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1~1(tC{~~ BEFORE THE HON'BLE

CENTRAL ELECTRICITY REGULATORY COMMISSION,

NEW DELHI

Petition No.: _1_/2017

IN THE MATTER OF

Automatic Generation Control (AGC) pilot project

AND

IN THE MATTER OF

National Load Despatch Centre

Power System Operation Corporation Ltd.

(A Government of India Enterprise) B-9, Qutab Institutional Area, Katwaria Sarai

New Delhi-II 00 16 .......... Petitioner

VERSUS

NTPC Limited & 152 Ors.

. ........ Respondents

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S. No.

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2

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5

6

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INDEX

Particulars

Submission

Annexe-l

Annexe-2

Annexe-3

Annexe":4

Annexe-.5

Annexe-6

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Power Systeni Operation Corporation Ltd.

~/~~ .. Represerited by: S.R.Narasimhan

Additional General Manager, NLDC - POSOCO

Place: New Delhi

Dated: 31.03.2017 .

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BEFORE THE CENTRAL ELECTRICITY REGULATORY COMMISSION

NEW DELHI

IN THE MATTER OF:

Automatic Generation Contro l (AGC) pilot project

AND

Nationa l Load Despatch Centre Petitioner

VERSUS

NTPC Limited & Drs. Respondents

AFFIDAVIT

I, S. R. Naras imhan, working as Additiona l General Manager, NLDC, Power System Operation

Corporation Limited (POSOCO), having its registered office at 8 ·9, Qutah Institutional Area,

Katwaria Sara i, New Delhi· ) 10016, do solemnly affi rm and state as follows:-

I. I, S. R. Narasimhan, working as Addit ional General Manager, NLDC, Power System

Operat ion Corporation Limited, the representative of the Petitioner in the above matter, am duly

authorized to make this affidav it.

2. The statements made in the Petition herein are based on the Company's offic ial record

maintained in the ord inary course of business and I believe them to be true and correct.

y~ DEPONENT

VERIFICATION

Solemnly affi rmed at Delhi on this 31 st day of March, 20 17 that the conten ts of the above affidavit

are true to my knowledge and belief and no part of it is fa lse and nothing material has been

concealed there from.

ATTEsTEb

)J 'i~· \~~ BAU/T S/ ~IGH

NOlary PUblic-R-l0015 GO'r'l cr 1"113

New /'\,." II

3 1 MAR _J17

DEPONENT

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Most Respectfully Showeth:

1. Han'hle Commission has vide Order dated 13th Oct 2015 in petition no IliSM/2015 gIven a

roadmap for operationalization of generation reserves in the country. The objective of the Order

was to provide a vision to introduce Spinning Reserves in the country, which is one of the

important components for ensuring grid security, quality and reliability by achieving adequacy of

supply and maintaining load-generation balance. The CERC Order on Spinning Reserves is

enclosed as Annexe-l.

2. As per the Order on Spinning Reserves by Hon'ble Commission, each region should maintain

primary, secondary and tertiary reserves. Hon'ble Commission in its Order mentioned that all

generating stations that are regional entities must plan to operationalise Automatic Generation

Control (AGe) along with reliable telemetry and communication by 1 ~t April, 2017. Hon 'hie

Commission also noted that this would entail a one-time expense for the generators to install

requisite sofuvare and firmware, which could be compensated for and that the communication

infrastructure must be planned by the Central Transmission Utility (CTU) and developed in

paraUeI, in a cost-effective manner.

3. The Hon'ble Commission directed NLDC/POSOCO to submit a detailed procedure to

operationalize reserves in the country vide Order dated 13th Oct 2015. In this connection, an

outline procedure was submitted by posaca to CERC vide letter dated 15 th December 2015. In

the outline procedure, posaca proposed to take up a pilot project with one of the NTPC plants

in a region based on which further activities could be taken up. A copy of the letter dated 15 th

December 2015 is enclosed as Annexe-2. POSOCO was advised to submit the draft detailcd

procedure and implementation plan for operationalization of Reserves within three months of

implementation of Ancillary Services Regulations. A copy of the letter by CERC dated 5th

February 2016 is enclosed as Annexe-3.

4. POSOCO had organized a two day discussion-cum-brainstorming session on implementation of

AGC in Indian power system at New Delhi on 19th and 20th January 2016. Representatives from

CERe, CEA, POWERGRID, NTPC and POSOCO participated in the above meeting. Professor

Anjan Bose, Professor, Washington State University, USA was also available as an expert during

this workshop. Four SCADA vendors were also invited to demonstrate the functionality of their

AGC software; three vendors presented the details of their software.

5. As a broad area of convergence after the two day session, a pilot project in each region was

agreed to be initiated to cover coal fired, gas based stations and storage hydro power stations. ft

was also discussed and agreed that generic technical specification should also be finalized under

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the proposed pilot project. Accordingly, summary of the discussion-cum-brainstorming meeting,

along with the short term action points were communicated to CERC vide letter dated 15th March

2016. The copy of the same is enclosed as Anncxe-4.

6. The summary of the discussion-cum-brainstorming session had also been communicated to the

members of the Forum of Load Despatchers (FOLD) in its 16th meeting held on 2nd March 2016.

This was welcomed by the FOLD members.

7. From the interactions with national and international expelts on power systems and experience

with Ancillary Services till date, the general understanding of POSOCO is that different

solutions as a package like load and Renewable Energy (RE) generation forecast, proper

portfolio management by the states, primary response from the generators, secondary control in

the form of AGC, Ancillary Service products in different time frames etc. are needed for the

stable frequency operation orthe powcr system. No unique solution exists. A bad or no forccast

of loadlRE generation and poor portfolio management by the state utilities would lead to heavy

deviations from schedule and grid indiscipline exhausting all reserves in the system and making

the system insecure. Automatic Generation Control (AGC) effectiveness would have to be seen

in this overall context. AGC Pilot Project is one of the steps in that direction for stable frequency

operation and security of the grid. Since this pilot project is being implemented onjust two units

with very little spinning reserve to start with, the pilot AGC may not exert any control on the ISO

GW large Indian power system. However, the response of the generator for variation in Area

Control Error (ACE) due to deviations in tie line flows ofNOithern Region (NR) and frequency

can be seen in this pilot project. Valuable experience can be gained in terms of implementation

aspects, communication protocols, generator regulation and load following capabilities, cyber

security etc. which will be useful during implementation of secondary control on a large scale.

8. During the discussion with NTPC representatives in the above said meeting, NTPC Dadri stage­

II was suggested by them for implementation of the first AGC pilot project keeping in view the

following:

a. Dadri Stage II power plant is located near NLDC, New Delhi.

b. Ease in monitoring the field level implementation process.

c. The variable cost of the power plant is higher than other thermal plants in Northern Region

under RLDC jurisdiction, being a load centre plant. Hence it is easy to keep Spinning

Reserves in the same. The only thermal plants in NR costlier than Dadri Stg -II are Dadri

Stg-I and Jhajjar. Other costlier plants (other than thennal) are all Gas based stations, which

might be considered for reserves subsequently.

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9. Accordingly, a team from POSOCO, POWERGRID and Mis Siemens visited NTPC Dadri on 6th

May 2016 to explore the ground level requirements/issues (if any) in the implementation of

Automatic Generation Control (AGC) at NTPC Dadri as a pilot project. Representatives from

NTPC demonstrated the existing plant level control system and also discussed the requirements

at plant level.

10. The proposed AGC pilot project shall be operated from NLDC/RLDC along with the required

hardware and software to be installed at NLDC/RLDC and NTPC Dadri Stage II. From the

experience of the brainstorming meetings, plant visit and internal discussions, detailed technical

specifications of the pilot AGC project were prepared by POSOCO. The AGC software would be

integrated with the existing SCADA system at NLDC/RLDC and data exchange would take

place accordingly. Modelled generating station/units with the static and dynamic data wil! be

configured along with the desired real-time data in the proposed AGC software. Phasor

Measurement Units (PMUs) would be installed by NTPC separately on the generator terminals at

Dadri Stage-II for monitoring the generator behaviour during different contingencies in the

system.

11. Further, in discussions with NTPC it was decided 10 place a combined award [rom POSOCO's

side for works at both NLDC and NTPC Dadri end. NTPC would reimburse posoca the costs

for its portion. Based on this finalised scope of works, bids were invited from prospective

vendors in October 2016 and MIS Siemens emerged as the successful bidder. Letter of Award

(LOA) was issued to MIS Siemens on 181ft January 2017 to start the execution of the AGC pilot

project. Same is enclosed as Annexe-S. POSOCO would be separately approaching the

Commission for approval orthe expenditure incurred for the AGC pilot project.

12. The AGC Pilot project was also discussed in the meetings by WRPC and SRPC forums attended

by POSOCO. AGe Pilot Project was discussed with SRPC constituents during a workshop on

AGC dated 3rd October 2016 at SRLDC, Bangalore. A presentation was made by NLDC at

SRPC Board Meeting dated 24th _25th February 2017 on the topic of AGC. WRPC and posoca discussed the AGC Pilot project as an agenda item in the 2~day workshop from 9th ~l alh February

2017 at Mumbai.

13. A detailed half year analysis and feedback on Reserve Regulation Ancillary Services (RRAS)

implementation in Indian Grid covering implementation aspects, challenges was submitted for

perusal of the Hon'ble Commission on 17ill November 2016. A copy of this report is available on

POSOCQ's website also at https:l/posoco.in/do\Vnload/halr-year~fecdbaek-to~

ecrel?\','Pdmdl=8916. It was observed that for Regulation 'Down', about { 0.49 per unit has been

retained by RRAS provider on an average in the period of six months. While for Regulation 'up'

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50 paise/kWh is being paid to the RRAS provider as per the Orders of the I-Ion 'ble Commission.

This aspect becomes important while finalizing the settlement mechanism for plants under AGC

outlined in the subsequent paragraphs.

14. The AGC Pilot Project mentioned is expected to be commissioned by mid-May 2017. While

severa! methods exist worldwide for compensating generating stations providing secondary

regulation services through AGC such as payments in tenns of Rs.JMW (considering opportunity

costs), a simple method is required considering that the power plant is under CERC'sjurisdiction

as far as tariff is concemed, its fixed cost liability is being shared by the beneficiaries and little

opportunity cost is involved in bringing this plant under AGC. To ensure the accounting and

settlement of the energy and power under Automatic Generation Control (AGC) and continuous

operation of the project the following is proposed

I. Energy produced due to AGC signals should be duly factored while working out the

deviations from the schedule.

ll. Aggregated AGC incrementa! MW signals over 15 minutes / 5 minutes would be logged in

MWh at NLDCINRLDC and NTPC Dadri as AGC MWh. NTPC Dadri may send its AGC

MWh account every week to NRLDCINLDC.

Ill. AGC MWh logs would be forwarded to NRPC secretariat on weekly basis to NRPC through

NRWC.

IV. Deviation in MWh for every 15~minute time block would be worked out as

MWh deviation = (Actual MWh)~(Scheduled MWh)~(AGC MWh) which would be settled as

per the existing Deviation Settlement Mechanism (DSM) Regulations.

v. For AGC MWh increase computed during every 15~minute time block, payment shall be

made based on variablc charges submitted to the NRPC by Dadri under RRAS Regulations.

Payment would be made from the Northern Region DSM pool.

VI. For AGe MWh reduction computed during a IS-minute time block, Dadri shall pay as per

the same variable charges above to the NR DSM pool.

vii. For AGC MWh computed for each 5~minute time block, 50 paise/kWh mark-up shaH be

payable to NTPC Dadri from NR DSM pool for both positive AGe MWh generation and

negative AGe MWh reduction.

Vill. It is proposed to keep 50-lOa MW Spinning Reserve at NTPC Dadri Stg~1I units 5&6

combined to start with. Hon'ble Commission may facilitate NRLDCINRPC to earmark 50

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MW up/down reserves at NTPC Dadri Stage~n on days when full generation is requisitioned

or schedule is at technical minimum.

15. A presentation was made by POSOCO on loth March 2017 before the I-Ion'ble Commission on

the, frequency profile of India, operationalization of the CERC reserves order dated 13 th Oct

2015 and related aspects of AGC Pilot Project mentioned in above paragraphs. A copy of this

presentation is enclosed at Annexe-6.

16. A discussion on the proposed payment mechanism and related aspects of AGC Pilot Project was

held with NTPC at NLDC on 17th March 2017. A general consensus was arrived at after the

discussion on the items in the para 14.

Prayer:

Implementation of Automatic Generation Control (AGe) is a landmark event as far as power system

operation in India is concerned. The pilot project is the first step in this direction and all the

intricacies involved in generator's participation in regulation services would be experienced for the

first time.

The Hon'ble Commission may kindly approve

i. Commissioning of AGC Pilot Project between NLDC and NTPC Dadri Stage-II as mentioned in

above paragraphs.

ii. The procedure for accounting & settlement of the payments in respect of AGC services outlined

in para 14 above.

III. Similar pilot projects to be taken up by POSOCO, in at least one other regional grid of the

country.

iv. Issue of necessary directions for extending optical fibre connectivity to maximum number of

power plants under the control area jurisdiction of RLDCs so that technical feasibility for

pru1icipation of more generating stations under AGC is created.

v. Pass any other orders as this Hon'ble Commission may deem fit and proper under the facls and

circumstances of the present case and in the interest of Justice.

Date: 31 st March 2017

Place: New Delhi

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9

Order in Suo-Motu Petition No. 11/SM/2015 Page 1 of 13

CENTRAL ELECTRICITY REGULATORY COMMISSION NEW DELHI

Petition No. 11/SM/2015

Coram: Shri Gireesh B. Pradhan, Chairperson Shri A.K. Singhal, Member Shri A.S. Bakshi, Member Dr. M.K. Iyer, Member

Date of Order: 13.10.2015

In the matter of Roadmap to operationalise Reserves in the country

ORDER

The Electricity Act, 2003 entrusts on the Central Commission important

responsibilities inter-alia of regulating the inter-State transmission of electricity,

specifying grid code and also enforcing standards with respect to quality, continuity and

reliability of service by licensees. Laying down of framework for effective and secure

grid operation is thus one of the most important mandates of the Commission. The

Central Commission has taken initiatives towards this end through regulations on Indian

Electricity Grid Code and Deviation Settlement Mechanism and related matters. The

Commission has also issued direction from time to time for enforcing grid discipline.

2. Over the period, reliance of the utilities on the grid for meeting their short term

energy demand was increasing. This caused serious threat to grid security. The

Commission, therefore, tightened the operating band of grid frequency and made

deviation charges stringent enough to discourage the utilities from deviation from their

schedule. This has started yielding the desired results in terms of operation of the grid

10

Order in Suo-Motu Petition No. 11/SM/2015 Page 2 of 13

closer to 50 Hz. The Commission has reiterated time and again that un-scheduled

inter-change (UI) mechanism cannot be used as platform for meeting the energy

demand of the utilities. Last mile imbalances are inevitable, but for this reliance on grid

is not desirable. This need be planned for, and adequate reserves need be contracted

to address such last mile imbalances.

3. The National Electricity Policy (NEP) mandates that adequate reserves may be

maintained to ensure secure grid operation:

“5.2.3 In order to fully meet both energy and peak demand by 2012, there is a need to create adequate reserve capacity margin. In addition to enhancing the overall availability of installed capacity to 85%, a spinning reserve of at least 5%, at national level, would need to be created to ensure grid security and quality and reliability of power supply.”

4. However, creation of adequate system reserve margin and spinning reserves at

national level has not yet materialised. In furtherance to the provisions relating to the

requirement of Spinning Reserves in the Electricity Act, 2003, National Electricity Policy

and Tariff Policy, and to facilitate-large scale integration of renewable energy sources,

balancing, deviation settlement mechanism and associated issues, CERC constituted a

Committee vide letter No, 25/1/2015/Reg. Aff. (SR)/CT.RC dated 29th May 2015, under

the chairmanship of Shri A.S. Bakshi, Member CERC, to examine the technical and

commercial issues in connection with Spinning Reserves and evolve suggested

regulatory interventions in this context.

5. The Committee submitted its final report to the Commission on 17th September

2015 (annexed as Annexure-I). Major findings of the Committee are as under:

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Order in Suo-Motu Petition No. 11/SM/2015 Page 3 of 13

(a) Spinning Reserves are required to be maintained of requisite quantum

depending upon the grid conditions. Operation at constant frequency target of

50.0 Hz with constant area interchange should be the philosophy adopted.

(b) The Spinning Reserve may be maintained, to start with at the regional level in a

distributed manner.

(c) The respective RLDC should be the Nodal agency at the regional level and

NLDC at the country level.

(d) Each region should maintain secondary reserves corresponding to the largest

unit size in the region and tertiary reserves should be maintained in a de-

centralized fashion by each state control area for at least 50% of the largest

generating unit available in the state control area. This would mean secondary

reserves of 1000 MW in Southern region; 800 MW in Western regions; 800 MW

in Northern region; 660 MW in Eastern region and 363MW in North-Eastern

region (total approx. 3600 MW on an All India basis). Primary reserves of 4000

MW should be maintained on an All India basis considering 4000 MW generation

outage as a credible contingency. The same should be provided by generating

units in line with the IEGC provisions.

(e) The reserve requirement may be estimated by the nodal agency on day-ahead

basis along with day ahead scheduling of all available generating stations.

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Order in Suo-Motu Petition No. 11/SM/2015 Page 4 of 13

(f) Implementation of AGC is necessary along with reliable telemetry and

communication. The AGC may be planned to be operationalised in the power

system from 1.4.2017.

(g) It is essential that load forecasting is done at each DISCOM level, at each

SLDC/State level and each RLDC/Regional level and finally at NLDC/country

level.

(h) It is also essential to forecast the generation from renewable sources of energy

by the generators, and similarly by the DISCOMs, by the SLDCs and by the

RLDCs.

(i) To start with a regulated framework in line with the Ancillary Services

Regulations may be evolved for identification and utilising of spinning reserves

and implemented with effect from 1.4.2016. This framework may continue till

31.3.2017.

(j) The reserves at the regional level, should be assigned to specific identified

generating station or stations duly considering the various technical and

commercial considerations including energy charges of the generating stations.

The nodal agency should be empowered to identify the ISGS irrespective of type

and size of the generating station for providing spinning reserve services and it

should be mandatory for such generating stations to provide spinning reserve

services.

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Order in Suo-Motu Petition No. 11/SM/2015 Page 5 of 13

(k) The nodal agency may have the option of carrying such reserves on one or more

plants on technical and commercial considerations and may withhold a part of

declared capacity on such plants from scheduling. It could be in terms of % of

declared capacity or in MW term as deemed fit.

(l) A framework as specified in the Central Electricity Regulatory Commission

(Ancillary Services Operations) Regulations, 2015 may be followed for the

Spinning Reserve Services as well. The Central Electricity Regulatory

Commission (Ancillary Services Operations) Regulations, 2015 may be amended

to incorporate the necessary changes in this regard.

(m)Going forward, a market based framework may be put in place from 1st April

2017 for achieving greater economy and efficiency in the system. A detailed

study is required to be carried out before the market mechanism on spinning

reserves is put in place. It is suggested that the NLDC be directed to commission

study through a consultant in the context and submit a proposal to the

Commission for approval.

The Commission has carefully considered and accepted the findings of the

Committee.

6. One of the important components of ensuring grid reliability includes achieving

adequacy of supply and maintaining the load-generation balance. This poses a

challenge to grid operators on various time-scales: on a daily level as weather varies,

for example, on an hourly level as load varies during the day, and on sub-hourly/time-

14

Order in Suo-Motu Petition No. 11/SM/2015 Page 6 of 13

block level as there are errors in forecasting of load or unplanned outages of generating

units or transmission lines. Sudden disturbances in the Power System can initiate a

steep fall or rise in the frequency of the Power System, which can be detrimental to the

Power System operation, if not contained immediately. Thus, to ensure 24x7 power

supply and grid reliability, grid operators must have access to reserves at different

locations and factoring transmission constraints, the system operators should be able to

increase or decrease power supply on the grid at any time of the day.

7. Three types of reserves are generally considered depending on the timeline of

initiation and functional need. Primary control refers to local automatic control available

in all conventional generators, which delivers reserve power negatively proportional to

frequency change. Such immediate automatic control is implemented through turbine

speed governors, in which the generating units respond quickly to the frequency

deviation as per droop characteristic of the units. However, this response to arrest

frequency drop or rise lasts for short period of up to 30 seconds - 15 minutes, within

which secondary control should come into play should the contingency last longer than

that. IEGC section 5.2(i) specifies a provision for primary reserves, as under:

“The recommended rate for changing the governor setting, i.e., supplementary control for increasing or decreasing the output (generation level) for all generating units, irrespective of their type and size, would be one (1.0) per cent per minute or as per manufacturer‟s limits. However, if frequency falls below 49.7Hz, all partly loaded generating units shall pick up additional load at a faster rate, according to their capability.”

However, this has not been adhered to fully by the generators.

15

Order in Suo-Motu Petition No. 11/SM/2015 Page 7 of 13

8. Secondary control involves Automatic Generation Control (AGC) which delivers

reserve power in order to bring back the frequency and the area interchange programs

to their target values. For AGC, units as well as load dispatch centres have to be

equipped with necessary communication infrastructure, as it involves sending

automated control signals from the LDC to the generator based on grid conditions. AGC

has been absent in the Indian power system. Very commonly, this results in „load

shedding‟ by DISCOMs in case generation is lagging load. The Indian power sector was

beset with scarcity for a long time; however, now the scenario is changing and margin

for reserves is feasible. With a large interconnected grid meeting a peak load of over

145 GW, both primary and secondary controls are essential components for reliable grid

operation.

9. Tertiary control refers to manual change in the dispatching and unit commitment

in order to restore the secondary control reserve, as loss of generator may cause a

system contingency that lasts for several hours.

10. Traditionally, imbalance handling on the Indian grid has been done through the

Unscheduled Interchange (UI) or the Deviation Settlement Mechanism (DSM)

framework, in which the frequency-linked UI rate gave a signal to the grid participants to

correct for instantaneous frequency deviations. However, it led to use not meant for,

and further grid indiscipline besides stress/constraints in the transmission network.

While measures like tightening of the operating grid frequency band and provision for

deterrent deviation charges, have been resorted to and this has resulted in

improvement of grid operation, the Commission feels that the power system operation in

16

Order in Suo-Motu Petition No. 11/SM/2015 Page 8 of 13

the country still needs to mature further. Even now States have been deviating from

schedule substantially. For instance, in 2014-15, Rajasthan deviated in the range of (+)

1202 to (-) 1324; UP in the range of 1613 to (-) 2291; Karnataka in the range of 945 to

(-) 787 etc.; Tamil Nadu in the range of 546 to (-) 990; Gujarat in the range of 1174 to

(-) 1162. These are not only undesirable but also a cause of serious concern. The DSM

Regulations provide for a periodic review of the DSM rates and the Commission directs

the Staff to undertake a review of the same and submit a proposal for consideration of

the Commission.

11. The Commission would like to underscore that grid does not generate electricity

and as such cannot be relied upon for meeting energy needs. Reserves and reserves

alone can address this and the earlier the stakeholders realise this, the better it is for

safe and secure system operation. Reserves assume greater significance additionally in

the wake of the goal of integration of large scale variable renewable energy sources.

With increasing penetration of variable and intermittent RE generation, flexible

generation such as pumped storage hydro plants are needed. There is a need for more

flexibility in the operation of conventional generation plants also and flexibility needs to

be quantified, measured and duly compensated for. The Commission has already made

a beginning in this direction by proposing amendment to the Indian Electricity Grid Code

(IEGC) in respect of „technical minimum‟ which is expected to be notified shortly. „Ramp

up‟ and „ramp down‟ rates are other important parameters for flexibility which would

gradually be introduced through Regulations.

17

Order in Suo-Motu Petition No. 11/SM/2015 Page 9 of 13

12. The grid operator would now be required to undertake planning exercise to meet

Net Load, which is defined as: Net load = Load – RE power. This quantum must be met

with conventional generation with adequate flexibility at every point in time. To even

begin an exercise of planning for ongoing load-generation balance, load forecasting is

essential. It is also necessary to ensure conventional generators to generate as per the

schedules. Forecasting and scheduling of solar and wind generating stations is the next

critical step for the grid operators to estimate the amount of RE power they can

anticipate to be injected into the grid, on a day-ahead and hour-ahead basis. Thus, the

variability that can be predicted in the forecasts must be accounted for in planning

flexible generation as well as tertiary reserves day-ahead and hour-ahead. Furthermore,

balancing the uncertainty of RE power on a continuous basis necessitates a streamlined

process for deploying spinning reserves. This would be effectively balancing the

forecasting error in net load.

13. The Commission notified Central Electricity Regulatory Commission (Ancillary

Services Operations) Regulations, 2015 on 19th August 2015 with the objective of

utilizing un-requisitioned surplus in ISGS. These regulations are a first step towards the

entire gamut of Ancillary Services, starting with tertiary frequency control services.

Applicable to regional entities, the regulations outline a framework for both Regulation

Up and Regulation Down service by Reserves Regulation Ancillary Services (RRAS)

providers. NLDC along with RLDC, operating as the nodal agency, shall call for these

services in varying situations, such as extreme weather events, loss of generating unit

18

Order in Suo-Motu Petition No. 11/SM/2015 Page 10 of 13

or transmission line outage, load-generation imbalance, etc. The RRAS providers shall

be paid from the Regional DSM Pools.

14. Furthermore, the Commission notified the Order on Extended Market Session on

Power Exchanges on 8th April, 2015, and the power exchanges started operating

extended hours for intra-day products by end of July. The trading window is now open

round-the-clock for delivery of power on the same day, with a 3-hour delivery time-

frame. This can enable to significantly correct for intra-day imbalances in a proactive

manner, and not passively rely on the grid for the same. It is expected that the

Distribution Control Centres (DCCs) of DISCOMs also operate in a 24 x 7 manner to

reap the advantages from these extended market sessions. Depending on the market

needs, there is a need for newer products in the electricity market to provide more

opportunities to the participants to balance their portfolio. The Commission directs the

staff to examine this aspect of market design and submit a proposal for consideration of

the Commission.

15. It is also expected that with provision for reserves and harnessing the same

through „controls‟, the inter area power flows would be manageable and help in

optimizing the Transmission Reliability Margin (TRM). This would benefit all

stakeholders to a great extent.

16. In due recognition of the above factors, the Commission would like to chart out a

road map for introduction of reserves in the country. Accordingly, the Commission

directs as under:

19

Order in Suo-Motu Petition No. 11/SM/2015 Page 11 of 13

(a) For reliable and secure grid operation, to maintain continuous load-generation

balance, to counter generation outages as well as unexpected load surges or

crashes, and for large scale integration of variable renewable power, it is

essential for the grid operators to have access to distributed Spinning Reserves

which are dispatched taking due care of transmission constraints whenever

required.

(b) The Commission reiterates the need for mandating Primary Reserves as well as

Automatic Generation Control (AGC) for enabling Secondary Reserves.

(i) All generating stations that are regional entities must plan to

operationalise AGC along with reliable telemetry and

communication by 1st April, 2017. This would entail a one-time

expense for the generators to install requisite software and

firmware, which could be compensated for. Communication

infrastructure must be planned by the CTU and developed in

parallel, in a cost-effective manner.

(ii) On the other hand, National/Regional/State Load Dispatch Centres

(NLDC/RLDCs/SLDCs) would need technical upgrades as well as

operational procedures to be able to send automated signals to

these generators. NLDC /RLDCs and SLDCs should plan to be

ready with requisite software and procedures by the same date.

20

Order in Suo-Motu Petition No. 11/SM/2015 Page 12 of 13

(iii) The Central Commission advises the State Commissions to issue

orders for intra-state generators in line with this timeline as AGC is

essential for reliable operation of India‟s large inter-connected grid.

(c) To start with, a regulated framework in line with the Ancillary Services

Regulations would need be evolved for identification and utilising of spinning

reserves and implemented with effect from 1st April, 2016. This framework may

continue till 31st March, 2017. This may only include generating stations

regulated by CERC, which could be started off with a manual process for

secondary reserves. The NLDC/POSOCO is directed to submit a detailed

procedure in this regard for approval by the Commission within one month from

the issue of this Order. The amendments required in various Regulations issued

by the Commission would also need to be indicated. As the Renewable Energy

(RE) penetration levels increase in the coming years, the impact on the quantum

of reserves would need to be separately studied and provided for through further

amendments.

(d) In the long term, however, a market based framework is required for efficient

provision of secondary reserves from all generators across the country. For this,

NLDC/POSOCO is directed to commission a detailed study through a consultant

and suggest a proposal to the Commission for implementation by 1st April, 2017,

giving due consideration to the experience gained in the implementation of

Spinning Reserves w.e.f. 1st April, 2016.

21

Order in Suo-Motu Petition No. 11/SM/2015 Page 13 of 13

(e) The States must undertake separate scheduling and energy accounting of all

generating and load entities. Deployment of DSM framework shall greatly

prepare the State to differentiate between and attribute deviations caused due to

various entities involved. Recording of this data shall also give the State grid

operator much needed clarity on which entities are responsible for schedule

deviations, and to what extent.

(f) Load forecasting must be undertaken by all DISCOMs. Combined with DSM, it is

the foundation on which strong and reliable grid management can be built.

(g) In order to ensure reliable and secure operation of the grid, in addition to

compliance to standards and regulations, adequate defense mechanisms such

as Under Frequency Relays (UFRs), df/dt (rate of change of frequency), System

Protection Schemes (SPS), etc. must be put in place and which also need to be

periodically reviewed and checked for healthiness.

17. The petition is disposed of in terms of the above directions.

sd/- sd/- sd/- sd/-

(Dr. M.K. Iyer) (A. S. Bakshi) (A.K. Singhal) (Gireesh B. Pradhan) Member Member Member Chairperson

22

23

(A wholly owned subsidiary of POWERGRID)

~ ~ ~ Cfil4f(14: aft-9, ~~ ffil, ~ ~~R'("'" ~~ CficCllf{41 mr:r, ~ ~-110 016 Registered & Corporate Office : B - 9, 1st Floor, Qutub Institutional Area, Katwaria Sarai, New Delhi - 110 016 Website : www.posoco.in, www.nldc.in, Tel: 011-26536832, 26524522, Fax: 011-26524525, 26536901

~~ tr: POSOCO/Legai/NLDC R1 i Cfl: 15.12.2015

Subject: Roadmap to operationalise Reserves in the country and procedure- regarding

Madam,

The Hon'ble Commission has vide its Order dated 13th October 2015 in petition no

11/SM/2015 paved a way forward for operationalizing generation reserves in the country.

The Hon'ble Commission directed NLDC/POSOCO to submit a detailed procedure in this

regard for approval by the Commission. In this connection, an outline of the same is

enclosed. Considering the complexity of the issue and the fact that shortly the Ancillary

Services Framework would become operational when directed by the Commission, further

discussions would be required with the stakeholders, particularly the generators identified

for secondary control. We may be kindly permitted to submit a detailed draft procedure to

operationalize Reserves in the country three {3) months after implementation of the CERC

(Ancillary Services) Regulations, 2015.

~.

ct\k\1,~'~'~ ( ~. eft. ~· ~)

Cfli441Wfl ~~fCfl. u. m. ~. ~.

~ ~<1 l!cf :CI~~<1 lf ~ ~ Save Energy for Benefit of Self and Nation

24

Power System Operation Corporation Limited

New Delhi

15th Dec 2015

Sub: Operationalization of generation reserves in the country

1.0 The Hon’ble Commission has vide order dated 13th Oct 2015 in petition no

11/SM/2015 given a roadmap for operationalization of reserves in the country. The

order was based on the Report of the Committee constituted earlier by CERC under

the Chairmanship of Shri A S Bakshi, Hon’ble Member, CERC.

2.0 As per the recommendations of the Committee constituted by CERC to examine the

technical and commercial issues in connection with Spinning Reserves, each region

should maintain secondary reserves corresponding to the largest unit size in the

region and tertiary reserves should be maintained in a decentralized fashion by each

state control area for at least 50% of the largest generating unit available in the state

control area. This would mean secondary reserves of 1000 MW in Southern region;

800 MW in Western region; 800 MW in Northern region; 660 MW in Eastern region

and 363 MW in North-Eastern region (total approx. 3623 MW on an All India basis).

Primary reserves of 4000 MW should be maintained on an All India basis considering

4000 MW generation outage as a credible contingency.

3.0 Tentative plausible generators have been identified for providing the requisite

secondary reserve and the list is enclosed. It would be observed from these lists that

in case the stations with variable cost less than 250 paise/kWh have to be excluded

from secondary control, then limited power stations in each region are available and

almost 35-100% of this capacity has to be kept as reserve in some of the regions

which might be impractical. Primary Reserves have to be maintained by all the

generators mandated by IEGC and need not be separately identified. Tertiary

Reserves operationalization needs proactive sensitization of the states regarding the

CERC Road map to operationalize Reserves.

4.0 To evolve a procedure, some further brainstorming has to be done with all

concerned parties (particularly with the identified generating plants as

communication and control infrastructure is needed at the generator end also to

operationalize the secondary reserves). Also, from the philosophy and

implementation side a few questions have to be decided after discussion and

brainstorming (like the current meaning and usage of Un Requisitioned Surplus (URS)

after the CERC Ancillary Services Regulations, security constrained merit order, day

25

ahead reserves requisition, forecast procedure, mechanism of generating control

signals, communication protocols etc.).

5.0 Main topics/areas to further work on, for making the procedure to operationalize

the Reserves in the country in line with CERC Order dated 13.10.15 mentioned in the

above para are explained hereunder:

i. Meaning of Un Requisitioned Surplus (URS):

Post CERC (Ancillary Services) Regulations, 2015, URS can be scheduled by NLDC to

the Virtual Ancillary Entity i.e. the Pool but will be paid in a different head. We need

not earmark Spinning Reserves especially all the time in costlier plants since URS is

there in any case as Spinning Reserve and many times we have significant URS left.

Many power station units (units especially earmarked to provide secondary reserves

and cheaper units with URS unutilized, both) have to be wired with communication

to make this whole exercise more economical. In a market based system, it is also

important that each plant is wired so that it can provide secondary control whenever

it emerges as a successful bidder. So for starts, no separate reserve would be

provided by RLDCs/NLDC but only the URS would be used as a spinning reserve.

However on days when the URS quantum falls to low levels, RLDCs/NLDC can specify

the reserves to be kept in each plant mentioned in the Annexure. This might be the

case with Southern Region where generally the URS quantum is quite low and the

need for earmarking reserves at the different plants whose tariff is regulated by

CERC may be required. This would also require the IEGC/CERC Regulations to specify

that scheduling beyond a specified percentage of Declared Capability (DC) is

prohibited.

ii. Automatic Generation Control (AGC) software:

Constant frequency with area interchange has been specified as the philosophy by

the Commission. Each regional grid is treated as one area for the purpose. For

starters, it is necessary to define the Area Control Error (ACE) of each control area as

well as the region as

Area Control Error (ACE) = ∆ P + k ∆f

Where ∆ P = (Actual Net Interchange, NIA )– (Scheduled Net Interchange, NIs )

∆f = (Actual Frequency, FA – Scheduled Frequency, FS) in Hz

k = Frequency Bias of Control Area in MW/Hz, usually with a negative sign.

26

For starters, the value of ‘k’ could be taken based on the past trend of regional

Frequency Response Characteristics (FRC). Accurate values of ∆ P also necessitates

proper availability of real time data which is also a subject matter of 7/SM/2014

petition pending before the Commission.

The control centres of the five RLDCs have already been upgraded recently. As the

specifications for the same had been formulated around 2010-11, provision for AGC

was not kept at that stage. The NLDC Control Centre is yet to be upgraded and as of

now, POSOCO has kept a provision for AGC. Detailed implementation logic has to be

discussed with the prospective vendors. The software would obviously require

customization to adapt it to Indian Power System on account of URS. Worldwide,

AGC software running at one control centre would try to bring ACE of the particular

control area to zero. In the Indian context, the AGC software at NLDC would

essentially be the equivalent of 5 separate AGC softwares running at the same

control centre or AGC software with five separate regional models at NLDC.

AGC software at NLDC alone may be insufficient. The AGC signals transmitted to the

power plant would indicate the MW up or MW down for the plant as a whole.

Within the plant, suitable Programmable Logic Controllers (PLCs) would have to

distribute this MW on the different generating units. There would have to be close

coordination between the control centre AGC vendor and the plant vendor. In case

the control centre AGC software itself gives unit wise regulation, then the

implementation at plant level would also have to be studied from implementation

logistics. AGC software requirement at SLDCs needs to be further debated and

understood.

Considering the above complexities, POSOCO proposes to first take up a pilot project

with one of the NTPC plants in a region based on which further activities could be

taken up. In case the entire country were to be treated as one control area and

frequency control was the sole objective, a manual system could have been feasible

as was being done in the UK system. However, constant frequency with area

interchange control is difficult albeit impossible to achieve with manual control. Even

the NORDEL system has migrated to AGC (known as Load Frequency Control or

Frequency Restoration Service-Automatic).

27

iii. Communication:

One important requirement in this whole process is the communication. We would

need depending on the philosophy we would agree with later, reliable two way

communication from all/many power stations under RLDC’s jurisdiction, as it would

be one of the inputs and outputs to the AGC software. For automatic generation

control, the communication protocols and type of signals (continuous or step) have

to be discussed with all the major parties.

iv. Security Constrained Merit Order:

To make the process of dispatch of Reserves economic, as long as the flows don’t

exceed the ATC limit, All India merit order can be followed; else region wise merit

order has to be followed. With this strategy, region wise ACE becomes redundant

and the focus would be on only all India frequency restoration as long as flows don’t

exceed ATC. But, in classical theory, region wise ACE is used to make the secondary

control decision to counter the probabilistic unit tripping and to do the load

following.

Making the choice of philosophy is one important step and has to be frozen first.

v. Day ahead Reserves:

The Reserves have to be decided day ahead using the available demand forecast and

the requisition of the entities after the R0 revision is put in the website by respective

RLDCs. This might need some experience obtained after implementing the CERC

(Ancillary Services) Regulations, 2015.

vi. Commercial:

Two key issues arise; how would fixed charges be paid for the reserves kept in

different power plants and how would the variable charges be paid for the

regulation up/down services? A method to convert the AGC signals to a ‘schedule’ to

be superimposed over the normal schedule is required which would form the

baseline for accounting for deviations, under the Deviation Settlement Mechanism

(DSM) Regulations.

28

The Hon’ble Commission has introduced the CERC (Ancillary Services) Regulations, 2015 on

19.08.15. A comprehensive procedure has been drafted to this end by POSOCO and

submitted to the Hon’ble Commission recently on 2nd Nov 2015 for approval. The

implementation of the same shall augur a worthy and important experience for the

development of a suitable procedure for operationalizing reserves in the Indian market.

In light of the observations made above, a detailed procedure to operationalize Reserves in

the country shall be framed in consultation with the Hon’ble Commission and submitted

three (3) months after implementation of the CERC (Ancillary Services) Regulations, 2015.

x-----x------x

29

NR 800 All India 4000 MW

ER 660WR 800SR 1000

NER 363Total 3623

Region State Tertiary Reserves needed in State in MW

Largest Generator Size

Punjab 400 Talwandi Saboo 800Haryana 330 CLP Jhajjar(JV)/Khedar 660Rajasthan 330 Kawai 660Delhi 105 Badarpur/Bawana 210UP 330 Lalitpur 660Uttarakhand 38 Maneri 76HP 50 Baspa 100J&K 75 Baglihar 150Chandigarh 0 nil 0NR Total 1658 3316Chhattisgarh 250 Korba West 500Gujarat 330 Vadinar 660MP 300 Malwa 600Maharashtra 330 Tiroda 660Goa 0 nil 0DD 0 nil 0DNH 0 nil 0Essar steel 62.5 Essar 125WR Total 1353 2705Andhra Pradesh 400 SDSTPS 800Telangana 250 Kakatiya 500Karnataka 300 UPCL 600Kerala 62.5 Kayamkulam 125Tamil Nadu 300 Mettur 600Pondy 0 nil 0SR Total 1343 2685Bihar 55 MTPS 110DVC 300 Raghunathpur 600Jharkhand 105 Tenughat 210Odisha 300 Sterlite 600West Bengal 150 Sagardighi 300Sikkim 0 nil 0ER total 857 1713Arunachal Pradesh 0 nil 0Assam 25 Langpi 50Manipur 0 nil 0Meghalaya 22.5 MPL 45Mizoram 2 Kolasib 4Nagaland 4 Khiphire 8Tripura 11 Rokhia 22NER total 65 129

Total 5218 10435

UMPP Outage

Primary Reserves Quantum needed in MW

NER

Secondary Reserves Quantum needed in MW (Region wise)

Tertiary Reserves Quantum needed in MW (State Control Area Wise)

NR

WR

SR

ER

Summary of Reserves required as per the CERC order

30

S.No. Region Type Name UNITSTOTAL (MW)

Energy Charge Rs /

Kwh

For Gas Stations (Energy

charge of next costly

fuel)

Fixed Charge (Rs./kWh)

1 NR THERMAL SINGRAULI TPS 5x200+2x500 2000 1.23 0.572 NR THERMAL RIHAND I 2x500 1000 1.67 0.93 NR THERMAL RIHAND II 2x500 1000 1.71 0.964 NR THERMAL RIHAND III 2x500 1000 1.70 1.365 NR THERMAL DADRI STG-1 4x210 840 3.88 0.96 NR THERMAL DADRI STG-2 2x490 980 3.63 1.827 NR THERMAL UNCHAHAR TPS -I 2x210 420 2.82 0.928 NR THERMAL UNCHAHAR TPS -II 2x210 420 2.75 0.959 NR THERMAL UNCHAHAR TPS -III 1x210 210 2.75 1.39

10 NR GAS ANTA GPS 3x88.71+1x153.2 419.43 3.01 9.1 1.311 NR GAS AURAIYA GPS 4x111.19+2x109.30 663.36 3.68 11.1 1.6212 NR GAS DADRI GPS 4x130.19+2x154.51 829.78 3.64 6.55 1.3813 NR THERMAL INDIRA GANDHI TPS JHAJJAR 3x500 1500 4.19314 WR THERMAL Korba STPS Stage-I and II 3x200+3x500 2100 1.0515 WR THERMAL Korba STPS Stage-III 1 x 500 500 1.0416 WR THERMAL Vindhyachal STPS (stage 1) 6 x 210 1260 1.68 0.8717 WR THERMAL Vindhyachal STPS (stage 2) 500*2 1000 1.58 0.8318 WR THERMAL Vindhyachal STPS (stage 3) 500*2 1000 1.57 1.319 WR THERMAL Vindhyachal STPS (stage 4) 500*2 1000 1.58 1.5920 WR THERMAL Vindhyachal STPS (stage 5) 500*1 500 1.5821 WR THERMAL Sipat STPS Stage-I 3 x 660 1980 1.41 1.5122 WR THERMAL Sipat STPS Stage-II 2 x 500 1000 1.41 1.4423 WR THERMAL Mauda 2x500 1000 3.77 4.47

Probable candidates for Secondary Reserves - Region Wise: NR: 11283 MW WR: 15121 MW SR: 10490 MW ER: 6760 MW NER: 1101 MW

Details of Central Sector coal and gas fired power stations under RLDC's jurisdiction

31

Probable candidates for Secondary Reserves - Region Wise: NR: 11283 MW WR: 15121 MW SR: 10490 MW ER: 6760 MW NER: 1101 MW

Details of Central Sector coal and gas fired power stations under RLDC's jurisdiction24 WR THERMAL NSPCL 2x250 500 2.2125 WR GAS NTPC KAWAS 4x106+2x116.1 656.2 2.77 9.29 2.5226 WR GAS NTPC GANDHAR 3x144.3+1x255 657.39 2.55 9.09 3.2427 WR GAS RGPPL PH - I 2X205+1X230 640 8.428 WR GAS RGPPL PH -II 2X213+237.54 663.54 8.429 WR GAS RGPPL PH- III 2X213+237.54 663.54 8.430 SR THERMAL RAMAGUNDAM T.P.S (ISGS) - NTPC stg 1 3x200+3x500 2100 2.44 0.6131 SR THERMAL RAMAGUNDAM T.P.S (ISGS) - NTPC stg 2 1x500 500 2.54 0.9332 SR THERMAL TALCHER STAGE II (ISGS) - NTPC 4x500 2000 1.46 0.7933 SR THERMAL SIMHADRI - NTPC STAGE-II 2x500 1000 2.59 1.6934 SR THERMAL VALLUR NTECL 3x500 1500 2.0835 SR LIGNITE NEYVELI-II (ISGS) - NLC 7x210 1470 2.2236 SR LIGNITE NEYVELI TPS-I (Expn.)- NLC 2x210 420 2.1237 SR LIGNITE NEYVELI TPS-II (Expn.)- NLC 2x250 500 2.1238 SR THERMAL NTPL 2X500 100039 ER THERMAL FARAKKA stg 1 and 2 3x200+2x500 1600 2.9540 ER THERMAL FARAKKA stg 3 1x500 500 2.9241 ER THERMAL KAHALGAON STG I 4x210 840 2.5842 ER THERMAL KAHALGAON STG II 3x500 1500 2.4243 ER THERMAL BARH 2x660 1320 3.744 ER THERMAL TALCHER 2x500 1000 1.4645 NER GAS AGBPP (Kathalguri)- (GT+ST) 6x33.5 + 3x30 291 2.6346 NER GAS AGTPP (R C NAGAR) 4x21 84 3.4647 NER GAS PALATANA CCPP 2X363.3 726 1.11

Total 44754.24

32

S.No. Region Type Name UNITSTOTAL (MW)

Energy

Charge Rs

/ Kwh

For Gas Stations (Energy

charge of next costly

fuel)

1 WR THERMAL Mauda 2x500 1000 3.77Total Reserves Required in WR 800

2 WR GAS NTPC KAWAS4x106+2x1

16.1656.2

2.77 9.29

Total Capacity available in this price range 2313

3 WR GAS NTPC GANDHAR3x144.3+1

x255657.39 2.55 9.09 Percentage 35

4 SR THERMALSIMHADRI - NTPC STAGE-

II2x500 1000 2.59

5 SR THERMALRAMAGUNDAM T.P.S

(ISGS) - NTPC stg 21x500 500 2.54

Total Reserves Required in SR 1000

Candidates for Secondary Control in case variable cost above 250 paise/kWh is to be selected and costly fuels excluded

33

S.No. Region Type Name UNITSTOTAL (MW)

Energy

Charge Rs

/ Kwh

For Gas Stations (Energy

charge of next costly

fuel)

Candidates for Secondary Control in case variable cost above 250 paise/kWh is to be selected and costly fuels excluded

6 NR THERMALINDIRA GANDHI TPS

JHAJJAR3x500 1500 4.19 Total Capacity

available in this price range 1500

7 NR THERMAL DADRI STG-1 4x210 840 3.88Percentage 67

8 NR GAS AURAIYA GPS4x111.19+

2x109.3663.36

3.68 11.1

9 NR GAS DADRI GPS4x130.19+

2x154.5 829.78

3.64 6.55Total Reserves Required in NR 800

10 NR THERMAL DADRI STG-2 2x490 980 3.63 Total Capacity available in this price range 6282

34

S.No. Region Type Name UNITSTOTAL (MW)

Energy

Charge Rs

/ Kwh

For Gas Stations (Energy

charge of next costly

fuel)

Candidates for Secondary Control in case variable cost above 250 paise/kWh is to be selected and costly fuels excluded

11 NR GAS ANTA GPS3x88.71+1

x153.2 419.43

3.01 9.1 Percentage 13

12 NR THERMAL UNCHAHAR TPS -I 2x210 420 2.82

13 NR THERMAL UNCHAHAR TPS -II 2x210 4202.75

Total Reserves Required in NER 363

14 NR THERMAL UNCHAHAR TPS -III 1x210 2102.75

Total Capacity available in this price range 375

15 NER GAS AGTPP (R C NAGAR) 4x21 84 3.46Percentage 97

16 NER GASAGBPP (Kathalguri)-

(GT+ST)6x33.5 +

3x30291 2.63

17 ER THERMAL BARH 2x660 13203.7

Total Reserves Required in ER 660

35

S.No. Region Type Name UNITSTOTAL (MW)

Energy

Charge Rs

/ Kwh

For Gas Stations (Energy

charge of next costly

fuel)

Candidates for Secondary Control in case variable cost above 250 paise/kWh is to be selected and costly fuels excluded

18 ER THERMALFARAKKA stg 1 and 2 3x200+2x5

00 16002.95

Total Capacity available in this price range 4260

19 ER THERMALFARAKKA stg 3 1x500

5002.92 Percentage 15

19 ER THERMALKAHALGAON STG I 4x210

840 2.58

36

37

CENTRAL ELECTRICITY REGULATORY COMMISSION

No.: 1110/20 12-Reg.Aff.(REC-Gen. )/CERC

Shri S.K. Soonee Chief Executive Officer Power System Operation Corporation (POSOCO) 18-A, Shaheed Jeet Singh Sansanwal Marg Katwaria Sarai New Delhi- 110 016.

artttftr~ CERC

Dated: 05111 February, 2016

Subject: Grant of extension to POSOCO for submission of implementation plan on Spinning Reserves

Sir,

This has reference to the Power System Operation Corporation Limited's letter No. POSOCO/Legal/NLDC 1139 dated 15.12.2015 requesting Central Electricity Regulatory Commission (CERC) for grant of extension to POSOCO for submission of implementation plan on Spinning Reserves. The matter has been examined in the Commission.

2. The Central Commission has issued a roadmap to operationalize Reserves in the country through Suo-Motu Petition No. 11/SM/2015 dated 13.10.2015. The objective of the order was to provide a vision to introduce Spinning Reserves in the country, which is one of the important components of ensuring grid reliability by achieving adequacy of supply and maintaining load-generation balance.

3. Considering the relevance of experience and learnings from Ancillary Services, the request received from POSOCO seeking grant of extension for submission on implementation plan on Spi1ming Reserves has been accepted by the competent authority.

4. POSOCO is advised to submit the draft detailed procedure and impiementation plan for Reserves within three months of impleme~on of

""" Ancillary Services Regulations.

Yours faithfully,

(Sushanta K~j;e) £1) -L'- i)-C. ~ ?/,Qf-JJ) "-Joint Chief(RA)

~ '\ {\ /, ;- 3={J\ ~ ~ ~) fi.rl' ~\ tft~il ~-fttcl. T.l~<ffi(f) ~fWll. 36. \JRlJ~. ~ ~~-110 oo1

Third Floor, Chanderlok Building, 36, Jan path, New Delhi-1·1 0 001 Phone: 91-11 -2335 3503 Fax: 91-11-2375 3923 E-mail: info@cercind.gov.in

38

39

40

41

Page 1 of 4

Brainstorming session on 19th and 20th Jan 2016 at POSOCO, NLDC, New Delhi on

implementation of Automatic Generation Control (AGC)

1.0 Background:

A two day meeting cum brainstorming session was held on 19th and 20th Jan 2015 at NLDC,

New Delhi on the topic of implementation of Automatic Generation Control (AGC). Representatives

from NTPC Ltd., Central Electricity Regulatory Commission (CERC), Central Electricity Authority (CEA),

POWERGRID and POSOCO attended the meeting. Mr. P.P. Francis, ex-NTPC professional, also attended

the meeting on 19th Jan 2016 and gave valuable inputs. The list of participants is enclosed at Annexe-I.

Executives from ERLDC, WRLDC, NERLDC and SRLDC also participated through Video Conference (VC).

Professor Anjan Bose, Regents Professor, Washington State University presided over the two

day session. CEO, POSOCO, in his opening remarks, stated that all the discussions are required from

practical implementation point of view. The objective should be to have a prototype, learn from the

experience, gain confidence and make it gradually better.

Professor Anjan Bose stated that the most important thing to target at this time is to make

something work on the Indian grid that meets all the requirements for frequency control as laid out in

the rulings of the CERC. Such a prototype system doesn’t have to be comprehensive or the most

efficient; the key issue is to demonstrate that it works. It needs to be appreciated that the Indian grid is

a big and complex one and completely interconnected, so complete implementation of a smooth

running frequency control will take time and learning.

With these opening remarks, the presentations and discussion followed.

2.0 Presentations made in the two day meeting

POSOCO’s presentation covered the salient features of the 13th October 2015 order of CERC on spinning

reserves and the communication dated 15th Dec 2015 from POSOCO to CERC outlining the broad areas

of implementation which needed a broad agreement. A copy of POSOCO’s presentation is enclosed at

Annexe-II.

NTPC’s presentation covered on the need to keep higher variable cost generating stations on AGC,

availability of Coordinated Master Control (CMC) as a necessary requirement for placing units on AGC

and the associated higher O & M costs and Heat Rate degradation on account of flexing of generation

due to AGC actions. A copy of NTPC’s presentation is enclosed at Annexe-III.

POWERGRID Load Despatch & Communication (LD & C) division, who are consultants to POSOCO for the

SCADA/EMS upgradation project, presented the outline of specifications for AGC in the NLDC

upgradation project. The extracts from the specification presented by POWERGRID is enclosed at

42

Page 2 of 4

Annexe-IV. It was emphasized by POWERGRID that the AGC signals would be from the Control Centre to

the power station Remote Terminal Unit (RTU) generally located in the switchyard control room. From

this point onward, all signals to the individual generating units needed to be arranged by the power

plant.

One of the SCADA/EMS vendors, M/s OSI gave their presentation through Video Conference from the

United States. A copy of M/s OSI’s presentation is enclosed at Annexe-V.

On the second day, two other SCADA/EMS vendors, M/s Alstom and M/s Siemens gave their

presentations. A copy of these is enclosed at Annexe-VI and Annexe-VII respectively.

3.0 Key Issues discussed and broad consensus reached:

Broad consensus was reached on the following:

i) Regional Area Control Error (ACE): ACE can be computed based on a regional basis to start with.

The Frequency Response Characteristics (FRC) for different regions could be used for determining

the frequency bias to be used in ACE computations for each region.

ii) Regional Entities under CERC tariff would be under AGC: To start with, Regional Entities under

CERC tariff would be under AGC. If the anticipated CERC order of 55% technical minimum in the

generators is implemented, then more units could be kept on bar. Under normal operating

conditions, there is significant quantum of UnRequisitioned Surplus (URS) in these stations and

therefore no specific reserves need to be earmarked. However on days when URS quantum falls

below a certain level, POSOCO could identify reserves at each station. Schedule beyond a certain

percentage of Declared Capacity (DC) could be restricted on such days to have reserves.

iii) Signal to plant level from the Control Centre will be Delta P or the change in station MW: Signal to

plant level will be in the form of Delta P rather than continuous pulses. The delta P would ordinarily

be for the station as a whole and its further decomposition to unit level would be done at the

power station level. This is a broad guideline; there could be variants for individual power stations

where unit wise Delta P signal could be sent.

iv) Merit order might be ignored initially: So as to cover more units on AGC, merit order could be

ignored. Even in lower variable cost generating units, significant quantum of URS is available which

could be used for AGC.

v) Pilot projects of one in each region in phases: A pilot project in each region could be initiated

covering coal fired and gas based stations. Storage hydro power stations could also be covered

under AGC.

vi) Periodic monitoring of reserves: A process chart has to be prepared for the periodic monitoring of

the reserves at NLDC and RLDCs.

43

Page 3 of 4

vii) Inter-Regional tie line flows: The desirable refresh rate for such flows used for working out ACE

should be 4 seconds or better. However to start with this need not be insisted upon.

viii) Neighboring countries also to have AGC: Considering the expanding SAARC grid, a provision for

AGC in neighbouring countries needs to be kept in the Interconnection Agreements.

ix) Blocking AGC under special conditions: All the general conditions under which AGC has to be

blocked have to be listed.

x) Plant level standard specifications for receiving AGC signals: All the plant level standard

specifications for receiving AGC signals and performing the control actions have to be prepared.

This would be covered under pilot project.

xi) Spread Reserves on more units: For better ramping response from the generators, the reserves

have to be spread on more units.

xii) Tie line flows, Frequency and generation are Class ‘A’ telemetry values: Tie line flows, Frequency

and Generation in MW should be branded as class-A telemetry for the purpose of AGC and their

availability/accuracy should be very high. Communication path redundancy and high refresh rates

for these values must be ensured as far as possible. MW values at generator terminal, while

desirable, may not be insisted upon in the initial stage.

xiii) Delinking Deviation pricing from frequency: Deviation pricing has to be delinked from frequency

for incentivizing AGC. Payment to generators under AGC could be made on the basis of actual

generation. It was also felt that higher the deviations by state control areas will result in limited

effectiveness of AGC and therefore state control areas have to minimize deviation from the

schedule.

xiv) Converting AGC signals to scheduled MWh: AGC signals need to be converted into scheduled

MWh for the purpose of deviation accounting unless payment to generators under AGC is made on

the basis of actual generation.

xv) Load forecasting and scheduling: Load forecasting and scheduling have to be implemented,

starting from the State level till National level. This would also ensure correct load following by

generators thereby improving the effectiveness of secondary control.

xvi) Compensation to generators under AGC: Performance Indices for generators under AGC have to

be developed.

xvii) Primary control working and manual secondary control: A working primary control ensures that

the governors are working and are ready to accept a set point change. For manual secondary

control, the speed reference set point of the governor has to be changed. This needs governors be

44

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operational. In the present context where primary control is generally ineffective on many

generating units, AGC signals would be used to vary the load set point on each unit.

4.0 Next steps:

To implement AGC, a number of organizations have to be involved and the engagement of the

stakeholders needs to be on a continued basis. However for the purpose of confidence building in one

of the key areas in power system improvement, the role of NTPC Ltd. would be crucial. Broad

responsibilities and actions required are tabulated below.

Short term action items

S.NO.

Action item

Responsible Entities

Indicative time line

1.

Develop screens for AGC at National and

Regional level suitable for manual AGC

POSOCO (NLDC and RLDCs) By 31st March 2016

2.

Pilot project on AGC

i) Identify power plants

ii) Decide the objectives

iii) Discuss with NTPC on amount of

reserves to be kept on pilot plants

iv) Contracting and project

implementation

i) NTPC & POSOCO

ii) NTPC & POSOCO

iii) NTPC & POSOCO

By 31st March 2017

3. Ensure Communication to pilot plants CTU/POWERGRID By 30th Sep 2016

Long term action items (beyond 31st March 2017)

S.NO.

Action item

Responsible Entities

1. Learnings from pilot project

POSOCO & NTPC

2.

Market based approach for Reserves, Regulations on Reserves covering technical requirements, payments, performance indices etc.

CERC, POSOCO, CEA and other stakeholders

3. AGC software, equipment at power station end, communication systems etc. for full fledged country wide AGC

POSOCO, CTU and other stakeholders

45

46

47

48

49

50

Implementation of Automatic Generation Control (AGC) 

POSOCO

19th – 20th January 2016 New Delhi

Related CERC documents

• Report of the Committee on Spinning Reserves

– 17th September 2015

– http://www.cercind.gov.in/2015/orders/Annexure‐%20SpinningReseves.pdf

• Roadmap to operationalise Reserves in the country

– 13th October 2015

– http://cercind.gov.in/2015/orders/SO_11.pdf

• Central Electricity Regulatory Commission (Ancillary 

Services Operations) Regulations, 2015

– 13th August 2015

– http://cercind.gov.in/2015/regulation/Noti13.pdf

51

Roadmap to operationalise Reserves in the country‐ Salient points…..(1)

• Order dated 13th October 2015

• Detailed procedure to be submitted by POSOCO

• Recommendations of the Committee constituted by CERC taken into consideration

• Philosophy recommended to be adopted

–Operation at constant frequency target of 50.0 Hz with tie line bias

Roadmap to operationalise Reserves in the country‐ Salient points …..(2)

• Both primary and secondary controls areessential components for reliable grid operation.

• Reserve requirement– Nodal agency may estimate on day‐ahead basis

• Reliable telemetry and communication

• The AGC may be planned to be operationalised

– from 1.4.2017

52

Roadmap to operationalise Reserves in the country‐ Salient points …..(3)

• For AGC, units as well as load dispatch centres

– To be equipped with necessary communication infrastructure

– Automated control signals

–from the LDC to the generator 

–based on grid conditions

Roadmap to operationalise Reserves in the country‐ Salient points …..(4)

• All generating stations that are regional entities 

–must plan to operationalise AGC 

– along with reliable telemetry and communication 

– by 1st April, 2017. 

– This would entail a one time expense 

• to install requisite software and firmware

• which could be compensated

– Communication infrastructure 

• must be planned by the CTU 

• developed in parallel in a cost effective manner

53

Roadmap to operationalise Reserves in the country‐ Salient points …..(5)

• NLDC /RLDCs and SLDCs 

– To be ready with requisite software 

– procedures 

• Central Commission advises the State Commissions

– to issue orders for intra state generators

– in line with this timeline 

Roadmap to operationalise Reserves in the country‐ Salient points …..(6)

• Scenario is changing 

–margin for reserves is feasible in India

• Regulated framework to be evolved 

– In line with the Ancillary Services for identification and utilization of spinning reserves 

– to be implemented with effect from 1.4.2016

• may continue till 31.3.2017

54

Roadmap to operationalise Reserves in the country‐ Salient points …..(7)

• A market based framework for procuring reserves

– from 1st April 2017 

– for achieving greater economy & efficiency in the system

– NLDC to commission a detailed study

• Tertiary control refers to manual change 

– in the dispatching and unit commitment

– in order to restore the secondary control reserve

– Ancillary Services Regulation

Roadmap to operationalise Reserves in the country‐ Salient points…..(8)

• Proposed amendment to the Indian Electricity Grid Code (IEGC) – in respect of technical minimum

– Ramp up and Ramp down rates

– other important parameters for flexibility through regulations

55

Report of the Committee on Spinning Reserves‐ Salient points…..(1)

• Spinning Reserves 

– may be maintained of requisite quantum 

– depending upon the grid conditions

• The philosophy 

– operation at constant frequency target of 50.0 Hz 

with tie line bias

• The Spinning Reserve may be maintained, 

– to start with at the regional level. 

Report of the Committee on Spinning Reserves‐ Salient points…..(2)

• Each region should maintain secondary reserve 

– corresponding to the largest unit size in the region

• Tertiary reserves 

– should be maintained in a de‐centralized fashion by each state control area 

– for at least 50% of the largest generating unit available in the state control area. 

• More statistics provided in the next slides

56

Primary and Secondary Reserves

• Secondary Reserves (centralized approach)

– North :  800 MW

– East : 660 MW

– West : 800 MW

– South : 1000 MW

– North East :  363 MW

– Total :  3623 MW

• Primary Reserves (distributed )

– 4000 MW considering Ultra Mega Power Plant out

Tertiary Reserves (decentralized)

• All India level  :   5218 MW

– NR :  1658 MW

– WR :  1353 MW

– SR :  1343 MW

– ER :  857 MW

– NER :                65 MW

• Reserves to be maintained at intra state level

57

>2000 MW  97%

>2500 MW         92%

>3000 MW          87%

>4000 MW          71%

>5000 MW          51%

>6000 MW          32%

Frequency profile, Deviations, ACE

• Frequency profile

• Deviations from the schedule

• Area Control Error (ACE) considering regions

58

Issues to be discussed and roadmap evolved

i. Should reserves be earmarked specifically?– 5000‐6000 MW UnRequisitioned Surplus (URS) – Earmark only on days when URS falls to low value

• Prohibit generation above 95‐98% of DC on these days

ii. Should most of the units be wired for AGC?iii. Need to define Area Control Error (ACE)

– Area Control Error (ACE) = ∆ P + k ∆fWhere ∆ P = (Actual Net Interchange, NIA )– (Scheduled Net Interchange, NIs )∆f = (Actual Frequency, FA – Scheduled Frequency, FS) in Hz k = Frequency Bias of Control Area in MW/Hz, usually with a negative sign.

Issues to be discussed and roadmap evolved

iv. Automatic Generation Control (AGC) software

– Implementation at NLDC level

• Equivalent to five (5) Regional AGCs

– Plant wise signals or unit‐wise signals

– Single point responsibility in case of plant wise signal

– Accurate value of ∆P (telemetery errors & redundancy in measurements) 

v. Communication protocols and type of signals

vi. Security Constrained merit order

vii. Day Ahead earmarking of Reserves

59

Issues to be discussed and roadmap evolved

viii. Commercial treatment of units under AGC

– Normal scheduling process

– Ancillary Services (AS) despatch schedule

– AGC signals and its conversion to schedule

– Payment for units under AGC

– Commercial treatment of deviations from the schedule

– Sufficient incentives for units under AGC

ix. Pilot projects for better understanding

– Candidate stations in each region

– Data inputs for AGC

Possible candidates for secondary control

Region Secondary reserve  required ‘MW’

No of power stations available for AGC

MW capacity available for AGC

Stationsavailable if variable cost > 250 paise/kWh only to be considered

Capacity available if variable cost > 250 paise/kWh

NR 800 13 11283 9 6282

WR 800 16 15121 3 2313

SR 1000 9 10490 2 1500

ER 660 6 6760 4 4260

NER 363 3 1101 2 375

Total 3623 47 44755 20 14730

60

Thank you

Sample Regional ACE data for 06th December, 2015 

61

NR

WR

62

SR

ER

63

NER

Frequency profile over the years

64

65

Typically 100‐120 excursions above 50.03 Hz and similar excursions below 49.97 Hz

66

Current Installed Generation CapacityNTPCOwned:39,352MW JVandSubsidiary:6196MW

• Incorporated in 1975 ; Pan India Presence

• 45,548 MW capacity under Operation ; 23,004 MW under Construction

• Ten (10) coal mine blocks

• 25,000 committed workforceSource: Central Electricity Authority (CEA)

67

NTPC’s share in All India Generation and CapacityShareinInstalledCapacity ShareinGeneration

NTPC Group – 45.5 GW / 260 BURest of India – 223.2 GW / 788 BU

NTPC’s installed capacity is more than 3.3 times the capacity of next largest generating company

Source CEA, Data as on Oct.’15

Issue of Plant Load Factors - coming down year after year

Units operate at part loads leading to decrease in operating Efficiency.

Data as on Aug-15

68

REGIONS STATIONAverage URS in

FY16(MW)

Energy Charge Rate

Paise/KwhDadri 590 337-365

Rihand 231 155-192Unchahar 153 261-270

Jhajjar 341Singrauli 61 130-135

1376

Mouda 679 248-258Sipat 174 110-115

Korba 17 98-102Vindhyachal 523 131-138

1393Ramagundam 131 224-231

Simhadri 220 247-250

Vallur 8

359Farakka 245 276-280

Kahalgaon 371 261-273Barh-2 137 313-315

Talcher Kaniha 51 125-130803

NR-800 MW out of 7660 MW Cap Available for Spinning

Res.CAP.(20Units)

WR-800 MW- Av. Cap 8380 MW (16 Units)

SR-1000 MW - Av. Cap 6100MW (14Units)

ER-660 MW-Av Cap for Spinning Res. 3260 MW (8

Units)

Region wise break up of URS

Load following

Regulation

Increasing Variability of “Net / Residual Load” with large RES integration

Conventional Generation 

Load Demand – RE Power Injection + System Losses=

69

Three types of Imbalance control

Challenges for Conventional Generation:Major challenges which will be faced by NTPC in order to flex conventional generation to balance the increased variability & intermittency of “Net Load”

Issues Expectations / Apprehensions

Spinning ReserveUse under Normal conditionSecondary (AGC) Control:i) Regulation services: Continuous

& frequently demanded.

ii) Load Following Services:

Mostly higher VC stations will be earmarked.

i) Continuous response to balance load-Gen. If reserve is kept on many m/cs in acontrol area, miniscule variations (1% orless) will be demanded & not pose anydifficulty.

ii) a) Quantum of Load ramp up / down willbe high. Need to keep full auxiliariesrunning even when in part load.

b) Open cycle operation of gas plants maybe called for but its cost ??

70

Challenges for Conventional Generation:

Issues Expectations / Apprehensions

Spinning ReserveUse under Contingency conditiona) Primary Control Reserve:

Response in seconds (5-30 sec),Frequency- rarely (hrs / days)

a) Restoration of Primary controlreserve following its delivery aftercontingency. Response in 15 min,Frequency- rarely (hrs / days)

a) Reserves to be maintained in higher costm/cs. But most of the m/cs should be onGovernor control & to achieve that--thepre-condition will be containment ofnormal frequency excursion within thedead band of governor by AGC action.

b) By depleting secondary control spinningreserves. Higher quantum of Loadramping of conventional thermal m/c willtake place.

Frequent variation in loading of machine, would affect the residual life of machine.This may lead to increase in number of break downs of equipments, tube leakage,line leakages, fatigue, creep etc. with impact on R&M cost of machines.

Part load operation would adversely impact the Heat Rate, SOC and APC. Thisneeds to be compensated suitably.

AGC—envisaged by NTPC

NR‐800 MW  reserves required  out of 7660 MW Cap Available.(20 Units)URS of 1300 MW can be utilised

WR‐800 MW required‐ Av. Cap 8380 MW (16 Units)URS ‐1375 MW can be utilised 

SR‐1000MW required  ‐ Av. Cap  6100MW (14Units)URS ‐361MW can be utilised

ER‐660 MW‐Av Cap for Spinning Res. 3260 MW (8 Units)URS available‐803 MW

AGC

High V.C StationsMargins are kept

Biasing unit:Selection Logica) CMC Av-Yb) Tech

Constraints-Nc) NHR -Lo

Unit#Selected

*High variable costs units would likely be selected for providing spinning reserve.But as only CERC regulated stations would be covered in the beginning, some lowvariable cost units (mainly in SR) may also be included in it.

71

Operating band for Spinning Reserve & Automatic Generation Control (AGC)

Scope of AGC and communication Infrastructure/interface

In the scope of NTPCNTPC’s SCOPE

In the scope of NLDC/RLDC

72

THANK YOU.

Spinning Reserves

Time for mills from start to coal firing varies from 5 Min to >30 Min

It is desirable to have larger number of units for spinning reserves with

small quantum of reserve requirement per unit.

This will enable us to utilize the reserve available in auxiliaries

However, keeping large margins in unit/station auxiliaries will increase

the APC.A tradeoff between APC and margins requirements for

spinning reserves may be done.

In some cases wherein additional mill is required to be taken in

service , it may be difficult to maintain the timeline for spinning

reserves . (30 sec-15 min)(Unchahar St-2,Vind-St-2,Ramagundam St-

1 etc.)

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2.2.11 Automatic Generation Control (AGC) Introduction/Back-ground/Preface:

POSOCO intends to implement Automatic Generation Control (AGC) at National Grid Level. In the beginning, each of the five regional grids will be considered as one control area. Each of the neighboring country power system interconnected with the National Grid shall be defined as another control area for defining the trans-national exchanges. The ACE calculations, performance monitoring etc shall be carried out only for the five regional grid (control area) initially. However, gradually this can be extended to Bid Area or each regional entity as one control area. The complete AGC system shall be implemented in two parts.

In the first part, the AGC system will be running at NLDC SCADA/EMS system to control frequency and interchange with the control area. The contractor shall provide the AGC system at NLDC meeting the functional requirement as described in subsequent sections. The AGC system at NLDC shall be able to transmit the MW set points signals to the respective regional entity generators (plant wise) for increase / decrease of generation from their scheduled generation.

In the Second part, all the Regional Entity Generators identified for providing secondary control through AGC, shall have AGC servers installed in their premises. The AGC system installed at respective regional entity generators, will receive the MW set points for the station as a whole, and do further distribution among the physical generating units within the station considering the technical minimum/maximum, ramp up/ramp down rate, etc

The present scope of work for the contractor is to design, engineering, installation, commissioning and testing of AGC system at NLDC (first part only) The interface requirement at NLDC with the AGC system to be installed at respective regional entity generators (including received a signal last MW set point received/executed at regional entity generator end). The signal list to be exchanged between AGC system at NLDC and AGC servers at Regional Entity Generators is enclosed as Appendix-K.”

User Interface Requirement as described in Section 3, Part B of this Technical Specification shall be provided for all the AGC functions as mentioned in the following sections.

“Contractor's Standard Product

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Bidders are encouraged to supply standard, unmodified products that meet or exceed the Specification requirements. These products may be provided from the bidder's in-house baseline offerings. Alternatively, they may be provided by the computer manufacturer and established third-party software suppliers. Bidders shall describe all standard; unmodified products proposed and shall highlight those features that exceed the Specification requirements. Although the bidder is encouraged to use as much standard hardware and software as possible, the proposal will be judged by its conformance to the functional requirement of Specification. The proposal shall clearly identify all deviations from the Specification to help Employer evaluate the degree of conformance of the Bidder's offering.”

2.2.11.1 Generation Control (described in this section):

The principle Generation Control functions described herein include:

• Operations Monitor (OM) • Automatic Generation Control (AGC) • Reserve Monitoring (RM)

These functions address the NLDC operational objective of Reliable Power System Operation. These functions shall monitor and coordinate generation while supporting regional and national LDC operating personnel. Although the Generation Control functions, specifically AGC, will execute in an open-loop advisory mode initially, the Contractor shall provide the software, database, and user interface to perform closed-loop generation control in the future. The user shall be able to test and activate AGC in a closed-loop mode as control equipment becomes available in the field. The AGC calculation shall also take into account transmission congestion/ constraints.

Generation Control shall assist the NLDC/RLDC dispatchers to maintain scheduled frequency and scheduled power interchanges by:

(1) Running the ISGS according to ABT schedule (2) Allocating the generation raise/ lower signal within each RLDC's

area of jurisdiction (3) Using available generation to maintain power system frequency (4) Monitoring available spinning and non-spinning reserve

capacities.

Within this context, the principle real-time dispatching activities of the LDC are summarized as follows:

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(a) Activities: (1) Monitor the Region's generating resources, reserves, loads,

, inter-regional imports/exports, and frequency (2) Monitor each Area’s actual net interchange versus its

scheduled value (obligation) and maintain records of interchange errors

(3) Dispatch the region's ISGS (4) Enter into import/export transactions with other regions (5) Send ISGS actual unit output data to the NLDC for National

monitoring (6) Send directives to the region (for example, to change

generation and shed/restore load). 2.2.11.1.1 Operations Monitor

Operations Monitor (OM) shall provide shift operators/supervisors with a continual and accurate description of the demand/supply situation within their areas of responsibility.

OM shall produce information for display (numerical and trending) and for historical records. All the items listed below shall be calculated and monitored at the NLDC, which shall receive the required telemetered, calculated as well as user-entered information from all relevant sources comprising the hierarchical SCADA/EMS.

The following calculations as a minimum shall be performed at an adjustable periodicity (initially set to 1 minute):

(b) Actual Generation MW: (1) Total for all India (2) Total for each region (3) Total for each company/part of company, ISGS, regional

entity and the users' share breakdown. Generation shall be mentioned fuel-wise also. (c) Unallocated ISGS Generation MW: (1) Total for all India (2) Total for each region, control area.

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(3) Total for each Company/part of company, ISGS, regional entity and user.

(4) Total for Cross Border, International. Unallocated Generation shall be mentioned fuel-wise also. (d) Net Interchange MW (actual, scheduled, and deviation from

schedule): Net Interchange definitions and calculations shall be user-definable:

(1) Net for all India and breakdown per region and control area. (e) Actual Drawal MW (including transmission losses): (1) Total for all India (2) Total for each region. (3) Total for regional entities. (4) Total for Inter-national. (f) Area Control Error (ACE): ACE for 6 operating (5-Five Regions &

1- one NLDC)and processed ACE values shall be calculated based on actual frequency, actual net interchange, scheduled frequency, and scheduled net interchange. Control areas and associated ACE calculations will be defined by Employer during project implementation.

(1) For all India (2) For each region.

The NLDC shall retain the operational characteristics of each ISGS generating unit. The RLDCs shall report changes to unit characteristics to the NLDC as they occur. Each RLDC shall maintain its own unit information.

2.2.11.1.2 Automatic Generation Control Functions:

The primary objective is that AGC shall provide supplementary or secondary control action, which attempts to maintain the steady state values at specific levels. Primary control action for short-term swings shall be provided by the governors of the unit prime movers. The primary purpose of AGC to be delivered under this project is to adjust generation in response to changes in area load and Interchange requirement and to return frequency to its original value and maintain the difference between the constant frequency control error and the constant net interchange error within an acceptable range. This difference is the Area Control Error or ACE.

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Automatic Generation Control (AGC) shall have the ability to: (a) Execute in open-loop, i.e., without sending control signals to the

generating units (b) Perform standard load-frequency control calculations if the

generating capacity exceeds the load requirements, i.e., maintain scheduled frequency and net interchanges within prescribed values.

Initially, AGC will operate in open-loop, i.e., the control signals determined by functions will not be sent to the generating units and/or power plants. Full capability shall be provided, however, for the AGC functions to be field-upgradable to closed-loop operation without any need of additional computer software and/or hardware if, at a later date, Employer chooses to do so.

During normal open-loop operation (generation capacity greater than load), NLDC dispatchers shall be provided with the ability to manually select either the Load Frequency Control Mode. AGC shall compute the desired MW increase or decrease at each generating unit. The required MW changes shall then be totalled on a power station basis and communicated. The dispatcher shall be provided with the ability to validate or manually modify the MW changes required at each generating unit and power station. Upon dispatcher request, the MW change requirements shall be sent to the power station operators for subsequent control action.

During periods characterized by low frequency and generation capacity deficiency, AGC shall compute the amount of MW load reduction to be implemented. This information shall be displayed/ sent at the LDCs and, in addition, shall be automatically made available as input to the SCADA and ICCP.

At the NLDC, the Generation Control applications shall be fully implemented to allow the dispatchers to maintain the scheduled frequency and net interchanges within the prescribed limits. At the NLDC the capability shall be provided for the dispatcher to monitor the execution of the Generation Control applications within the RLDCs through periodically and on-demand updated Generation/Load Summary displays. Data for each generating unit region wise shall be displayed.

AGC shall retrieves and processes SCADA data and also trigger the rest of the AGC sequence, which shall be user configurable (initially every five minute), which includes:

• ACE calculations.

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• Issue of controls.

• Reserve Monitor.

AGC shall be capable of providing supplementary control that automatically adjusts the power output levels of identified generators within the defined control area in response to Area Control Error. AGC shall account for the number of generating units and tie lines within a control area. Automatic Generation Control (AGC) shall have the ability to (through simple graphical user interface):

(a) Select/ Modify the AGC Status of operation

System Operator/User shall be able to select or modify one of the following AGC Status, either:

a. ON —AGC is fully functional and control command are

issued.[ This will be enabled once the AGC system at Regional Entity Generators is in service]]

b. OFF — Off Control. AGC is not functional, but issues no controls.

c. MONITOR — Monitor Control. AGC is fully functional,

except no controls are issued (i.e., Monitor only).

On Selection the new status shall became active, next AGC cycle.

(b) Select the type of computation for ACE (tie-line bias

control, frequency control only, or tie-line control only) Three types of dispatcher selectable ACE calculation procedures shall be provided as follows:

The total plant allocation action required in AGC's control cycle shall be determined at the NLDC and assignments made to individual plants and units based on their control and operating status, operating limits, response rate limits, and deviation from schedule/ desired loading. Plants and unit control modes shall initially be set by default to "Off Control." Their limits, however, shall be dispatcher selectable and the capability shall be provided to adjust the parameters of AGC through user interface. The plant allocation function shall continuously determine MW requirements both for plants under NLDC jurisdiction and RLDC jurisdiction.

Three types of dispatcher selectable ACE calculation procedures shall be provided as follows:

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(a) Tie-Line Bias Control, where ACE is calculated from the following formula:

ACE = (Ia - Is) + 10 Bf (fa - fs) where: ACE = positive value for excess generation Ia = actual net interchange (positive value for export) Is = scheduled net interchange (positive value for export) Bf = frequency bias coefficient in MW/0.1 Hz (positive

value) fa = actual system frequency fs = scheduled system frequency (b) Frequency Control only, where ACE is calculated by setting (Ia -

Is) to zero (c) Tie-Line Control only, where ACE is calculated by setting Bf(fa -

fs) to zero.

There shall be suitable display at operator screen to monitor the following parameters: • Status and Mode of AGC Operation for each of the Area • Graphical trend of ACE for each area • Total Load and Generation of the respective area • Spinning reserve and operating reserve requirement of the respective area • Spinning reserve and operating reserve availability of the respective area

Although, during initial operation AGC will be executed in open-loop, ACE shall be conditioned (to produce a processed ACE) such that generator control action, if it were to be implemented, may occur only as necessary to reduce the magnitude of ACE with a minimum of governor control action. The AGC algorithm shall reduce governor action due to ACE noise and still respond to fast real changes of ACE by using digitally filtered adaptive and predictive controls. For each controllable unit in the system, a dispatcher selectable unit control mode shall be provided.

Actual control of a given unit shall be a function of the AGC control mode and the individual unit control mode. The capability shall be provided for software maintenance personnel to enter e.g. gains, regulating factors, assist factors, dead band values, program execution periods, and other factors as appropriate through interactive User Interface.

Initially, the length of the AGC cycle will be large enough to enable NLDC dispatchers and power plant operators to implement the

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recommended control actions. At a later date, when AGC operates closed-loop control, the execution cycle will be reduced in accordance with the real-time control requirements. In closed-loop implementation, it shall monitor control performance. .

2.2.11.2 AGC Measurements

All unit measurements and parameters will be on the basis of telemetered generation as defined by Employer during project implementation. The following telemetered data shall be provided to the Area Control Error computation algorithm:

(a) Tie-line power flow values (b) Schedule generation of each Unit/Plant

(b) Actual MW generation of each unit 2.2.11.2.1 Dispatcher Inputs to AGC

The Despatcher data entry requirements to AGC shall comprise, but not be limited to, the following functions:

(a) Select the AGC mode of operation (b) Choose the type of computation for ACE (tie-line bias control,

frequency control only, or tie-line control only) (c) Select generating unit control mode (this capability shall be

initially disabled) (d) Enter actual interchange for tie-line values normally not

telemetered (e) Enter generating unit limits (f) Enter unit response rates (this capability initially may be disabled) (g) Deactivate and activate telemetry values (both analog and status) All dispatcher entries shall be subject to validity checking. . 2.2.11.2.2 Generating Unit Control Modes AGC shall recognize the following generating unit control modes: (a) Not Available: The unit is out-of-service and is unavailable to the

user.

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(b) Off-Line: The unit is off-line but can be brought on-line if needed. (c) Plant Control: The unit is on-line but is directly under plant control.

The desired generation for the unit is determined by the plant operator.

(d) On Control: The unit is on automatic generation control and

controlled by AGC within the operating limit settings. .

The unit is controlled by AGC to follow the load based on its capacity. The user shall be prevented from placing a unit on control unless the plant operator has the unit on AGC.

2.2.11.2.3 Generating Unit Limits The following generating unit limits shall be recognized: (a) Total Capability: A user-entered limit indicating the maximum

output the unit can maintain. (b) Operating High Limit: A limit indicating the highest output the unit

can maintain with the equipment in service at the time. (c) Operating Low Limit: A limit indicating the lowest output the unit

can maintain with the equipment in service at the time. (d) Low Capability: A user-entered limit indicating the minimum

output that can be maintained. (e) Response: A user-entered limit representing the maximum

sustained rate-of-change-of-output for the unit.

A check shall be performed on limits (a) through (d) to determine that the values are consistent with one another. An alarm shall be generated whenever they are not consistent and control of the affected generating unit shall be suspended until the limits are corrected.

2.2.11.2.4 Turbine Control Logic

The desired generation for each generating unit shall be computed using the unit's base generation, , the change in total generation since the last execution of the function, the unit's regulating participation factor, and PACE as follows:

UDG = UBG + - (URPF * PACE) where:

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UDG = Unit's Desired Generation UBG = Unit's Base Generation URPF = Unit's Regulating Participation Factor PACE = Processed Area Control Error.

Regulating participation factors shall normally be calculated in proportion to the generating units' respective response rates. The user shall be able to enter a response rate for the calculation of each unit's regulating participation factor, but the manually entered values shall not be used for other functions requiring response rates (such as Reserve Monitoring). All regulating participation factors shall be normalized based on the units in the Fixed Load with Regulation. The unit's desired generation and all of its component terms shall be displayable.

When AGC is implemented in closed-loop mode in the future, generating units shall be driven to their desired generation in a manner consistent with the control type and the unit control modes and limits. The response characteristics of each unit shall be modelled to: (1) anticipate unit response, (2) minimize the control action that has to be sent to each unit, (3) avoid overshoot, and (4) determine when a unit fails to respond. The response models shall include stored energy effects so as to allow selected units to move faster than their response rate limit for a short period. Unit dead bands and other logic shall be used to avoid issuing control signals smaller than the control resolution of units while at the same time ensuring that control errors do not accumulate.

2.2.11.2.5 Generating Unit Control Signals

In the Future, some generating Plants shall be controlled by a set point representing the Plant’s desired generation. A set point for each unit of such plant in control shall be calculated at plant level and based on the change sent to generating plant by AGC. The selection of set point or raise/lower control shall be made on a Plant basis by the dispatcher.

2.2.11.2.6 Control Suspension/Trip

If data cannot be collected from a generating plant or if a unit has not responded within a programmer-adjustable period, the plant shall be set to Off Control and an alarm generated. Excessive deviations of frequency or ACE shall cause a suspension in control output to all generating plants until frequency and ACE are normal. The limit for these deviations shall be changeable by the dispatcher. AGC shall be suspended if the measurement from any tie line (except in the Constant Frequency control mode) or the primary frequency source (except in the Constant Net Interchange control mode) has failed. If AGC suspends control for longer than a dispatcher-changeable time period, AGC shall be tripped (i.e., control output to all plants shall cease), thereby requiring manual intervention to restore control. If the

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failed measurement becomes valid prior to the timeout, or if the user enters a substitute value or selects a redundant source for the telemetry prior to the timeout, or if excessive values return to within limits prior to the timeout, AGC shall resume and provide appropriate messages describing these events.

The user shall be able to trip AGC at any time. When AGC is suspended or trips for any reason, all calculations including ACE shall continue to be performed. All actions that cause a suspension or trip shall be alarmed with a message identifying the reason for the action.

2.2.11.2.7 AGC Performance Monitor

Control performance shall be monitored against the defined Performance Criteria. These standards are based on the combination of the ACE and the frequency deviation averages over the past twelve months. The AGC software shall have a Performance Monitor function and displays the results. It shall be possible to generate periodic reports of the performance parameters. Statistics shall be maintained as required to complete the defined Performance Criteria. These statistics shall be maintained for presentation on displays and output to a printer.

2.2.11.2.8 Non-telemetered interchange / generation:

The operator shall be able to enter manually the non-telemetered interchange or generation values.

2.2.11.2.9 Specifying Area Scheduled Frequency:

It shall be possible to specify the area scheduled frequency for each of the control area.

2.2.11.2.10 Specifying Area Frequency Bias Coefficient (Bf)

The system operator shall be able to specify whether the area frequency bias should be calculated by software or whether it should be manually entered, and to enter the frequency bias if the manual entry is selected.. The area frequency bias is represented in MW/0.1Hz.

2.2.11.2.11 Entering Reserve Requirements

The operator shall be able to enter/specify the Spinning reserve / Operating Reserve requirement for each of the Control Area.

2.2.11.2.12 Entering Operating Area Response Rate Requirement

The system operator shall be able to specify/ modify the operating area response rate requirement to be used by AGC. This value defines the

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minimum short-term rate in both the upward and downward direction for the entire operating area.

2.2.11.2.13 Selecting/Modifying a Generating Station Regulating

Participation Factor:

The operator shall be able to select or modify the generating station relative participation during proportional regulation duty. Alternately operator shall be able to define priority list for assigning the regulation requirement. The operator shall have the option to enter the PLC's Generators regulation participation factor (RPF) or use a RPF computed by the AGC function or list of priorities.

AGC shall calculate regulation participation factors for those Generators that are not using manually entered values. The manually entered values for the Generator that can regulate are added up and subtracted from 100. The amount left over is divided up among the remaining Generators that can regulate, using calculated factors in proportion to the Generators nominal up response rates. The resulting values are normalized over the set of Generators that are actually regulating (within each regulation priority) for that given cycle, to come up with the final participation factors used for the cycle.

2.2.11.2.14 Specify Jointly Owned Unit Operation

It shall be possible to specify some generating station for jointly owned unit operation (e.g.; SASAN UMPP which has shares in more than one control area). In such cases the generating unit shall participate for regulation for all the control area owns the generating station.

2.2.11.2.15 Interfacing with the Scheduling Software at NLDC:

AGC software at NLDC shall design a suitable interface with Scheduling Software in line with section 8.0 web design at NLDC to extract the following inputs for each 15 minute time block period:

• Declared Capacity of the Generating station ( DC) • Ramp Up / Ramp Down Rate • Base Point Generation ( Schedule Generation)

2.2.11.3 Real-Time Dispatch

The NLDC shall calculate the generation requirements for the participating ISGS based on ACE. AGC for real-time dispatch shall be

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performed at an adjustable periodicity (initially 5 minutes) or upon the occurrence of any of the following events, providing that at least 30 seconds has elapsed since the last AGC:

(a) Significant change in system generation/ Transmission Network

(b) Significant change in actual net interchange (c) On demand by the user. (d) Dispatcher request

(e) Every Quarter of an hour/ Every Time block of ABT (f) A significant (software selectable) change in system load

since the last dispatch calculation (g) A significant change in actual net interchange since the last

dispatch (h) Significant Change in Transmission Network

2.2.11.4 Reserve Monitoring

The Reserve Monitoring (RM) function shall account for available generation capacity and system reserves both system-wise and by individual generating Plant/unit. Its sizing and data interfaces shall be coordinated with OM and Interchange Scheduling & ABT scheduling. This function shall obtain input data, perform necessary calculations, and produce the results for each Plant/ generator. Reserve Monitoring shall compute the following: (a) Plant/Generating capacity: The maximum MW output that can be committed within present operating constraints associated with the unit. This number can be manually entered by the dispatcher. (b) Spinning reserve: The total on-line synchronized generation reserve The ability shall exist for this function to be executed periodically (user-adjustable), on-demand, and by event trigger, e.g., each time an unscheduled unit tripping takes place.

2.2.11.4.1 Reserve Monitoring Inputs

The input data required by the Reserve Monitoring function shall be obtained automatically, from SCADA, or manually entered by the dispatcher. The input data shall include: (a) Current MW output of each generating unit (b) Maximum instantaneous MW available on each generating unit

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(c) Parameter data, e.g., rated MW capacity for each unit, Nominal reserve, MW rate-of-change for each unit. (d) Forecasted Region-wide load and scheduled interchanges with neighbouring area for the next time period. 2.2.11.4.2 Reserve Monitoring Outputs The outputs shall consist of the calculated values of capacity and spinning reserves both for each plant and for the entire Area. The various reserve values shall be presented to the operator on User Interface displays. 2.2.11.4.3 Reserve Monitoring Alarms Alarms shall be generated when the following system conditions exist: (a) Spinning reserve less than the nominal reserve (b) Capacity for the next tile period insufficient to meet forecasted load and scheduled interchange as calculated in the middle of time period.

2.2.11.5 Production Statistics

Production Statistics (PS) shall be provided at the NLDC to maintain an accurate accounting of relevant production performance, production cost, plant availability factor, scheduled vs actual generation, and daily/ monthly generation regulation participation. Results shall be saved for display and trending and historical purposes and for daily and monthly reports. The following results shall be available at the end of the hour on a plant/unit, and regional basis: (a) Actual generation in net MWh (b) Actual and schedule generation

2.3 Dispatcher Training Simulator

A Dispatcher Training Simulator (DTS) shall be provided for Control Centre computer system training during power system normal, emergency, restoration activities. The major DTS features shall include:

(a) A Power System Model (PSM) that simulates the power system in a realistic manner, including its response to simulated events, Instructor actions, and Trainee actions. PSM response shall be identical to the response observed by the dispatcher in the actual computer system environment. The User Interface shall also be identical to that of the production system in order to provide a realistic and immersive training simulation.

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OSI Corporate Overview

January 19, 2016

88

89

20-JAN-2016

Brain Storming Session for implementation of AGC in India

New DELHI

Indranil BANDYO

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Spectrum PowerTM 7Power Applications for Transmission System Operators

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Page 2 Energy Management Division – Smart Grid Solutions

Spectrum Power™ 7 Power Applications

Overview

The Spectrum Power™ Power Applications suiteprovides the complete functionalities for:

• load frequency control, i.e. for maintaining real-time equilibrium between generation and load, whilst maintaining an optimum generation dispatch and scheduled interchange, and for

• generation dispatch control, i.e. for satisfying real-time ancillary requirements, e.g. regulating power, whilst meeting energy delivery contracts.

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Spectrum Power™ 7 Power Applications

Power Applications modes

The Spectrum Power™ Power Applications suitesupports, accordingly, the following 2 modes ofoperation:• Control Area / Regional Operator: the company is

responsible for one or more control areas where generation belongs to one or more companies and regulating generation is either own or acquired in the regulating market.

• Power Producer: the company dispatches its generation on the basis of its own generation schedule (energy delivery contracts) and regulating generation (bid in regulating markets) requested by one or more Area Operators.

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Spectrum Power™ 7 Power Applications

Power Applications Overview (1) – Single Control Area

Consumers

Control Area

SchedulesSchedules

LoadFrequency

Control

Economic Dispatch

Reserve Monitor

Production Cost Monitor

Power Applications

ConsumersGenerating

Units

Interchange(Tie Lines)

Consumers

Consumers

Generating Units

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Spectrum Power™ 7 Power Applications

Power Applications Overview (2) – Multi-Area / Hierarchical model

GenerationDispatch Control

Economic Dispatch

Reserve Monitor

Production Cost Monitor

Power ApplicationsRegional

Operator

Control AreaOperator

Control AreaOperator

Control Area X Control Area Y

Internal Exchange

External Exchange

External Exchange

Remote ACE requirement

Remote ACE requirement

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Spectrum Power™ 7 Power Applications

Functions

• Load Frequency Control (LFC)• Economic Dispatch (ED)• Reserve Monitor (RM)• Production Cost Monitor (PCM)

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Spectrum Power™ 7 Power Applications

Load Frequency Control (LFC)

LFC provides real-time (secondary) control of thegenerating units participating in area regulation tomaintain system frequency, i.e. real-time equilibriumbetween generation and demand, whilst maintaining“optimum” dispatch and scheduled interchange.Accordingly,

• LFC determines the area control error, or ACE, that combines frequency and net interchange deviations plus additional corrective terms such as inadvertent energy compensation and/or remote ACE, then

• LFC calculates the necessary total generation correction, allocates it to the individual participating units, and implements the corresponding control signals via SCADA

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Spectrum Power™ 7 Power Applications

Load Frequency Control (LFC)LFC supports among many other features:

• Hierarchical and multiple control areas• 3 ACE modes: Constant Interchange (CNI),

Constant Frequency (CF) & Tie Line Bias (TLB)• 4 LFC control modes (filtered ACE bandwidth):

basepoint, regulation, permissive & emergency• Unit MWh deviation monitoring & control• Jointly Owned Units (JOU)• Virtual Unit• Net/Gross value conversion• Performance monitoring according to NERC

(CPS1 & CPS2) or ENTSO-E requirements• Unit Response tests

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Control Mode

Type of Power Utility

GenerationCompanies

TransmissionSystem

Operators

VerticallyIntegrated

Utilities

Frequency Control B * ∆f B * ∆f

Interchange Control ∆P

Tie-line Bias Control ∆P + B * ∆f ∆P + B * ∆f

Time Correction TC TC

Energy Correction EC EC EC

Spectrum Power™ 7 LFC – ACE Modes

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Spectrum Power™ 7 LFC - Control loops

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Spectrum Power™ 7 LFC – Unit Operating Modes

Off Remote Control On Remote Control

Independent

Not Updated Updated NonRegulating

Assist Regulating

Manual

Station

Dispatch

Base Monitoring

Base Advisory

Base Base Assist

Base Regulating

Ramp Monitoring

Ramp Advisory

Ramp Ramp Assist

Ramp Regulating

Schedule Monitoring

Schedule Advisory

Schedule Schedule Assist

Schedule Regulating

Economic Monitoring

Economic Advisory

Economic Economic Assist

Economic Regulating

Operator

Schedule

Economic Dispatch

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Spectrum Power™ 7 LFC – Control area regulating ranges

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Spectrum Power™ 7 LFC – Generation Distribution

• Distribution according to a Merit Order List (MOL)typically chosen by Transmission System Operators

• Distribution According to Technical Generating Unit Parameterstypically chosen by Generation Companies

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Room-To-Move RegulationGenerating unit regulation participation factors are derived as the individual regulating capacities divided by the total regulating capacity of all units on remote control and either in regulating or assist mode.

Manual RegulationUnit regulation participation factors are defined manually as percentages.

Ramp RegulationUnit regulation participation factors are based on the generating units’ ramp rates rather than their regulating ranges. Depending on the regulation situation, this might allow reaching the needed regulation faster than with the Room-To-Move Regulation.

Spectrum Power™ 7 LFC –Distribution acc. to technical unit parameters

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Spectrum Power™ 7 LFC – Distribution according to MOL

Transmission System Operators (TSO) have additional needs:

• Acquisition of bids and confirmation of the contracts (usually on a day-ahead basis)

• Creation of a Merit Order List (MOL) based on one or more parameters like price, energy price, amount, bid time, etc.

Additional tasks for LFC :• Process the MOL at the beginning of each

contractual period or in case of changes• Distribute the temporary generation

according to the MOL among the bidders

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Page 16 Energy Management Division – Smart Grid Solutions

Spectrum Power™ 7 Power ApplicationsLoad Frequency Control – Summary

Flexible design supports operation on all levels of system control

To be used as area controller, plant controller and unit controller

Distribution of temporary generation among regulating units using

• operator-defined unit regulating ranges (under normal conditions) or

• proportional to the units’ maximum regulating power limits (under stress conditions)

Optimum allocation of temporary generation according to the units` regulating capabilities

Fully compensated area controller with separated small and large signal handling

Smooth Area Control Error correction guarantees minimum stress for all controlled generating units

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Spectrum Power™ 7 Power Applications

XML-IO Application (XML-IO)

XML-IO is a powerful interface application to import or export data in XML file format.

Among other features, XML-IO provides• easy exchange of ENTSO-E Scheduling System

(ESS) and ENTSO-E Reserve Resource Process (ERRP) Data

• semantic checks against XML schemas with notifications in case of errors

• highly customizable interfaces with your own pre- and/or post-processors

• interaction with the Spectrum Power™ schedule management for MOL and schedule data

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Spectrum Power™ 7Power Applications

XML-IO Application (XML-IO)

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Spectrum Power™ 7XML-IO Application – Summary

Generic application architecture and configuration

Allows concurrent processing of multiple files and is suited for many use cases

Highly configurable interfacesAllow the creation of own pre- and post-processor scripts for checks or edits of the provided files

Compliance with the latest ESS and ERRP standards

Allows easy data exchange in standardized XML file formats with internal and external parties

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Spectrum PowerTM 7Power Applications – Economic Dispatch

Economic Dispatch (ED)ED allocates optimally the total generation requirement (sum ofbase point values + system regulation calculated by LFC)among participating generation units. This allocation eitherminimizes the total system production cost or maximizes thetotal system profit subject to

• Total generation requirement • Reserve (spinning) requirements• Plant and unit limits• Production cost characteristics

The solution is derived from an algorithm based on thenonlinear Dantzig/Wolfe decomposition principle.

ED is executed cyclically, on operator request or on LFCtrigger and can be executed either in normal mode or inanticipatory mode.

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Spectrum PowerTM 7Power Applications – Economic Dispatch

Economic Dispatch (ED)ED provides 3 optimum dispatches:

• A Control Dispatch (for LFC use), to calculate base points of all online units that are on AGC control and in Economic base point mode

• An Advisory Dispatch, to calculate base points of all online units that are

• on AGC control and in Economic base point mode,

• off AGC control and in Advisory, Monitoring or Independent (Economic Dispatch) mode - base points of units in Advisory mode are communicated to the respective plant operators

• A Target Dispatch (for PCM use), to calculate unconstrained base points for all online units whose Target Dispatch Flag is on.

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Spectrum PowerTM 7Power Applications – Economic Dispatch

Economic Dispatch Functional Diagram

* Each Dispatch constructs a dispatch solution

Control Dispatch*

Advisory Dispatch*

Target Dispatch*

System Optimal Dispatch

Unit Optimal Dispatch

Two-stepsolutionalgorithm

Calculate Generation

Requirement

Construct Incremental Cost Curves

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Spectrum PowerTM 7Power Applications – Reserve Monitor

Reserve Monitor (RM)RM provides the online monitoring of the system reserverequirements. It runs periodically within a configured cycle timeto

• calculate active reserves• compare the reserves to the requirements• issue an alarm upon a requirement’s violation

RM supports reserve requirements’ schedules retrieved froman external scheduling application, e.g. unit commitment, orspecified by an operator by selecting any one of the predefined rules.

RM allows an operator to modify each unit’s mode (regulating,not regulating, standby, unavailable) of contribution to eachreserve requirement type.

RM can operate in one or more control area.

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Spectrum PowerTM 7Power Applications – Reserve Monitor

Reserve Monitor (RM)

RM supports the following reserve classes:• Responsive (incl. regulating) Reserve (<20s)• Spinning Reserve (<2m)• Operating Reserve (<10m)• Quick Start Reserve (<30m)• Slow Start Reserve (<2h)

RM supports the following reserve policies:• Schedule (from a scheduling application)• or...

• Value (MW)• % of largest unit• % of largest tie flow• % of largest (largest unit, largest tie flow)• % of total load

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Spectrum PowerTM 7Power Applications – Production Cost Monitor

Production Cost Monitor (PCM)

PCM provides the online monitoring of the actualproduction costs based on actual unit generationsagainst the optimal production costs based on ED’starget dispatch results. Whenever the actual costsexceed the target costs, PCM produces an alarm.

Cost calculations are made • per unit, plant and system, and • for current values, hourly averages and daily

integrals of the hourly average values.PCM provides also for the calculation of

• fuel consumption, including that of water, and• startup costs including number of daily startups,

etc.

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Spectrum PowerTM 7Content

• Overview

• Functions

• User Functions

• Summary

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Spectrum PowerTM 7Power Applications – New Modern User Interface

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Page 28 Energy Management Division – Smart Grid Solutions

Spectrum PowerTM 7Content

• Overview

• Functions

• User Functions

• Summary

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Page 29 Energy Management Division – Smart Grid Solutions

Spectrum Power™ 7 Power ApplicationsLoad Frequency Control – Summary

Various selections of area control modes can be combined:

• Frequency error correction• Time error correction• Net interchange error correction• Inadvertent energy correction

within the current period• Inadvertent energy correction

based on data calculated by the Energy Accounting application

Allows on demand selection of control modes by the operators depending on the current network requirements and contractual obligations

Anticipatory mode algorithmBest reduction of Area Control Error during steadily increasing and decreasing load situations

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Spectrum Power™ 7 Power Applications –Economic Dispatch Summary

Based on the principle of equalincremental costs (lambda dispatchalgorithm)

Very short calculation time allows economic real-time dispatch of the temporary generation

Handling of multiple fuels possible

Up to five fuel types per generating unit possible

Supports percentage based calculation of fuel mixtures

base fuel/top fuel handling

Cost savings in fuel cost and unit maintenance cost due to detailed modeling of the reality

Automatic consideration ofuneconomic regions (valve points)for both thermal and hydrogenerating units

Prevents units from being driven at power values where the throttling losses are a maximum, i.e. when a valve is nearly closed

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Spectrum Power™ 7 Power Applications –Reserve Monitor Summary

Supports up to 5 reserve classes and

various reserve calculation modules

for a wide range of reserve elements

Cost savings due to detailed modeling of the reality

Reserve policy for different

emergency situations like loss of

units or interchange

Suited both for generation and transmission companies

Allows different reserve policies for

working days, holidays and

weekends, and up to 5 special days

defined by certain dates

Reserve policy is highly adaptive to the network load on different days

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Spectrum Power™ 7 Power Applications –Reserve Monitor Summary

Highly configurable requirements

for reserve classes (MW values,

user-defined percentage of

biggest generating unit, user

defined percentage of biggest

interchange, user-defined

percentage of current system

load)

Allows fine tuning of required system reserve, thus helping to minimize the system operation and standby costs

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Spectrum Power™ 7 Power Applications –Production Cost Monitor Summary

Online monitoring of production

costs and fuel consumption

Real-time feedback on how close the system is operated to the economic optimum

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Page 34 Energy Management Division – Smart Grid Solutions

Spectrum Power™ 7 Power Applications

Thank You !

kiran.rasane@siemens.comvikas.yadav@siemens.comgirish.muley@siemens.com

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~

Annexe-5

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109

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111

112

113

114

Automatic Generation Control (AGC)

First Pilot Project at NTPC Dadri

10th March 2017

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Outline

• Commission’s orders on spinning reserves

• Frequency profile of different systems and India

• Primary Control

• Secondary control through Automatic Generation Control (AGC) – Details of pilot project by POSOCO and NTPC

– Further steps

• Commercial mechanism for plants under AGC

• Further directions required from Hon’ble Commission

2

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Commission’s orders

• Central Electricity Regulatory Commission (Ancillary Services Operations) Regulations, 2015

– 13th August 2015

– http://cercind.gov.in/2015/regulation/Noti13.pdf

– Implemented from: 12th April 2016

• Report of the Committee on Spinning Reserves

– 17th September 2015

– http://www.cercind.gov.in/2015/orders/Annexure-%20SpinningReseves.pdf

• Roadmap to operationalise Reserves in the country

– 13th October 2015

– http://cercind.gov.in/2015/orders/SO_11.pdf

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Roadmap to operationalise Reserves in the country - Salient points

• Philosophy recommended to be adopted

– Operation at constant frequency target of 50.0 Hz

– with constant area interchange

• For AGC, power plants and Load Dispatch Centres (LDCs)

– necessary software and communication infrastructure

– Automated control signals from LDC to the generator

• AGC to be operationalized wef 1st April 2017

POSOCO awarded a pilot AGC project on 18th Jan 2017

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Primary and Secondary Reserves

• Secondary Reserves (centralized approach)

– North : 800 MW

– East : 660 MW

– West : 800 MW

– South : 1000 MW

– North East : 363 MW

– Total : 3623 MW

• Primary Reserves (distributed )

– 4000 MW considering Ultra Mega Power Plant out

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Tertiary Reserves (decentralized)

• All India level : 5218 MW

– NR : 1658 MW

– WR : 1353 MW

– SR : 1343 MW

– ER : 857 MW

– NER : 65 MW

• Reserves to be maintained at intra state level

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Year: 2016 Source: Derived from http://fnetpublic.utk.edu/ 7

121

Frequency profile of Continental Europe

Narrow range of 49.96-50.04 Hz!!

Deterministic frequency deviations – root causes and proposals for potential solutions -------------------------------------------------------------------------------------------------- A joint EURELECTRIC – ENTSO-E response paper

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Typical frequency profile for Eastern Interconnection, US

For 11th April 2012

Based on 2 second frequency data available from PJM website

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Sample Daily Frequency Profile of India

Generally remains within 49.90-50.05 Hz for 70-75% of the time

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Frequency Profile 125

Frequency Profile

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Frequency Variation Index (FVI) over the years

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127

Frequency Profile

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Frequency Profile

Maximum Frequency

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Frequency Profile

Average Frequency ~ 50 Hz.

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130

Minimum Frequency

Frequency Profile

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Frequency Profile

FVI consistently hovering around 0.03 to 0.05

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Frequency as per global standards in India • Load and RE forecasting

– Decentralized at State level

• Unit commitment and Scheduling – Decentralized – Move from 15-minutes to 5-minute scheduling (SAMAST)

• Load following resources – Decentralized

• Fast/slow tertiary response – Centralized through Ancillary Services at ISTS level

• Secondary response – Automatic Generation Control (AGC) at regional level

• Primary control – Decentralized

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49.83

49.88

49.93

49.98

50.03

50.08

1 501 1001 1501 2001 2501 3001 3501 4001

Jan-15 Feb-17

Early frequency recovery in Feb 2017 PMU plot due to improved Primary Response in comparison to Jan 2015 for a similar event(1000 MW Generating Unit Tripping )

49.88 Hz

49.85 Hz

Hz

50.07 Hz

49.91 Hz

Kudankulam 1000 MW tripping event 134

• Frequency Response Characteristics (FRC) has increased from 6000 MW/Hz in early 2015 to over 9000 MW/Hz in Mar 2017

• Quarterly reports submitted to CERC for 39 events since Jan 2015

Commission’s orders have facilitated primary response order dated 13th Feb 2017 in petition 65/MP/2014 Target FRC of 15000 MW/Hz suggested along with testing

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CERC Terms and Conditions of Tariff Regulations, 2014

“ the rate of return of a new project shall be reduced by 1% for such period as may be decided by the Commission, if the generating station or transmission system is found to be declared under commercial operation without commissioning of any of the Restricted Governor Mode Operation (RGMO)/ Free Governor Mode Operation (FGMO), data telemetry, communication system up to load dispatch centre or protection system:

as and when any of the above requirements are found lacking in a generating station based on the report submitted by the respective RLDC, RoE shall be reduced by 1% for the period for which the deficiency continues “

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Secondary Control through AGC

• Pilot at NTPC Dadri Stg-II (2 x 490 MW) – Dadri Stage II power plant is located near Delhi.

– Easy to visit and monitor the field level implementation process.

– High variable cost of the order of 325 paise/kWh

– Economical to keep Spinning Reserves as little opportunity cost

• Subsequent pilots could be explored in each region – Simhadri-II in Southern Region

– NP Kunta Solar

– Wind project

• Detailed procedure would be submitted by POSOCO

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Project progress • A team from POSOCO, POWERGRID and M/s Siemens

– visited NTPC Dadri on 6th May 2016 – to explore the ground level requirements with NTPC

• Execution of AGC pilot project as per technical specifications through limited tender – Invited bids on 21st October 2016 from the four SCADA vendors

• M/s ALSTOM • M/s OSI • M/s Siemens • M/s ABB

• Bids opened on 30th Nov 2016 • Letter of Award (LOA) issued to M/s Siemens on 18th Jan’17

and accepted by Siemens on 25th Jan ‘17

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Technical Specifications

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Area Control Error (ACE) formula

• ACE = A * (Ia - Is) + 10 * Bf * (50 - Fa) A = 0 or 1; 0 -> for adopting ‘only Frequency control

mode’ and 1 -> for adopting ‘Tie Line Bias mode’ (user entry)

Ia = Actual net interchange

Is= Scheduled net interchange

Bf = Frequency Bias Coefficient in MW/0.1 Hz

Fa = Actual System Frequency

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ACE and AGC set point • Spikes in ACE data are present for different

reasons. – By design, AGC cannot handle large changes in ACE – Pilot AGC shall clamp ACE exceeding +/- 800 MW to +/-

800 MW

• Method for Scaling of ACE – Scale using a factor of 15 (800/15 = approx 50 MW, the

maximum Spinning Reserve.

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141

Draft Rules for the CLU Algorithm at NTPC

• Receive Unit Status, Present Schedule and DeltaP signal and number of mills.

• If Present Schedule is close to 230, 330 or 430 MW, start

another extra mill to create Spinning Reserve. • Delta P signal be clamped to +/- 50 MW if the value is

outside +/- 50 MW. • The biasing between units should be user enterable. Start

with 0.5, for equal contribution. • Difference between two consecutive ICCP refresh values of

Delta P shall be clamped to a limit of 1 MW to start with. (i.e., Max(Delta Delta P) = 1 MW) 28

142

Proposal for commercial settlement for AGC services offered by NTPC Dadri Stage-II

1. Factoring AGC signals while evaluating Deviations.

2. Compensate for the Extra Energy spent/saved

3. Incentivize for the ‘secondary regulation’ services

• CERC Order needed to facilitate all of the above

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143

1. Factoring AGC signals while evaluating deviations

• Energy produced due to AGC signals should not be considered as deviation from the schedule

• Aggregated AGC incremental MW signals over 15 minutes / 5 minutes would be logged in MWh at NLDC.

• AGC MWh logs forwarded to NRPC secretariat on weekly basis.

• Deviation in MWh for every time block would be worked out as

– MWh deviation = (Actual MWh)-(Scheduled MWh)- (AGC MWh) which would be settled as per the existing DSM Regulations

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2. Compensate for the Extra Energy spent/saved

• The AGC energy account will be available every week

• For AGC MWh generated during a block,

– payment @ variable charges to Dadri from the NR DSM pool

• For AGC MWh reduced during a time block

– Dadri pays @variable charges to the NR DSM pool

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145

3. Incentivize for the ‘secondary regulation’ services

• For AGC MWh in each time block (+ve or –ve)

– 50 paise/kWh mark up payable to NTPC Dadri from NR DSM pool

• Mark up of 50 paise/kWh similar to Ancillary Services (AS) framework of CERC.

• Periodic checks regarding compliance of plant to AGC signals

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146

Inputs needed for Accounting (Main and Standby)

• MW Delta P signals every 10 seconds at NTPC Dadri (Main)

Delta P = PAGCsetpoint – Pschedule

Integrated into MWh values for 15 minutes and 5 minutes

• MW Delta P signals sent every 10s from NLDC

(Standby)

– Integrated into MWh values for 15 minutes and 5 minutes

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147

Regulation accuracy of the solar plant demonstration exceeded accuracy of conventional resources

Page 34

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

SteamTurbine

PumpTurbine

Hydro CombinedCycle

LimitedEnergyStorage

GasTurbine

Solar PV(Middle ofthe Day)

Solar PV(Sunset)

Solar PV(Sunrise)

Regulation Up Accuracy

Blue bars taken from the ISO’s informational submittal to FERC on the performance of resources providing regulation services between January 1, 2015 and March 31, 2016

Source: CAISO

148

CERC approval is needed on the following • Go ahead for the pilot project for NTPC Dadri Stage-II (2 x 490 MW) to

receive AGC signals from NLDC and regulate to the extent of 50 MW up/down to start with and with provision to go up later.

• Deviation Settlement Mechanism (DSM) for Dadri Stage-II under AGC – Factoring AGC signals while working out deviations from the schedule

• Incentivize NTPC Dadri stg-II for the AGC services – 50 paise/kWh mark up similar to Ancillary Services framework

• Facilitate NRLDC to earmark 50 MW up/down reserves at NTPC Dadri Stage-II on days when full generation is requisitioned or schedule is at technical minimum

• Take up other pilot projects including wind and solar

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Thank you

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