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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
Page 24
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
Cost Elements Parameters
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
O&M Expn Rs.20.25 lakh/ MW
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
Cost Elements Parameters
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%
O&M Expn Rs.12.00 lakh/ MW
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
Page 29
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
Page 30
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
4.3.2 Determination of Variable Cost
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
Unit Size (100-300 MW)
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
Unit Size (100-300 MW)
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
The Commission in its earlier regulation had provided Return on Equity (RoE) at
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
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
Return on Equity (%) 16% 14% (Post-
tax)
16% 16% 19.85%
Accordingly, the Commission has decided to allow Return on Equity at the rate of
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.
5.1.2 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. 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
Date of order 31.3.09 &
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
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
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
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
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
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
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
5. Interest on WC - 12.80% p.a.
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
5.2.2 Determination of Variable Cost
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
Financial Year Variable Cost
(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
5.2.3 Effective Tariff
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:
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
Page 48
Month, Receivables – 2 months, Spares
cost – 15% of O&M expenses
5. Interest on WC - 12.80% p.a.
6. Plant Load Factor - 50%
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
Taking into account the technical and financial parameters considered by the
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 70% -80% 20 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
Orders of the other Commissions on Capital Cost
Particulars Andhra
Pradesh
Gujarat Haryana Karnataka Tamilnadu
Date of order 31.3.09 &
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.
6.2.2 Return on Equity
The Commission in its earlier regulation had provided Return on Equity (RoE) at
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
Orders of the other Commissions on Return on Equity
Particulars Andhra
Pradesh
Gujarat Haryana Karnataka Tamilnadu
Date of order 31.3.09 &
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.
6.2.3 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. 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
Orders of the other Commissions on O&M Expenses
Particulars Andhra
Pradesh
Gujarat Rajasthan Karnataka Tamilnadu
Date of order 31.3.09 &
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
Gujarat Haryana Karnataka Tamilnadu
Date of order 31.3.09 &
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
Gujarat Haryana Karnataka Tamilnadu
Date of order 31.3.09 &
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
Date of order 31.3.09 &
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
Taking into account the technical and financial parameters considered by the
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
Financial Year Variable Cost
(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 80% -85% 15 Paise per Kwh
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
2. Return on Equity - 16% of Equity amount (pre-tax)
3. O&M Expenditure - 2.5% of escalated approved Project Cost
4. Interest on Debt - 10.25% per annum
5. Escalation on O&M expenses - 5.72% p.a.(compounded basis)
6. Working Capital - O&M Expenses – 1 Month,
Receivables – 2 months,
Spares cost – 15% of O&M expenses
7. Interest on WC - 12.80% p.a.
8. Plant Load Factor - 35%
9. Auxiliary Consumption & - 1%
Transformation Losses
7.1.1 Effective Tariff
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
Orders of the other Commissions on Capital Cost
Particulars Andhra Pradesh CSEB Haryana Karnataka Kerala
Date of order 31.3.09 &
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
7.2.2 Return on Equity
The Commission in its earlier regulation had provided Return on Equity (RoE) at
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
Orders of the other Commissions on Return on Equity
Particulars Andhra
Pradesh
CSEB Haryana Karnataka Kerala
Date of order 31.3.09 &
20.3.04
22.5.2008 15.5.2007 18.1.2005 24.6.2006
Return on Equity (%) 16% 16% 16% 16% 14%
Accordingly, the Commission has decided to allow Return on Equity at the rate of
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
Orders of the other Commissions on O&M Expenses
Particulars Andhra
Pradesh
CSEB M.P. Karnataka Kerala
Date of order 31.3.09 &
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
Taking into account the technical and financial parameters considered by the
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
PLF (More than 45% to 50%),Capital Cost (Rs 6.2 Cr /MW)
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
PLF (More than 50% to 55%),Capital Cost (Rs 6.65 Cr /MW)
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
PLF (More than 55% to 60%),Capital Cost (Rs 7.1 Cr /MW)
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
PLF (More than 60% to 65%),Capital Cost (Rs 7.55 Cr /MW)
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
PLF (More than 65% to 70%),Capital Cost (Rs 8.0 Cr /MW)
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
List of Participants attended Public Hearing on 25.5.09
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. Anoop Kumar, DSCL
5. Sri. Ram Sharma, Simbhaoli Sugar Ltd.
6. Sri. S.C Rathi, Dhampur Sugar Mills Ltd.
7. Sri Pankaj Rastogi, Dalmia Chini MIlls
8. Sri Pradeep Mittal, Dalmia Chini MIlls
9. Sri. R.K Chakravorty, UP Co-gen Association
10. Sri. Anil Gupta, Balrampur Chini Mills Ltd.
11. Sri. D.D Chopra, Advocate
12. Sri. S.N.M Tripathi, BHL & BHSIL
13. Sri. G.K Thakur, BHL
14. Sri. R.P Sharma, HIndalco
15. Sri. Anup Singh, DCM Sriram Consolidated Ltd.
16. Sri. G.N Agarwal, Mawana Sugar Ltd.
17. Sri. P.K Bhalla, Mawana Sugar Ltd.
18. Sri. M.L Arora, Sukhbir Agro Energy 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.
23. Sri. S.S Singh, J.K Sugar Ltd.
24. Sri. R.K Modwell, Dwarikesh 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
List of Participants attended Public Hearing on 27.5.09
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. Ram Sharma, Simbhaoli Sugar Ltd.
5. Sri. S.C Rathi, Dhampur Sugar Mills Ltd.
6. Sri Pankaj Rastogi, Dalmia Chini MIlls
7. Sri Pradeep Mittal, Dalmia Chini MIlls
8. Sri. R.K Chakravorty, UP Co-gen Association
9. Sri. Anil Gupta, Balrampur Chini Mills Ltd.
10. Sri. D.D Chopra, Advocate
11. Sri. S.N.M Tripathi, BHL & BHSIL
12. Sri. G.K Thakur, BHL
13. Sri. Utkarsh Raghubanshi, Hindalco
14. Sri. Anup Singh, DCM Sriram Consolidated Ltd.
15. Sri. M.L Arora, Sukhbir Agro Energy Ltd.
16. Sri. Vaibhav Pandey, Universal Biomass
17. Sri. S.S Singh, J.K Sugar Ltd.
18. Sri. R.K Modwell, Dwarikesh Sugar Ltd.
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
List of Participants attended Public Hearing on 27.8.09
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.
13. Sri. Ram Sharma, Simbhaoli Sugar Ltd.
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.
19. Sri. Sameer Sinha, Triveni Engg. & Industries 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.