretary to

the Commission shall get these Regulations notified in the official gazette with

Hindi Translation. Pending Gazette Notification, the Regulations approved by the

Commission shall be made public by posting it on the Website of the Commission

and informing all persons by a Public Notice in the newspapers.

13. The matter is disposed of.

(Rajesh Awasthi)

Chairman

Place: Lucknow

Dated: 09-09-09

Page 69

Annexure 1

List of Participants attended Public Hearing on 15.5.09

1. Sri. Durga Prasad, UP Co-gen Association

2. Sri. K.N. Ranasaria, UP Co-gen Association

3. Sri. Sameer Sinha, Triveni Engg. & Industries Ltd.

4. Sri. S.C Rathi, Dhampur Sugar Mills Ltd.

5. Sri Pankaj Rastogi, Dalmia Chini MIlls

6. Sri Pradeep Mittal, Dalmia Chini MIlls

7. Sri. R.K Chakravorty, UP Co-gen Association

8. Sri. Anil Gupta, Balrampur Chini Mills Ltd.

9. Sri. D.D Chopra, Advocate

10. Sri. S.N.M Tripathi, BHL & BHSIL

11. Sri. G.K Thakur, BHL

12. Sri. R.P Sharma, HIndalco

13. Sri. Anup Singh, DCM Sriram Consolidated Ltd.

14. Sri. G.N Agarwal, Mawana Sugar Ltd.

15. Sri. M.L Arora, Sukhbir Agro Energy Ltd.

16. Sri. Anil Modi, Anil Modi Oil Ind. Ltd. (AMOIL)

17. Sri. R.Kumar, Abhinav Steels Pvt. Ltd.

18. Sri. S.S Singh, J.K Sugar Ltd.

19. Sri. R.K Modwell, Dwarikesh Sugar Ltd.

20. Sri Rinkesh Kumar, Universal Biomass.

21. Sri R.K. Lawania, Mawana Sugars.

22. Sri Dilip Kumar, Kanoria Chemicals.

23. Sri S.P. Pandey, E.E., UPPCL.

24. Sri S.N. Dubey, C.E., UPPCL.

25. Sri N.K. Garg, DCM Sriram Consolidated Ltd.

26. Sri Rakesh Kumar, Dhampur Sugar.

27. Sri R.K. Bharti, DSCL.

28. Sri S.P. Bose, Advocate.

29. Sri Utkarsh Raguhubanshi, Hindalco.

Page 70


1. Sri. Durga Prasad, , UP Co-gen Association



4. Sri. Anoop Kumar, DSCL

5. Sri. Ram Sharma, Simbhaoli Sugar Ltd.









14. Sri. R.P Sharma, HIndalco


16. Sri. G.N Agarwal, Mawana Sugar Ltd.

17. Sri. P.K Bhalla, Mawana Sugar Ltd.


19. Sri. Akshay Modi, Anil Modi Oil Ind. Ltd. (AMOIL)

20. Sri. R.Kumar, Abhinav Steels Pvt. Ltd.

21. Sri. Vaibhav Pandey, Universal Biomass

22. Sri. C. Vani, Mawana Sugar Ltd.



25. Sri. Praveen Kumar, Dwarikesh Sugar Ltd.

26. Sri. B.D Banerjee, Balrampur Chini Mills Ltd.

27. Sri. A.K Srivastava, Dwarikesh Sugar Ltd.

Page 71


1. Sri. Durga Prasad, , UP Co-gen Association












13. Sri. Utkarsh Raghubanshi, Hindalco



16. Sri. Vaibhav Pandey, Universal Biomass



19. Sri. Praveen Kumar, Dwarikesh Sugar Ltd.

20. Sri. B.D Banerjee, Balrampur Chini Mills Ltd.

21. Sri. A.K Srivastava, Dwarikesh Sugar Ltd.

22. Sri. N.K Garg, DCM Sriram Consolidated Ltd.

23. Sri. A.M Srivastava, Abhinav Steels Pvt. Ltd.

24. Sri. S.N. Dubey, CE, UPPCL

25. Sri. S.P. Pandey, EE, UPPCL

26. Sri. R.K Lavania, Mawana Sugars

27. Sri. Sandeep K. Verma, Mawana Sugars

Page 72


1. Sri S.K. Agarwal, Director, UPPCL.

2. Sri. Anoop Singh, G.M., DCM Sriram Consolidated Ltd.

3. Sri. M.L Arora, G.M., Sukhbir Agro Energy Ltd.

4. Sri Feroz Ahmad, U.P., NEDA.

5. Sri. S.C Rathi, Consultant, Dhampur Sugar Ltd.

6. Sri Rajiv Sehgal, Dalmia Chini Mills Ltd.

7. Sri Anil, G.M., Parle Sugar.

8. Sri Sanjeev Sinha, Dy. G.M., Parle Sugar.

9. Sri Pankaj Rastogi, Dy. Executive Director, Dalmia Chini Mills.

10. Sri. Anil Gupta, C.G.M.(Power), Balrampur Chini Mills Ltd.

11. Sri R.K. Chakravarti, Co-gen Association.

12. Sri. K.N. Ranasaria, U.P. Co-gen Association.


14. Sri. Durga Prasad, UP Co-gen Association.

15. Sri Rakesh Kumar, Member Co-gen Association, Dhampur Sugar.

16. Sri S.N.M. Tripati. Sr. Advisor (Tech) M/s BHL & BHSIL.

17. Sri Pradeep Mittal, Member, Co-gen, Dalmia Chini Mills.

18. Sri. R.K Modwell, Advisor, Dwarikesh Sugar Ltd.


20. Sri. D.D Chopra, Advocate, UP Co-gen Sugar Mills Association

21. Sri Sudhir Kumar, Director (NEDA).

22. Sri A.K. Arora, Noida Power Co. Ltd.

23. Sri Prashant Chaturvedi, Dy. Manager, NTPC, NRHQ, Lucknow.

24. Sri S. Ganguly, Sr. Manager, NPCL.

25. Sri B.D. Banerji (Corporate Coordinator), Balrampur Chinni Mills Ltd.

26. Sri R.K. Lawania, Mawana Sugars Ltd.

27. Sri. S.S Singh, J.K. Sugar Ltd.

Documents

BEFORE THE UTTAR PRADESH ELECTRICITY REGULATORY COMMISSION