Electricity Grid Management in India- An Overview Published in 2007 Annual issue of “Electrical India”-Vol 47 No 11, November 2007 (Electrical India is India’s oldest magazine on power & electrical products industry. It is being published since 1961by Vivek Pandey Introduction‘Transmission’ and ‘Grid Management’ areessential functions for smooth evacuation of power from generating stations to the consumers. Transmission function primarily consists of construction and maintenance of the transmission infrastructure while the job ofthe grid operator is to give operating instructions to the engineers in the field andensure moment-to-moment power balance in the interconnected power system. Grid management involves taking care of the over all reliability, security, economy and efficiency of the power system. Fig-1: Five Regional grids in India Grid Management in India is carried out on a regional basis. The country is geographically divided in five regions namely, Northern, Eastern, Western North Eastern and Southern. All the states and union territories in India fall in either of these regions. The first four out these five regional grids are operating in a synchronous mode, which implies that the power across these regions can flow seamlessly as per the relative load generation balance. The Southern Region is interconnected with the rest of India grid through asynchronous links. This implies that quantum and direction of power flow between Southern Grid and rest of India grid can be manually controlled. Load Despatch Centres Each of the five regions has a Regional Load Despatch Centre (RLDC), which is the apex body, as per the Electricity Act 2003 (EA 2003), to ensure integrated operation of thepower system in the concerned region. The RLDCs for North, East, West, South and Northeast regions are located at Delhi,Kolkatta, Mumbai, Bangalore and Shillong respectively. Fig-2: Load Despatch Centres The RLDCs coordinate amongst themselves both offline as well as online for maintaining the security and stability of the integrated pan-India grid. In line with the federal structure of governance in the country, every state has a State Load Despatch Centre (SLDC), which is the apex body to ensure integrated operationof the power system in the state. Page 1 of 7
--------------------------------------------------------------------------------
Page 2
Fig-3: Regional Load Despatch Centres The RLDCs in India are presently owned, managed and operated by the Central Transmission Utility (CTU), POWERGRID while the SLDCs in the state are owned operated and managed by the respective State Transmission Utility (STU) or the State Electricity Board (SEB) as the case may be. The EA 2003 has a provision for a National Load Despatch Centre (NLDC) for optimumscheduling and despatch of electricity across various regions and also coordinating cross border energy exchanges in real time. Ministry of Power has notified the functions of NLDC that is under construction. Presently, POWERGRID is operating a National Power System Desk (NPSD) in New Delhi for information exchange and facilitating inter-regional transactions. The cross border exchanges are coordinated by the RLDC of theregion whereinthe international interconnection is situated. Role of Load Despatch Centres As per the Electricity Act 2003, the Regional Load Despatch Centre monitor grid operations, exercise supervision and control over the inter-state transmission system, are responsible for optimum scheduling and despatch of electricity within the region, in accordance with the contracts entered intowith the licensees or the generating companies operating in the region and keep accounts of quantity of electricity transmitted through the regional grid. RLDC is responsible for carrying out real time operations of grid control and despatch of electricity within the region through secure and economic operation of the regional grid in accordance with the Grid Standards and Grid Code. The functions of SLDC elaborated in EA 2003 are similar to that of the RLDC except the area ofjurisdiction, which in case of SLDC is the state. Grid management functions Functions of grid management can be segregated into ex-ante, real-time and post-facto functions. The ex-ante functions are more in the nature of planning for the day of operation. It involves estimating the future scenarios, evaluating options and making elaborate plans to meet the anticipated as well as unforeseen events. Fig-4: Typical frequency variation in a day The real time functions primarily comprise of balancing the dynamically varying supply and demand of electrical energy in theinterconnected system. Fig-5: Bus voltage variations in a day Page 2 of 7
--------------------------------------------------------------------------------
Page 3
Vital grid parameters such as frequency, nodevoltages,transmission line loading, transformer loading, electrical (angular) separation between generation pocket and load centre etc. are monitored round the clock and suitable instructions are passed on to the SLDCs or generating stations in case the values of the above parameters are seen to be outside the permissible bands. The operating band has been specified in the Indian Electricity Grid Code (IEGC), approved by Central Electricity Regulatory Commission (CERC). Fig-7: Data acquisition systemUnder the system the vital system variablesare measured by transducers installed at all theimportant locations. The recorded data is transmitted through communication channels and ultimately displayed in the operator consoles in the load despatch centres.Fig-6: Line power flows All this requires extensive coordination with the operating personnel positioned at switching stations, generator control roomsand other load dispatch centres. Critical decisions have to be taken at the spur of the moment. Post facto functions involve grid performance reporting, post mortem of events, settlement of accounts, documentation of experience and interaction with stakeholders. Fig-8: Typical real-time display The grid operator supervises the power system through this system. It acts like the sensory organs of the grid operators and helps them to diagnose the states of system and also take corrective measures. It also ensures transparency in grid operation and facilitates amicable resolution of day-to-day problems associated with this complex task of grid operation. The real time data is archived continuously and is later retrieved for analysis of events occurring in the grid. Operating aids for grid management In order to enhance the power system visibilityand improve the quality of supervision in real time power grid operation in the country, the grid control rooms at the regional and state level have been equipped with a state-of-the-art communication and data acquisition system. Various states of grid operation The interconnected network under currenttechnology creates strong interactions across locations. Behaviour of various power system elements synchronised with the grid influence the system parameters giving rise to a dynamically varying system states. These Page 3 of 7
--------------------------------------------------------------------------------
Page 4
states are normal, alert, emergency, extreme and restorative. The operator actions are perpetually guided by the objective of maintaining the system directed in normal state for most of the time. Nevertheless the system may slip from a normal to alert, emergency or extreme state inless than a second due to a small or large perturbation in the system. Contingencies disturb the grid parameters and call for immediate operator intervention. Normally it takes a few minutes to restore the system back to normal state but during major disturbances it may take several hours or several days to restore normalcy. It is therefore essential that all precautions be taken to prevent the system from degenerating to an extreme state. Thisrequires suitable and timely interventions inthe power system in short term as well as inmedium and long-term. Regional Electricity market The regional electricity market in India that operates over the Inter State Transmission System (ISTS), is governed by the frequency linked operation and commercial settlementmechanism known as the Availability Based Tariff (ABT) and Unscheduled Interchange (UI) mechanism. The ABT mechanism has replaced the command and control systememployed earlier with a contractual approach. The utilities have full freedom and choice to enter into long-term and short-term bilateral contracts. These contracts are incorporated in the daily interchange schedules issued by the RLDCs. Fig-9: Day-ahead resource scheduling process The interchange schedules whether despatch, drawal or inter-regional are treated ascommitment to deliver or withdraw a certain quantum of power at a designated time from the grid. The utilities also have the option of reviewing and revising the scheduled interchanges in real time to suit the demand/supply position in real time. Therevised schedules get implemented within sixtime blocks after registering the request with the RLDCs. Fig-10: UI price vector Further, the generating station operators and state grid operators have been empowered to respond to the real time pricing signals generated from the frequency dependent UI price vector.Electricity trading Open Access (OA) in ISTS has been implemented in all the regions since 6thMay 2004 in line with the open access regulations issued by CERC. The regulations aim atpromoting non-discriminatory usage of the transmission system by customers after payment of appropriate charges. Access can be granted under two categories: long -term and short-term. Long-term access is granted for usage of 25 years or more while the short-term access is for a maximum for three months at a stretch. As per the existing regulations the long-term users pay higher charges and have a higher priority over short-term users. The grid operator declares the anticipated power transfer capability availablein thetransmission system during the forthcoming three months. Within the short-term category reservations on the transmission corridor may be made under any of the categories: advance, first-come-first-served, day-ahead and sameday. Page 4 of 7
--------------------------------------------------------------------------------
Page 5
Fig-11: Short-term Open Access Open access in transmission effectively introduces competition in wholesale electricity market. Although, the overall inter state trade volume is currently only 3.0 % to 5 % of the country’s total energy consumption, it has had a multiplier effect on the entire power sectorby promoting competition, efficiency andeconomy. The RLDCs and SLDCs are playing a key role in facilitating and scheduling these transactions without compromising on the security and reliability of the grid. The regional transmission system and theinterregional links are being utilized to transport surplus hydro generation in northeastern region and pithead generation in the eastern region to the energy deficit loadcentres in the northern, western and southern regions. The inter-regional exchanges have increased manifold after introduction of open access. Almost all utilities in the grid havetaken advantage of the open access provisionsand transactions have taken place in all possible directions in the country say from Northeast to North (e.g. Tripura to Haryana), North to South (e.g. Punjab to Andhra Pradesh), South to North (e.g. Kerala to Punjab), West to North (e.g. Gujarat to Uttar Pradesh), North to West (e.g. Punjab to Maharashtra) and East to all other corners of the country. The electricity trade in the country is expected to grow further after the commissioning of new generating stations and establishment of the proposed organized platform for trading in the form of Power Exchange (PX). The grid operator would continue to provide the interface between the physical system and the electricity market. Settlement system For purpose of scheduling and settlement theentire day in divided into 96 time blocks of 15 minute each. At the end of the day all before the fact revisions in schedules get incorporated as ‘Implemented Schedules’ and they serve as a datum for the payment of capacity charge,energy charge and generation incentive to the generating stations governed by the ABTregime. The actual energy interchanges for every 15-minute time block, are recorded with the help of Special Energy Meters (SEM) installed at all inter utility exchange points inthe region. These readings are used for working out the actual injection of Inter State Generating Stations (ISGS) and off-takes of each state utility from the grid. The actual values are then compared with the scheduledvalues to obtain the deviations from schedules. Real time deviations in a particular time block are priced at the corresponding Unscheduled Interchange rate (UI rate), and settled through a pool account being maintained by RLDC. The SEMs also record the reactive energyinterchanges at inter utility points. These aresettled as per the prevailing reactive energy prices. The regional reactive energy accounts are also managed by the RLDCs. Challenges in grid management Large interconnected grids are essential forreliability of power supply and for economic exploitation of spatially distributed energy resources and consumption centres in the country. The manifold growth in the network size has increased the complexity of grid management. Page 5 of 7
--------------------------------------------------------------------------------
Page 6
The physical nature of the power flows on transmission lines, rapidly changing demand patterns, dramatic changes in the system parameters, unexpected events in the grid andcalamities (natural or man made) make grid management extremely challenging. This requires tremendous presence of mind and multidimensional skills. A system operator hasto quickly switch roles as a planner, a strategist, an administrator, a consultant, an economist and a soldier, which makes his job highly demanding. The unbundling process in the power sector also has contributed significantly to the growing complexity in grid management. Competition has heightened the market pressure, forcing system to be operated closer to its physical limits. The number of utilitiesespecially in the state level has also increased leading to increased difficulty in coordination during offline as well as in real time. The conflict of interests, unclear responsibilities,inconsistency of objectives, inadequacy of resources and legacy issues among these utilities often impair the collectiveperformance of grid management. All the above coupled with rapidly diminishing species of “power system engineers” and the general lack of appreciation of this vital function is making grid management a tough job. Contribution of Grid Operators Operating conditions require close monitoring and control on very short time duration. Advanced technologies are indispensable for successful operation of the grid during the various operating states but the contribution ofthe engineers at the operating desk is equally noteworthy. Very few people outside the grid control centres are aware of the sweat and toil that goes behind keeping the grid secure and healthy. In fact the grid operator carries the credibility of the entire electricity supply industry in the country on his shoulders. Against the few occurrences of large griddisturbances such as the one that occurred in Northern Region on 2nd Jan 2001, there are innumerable cases when the alertness and alacrity of the grid operators have been vital in rescuing the grid from ‘near death’ situations. The operators have successfully tackled the most unusual scenarios in real time grid operation occurring at the most unexpected and demanding hours of the day. It is unfortunate that the heroes of such “near miss” situations go unsung and unnoticed.Neutrality of grid operator Generation and transmission at the inter state level has already been unbundled in 1991 after the formation of POWERGRID. Unbundling of generation, transmission and distribution in states has been achieved to a large extent. As per the EA 2003 the STUs are also expected to disengage themselves from the tradingfunction shortly. Both the RLDCs and SLDCshave been prohibited from engaging in the business of trading in electricity. Further the RLDC have been barred from engaging in generation of electricity. The Central Electricity Regulatory Commission and State regulatory Commissions regulate the fees and charges of RLDCs and SLDCs respectively. The RLDC charges are shared by the constituent states ofthat region in ratio of their weighted average allocations in the Central Sector power stations. The fees and charges are independent of the volume of power flow on the network, which ensures the neutrality in grid management. The grid management/operation is so designed that grid operator merely provides a secure and reliable platform for energy exchanges between various players in the grid without becoming a party to those transactions.Conclusions Modern economies are dependent on reliable and secure electricity services. Electricity makes an essential contribution to economicperformance, international competitiveness and community prosperity. The society’s dependence on electricity shall intensify as the world moves ahead in the twenty-first century. The pressure to operate system in ‘higher risk mode’ is bound to increase with increasing network complexity, growing electricity markets and increasing intensity of surprises Page 6 of 7
--------------------------------------------------------------------------------
Page 7
from Mother Nature. All these challenges have to be dealt with collectively and with sincerity of purpose. Grid management therefore deserves the recognition and attention of all the stakeholders. They must all come together to nurture this institution for the benefit of our own present and for posterity. The investmentrequired for this might appear to be a high in absolute monetary terms especially when it has to be shared by the direct beneficiaries or the state utilities. But it would be peanuts when compared with the opportunity cost of unserved electrical energy due to a blackout that could have been averted by the intervention of the system operators. Acknowledgement The author acknowledges the encouragementby POWERGRID management. The author is also thankful to Sh. S.R. Narasimhan, Chief Manager (NRLDC), Sh. S.K. Soonee, Executive Director (System Operation),POWERGRID and all colleagues for their guidance and untiring support. Disclaimer The views expressed in the article are the personal views of the author. References 1. Electricity Act 2003 2. Indian Electricity Grid Code, April 2006 3. www.nrldc.in4. www.cercind.gov.inPage 7 of 7
more
Press Release IEGC Order
India began to develop an inter-state transmission system (ISTS) to enable electricity ... of the changed legal provisions subsequent to the ERC Act 1998, ...www.cercind.gov.in/pressiegc.htm - 13k - Cached - Similar pages - Note this
IEGC Review Petition
IEGC Order. In April 1999, Power Grid Corporation of India Ltd. (PGCIL), .... the provisions of Electricity (Supply) Act,1948 and notifications/guidelines ...www.cercind.gov.in/iegcorder.htm - 19k - Cached - Similar pages - Note thisMore results from www.cercind.gov.in »
[PDF]
SOUTHERN REGIONAL POWER COMMITTEE
File Format: PDF/Adobe Acrobat - View as HTMLHe said that Government of India vide Resolution. dated 25 ... As per the Indian Electricity Act, 2003 and the revised IEGC, the SLDCs are ...www.srpc.kar.nic.in/meetings/cc/1CCMINUTES.pdf - Similar pages - Note this
[PDF]
India’s Electricity Act, 2003 Implications for Regional ...
File Format: PDF/Adobe Acrobat - View as HTMLIEGC. Indian Electricity Grid Code. IE-1910. Indian Electricity Act, 1910 ..... With the enactment of the Electricity Act, 2003 in June 2003, India ...www.sari-energy.org/ProjectReports/IndiaElectricityAct2003_ExecSum.pdf - Similar pages - Note this
In the matter of (i) Grid Code & (ii) Load Despatch & System ...
(b) Addition at the end “accordingly economic power system operation in terms of section 55 (3) of E(S) Act and IEGC shall be considered separately for ...www.rerc.gov.in/OrderonGridCode.htm - 67k - Cached - Similar pages - Note this
Status of Power Exchange in India: Trading, Scheduling, and Real ...
operation in India with regulatory mechanism in place. Open. access to transmission is encouraging ... Act 2003. Indian Electricity Grid Code (IEGC) and the ...ieeexplore.ieee.org/iel5/9893/32012/01489120.pdf?arnumber=1489120 - Similar pages - Note thisby S Mukhopadhyay - 2005 - Cited by 1 - Related articles
[PDF]
To provide for the constitution of Electricity Regulatory ...
File Format: PDF/Adobe Acrobat - View as HTMLIndia in allocation of power exclusively from the Badarpur TPS. The MES made a .... dispatch as specified in the Act, IEGC, Regulations of CERC, CEA, ...www.derc.gov.in/ordersPetitions/orders/Misc/2007/Reassignment%20of%20PPA.pdf - Similar pages - Note this
[DOC]
The Gazette of India
File Format: Microsoft Word - View as HTMLPromotion of competition in the electricity industry in India is one of the key objectives of the Electricity Act, 2003 (the Act). ...powermin.nic.in/acts_notification/electricity_act2003/pdf/CBG%20notified%2027.9.07-clean.doc - Similar pages - Note this
Statutory and Regulatory Requirements for India: The Indian ...
The Indian Electricity Rules, 2005: The Government of India issued these Rules on 8th June, 2005. Download. The A.P. Electricity Reform Act, ...statutory.blogspot.com/2007/03/indian-electricity-rules.html - 80k - Cached - Similar pages - Note this
Overview of Power Sector in India (For Foreign Customers) - Market ...
Annexure 19- IEGC- grid code- dec1999 (pdf format) Annexure 20- ABT Order- jan2000 ... Annexure 32- Notifications under Electricity Act 2003 (pdf format) ...www.bharatbook.com/bookdetail.asp?bookid=7776&publisher= - 78k - Cached - Similar pages - Note this
Next
ORDER
1- Section 9 (h) of Rajasthan Power Sector Reforms Act 1999 (Reforms Act) provides for the Commission to regulate operation of power system within the State. The Section 55 of the Electricity (Supply) Act 1948 (Supply Act) entrusts the integrated grid operation in the State to the State Load Despatch Centre (SLDC) to be notified under section 2 (9c) of Supply Act, and also, interalia, provides for its operations by State Transmission Utility (STU) till otherwise specified by State Government and compliance of its direction by every licensee, transmission licensee, generating company, generating station or substations etc. in the State. State Government has notified load despatch centre at 400 KV GSS Heerapura (Jaipur) as SLDC vide notification No.F12(21)/Energy/92 dated 22.1.2000. Rajasthan Rajya Vidhyut Prasaran Nigam (RVPN) has been notified as STU vide Government of Rajasthan’s notification No.F.15(2)/Energy/2000 dated 19.7.2000 under section 27 B (1) of the Indian Electricity Act, 1910. RVPN, as per section 13 (2) of Reforms Act and also as STU is, interalia, to undertake all planning and coordination relating to intrastate transmission and to exercise supervision and control over intrastate transmission system. For regulation of functions of RVPN as transmission licensee, STU and grid operator Sr. No.12 of the license for transmission and bulk supply of electricity issued to RVPN by RERC vide No.RERC/Transmission & Bulk Supply Licensee 4/2001 on 30-4-2001 provided for RVPN to submit draft Grid Code (including Conditions of Supply) within a period of 3 months of issue of licensee.
2- RVPN had submitted the draft grid code on 10-1-01 (before the grant of licensee). The Commission’s comments were conveyed to RVPN vide Commission’s letter of dated 27-7-2001. Copy of draft grid code and comments thereon were also sent to CMD, Rajasthan Rajya Vidyut Utpadan Nigam (RVUN) & Jaipur, Jodhpur & Ajmer Vidyut Vitaran Nigams (VVNs) for conveying their comments. Thereafter, Commission granted extension of time to submit said Code duly modified upto 31.1.02 with draft to be supplied by 31.12.2001. RVPN submitted the same on 28-12-2001. Comments on which were given by the Commission on 14.3.2002 and final Grid Code version 2.1 was received on 29.6.2002. In the meantime, RVPN also submitted vide letter dated 27-11-01 draft load despatch manual on which Commission has sent its observations on 2.3.02. They furnished final load despatch manual vide letter dated 1.6.02. The combined comments on (i) ‘Grid Code’ version 2.1 and (ii) Load Despatch & System Operation Code (LD & SO Code) was sent by the Commission on 24.7.2002. Commission has also directed vide letter dated 24.7.02 to send copy of finalized codes to RVUN, three VVNs, Incharge SLDC, Northern Regional Electricity Board (NREB), Power Grid Corporation of India Limited (PGCIL), Northern Regional Load Despatch Centre (NRLDC) and principals of 4 leading engineering colleges in Rajasthan for their comments/suggestions. Commission also directed that SLDC should function independently and should be responsible to RVPN’s Board or one of its directors. Finalized draft of Grid Code version 2.2 & Load Despatch & System Operation Code version 1.1 was received from RVPN on 30.8.02. Thereafter RVPN was directed on 7.9.02 to publish notification in two leading Hindi newspapers of the State and one national level English newspaper inviting objections/suggestions.
3- RVPN issued notifications in Dainik Bhaskar (Hindi) on 12.9.02, Rajasthan Patrika (Hindi) on 12.9.02, Hindustan Times (English) on 13.9.02 and supplied the copy of finalized Grid Code to aforesaid utilities/organizations/ officers vide letter dated 30.8.02. Objections from the following five parties were received on Grid Code and load despatch and system operation code.
(i) Ajmer Zila Laghu Udyog Sangh, Ajmer (AZLUS)
(ii) Chairman & Managing Director, Ajmer Vidhyut Vitaran Nigam Limited (AVVNL).
(iii) Superintending Engineer (Comml.), Jaipur Vidhyut Vitaran Nigam Limited (JVVNL).
(iv) M/s C.S.D. Instruments (India) Private Limited, Jaipur (CSD).
(v) M/s PGCIL & NRLDC
4- RVPN had sent replies to the objectors vide letters dated 18.11.2002, 4.12.2002 and 9.12.2002. A bench consisting of Mr. Shanti Prasad and Mr. Prabhakar K. Das was constituted for hearing the objections and finalizing the Grid Code. The date of hearing was fixed on 17.12.2002 & hearing held on that day. However, before passing the order, Mr. Prabhakar K. Das, Member RERC expired and Commission decided to rehear the objections/replies on 11.3.03. Shri V. D. Singh (CSD), Shri S.K. Kalla (RVUN) and Shri B.L. Jain (SLDC) presented their point of view. Shri G.L. Modi (AVVNL) and Shri R.P. Goyal (Jaipur VVNL), offered no comments in view of their point of view covered in the presentation made by Shri K.L. Vyas, Director (RVPN). None was present on behalf of other objectors.
5- In passing this order, the Commission has considered the objections/suggestion/comments and presentation made by Director, RVPN and others during the hearing and replies of RVPN. Before discussing the objections etc., it is stated that Grid Code will consists of four parts viz. (i) General & Planning, (ii) Load Despatch & System Operation Code, (iii) Metering Code, and (iv) Grant of Transmission License to other operators through RVPN (as STU). Code under consideration covers part (i) & (ii) Metering Code has been already approved by the Commission vide its order dated 28.10.02 Part (iv) will be formulated separately by RVPN and will be approved later by the Commission.
6- M/s AZLUS has expressed that (a) Charter of Consumer Rights (b) Standard of Performance (c) Metering Code (d) Safety Code may have bearing on subject documents and therefore, the approval of the Grid Code and Load Despatch & System Operation Code may be kept in abeyance till approvals to all others relevant documents are accorded. These documents have no relevance with codes under consideration. Commission has already accorded approval to Metering Code of RVPN vide order dated 28.10.02 and order for Performance Standards of RVPN and Charter of Consumers’ Right is being issued. Safety Code is being notified for public objections. As such withholding of approval on this account is not called for.
Underfrequency Load Shedding
7- M/s AZLUS has referred to clause 8.5 of the Grid Code regarding automatic load shedding and rotational load shedding through installation of underfrequency relays and have suggested that in order to ensure that there is equitable treatment in load shedding there must be transparent guidelines to protect the interest of consumers and such guidelines must be approved by RERC and published for public information. RVPN has replied that it shall not unduly discriminate against or give preference to any one or group of persons and has elaborated the mechanism of scheduling and to effect load shedding in rotational manner by SLDC manually or through automatic load shedding underfrequency relays to contain the load within that scheduled. During hearing on 11.3.03, Director, RVPN suggested for deletion of this scheme from Grid Code and incorporating it in LD & SO Code.
8- Commission find that clause 8.5 of Grid Code and clause 3.4 and 7.4 of Load Despatch & System Operation Code are relevant to underfrequency load shedding. However, they do not address to issue of equitable treatment raised by AZLUS. Commission is of the view that Technical Committee and State Power Committee vide clause 3.7 & 3.4 of Grid Code, need prepare/approve the guidelines about load shedding However while implementing the same, the feeders to be covered under such scheme may be decided accordingly by SLDC, SubLDC, VVN’s control room or Incharge substation. There can be no objection to make such scheme available to consumer. Commission agree with AZLUS and direct that code may provide for preparation of guidelines for underfrequency load shedding by technical Committee to be approved by State Power Committee and copy of the same is to be made available to any person on payment of prescribed charges. The particulars of feeders or groups of feeders at a substation which shall be tripped under underfrequency load shedding scheme whether manually or automatic on rotational basis or otherwise shall be placed on notice board and will also be available at the GSS for the information of the consumer(s). Clause 3.5, 3.7.2 & 8.5 of Grid Code and 7.4 of LD & SO Code will be amended accordingly.
9- CMD, AVVNL has commented on clause 3.4.1 of LD &SO Code stating that in the event of underfrequency conditions, underfrequency relays may be operated in rotational manner to avoid tripping of one particular feeder at the same hour every day and have desired that rotational load shedding be introduced for all the feeders covered by underfrequency load shedding programme. RVPN has replied that underfrequency relay load shedding (UF) and rotational load shedding scheme, (RLSS) are two different schemes. Former (UF) is a system salvage scheme to prevent system collapse/grid failure when frequency is sinking beyond safe limit while latter (RLSS) aims at achieving load relief when frequency is in lower band. Commission views that AVVNL has made a valid point of concern so far as frequent tripping of same feeder is concerned. Commission is of the view that both underfrequency (UF) load shedding and underfrequency cum rate of change of frequency (UF+DF/dt) load shedding are the underfrequency load shedding schemes. Latter (& not UF) is the system salvage scheme. Only former UF can incorporate additional feature of effecting load shedding on rotational basis so that same feeder/group of feeders do not trip every time or on same time each day on the occurrence of underfrequency conditions. However providing of rotational underfrequency load shedding on all feeders have cost implications. The same objective can be achieved by other cost effective mechanism. For example, preparing the schedule of feeders to be tripped in rotation and effecting load shedding on rotational basis manually or by wiring trip circuits of various feeders (to be tripped on rotational manner) through the auxiliary contact(s) of underfrequency relay through multi-way switch, which is rotated daily or at any other schedule or on occurrence of each tripping etc.. There can be other innovative methods/mechanism to achieve same objective. These need be deliberated by technical committee /Protection Coordination Committee to be constituted under the Code and type of scheme to be adopted for underfrequency load shedding at a substation need be decided by that committee to ensure that frequent tripping of same feeder is avoided.
Transmission Losses
10- M/s AZLUS expressed that transmission losses of 8.5% claimed by RVPN is high and that meters for the purpose of billing by RVPN must be installed at GSS of every city. These are not relevant to the codes under consideration. Transmission loss will be subject to review while considering annual revenue requirement and/or tariff petition of RVPN. Meters to be provide for billing of electricity supplied to each discom has already been installed at each EHV GSS (whether supplying to a city or otherwise).
Protection of Lines
11- Superintending Engineer (Comml.), Jaipur VVNL has expressed that protection with high set element on all 33 KV & 11 KV lines at connection points at EHV substation as per clause 15.8 shall be provided for the first time and since downstream distribution system of 33 KV and lower voltage of the VVN is not provided with the protection scheme, it may lead to increase in number of interruptions unless the limit of high set element is kept enough to ignore the LV side faults. RVPN has replied that the proposed protection is proposed to coordinate with high set unit provided on 132 KV side of transformer for severe faults near to the bus bars of the GSS. This is to protect the costly equipment and bus connectors from damages/stress and that the apprehension of increase in the number of interruptions is unfounded since discrimination (among protection scheme) to trip on fault will be provided.
12- Commission agree with RVPN. The protection of 132 KV equipment, which are costly and whose interruption can effect large area/large number of consumers, has to be given priority over interruptions of downstream system. The setting of high set element, so as to provide discrimination among protection scheme not to cause tripping of 132 KV transformer yet reduce number of interruptions of all 33 and lower voltage feeders from EHV GSS, can be deliberated in protection coordination committee (vide clause 3.7.2) in which discom’s representative is a member. Accordingly the following function shall be added in clause 3.7.2.
“5- to deliberate and decide various protection settings”.
13- Protection on 33 KV & 11 KV transformers and lines (or their sectionalizing points) of HV system of Jaipur, Jodhpur & Ajmer VVNs need also be coordinated with the settings of protection to be provided as per clause 15.8. Discom may also give phased program of providing protection on their HV & LV system within 3 months.
Protection of Transformer
14- AVVNL has expressed that protection scheme vide Grid Code (Clause 15.9.2) has not been provided on power transformers (of capacity from 1.6 MVA to 10 MVA). Therefore, the above protection scheme shall be introduced in a phased manner. RVPN has agreed with AVVNL and proposed to delete this clause. Commission find that this clause is based on rule 64A (2) of Indian Electricity Rules 1956 (I.E. Rules), which provides for gas pressure type protection to give alarm & tripping on all transformers of rating 1000 KVA & above etc. As such deletion of this clause cannot be agreed. However for existing transformer, not provided with such protection, requisite relays cannot be provided immediately and relaxation to this provision is required. Commission, therefore, decide that following may be added at the end :-
“Provided that for the existing transformers, where protections as above are not existing, above protection shall be deliberated in protection coordination committee and provided in phased manner within 3 years.”
15- Ajmer as well as Jodhpur & Jaipur VVNs shall identify all transformers of 1.0 MVA & above which are without protection as per IE Rules [including requisite switchgear & battery (if required)] and shall submit scheme for such phased implementation to the protection coordination committee and the Commission alongwith financial implications etc. within 3 months of this order.
16- Last sentence of clause 15.9.2 appears relevant to clause 15.10 and may be shifted there.
Features of Disturbance Recorders etc.
17- M/s CSD has given their comments through letters dated 19-10-02, 23-10-02 and 5.11.02. CSD has expressed that to fulfill the principle objectives of grid code like system stability and security, it is mandatory (vide clause 6.16) to provide disturbance recorder (DRs) with event loggers (ELs) and to have correct time tagging using global positioning satellite (GPS) for faithful recording of dynamic performance of the system at all 400 KV/220 KV substations. They suggested for including substations of above 400 KV voltage, all the generating stations of capacity 200 MW and above and also classifying major 220 KV substations as that with transformer capacity above 200 MVA. They have expressed that DRs may have features like trigger slow scan (TSS) and continuous slow scan (CSS) and also fault location recording [as sought vide clause 15.3(c)]. They expressed that DRs. also monitors and stores all records of voltage and current (as required vide clause 10.5). They have proposed inclusion of new clause 15.11. A/B/C of some features like buffer of events, time synchronization through IRIG-B (International Range Instrument Group-B specification) of 1 millisecond accuracy, resolution time, galvanic separation, testing of event logger, softwares for fault locator, TSS & CSS for monitoring frequency changes, MW & MVAr level triggering, size of DRAM, prefault and postfault time, 16 bit analogue resolution, accuracy of GPS clock etc..
18- With reference to clause 15.7.1, M/s CSD have also advocated for use of numerical relays on the ground of their reliability, fast action and advanced technology and the feasibility of calibration and testing of system/relay units (vide clause 15.12) achievable by feeding the out put of DRs and actual records of faults to numerical relays. They have suggested for addition of additional features/functions of numerical relays at clause 15.7.1.2, 15.9.1.1 & 15.10.1 respectively for transmission line, transformer and bus bar protection. During hearing Shri V.D. Singh expressed that DRs, besides monitoring the system, can also monitor system voltage without extra cost. DRs output can be played back and fed to numerical relays to test its performance. They do not object to Code but bring out that DRs and numerical relays have features, which too need be considered in the minimum specification requirement of the Code.
19. Replying to CSD’s comments, RVPN has expressed that detailed specification is not the part of the Code and the protection committee vide clause 3.7.2, to be renamed as “Protection Coordination Committee”, can look into finer details while drafting specification based on provision of the Grid Code. Director, RVPN expressed during hearing that RVPN do not agree with CSD to define the generating stations etc. where DRs are to be provided.
20- While Commission agree with RVPN’s contention of detailed specification are not to be part of grid code but it appreciate some of the suggestions of M/s CSD. Commission directs for following changes in the Code:-
(i) Defining of stations where DRs will be provided as “All generating stations of capacity 200 MW and higher, substations with operating voltage 400 KV & above, and major 220 KV substation to be that with 220 KV/132 KV transformation capacity exceeding 250 MVA”. Clause 6.16 will accordingly provide for the same.
(ii) Addition of function of “Preparation and finalisation of technical requirement of various protections in line with the Code” as that of protection coordination committee at clause 3.7.2.
(iii) Clause 15.4 shall refer to the protection coordination committee vide clause 3.7.2.
(iv) The protection coordination committee may consider features as brought out by CSD while finalising the specification.
(v) The following will be added at the end of clause 15.2 to cover all types of relays meeting technical minimum requirement.
“Any type of relay satisfying the requirement, e.g. numerical relay, shall be acceptable even if the requirement listed hereunder might reflect a specific type of relay”.
(vi) Accuracy of clock for DR&EL has to be much better than that of meters. Feature of time stamping of events upto the accuracy of 1 millisecond, independent of scan rate and accuracy of DR’s clock, and its time synchronization using GPS so as to achieve above accuracy of time stamping will be specified at clause 6.16.
21- PGCIL and NRLDC have given common objections/comments, which indicate amendments in the form of addition/substitution/deletions. Most of these have been agreed by RVPN. Only the comments of PGCIL or RVPN not agreed by the Commission or requiring specific mention are discussed below:-
(A) Grid Code :-
(i) Changes proposed in clause 4.3.2 is as per section 27A(2)(b) & 27 B(2)(b) of IE Act:- National Power Plan formulated by Central Government will be guiding principle for CERC and SERC under section 28 (c) & 29(2)(g) of ERC Act (in case of Rajasthan Section 26 (2)(g) of Reforms Act). This plan may be based on national power policy and short term and long term perspective plan for power development developed by CEA vide Sec.3 (i) of supply Act and unless National Power Plan specifies otherwise, such perspective plan of CEA must be guiding principle otherwise legislative intent of developing such plan for control and utilization of National Power Resources will be defeated. In order to reflect this, additions as suggested by PGCIL will be added with ‘RLDC’ substituted by ‘NRLDC, through SLDC,’ and in addition words “national power plan formulated by central government,” will be added before “long term plan”.
(ii) Clause 6.6 will be redrafted as per IEGC clause 6.2(e) as connectivity criterion of IEGC is binding on RVPN’s system. The exemption from free governor mode operation in respect of run of river hydro stations without any pondage, steam turbine of thermal and gas based power stations not having free governor mode facility need be sought from CERC under clause 1.6 of IEGC. Such petition may be preceded by study preferably by CEA.
(iii) Clause 6.8 shall be redrafted as per IEGC clause 6.2 (g) with changes as suggested for clause 6.6. Exemption, where required, shall be sought under clause 1.6 of IEGC.
(iv) In clause 10.3, proposed amendment will be inserted after first sentence as follows. “RVPN & SLDC as constituents of northern region shall make all possible efforts to ensure that grid frequency remain within 49.0-50.5 HZ band”.
(v) No change will be made in clause 15.5 & 15.10 as it is applicable for ‘Users’ only.
(vi) Appendix-B :- Gas power stations planning data will be added by RVPN.
(vii) Title of appendix C-1 may refer to clause 7.3 of Grid Code. Thereafter columns listing “SLDC” can be omitted and new column titled “to be submitted by the agency “as per comments will not be required.
(viii) Appendix-F. Sr. No. (iii) role of SLDC and Sr. No.(v) role of RLDC. The provision, as per section 55 (8) of the Electricity Supply Act 1948, has been interpreted in para 3.9 of CERC’s order dated 31.10.99 on petition 01/99 and as such amendment as proposed may be incorporated.
(B) Load Despatch & System Operation Code
(i) Instead of substitution as proposed by PGCIL, words “NRLDC is engaged in the activities of integrated operation of the power system in the Northern Region” will be added before first sentence in clause 1.2.1.
(ii) Clause 1.2.1 (iii), 2.1.1 and note 2 below clause 2.1 :-RVPN/SLDC may check whether load despatch of other power stations in Northern Region in which a state has 100% share, is being carried out by that state’s LDC. If so amendment may be effected and load dispatching of RAPSA may be commenced by SLDC.
(iii) Clause 1.2.1 (iv) :- Every licensee, transmission licensee and others involved in power system operation has to comply with the decision of NREB. How decision of NREB arrived at whether unanimous or by majority, is not relevant. Commission observes that how the decision is arrived is defined in Supply Act and classified by CERC at para 38 of its order dated 30-10-99 on petition No.1/99 i.e. it will be a unanimous decision. NRLDC’s responsibilities may be mentioned as Sr. No.(v) and these may be as per clause 2.2.2 of IEGC.
(iv) Clause 2.3.6 :- It is learnt that ULDC Scheme’s RTU have provisions of remote control of circuit breaker. This may be checked by RVPN/SLDC. The second sentence will be retained/amended accordingly.
(v) Clause 3.4 may be shifted to chapter 7 and aspect of manual load shedding not to be carried out on feeders where load shedding by underfrequency relays is operative, may be mentioned in this clause.
(vi) In line with clause 1.6 (i) of IEGC, generating units of 125 MW and above will be replaced by “Thermal generating unit of 200 MW and above & reservoir based hydro units of 50 MW and above” in clause 7.9.
(vii) Clause 7.10 and title will be deleted, making proposed clause 7.10 as second para of clause 7.9 other clauses will be renumbered accordingly.
(viii) PGCIL has proposed addition of words “under ideal conditions, the generating units should operate close to unity power factor so that MVAr capability act as a fast reactive reserve available to the system under contingencies. The ideal conditions are difficult to achieve under extreme shortage/extremely low demand conditions ….” at the beginning of clause 7.14. RVPN has agreed for this amendment. Commission is of the view that PGCIL’s transmission system is mainly of 400 KV, which have high charging MVAr which is compensated by shunt reactors. As such on 400 KV system, drawl of power at a power factor not close to unity causes considerable voltage drops and consequently power factor on EHV line and in turn of generating unit is to be maintained close to unity. The state sector generating stations are mainly on 220 KV and lower voltage system, where transfer of power at comparably lower power factor is feasible. As such suggested addition is not to be incorporated.
(ix) With reference to PGCIL’s observation on clause 9.5, it is reiterated that Commission’s directions of 50% generation within the State (irrespective of whether from state sector or central sector or captive or NES or IPP power stations) is from the consideration that Rajasthan being at tail end must have minimum generation within the State to maintain voltage profile, to cater to essential load in the contingency of system islanding consequent to outage of main transmission/major generating units and to have lesser transmission losses. This will also enable renewable energy sources power plants (e.g. wind, solar, minihydro etc.) to remain operational irrespective of either loss of generation or their sale rate. The power system operations cannot solely be on maximum economy in generation cost and need consider system parameters and reliability (to meet contingency of outage) and incremental transmission losses and practically no loss of generation from non-conventional/renewal energy sources etc.. Proportion of generation within or outside state may however vary from time to time as per Commission’s directive. Accordingly, the following changes will be made :-
(a) Substitution of words “generating capacity of” by “specified generation capacity presently” at clause 9.5.1.
(b) Addition at the end “accordingly economic power system operation in terms of section 55 (3) of E(S) Act and IEGC shall be considered separately for within the State Power Stations and outside the State Power Stations/sources with due consideration to voltage profile, contingency to meet outage/islanded operation, stable operation of generating unit(s) and no loss of generation at renewable energy sources power plants”.
(x) Clause 9.9 to 9.11 – LD & SO Code is code as well as reference manual for system operator. As such amendment proposed by PGCIL may be inserted at the beginning of clause 9.9 with the addition that “prevalent methodology is mentioned hereunder and at clause 9.10 and 9.11”.
(xi) Clause 13.5.2 is mentioning the provision of section 6.5.2 of IEGC for the reference of LD operator and may be retained.
Free Governor Mode Operation of Thermal Units
22- Shri S.K. Kalla, Dy. Chief Engineer, RVUN expressed reservation on free governor mode operation of thermal units and requested for exemption. Commission cannot agree to RVUN’s request. For the secure and reliable integrated operation of regional grid, any licensee/utility (here RVPN) having interconnection with central transmission utility (i.e. PGCIL) has to satisfy CTU’s connectivity criteria. Similarly any licensee/utility having interconnection with State transmission utility (RVPN) has to satisfy the connectivity criteria which RVPN have to satisfy for its interconnection with CTU and additional criterion which RVPN may specify. As free Governor mode operation of thermal units with 200 MW and above capacity is one of the connectivity criteria of power grid (incorporated at clause 1.6 of IEGC and other clauses referred therein) so RVPN has to satisfy it and in turn, this criterion is to be satisfied by the RVUN having interconnection with RVPN. This Commission cannot relax this criterion and exempt RVUN from the same. RVUN, if required, may seek exemption from CERC under clause 1.6 of IEGC. Since IEGC have been finalized after hearing all concerned (including erstwhile RSEB) on the petition No.1/99 (vide para 5.3, 5.6, 5.13 & 5.14 of aforesaid order of CERC) and free governor mode is specified for overall grid control especially to prevent over frequency conditions and consequent damages to generating units. It will be desirable to comply with the provision except where RVUN have technical and practical difficulties in free governor mode, If, so study should be carried out by an expert body viz. Central Electricity Authority (CEA) and based on the recommendations of study, RVUN may provide for requisite equipments etc. and/or seek exemption from CERC for the period it may be necessary as per such study.
Backing down of Thermal Units
23- Shri K.L. Vyas, Director, RVPN requested Commission to incorporate a provision that directions issued by the load despatch may be complied by RVUN. Shri B.L. Jain, SLDC also expressed that RVUN is not backing down the units to arrest overfrequency conditions. He expressed that one day notice, as desired by the RVUN is not possible.. Shri Kalla expressed that it is not possible to back down the thermal unit on overfrequency conditions (say at 50.5 HZ or above) as per the SLDC’s instructions, as once backed down unit cannot be immediately brought up again. He also desired the Commission to consider whether ABT can be applied/considered for State Sector Generating Station. Under ABT, extra energy at over frequency condition will be available to RVPN free of cost as per availability based tariff (ABT) and extra generation under underfrequency conditions will be available at high rates as per ABT. Replying to this, Director, RVPN expressed that state sector generating stations and Nuclear Power Plant are not covered by ABT. Due to power shortage conditions, normally prevailing, generation schedule of RVUN is accepted and no advance scheduling is made and only when overfrequency conditions occurs, RVUN is directed by LD to back down the unit as per ramp rate/chart supplied by RVUN and 1 ½ hour advance notice may be adequate.
24- Commission express that integrated grid operation in the State with maximum economy and efficiency in power system operation is the responsibility of SLDC as per section 55 (4) of the Supply Act. Overfrequency conditions is caused as a result of generation in excess of load demand and such extra generation is not at all economical and is the wastage of fuel. Operation of turbines at high frequency conditions is also liable to cause damage to their blades and manufacturers do not specify such operation beyond a short duration. Only feasible method to control overfrequency is to back down generation or shut down the units. SLDC is, therefore, right in instructing backing down. Its instruction need ensure that backing down is carried out at a rate not detrimental to generating unit (i.e. at a ramp rate specified by supplier/RVUN). All such instruction has to be complied irrespective of authority issuing it. Any reservation to comply instructions has to be brought to higher authority and instructions revised. Commission do not agree that within the specified ramp rate and upto minimum specified load for stable operation, it is not possible to back down the generating unit(s).
25- Though any non-compliance of grid code or system operation and load despatch code, attract section 2 & Sr. No.6 of part-II of schedule of RERC’s (Fine & Charges) Regulations 2002, Commission feel that better course is that power purchase agreements between RVUN & RVPN may provide for generation scheduling linked to frequency and incentives and disincentive for over generation at abnormal frequencies.
26- Commission has not specified ABT in State sector. All financial implication due to ABT of Northern region is to be absorbed by RVPN and as such RVPN has right to keep its financial risk to minimum by grid control. System load is dependant on various parameters including weather conditions, availability of generating unit and transmission system etc. and is not precisely estimatable one day in advance. IEGC specifies for alterations in schedule during the day. As overfrequency conditions is not beneficial to any and over generation is a waste of fuel, so Commission direct that for a frequency beyond normal frequency of 50.0 HZ (where UI rate of ABT tariff will be 140 p/KWh), generation beyond the frequency linked generation schedule or generation schedule less backing down in MW as advised by SLDC, whichever is applicable, should not be effected and RVPN may not consider such excess generation for payment purpose after a period of 6 intervals (of 15 minutes) from such advise.
General
27- During hearing, Director, RVPN expressed that Grid Code will be applied to new substations/lines etc. and for existing substations only its operational aspects will be followed. Commission is of the view that ‘Grid Code’ under consideration need also have provisions similar to clause 1.6 for the period by which existing interconnection shall meet the connectivity criteria at a later date. A clause will be added to the grid code specifying that connectivity criteria & other provisions of the code (e.g. rupturing capacity of breakers, fault clearance time, installation of DRs, ELs, protective relays etc.) shall apply to new interconnections and equipments procured/provided for new works/ replacements after the grid code is made effective. Existing interconnection and equipment shall continue to operate till alterations are considered necessary by the technical committee. However operational aspects of grid code shall have no such relaxation and apply with immediate effect. The Grid Code shall apply to users, RVPN & future transmission licensees. Relevant clauses shall be amended accordingly.
28- With the above directions, Grid Code and Load Despatch & System Operation Code are approved. Finalized Grid Code and Load Despatch & System Operation code will be issued respectively by RVPN within one month.
29- Copy of order will be supplied to all objectors, RVUN, Three VVNs and SLDC.
30- Signed on 22nd March, 2003.
more
Electricity Grid Management in India- An Overview
Published in 2007 Annual issue of “Electrical India”-Vol 47 No 11, November 2007
(Electrical India is India’s oldest magazine on power & electrical products industry. It is being published since 1961
by Vivek Pandey
Introduction
‘Transmission’ and ‘Grid Management’ are
essential functions for smooth evacuation of
power from generating stations to the
consumers. Transmission function primarily
consists of construction and maintenance of
the transmission infrastructure while the job of
the grid operator is to give operating
instructions to the engineers in the field and
ensure moment-to-moment power balance in
the interconnected power system. Grid
management involves taking care of the over
all reliability, security, economy and
efficiency of the power system.
Fig-1: Five Regional grids in India
Grid Management in India is carried out on a
regional basis. The country is geographically
divided in five regions namely, Northern,
Eastern, Western North Eastern and Southern.
All the states and union territories in India fall
in either of these regions. The first four out
these five regional grids are operating in a
synchronous mode, which implies that the
power across these regions can flow
seamlessly as per the relative load generation
balance.
The
Southern
Region
is
interconnected with the rest of India grid
through asynchronous links. This implies that
quantum and direction of power flow between
Southern Grid and rest of India grid can be
manually controlled.
Load Despatch Centres
Each of the five regions has a Regional Load
Despatch Centre (RLDC), which is the apex
body, as per the Electricity Act 2003 (EA
2003), to ensure integrated operation of the
power system in the concerned region. The
RLDCs for North, East, West, South and
Northeast regions are located at Delhi,
Kolkatta, Mumbai, Bangalore and Shillong
respectively.
Fig-2: Load Despatch Centres
The RLDCs coordinate amongst themselves
both offline as well as online for maintaining
the security and stability of the integrated pan-
India grid. In line with the federal structure of
governance in the country, every state has a
State Load Despatch Centre (SLDC), which is
the apex body to ensure integrated operation
of the power system in the state.
Page 1 of 7
Page 2
Fig-3: Regional Load Despatch Centres
The RLDCs in India are presently owned,
managed and operated by the Central
Transmission Utility (CTU), POWERGRID
while the SLDCs in the state are owned
operated and managed by the respective State
Transmission Utility (STU) or the State
Electricity Board (SEB) as the case may be.
The EA 2003 has a provision for a National
Load Despatch Centre (NLDC) for optimum
scheduling and despatch of electricity across
various regions and also coordinating cross
border energy exchanges in real time. Ministry
of Power has notified the functions of NLDC
that is under construction. Presently,
POWERGRID is operating a National Power
System Desk (NPSD) in New Delhi for
information exchange and facilitating inter-
regional transactions. The cross border
exchanges are coordinated by the RLDC of the
region
wherein
the
international
interconnection is situated.
Role of Load Despatch Centres
As per the Electricity Act 2003, the Regional
Load Despatch Centre monitor grid
operations, exercise supervision and control
over the inter-state transmission system, are
responsible for optimum scheduling and
despatch of electricity within the region, in
accordance with the contracts entered into
with the licensees or the generating companies
operating in the region and keep accounts of
quantity of electricity transmitted through the
regional grid. RLDC is responsible for
carrying out real time operations of grid
control and despatch of electricity within the
region through secure and economic operation
of the regional grid in accordance with the
Grid Standards and Grid Code. The functions
of SLDC elaborated in EA 2003 are similar to
that of the RLDC except the area of
jurisdiction, which in case of SLDC is the
state.
Grid management functions
Functions of grid management can be
segregated into ex-ante, real-time and post-
facto functions. The ex-ante functions are
more in the nature of planning for the day of
operation. It involves estimating the future
scenarios, evaluating options and making
elaborate plans to meet the anticipated as well
as unforeseen events.
Fig-4: Typical frequency variation in a day
The real time functions primarily comprise of
balancing the dynamically varying supply and
demand of electrical energy in the
interconnected system.
Fig-5: Bus voltage variations in a day
Page 2 of 7
Page 3
Vital grid parameters such as frequency, node
voltages,
transmission
line
loading,
transformer loading, electrical (angular)
separation between generation pocket and load
centre etc. are monitored round the clock and
suitable instructions are passed on to the
SLDCs or generating stations in case the
values of the above parameters are seen to be
outside the permissible bands. The operating
band has been specified in the Indian
Electricity Grid Code (IEGC), approved by
Central Electricity Regulatory Commission
(CERC).
Fig-7: Data acquisition system
Under the system the vital system variables
are measured by transducers installed at all the
important locations. The recorded data is
transmitted through communication channels
and ultimately displayed in the operator
consoles in the load despatch centres.
Fig-6: Line power flows
All this requires extensive coordination with
the operating personnel positioned at
switching stations, generator control rooms
and other load dispatch centres. Critical
decisions have to be taken at the spur of the
moment. Post facto functions involve grid
performance reporting, post mortem of events,
settlement of accounts, documentation of
experience and interaction with stakeholders.
Fig-8: Typical real-time display
The grid operator supervises the power system
through this system. It acts like the sensory
organs of the grid operators and helps them to
diagnose the states of system and also take
corrective measures. It also ensures
transparency in grid operation and facilitates
amicable resolution of day-to-day problems
associated with this complex task of grid
operation. The real time data is archived
continuously and is later retrieved for analysis
of events occurring in the grid.
Operating aids for grid management
In order to enhance the power system visibility
and improve the quality of supervision in real
time power grid operation in the country, the
grid control rooms at the regional and state
level have been equipped with a state-of-the-
art communication and data acquisition
system.
Various states of grid operation
The interconnected network under current
technology creates strong interactions across
locations. Behaviour of various power system
elements synchronised with the grid influence
the system parameters giving rise to a
dynamically varying system states. These
Page 3 of 7
Page 4
states are normal, alert, emergency, extreme
and restorative.
The operator actions are perpetually guided by
the objective of maintaining the system
directed in normal state for most of the time.
Nevertheless the system may slip from a
normal to alert, emergency or extreme state in
less than a second due to a small or large
perturbation in the system. Contingencies
disturb the grid parameters and call for
immediate operator intervention. Normally it
takes a few minutes to restore the system back
to normal state but during major disturbances
it may take several hours or several days to
restore normalcy. It is therefore essential that
all precautions be taken to prevent the system
from degenerating to an extreme state. This
requires suitable and timely interventions in
the power system in short term as well as in
medium and long-term.
Regional Electricity market
The regional electricity market in India that
operates over the Inter State Transmission
System (ISTS), is governed by the frequency
linked operation and commercial settlement
mechanism known as the Availability Based
Tariff (ABT) and Unscheduled Interchange
(UI) mechanism. The ABT mechanism has
replaced the command and control system
employed earlier with a contractual approach.
The utilities have full freedom and choice to
enter into long-term and short-term bilateral
contracts. These contracts are incorporated in
the daily interchange schedules issued by the
RLDCs.
Fig-9: Day-ahead resource scheduling process
The interchange schedules whether despatch,
drawal or inter-regional are treated as
commitment to deliver or withdraw a certain
quantum of power at a designated time from
the grid. The utilities also have the option of
reviewing and revising the scheduled
interchanges in real time to suit the
demand/supply position in real time. The
revised schedules get implemented within six
time blocks after registering the request with
the RLDCs.
Fig-10: UI price vector
Further, the generating station operators and
state grid operators have been empowered to
respond to the real time pricing signals
generated from the frequency dependent UI
price vector.
Electricity trading
Open Access (OA) in ISTS has been
implemented in all the regions since 6
th
May
2004 in line with the open access regulations
issued by CERC. The regulations aim at
promoting non-discriminatory usage of the
transmission system by customers after
payment of appropriate charges. Access can be
granted under two categories: long -term and
short-term. Long-term access is granted for
usage of 25 years or more while the short-term
access is for a maximum for three months at a
stretch. As per the existing regulations the
long-term users pay higher charges and have a
higher priority over short-term users. The grid
operator declares the anticipated power
transfer capability available
in the
transmission system during the forthcoming
three months. Within the short-term category
reservations on the transmission corridor may
be made under any of the categories: advance,
first-come-first-served, day-ahead and same
day.
Page 4 of 7
Page 5
Fig-11: Short-term Open Access
Open access in transmission effectively
introduces competition in wholesale electricity
market. Although, the overall inter state trade
volume is currently only 3.0 % to 5 % of the
country’s total energy consumption, it has had
a multiplier effect on the entire power sector
by promoting competition, efficiency and
economy. The RLDCs and SLDCs are
playing a key role in facilitating and
scheduling these transactions without
compromising on the security and reliability
of the grid.
The regional transmission system and the
interregional links are being utilized to
transport surplus hydro generation in
northeastern region and pithead generation in
the eastern region to the energy deficit load
centres in the northern, western and southern
regions. The inter-regional exchanges have
increased manifold after introduction of open
access. Almost all utilities in the grid have
taken advantage of the open access provisions
and transactions have taken place in all
possible directions in the country say from
Northeast to North (e.g. Tripura to Haryana),
North to South (e.g. Punjab to Andhra
Pradesh), South to North (e.g. Kerala to
Punjab), West to North (e.g. Gujarat to Uttar
Pradesh), North to West (e.g. Punjab to
Maharashtra) and East to all other corners of
the country. The electricity trade in the
country is expected to grow further after the
commissioning of new generating stations and
establishment of the proposed organized
platform for trading in the form of Power
Exchange (PX). The grid operator would
continue to provide the interface between the
physical system and the electricity market.
Settlement system
For purpose of scheduling and settlement the
entire day in divided into 96 time blocks of 15
minute each. At the end of the day all before
the fact revisions in schedules get incorporated
as ‘Implemented Schedules’ and they serve as
a datum for the payment of capacity charge,
energy charge and generation incentive to the
generating stations governed by the ABT
regime. The actual energy interchanges for
every 15-minute time block, are recorded with
the help of Special Energy Meters (SEM)
installed at all inter utility exchange points in
the region. These readings are used for
working out the actual injection of Inter State
Generating Stations (ISGS) and off-takes of
each state utility from the grid. The actual
values are then compared with the scheduled
values to obtain the deviations from schedules.
Real time deviations in a particular time block
are priced at the corresponding Unscheduled
Interchange rate (UI rate), and settled through
a pool account being maintained by RLDC.
The SEMs also record the reactive energy
interchanges at inter utility points. These are
settled as per the prevailing reactive energy
prices. The regional reactive energy accounts
are also managed by the RLDCs.
Challenges in grid management
Large interconnected grids are essential for
reliability of power supply and for economic
exploitation of spatially distributed energy
resources and consumption centres in the
country. The manifold growth in the network
size has increased the complexity of grid
management.
Page 5 of 7
Page 6
The physical nature of the power flows on
transmission lines, rapidly changing demand
patterns, dramatic changes in the system
parameters, unexpected events in the grid and
calamities (natural or man made) make grid
management extremely challenging. This
requires tremendous presence of mind and
multidimensional skills. A system operator has
to quickly switch roles as a planner, a
strategist, an administrator, a consultant, an
economist and a soldier, which makes his job
highly demanding.
The unbundling process in the power sector
also has contributed significantly to the
growing complexity in grid management.
Competition has heightened the market
pressure, forcing system to be operated closer
to its physical limits. The number of utilities
especially in the state level has also increased
leading to increased difficulty in coordination
during offline as well as in real time. The
conflict of interests, unclear responsibilities,
inconsistency of objectives, inadequacy of
resources and legacy issues among these
utilities often impair the collective
performance of grid management.
All the above coupled with rapidly
diminishing species of “power system
engineers” and the general lack of
appreciation of this vital function is making
grid management a tough job.
Contribution of Grid Operators
Operating conditions require close monitoring
and control on very short time duration.
Advanced technologies are indispensable for
successful operation of the grid during the
various operating states but the contribution of
the engineers at the operating desk is equally
noteworthy. Very few people outside the grid
control centres are aware of the sweat and toil
that goes behind keeping the grid secure and
healthy. In fact the grid operator carries the
credibility of the entire electricity supply
industry in the country on his shoulders.
Against the few occurrences of large grid
disturbances such as the one that occurred in
Northern Region on 2nd Jan 2001, there are
innumerable cases when the alertness and
alacrity of the grid operators have been vital in
rescuing the grid from ‘near death’ situations.
The operators have successfully tackled the
most unusual scenarios in real time grid
operation occurring at the most unexpected
and demanding hours of the day. It is
unfortunate that the heroes of such “near miss”
situations go unsung and unnoticed.
Neutrality of grid operator
Generation and transmission at the inter state
level has already been unbundled in 1991 after
the formation of POWERGRID. Unbundling
of generation, transmission and distribution in
states has been achieved to a large extent. As
per the EA 2003 the STUs are also expected to
disengage themselves from the trading
function shortly. Both the RLDCs and SLDCs
have been prohibited from engaging in the
business of trading in electricity. Further the
RLDC have been barred from engaging in
generation of electricity.
The
Central
Electricity
Regulatory
Commission
and
State
regulatory
Commissions regulate the fees and charges of
RLDCs and SLDCs respectively. The RLDC
charges are shared by the constituent states of
that region in ratio of their weighted average
allocations in the Central Sector power
stations. The fees and charges are independent
of the volume of power flow on the network,
which ensures the neutrality in grid
management. The grid management/operation
is so designed that grid operator merely
provides a secure and reliable platform for
energy exchanges between various players in
the grid without becoming a party to those
transactions.
Conclusions
Modern economies are dependent on reliable
and secure electricity services. Electricity
makes an essential contribution to economic
performance, international competitiveness
and community prosperity. The society’s
dependence on electricity shall intensify as the
world moves ahead in the twenty-first century.
The pressure to operate system in ‘higher risk
mode’ is bound to increase with increasing
network complexity, growing electricity
markets and increasing intensity of surprises
Page 6 of 7
Page 7
from Mother Nature. All these challenges have
to be dealt with collectively and with sincerity
of purpose. Grid management therefore
deserves the recognition and attention of all
the stakeholders. They must all come together
to nurture this institution for the benefit of our
own present and for posterity. The investment
required for this might appear to be a high in
absolute monetary terms especially when it
has to be shared by the direct beneficiaries or
the state utilities. But it would be peanuts
when compared with the opportunity cost of
unserved electrical energy due to a blackout
that could have been averted by the
intervention of the system operators.
Acknowledgement
The author acknowledges the encouragement
by POWERGRID management. The author is
also thankful to Sh. S.R. Narasimhan, Chief
Manager (NRLDC), Sh. S.K. Soonee,
Executive Director (System Operation),
POWERGRID and all colleagues for their
guidance and untiring support.
Disclaimer
The views expressed in the article are the
personal views of the author.
References
1. Electricity Act 2003
2. Indian Electricity Grid Code, April
2006
3. http://www.nrldc.in/
4. http://www.cercind.gov.in/
Page 7 of 7
more
This is the html version of the file http://www.sari-energy.org/Publications/rakeshnath.pdf.Google automatically generates html versions of documents as we crawl the web.
Page 1
1
PREVAILING SITUATION IN INDIAN POWER SECTOR
AND
MAJOR ISSUES, BARRIERS AND BENEFITS OF EXPANDING
REGIONAL POWER TRADE
RAKESH NATH
Director (Technical)
POWER TRADING CORPORATION OF INDIA
MARCH 19, 2001
1.0 INTRODUCTION
1.1
The Indian Power System was demarcated in early sixties in five regions for the purpose of planning, development and operation with a view to
optimally utilize the unevenly distributed power resource in the country, as well as to achieve economy, reliability and security of supply. Five
Regional Electricity Boards, viz., Northern, Southern, Eastern, Western and North-Eastern were constituted to ensure integrated operation of
regional grids formed with progressive interconnection of contiguous state power systems. Five Regional Load Dispatch Centres were also set
up to coordinate the operations of the regional girds in real time.
1.2
The regional grids were strengthened with the establishment of large thermal, hydro and nuclear stations in the Central Sector in which the
states of the concerned region have shares. Central Sector transmission system was constructed for evacuation of power from these central
projects to the beneficiary states. The contiguous regions have also been interconnected through AC and HVDC back-to-back systems with the
ultimate objective of achieving a National Grid. Eastern & Northern-Eastern Regions operate in synchronous mode while other regions operate
independently and exchange power asynchronously through HVDC back to back systems or through AC lines in radial mode.
1.3
Eastern Regional grid is connected to Chukha Hydro Power Station (336 MW) in Bhutan through a 220 kV D/C transmission line on which
Indian Power System imports upto 270 MW. The exchange with Nepal are on a number of 11/33/132 kV lines in radial mode and are presently
of the order of 50 MW. In next few years the exchange with Nepal is expected to increase to 150 MW.
1.4
The installed generating capacity of Indian utilities is about 100086 MW comprising 71254 MW (71%) thermal, 24712 MW (25%) hydro, 2900
MW (3%) nuclear and 1220 MW (1%) wind power (Ref. figure – I). Out of total capacity, only 9073 MW (9%) is in private sector.
Page 2
2
Installed capacity of Indian Utilities
Thermal
71%
Hydro
25%
Nuclear
3%
Wind
1%
State Sector
60752 (MW)
Private Sector
9073 (MW)
Central Sector
30441(MW)
Western
30777 MW
Northern
27042 MW
North-
Eastern
1790 MW
Eastern
15714 MW
Southern
24765 MW
Regional break-up
figure - I
1.5 The demand for electric power has been increasing rapidly compared to addition in capacity. Consequently the country is faced with both energy
and power shortage. The annual energy requirement of the country is of the order of 480 Billion Units (BU) against which the availability is 450
BU, resulting in energy shortage of about 30 BU (6.2%). The peak demand in the country is 73,000 MW against which the availability is about
Sector-wise break-up
Page 3
3
64,000 MW, resulting in peak shortage of 9,000 MW (12.4%). All the regional grids face perennial energy shortage except Eastern Region, which
has surplus power varying from 1000 MW to 3000 MW throughout the year. In other regions, seasonal surpluses occur mostly during off-peak
hours in the periods of lean demand of weather-beating and agricultural loads. The load factors in Northern, Western & Southern Regional grids are
quite high due to high component of agriculture pumping load with staggered timing of power supply. The region-wise power supply position is
indicated in fig. – II & fig.-III. A typical load curve during summer for Northern Regional Grid is indicated in fig. – IV (Minimum/Maximum load
= 89%, load factor = 93.9%).
Region-wise Power Supply Position
0
50000
100000
150000
200000
NORTHERN REGION
WESTERN REGION
SOUTHERN REGION
EASTERN / NORTH-EASTERN REGION
Ene
r
gy
in MU
s
Requirement
Availability
Shortage
6.5 %
7.2 %
7.5 %
-0.7 %
fig.-II
Region-wise Power Supply Position (MW)
0
5000
10000
15000
20000
25000
30000
NORTHERN REGION
WESTERN REGION
SOUTHERN REGION
EASTERN / NORTH-EASTERN REGION
Dem
a
nd i
n
M
W
Peak Demand
Demand Met
Shortage
10.0 %
18.2 %
12.7 %
4.6 %
fig.-III
Page 4
4
Typical Load Curve for Northern Region
0
5000
10000
15000
20000
25000
30000
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hours in Days
Loa
d
in
MW
Regulated Load (MW)
Unregulated Demand (MW)
Thermal Generation (MW)
fig.-IV
1.6
The Indian Power Sector is in the process of restructuring and reforms following the trend around the globe to improve efficiency and to
encourage private sector investment. In 1991, Govt. of India took policy initiative to promote private sector investment in power generation.
The transmission has also been opened to private sector. Central Electricity Regulatory Commission (CERC) has been constituted at Central
level and State Regulatory Commission have already been formed in a number of States.The power sector is in the process of transfer of
authority from the Government to Regulatory Commission.
1.7 The state power systems which were being managed by vertically integrated State Electricity Boards (SEBs) are also in the process of vertical
unbundling separating the generation, transmission and distribution functions with a view to reduce transmission and distribution losses,
improve efficiency and financial viability of state utilities, with ultimate aim of privatising generation and distribution.
1.8 The 16
th
Energy Power Survey of India indicates energy requirement of 975 billion units and peak demand of 157,000 MW in the year 2012.This
corresponds to an incremental capacity addition of about 100,000 MW to the present installed capacity. Considering that capacity addition of only
about 4000 to 5000 MW every year has been possible in the past, it would be necessary to optimally utilize the existing resources by promoting
inter-state and trans-national energy exchanges.
Page 5
5
2. Power System operation Set-up
2.1
Regional Load Dispatch Centres (RLDC) have been given the status of apex body and all players have to comply with the directions of RLDC
for ensuring integrated operation of the inter-state transmission system and achieving maximum economy and efficiency in the operation of the
power system. State Load Dispatch Centres (SLDC) have been given similar responsibility in regard to operation of the intra-state transmission
system. Regional Electricity Board (REB) has representatives from SEBs/State Transmission utilities (where unbundling has taken place),
Central Sector Generation & transmission companies and Central Electricity Authority and meets from time to time to take decisions in the
matter relating to integrated system operation which have to be followed by the RLDCs & SLDCs in real time operation. REBs carry out their
functions through various Committees and Sub-Committees coordinated by REB secretariat, the Staff for which is provided by the CEA and the
constituent utilities. The RLDCs carry out the functions of settling up and operation & maintenance of load dispatch centre, real time operation
including day ahead operational planning, and REB Secretariats have been entrusted with operational planning (monthly & annual),
coordination of protection system, energy accounting and facilitation of trading of power, etc.
2.2
Two important developments have taken place recently in Indian Power System, viz. implementation of Indian Electricity Grid Code (IEGC)
w.e.f. 1
st
Feb. 2000 and Availability Based Tariff (ABT) to be implemented shortly. These developments have taken place on the orders of
CERC after public hearings. IEGC puts obligations on various players in the grid for maintaining security of the inter-state transmission system.
It brings set of rules to be followed by all utilities connected to the inter-state transmission system. The regional grids are proposed to be
operated as loose power pools and strict control of tie line/ generation schedule is not envisaged. Deviations are allowed depending on the
frequency level. If the frequency is below nominal, drawal of power less than schedule or generation more than schedule and when frequency
is above nominal, drawal more than schedule or generation less than schedule is encouraged. The incentives/disincentives to give signals for
correct grid operation are built in features of ABT. The unscheduled interchanges are to be billed at a frequency linked rate which varies
linearly from 0 at 50.5 Hz to 420 paise/kwh (US $ 90/Mwh) at 49.0 Hz.
3.
Present Status of Inter-State exchanges in India
3.1
Central sector transmission system associated with Central Power Stations has been planned and developed for evacuation of generating
capacity keeping in view the disbursal of shares to various beneficiary states in a region. The inter-regional transmission lines were not planned
to cater bulk inter-regional power transfers and were based on limited exchanges of operational surpluses. For example in Eastern Region, the
central sector transmission system was planned keeping in view disbursal of power from Central Sector Stations to beneficiary states within
Eastern Region. However, due to load growth not taking place in Eastern Region as anticipated and inadequate transmission system to transfer
surplus power to the neighbouring systems, it has resulted in bottling up of surplus power to the tune of 1000 to 2000 MW.
3.2
The five regional grids are connected by 132/220/400kV AC transmission lines and HVDC back to back systems. The total power transfer
capacity of the inter regional transmission system at 220kV and above and at HVDC back to back systems is about 5500 MW (7.5% of peak
demand). The inter regional transmission system which is presently under construction will add 3500 MW in the inter-regional power transfer
capacity. The existing inter-regional transfer capacity including approved/under construction is indicated pictorially in Exhibit-I.
Page 6
6
3.3
The main suppliers to the bulk power system are the State utilities own power stations, Central Sector Power Stations, the entire capacity of
which is allocated to States and IPPs having long term contracts with the States. There are no merchant power stations. Scheduled power
exchanges within the regional grids takes place in limited quantity. Inter-regional exchanges account for less than 2% of total energy
consumption. The quantum of inter-regional energy exchanges during the last five years is indicated in fig.-V.
Inter-Regional Energy Exchanges
2508
2801
2755
5093
7297
9041
0
1000
2000
3000
4000
5000
6000
7000
8000
9000
10000
1994-95
1995-96
1996-97
1997-98
1998-99
1999-00
Year
Ener
gy (
M
U
s
)
Source: Central Electricity Authority
fig.-V
3.4
In the absence of a trading company, standing commercial arrangements with prices linked to Central Stations’ tariff were devised by Regional
Electricity Boards for facilitating power exchanges in real time. Regional Load Despatch Centres were authorised to effect Inter-regional power
transfer in real time operation depending upon the surplus and deficit in the regional grids. Scheduled bilateral exchanges also takes place
between State utilities based on mutually agreed rates. Such exchanges are seasonal in nature. In Eastern Region the unutilized capacity in
central sector states has been allocated to states outside the region and export to the tune of 1000 MW takes place regularly to the neighbouring
regions.
4.0
Enhancing inter-state exchanges.
4.1
The main constraints in enhancing the inter state energy exchanges are
i.
Transmission Constraints.
ii.
Non-adherence to tie-line schedule.
Page 7
7
iii.
Tariff issues.
iv.
Financial viability of State distribution utilities.
v.
No Statutory provisions for direct sale by IPPs, etc.
4.2
Transmission Constraints:
4.2.1 As already stated above, the main constraint is being experienced in transfer of surplus power from Eastern Region. The planning of
transmission system has undergone a change and integration of Regional grids for bulk inter-regional power transfers is being planned to
optimally utilize the power resources of the country and to cater to variations in planned and actual load growth in different parts of the country.
Transmission Highways of high capacity have also been planned to be built up across the country to facilitate large scale trading of power
anticipated in future.Some of the major transmission system, planned for bulk power transfer across the region are that associated with Hirma
Mega Power Project comprising 400/765 kV AC and HVDC Transmission System interconnecting Eastern, Western & Northern Regions
transmission system and that associated with Tala Hydro Project being constructed in Bhutan inter-connecting Eastern & Northern Region by
high power 400 kV D/C transmission system and series compensation of some of the 400kV transmission lines. Further, the transmission
between Eastern & Northern regions is being strengthened by installation of a 500 MW back to back system. Power transfer capacity between
Southern and Eastern/Western Regions is also expected to be increased from 1650 MW to 4150 MW, by construction of HVDC Systems of
2500 MW capacity. The inter-regional transmission system expected by the year 2006 is indicated in Exhibit – II. Intra-regional transmission
system is also being strengthened by construction of new lines and series compensation of the existing lines to enable large scale power
transfers.
4.2.2 With the commissioning of above mentioned transmission systems four regional grids of India viz Northern, Eastern, North-Eastern and
Western Regions will be synchronized together and there will be a strong power highway across the country. A sketch showing the
transmission highways across the country (400/765 kV and HVDC) proposed by the year 2012 is enclosed at Exhibit III.
4.3
Non-adherence to tie-line schedules
4.3.1 Each constituents of the inter-connected power system has to control its own generation and load to ensure that net exchange with the grid is
maintained as per the schedule. However, the tie-line schedules are not being maintained resulting in subnormal frequency and sometimes low
voltage. Non-adherence to the schedule by one constituents affects the drawl of other constituents. Indian Electricity Grid Code (IEGC) based
on the order of the CERC after a public hearing has come into force w.e.f. 1
st
February’ 2000. IEGC puts obligations on various utilities of
regional grids for maintaining security and achieving economy in system operation. Some of the provisions of IEGC are linked to
implementation of Availability Based Tariff (ABT), which is expected to be implemented w.e.f. April, 2001 in phased manner in all Regions
will provide correct commercial signals to induce the utilities to follow grid discipline.
4.4
Tariff issues
4.4.1 The present bulk supply tariff is not based on commercially sound principles and is not conductive to economic operation. In so far as Central
Sector Stations are concerned, their fixed charges are recovered in proportion to the energy drawal rather than capacity allocation, making it
Page 8
8
effectively a flat energy tariff. Under the circumstances the incremental cost for a surplus state is generally the full fixed and variable charges of
a Central Sector instead of variable charges alone. The energy exchanges in real time are also, therefore, not transacted at Short Run Marginal
Cost.
4.4.2 Availability Based Tariff (ABT) proposed to be introduced for inter-state Generating Stations comprises of three components viz. (i) Capacity
charge in proportion to the allocated capacity. (ii) Energy charge on scheduled energy and (iii) Unscheduled inter-exchange (UI) charge to be
billed at a rate linked to grid frequency on the unscheduled interchange energy (difference of schedule energy and actual energy drawal).
Implementation of ABT along with enforcement of the Grid Code will encourage trading of energy based on sound commercial principles.
4.5 Financial viability of distribution utilities:
4.5.1 Non-payment of dues in time comes in the way of smooth interchange of power. It has been estimated that only about 50-60% of the electricity
generated in India is actually metered at the consumer end. The rest goes in T&D losses, un-metered supplies and theft. 100% metering has
been planned not only at consumers’ premises but also at delivery points (11/33 kV) to the distribution division to fix the concerned division
accountable for requisite metered energy.
4.5.2 Unbundling of SEBs with distribution as separate entity is the first step towards reforms. The distribution system in a state further needs to be
split in to manageable zones and subsequently privatized. Smaller distribution zones will eventually help in privatization process by providing
access to more number of Indian Companies instead of limiting large companies to take over large distribution areas.
4.6 No Statutory provisions for direct sale by IPPs, etc.
4.6.1 Surplus is available with the licensees, IPPs and CPPs of some of the states. This type of surplus should normally be available at marginal cost.
The electricity laws do not permit sale of such surplus by the licensee/IPP/CPP to neighbouring states without the approval of the host State
Government. In some cases where physical wheeling of power is not taking place, transmission losses in the host state could even reduce,
making the transaction more viable for both seller and purchaser of power. Some states are now considering granting permission to third party
sale for IPPs/CPPs giving access to the state’s transmission system.
5.0
Role & PTC
5.1
Power Trading Corporation of India (PTC) has been set up to facilitate development of Mega Power Projects and hydro projects, promoting
power trading to optimally utilize the power resources of the country, promoting exchange of power with the neighbouring countries, etc. The
ability of PTC to make its presence felt would be based on the perceived value addition that it would bring with its intermediary role. Typically
the intermediation cost of PTC would need to be either by a credit enhancement as proposed for the mega power projects or by its own capital
structure or a mix of two. This would reduce the perceived risk on the part of the power plant developers rendering them to reduce their tariff by
intermediation costs ensuring that the purchaser of power gets the same effective price.
Page 9
9
5.2
PTC has been nominated as nodel agency by Government of India for sale of power for Chukha Hydro Power Station in Bhutan and power
exchanges with Nepal.
5.3
The Mega and other power projects being handled by PTC have beneficiary states in different regions. Development of the transmission system
for these projects will help in further strengthening inter-connections between the Regional grids with the ultimate objective of achieving a
National Grid. For example transmission system planned for Hirma Mega Power Project (3960 MW-net) located in Eastern Region and having
beneficiaries in Western Region & Northern Regions will help in inter-connecting Eastern, Western & Northern Regions through high capacity
AC and HVDC transmission system. Similarly transmission system for Tala HEP (1020 MW) being constructed in Bhutan will enable inter-
connection of Eastern & Northern Regions through 400 kV D/C which will provide immense opportunities of trading surplus power of Eastern
Region to Northern Region. The Transmission system associated with these power project is also expected to provide opportunity for enhancing
cross boundary exchanges with the neighbouring countries. India can serve as a large power market for Nepal and Bhutan, rich in hydro
potential and Bangladesh, rich in gas resources.
6.0
Development of Bulk Power Markets in India
6.1
The Indian market comprises of the following:-
(i)
Suppliers of bulk power: Central generating stations, IPPs or Mega power projects, vertically integrated utilities/state transmission utilities in
surplus areas and PTC.
(ii)
Buyers of bulk power: State transmission utilities, SEBs and PTC.
(iii)
Infrastructure Providers:
a. POWERGRID and State Transmission Utilities, which provide transmission system.
b. Regional Load Dispatch Centers and State Load Dispatch Centers, which operate the Regional and State grids.
c. Regional Electricity Boards, which set up transactions, carry out energy accounting and settle energy traded.
d. SEBs, which provide transmission and distribution network.
6.2
Competition in supply and consumer choice is yet to be felt in the Indian Power Sector due to various reasons such as:
i)
Availability of few suppliers of bulk power. NTPC and SEBs own bulk of the capacity.
ii)
There are no merchant generators in India.
iii)
Transmission constraints.
iv)
Most states suffer from chronic energy and peak shortage. Allowing markets to operate under such conditions would result in the allocation of
power on the basis of paying capacity that would increase the imbalances in power position between the states.
Page 10
10
v)
Cross subsidization in tariff among the various classes of consumers. If consumers are given free choice, the industrial consumer who now
cross-subsidize other consumers will opt to buy from IPP and other generating stations, which will further aggravate the financial conditions of
the SEBs.
6.3
The Draft Electricity Bill 2000 provides for establishment of a bulk electricity spot market to facilitate efficient, competitive and orderly trading
and supply of electricity as the electricity industry develops and matures to benefit the consumers from resulting competition and free flow of
electricity.
6.4
It is expected that competitive markets will develop gradually with the reforms in SEBs, building up of ‘Transmission Highways’ across the
regional grids including strengthening of transmission system, commissioning of mega and other power projects developed through PTC and
associated transmission system to be constructed by POWERGRID and introduction of Availability Based Tariff. Introduction of new
electricity legislation will provide the necessary statutory provisions to enable establishment of the competitive power markets.
7.0
Cross Border Trading :
7.1
There are many examples world wide of grids of neighbouring countries being interconnected for exchange of power to their mutual benefit.
Some of the interconnected grids are Union for the Coordination of Electricity Generation and Transmission (UCPTE), Canada and USA,
Scandivanion Grid and Malaysia-Thailand-Singapore Grid. These interconnections have permitted the partner countries to reduce their costs,
improve security of supply and reduce environmental damage. Interconnection of power systems’ of SAARC countries will help in optimum
utilization of available resources due to diversity in demand, improve reliability of supply through coordinated operations, provide operating
economies by exchange of surplus power and energy, provide mutual assistance during emergencies and also secure additional economics
through coordinated development in power sector. Nepal, Bhutan and North Eastern Region of India possesses immense hydro potential, there
are huge gas reserves in Bangladesh and India has large reserves of coal.
7.2
Types of exchanges which could be effected between India and the neighbouring countries are emergency power, inter change power (economy
energy), limited time power exchange and long term power contracts.
7.3
At present India imports above 270 MW from Chukha Hydro Power Project from Bhutan and exchanges power with Nepal on border areas to
the tune of 50 MW. Kurichu (60 MW) hydro power station in Bhutan is expected to be commissioned in the year 2001-02 and bulk of its
output will be imported by India. Tala Hydro Power Project (1040 MW) in Bhutan is expected to be commissioned during the year 2004-05 for
export to India. The exchanges with Nepal are also expected to increase to 150 MW in next few years. There is no inter-connection with other
neighbouring countries. Talks have been held in the past for inter-connection with Bangladesh but no tangible progress has been made, so far.
8.0
Major issues in cross border trading :
The major issues in cross border trading of power are more or less the same as for inter-regional trading of power in a large country like India except
that the cross border transactions requires more preparations and involvement of federal governments. The issues with respect to exchange of power
Page 11
11
between India and the neighbouring countries, barriers and benefits are discussed in the following paras.
8.1
Market for power (demand/supply):
Northern, Western and Southern Regional Grids are the potential markets for power and energy from the neighbouring countries and have high
demand during summer and winter months due to agricultural and weather beating loads. Northern Region in particular has high component of
agriculture pumping load with a very high load factor. The energy requirement in Northern Region increases substantially during the
summer/monsoon months due to paddy irrigation pumping load. In winter months the load factor reduces and peak demand during the morning
hours is experienced besides the normal evening peak. This pattern of demand is compatible to hydro power stations which operate as base
load during summer/monsoon and in peaking mode during winter. Eastern Regional Grid though surplus in energy, is deficit only during the
evening peak hours. Northern, Western and Southern Regions also have seasonal surpluses during off peak hours when there are wide spread
rains.
Eastern Region Grid of India is surplus and can export power from its pit head coal based Thermal Power Stations to Western part of
Bangladesh which utilizes expensive liquid fuel for local generation and imports power from Eastern part, thus effecting operating economies.
Remote areas on the border of a country could get power supply from nearest source in neighbouring country. Some border areas of Nepal and
Bhutan have been importing power from India and similarly same border towns of India have been receiving supply from Nepal. Such
exchanges could be increased for reducing the cost of sub-transmission and distribution system and transmission losses.
8.2
Physical arrangements for transfer of power
There could be four types of arrangements for transfer of power, i) radial mode by connecting load of the importing system to the exporting
system, ii) synchronising generating unit(s) of the exporting system to the importing system and iii) synchronous operation of the systems and
iv) through asynchronous connection through HVDC system. The first two mode of power transfer have their own limitations. Synchronous
operation provides more flexibility in operation but adherence to pre-arranged schedules and load dispatched capabilities assume importance.
HVDC system though expensive, is the most practical way of bulk power transfers between systems following different operating practices.
Each type of transmission arrangement has to be examined for specific exchange keeping in view techno-economical and practical aspects by
carrying out technical studies.
A sub-committee comprising of engineers from India and Nepal examined the prospects of enhancing exchanges between India and Nepal and
has recommended construction of three 132 KV transmission lines: Butwal–Anandnagar, Birgunj-Motihari and Dhalkebar-Sitamarhi. Each
country has to build up the transmission line in its own territory. A 400 KV D/C line is under construction for evacuation of power from Tala
Hydro Power Project in Bhutan and will interconnect it with Eastern Regional Grid of India. Eastern Region which requires power only during
peak hours will pass on its surplus power during non-peak hours to Northern Region and for this a high capacity 400 KV D/C cooridor is being
built up inter-connecting the Tala transmission system to load centers in Northern Region. As already explained in preceding paras, high power
transmission highways have been planned inter-connecting Eastern, Western and Northern Regions by 400/765 KV transmission lines and
HVDC transmission system. HVDC back to back system between Eastern and Southern Regions are also being strengthened. We are
expecting a very strong backbone transmission system for intra and inter-regional ties for transmission of bulk power in the country
Page 12
12
by the year 2006. These transmission systems will also facilitate transfer of power from neighbouring countries by any state in India.
Exchange of Power between India and Bangladesh has been under discussion for quite some time. A high level Bangladesh delegation had
visited India in Sep. 1996 to explore possibility of import of power from India. ADB had undertaken a Technical Assistance Study by
appointing a Consultant to detail the technical and commercial aspects. Tripartite meetings were held between ADB, Govt. of Bangladesh and
Govt. of India in May, 1997 and in Feb., 1998. Exchange of 150 MW during normal condition and 300 MW during emergencies was proposed.
It was also tentatively proposed to construct 220 KV D/C line connecting a new sub-station at Krishnanagar (West Bengal) to Ishurdi (Western
Bangladesh) and Shahgi Bazar (Eastern Bangladesh) to Kumarghat (Tripura) and interconnect Eastern Regional Grid of India with Bangladesh
Grid in synchronous mode. A draft inter change agreement was also prepared. It was proposed that detailed studies will be carried out by
engineers from India and Bangladesh. However, after that no further progress has taken place.
8.3
Adequacy of Load Dispatch, operating practices and other Technical issues :
These aspects are important when the systems are synchronized. The Regional and State Load Dispatch Centres in India have limited
capabilities and are being augmented and modernized under ‘Unified Load Dispatch Centre’ Scheme by Power Grid Corporation of India.
Adherence to grid discipline is also being made effective through implementation of IEGC and ABT, which will help in arresting wide-
variations in frequency. However, IEGC envisages not very strict control of tie lines schedules and deviations are permitted depending on the
frequency. Thus Unscheduled Exchanges may take place in cross boundary exchanges and commercial arrangements have to be decided for the
same.
Operational protocols will have to be developed for synchronous operation taking into account the security standards and operating codes of the
two countries. Preparations for parallel operation will include load flows for assessing technical and voltage problems, short circuit studies and
transient analysis.
8.4
Economic/Financial Issues :
Presently the rate of energy for exchanges between India and Bhutan and Indian and Nepal are decided at the Govt. level which are not
necessarily based on sound commercial principles. It is necessary to devise the common agreed principles for determining the rates for
exchanges of different types including long term contracts for supply of power.
It would also be necessary to carry out economic analysis of the cost of delivered power from one country to another including the transmission
losses and wheeling charges for the intermediary systems. The whole data has to be transparent. For example for economy exchange the
incremental cost data has to be available for each power station. This data is not available for Indian Power System also and the operational
decisions are made based on the normative variable charges.
Eastern Region Grid of India is predominantly thermal based with a large number of coal based pit head power stations. The variable charges
vary from $ 9/Mwh to $ 16/Mwh and total fixed plus variable charges are of the order of $ 40/Mwh. The pooled transmission charges of
Eastern Region are of the order of $ 2.5/Mwh. In Northern Region which has about 30% of installed capacity in hydel stations, the tariff for
Page 13
13
hydro stations varies from $ 10 to $ 55/Mwh. The tariff for coal fired stations vary from $ 16/Mwh at pit had to $ 52/Mwh at the load center.
The variable charges of the coal fired stations vary from $ 13 / Mwh to $ 32 / Mwh. The pooled transmission charges for Northern Region are
of the order of $ 2/Mwh. However, the transmission charges are expected to increase with the planned augmentations. It would be desirable
that cost of delivered energy by the neighbouring countries to Northern Region is comparable to cost of delivered energy from Eastern Region.
8.5
Commercial/Legal Issues :
The ownership and contractual arrangements that allow fair allocation and management of risks, adequacy of existing legal and regulatory
issues and desirability for amendment or new laws and regulations needs to be analysed.
For India, PTC has been nominated as a nodel agency for coordination of power transfers with Bhutan and Nepal. PTC will enter into contracts
with the concerned organisations in the neighbouring countries on commercial basis. PTC will also coordinate with Central Transmission
Utility, generating companies and state utilities in India which are the bulk customers of power.
8.6
Social and Environmental aspects :
Development of power projects in neighbouring countries is expected to help in boosting the economy of the region and improve standard of
living of the people of the region. Setting up of gas based plants in Bangladesh and hydro stations in Bhutan and Nepal might help in
postponing coal based power projects in India which will help in reduction of environmental pollution in the region.
9.0
Conclusion :
India has a long history of cooperation in power sector with neighbouring countries. It constructed Trishuli and Devighat Hydro-electric
Projects in Nepal in 70s and 80s. It also constructed Chukha Hydro-electric Project in Bhutan in late 80s. Energy is being purchased by India
from these projects. Execution of Tala and Kurichu Hydro-electric Projects in Bhutan are presently under progress and power from these
projects will also be supplied to India. In the past, the tariff was fixed mostly on the basis of negotiations. Neither any PPA was signed nor any
principles for fixation of tariff were evolved. Such an arrangement could have worked in the past as the quantum of power exchange was
limited. However, in years to come the size of purchase may be substantial and calls for tariff fixation on the basis of well established financial
and economic principles.
Northern, Southern and Western Regional Grid of India may be the large markets for import of base load and peak power from the
neighbouring countries. Eastern and North-Eastern Regions are expected to be surplus except during evening peak hours and can supply
economy energy to neighbouring countries specially western part of Bangladesh which utilizes expensive liquid fuel for power stations. Huge
capacity transmission (highways) are under construction in India between the Regional Grids, which could also be used for cross boundary
trading of power. It is expected that by the year 2004-05, Eastern/North-Eastern Regional Grids will be synchronized with Northern Regional
Grid and Western Regional Grid.
The type of exchanges which could be expected between India and neighbouring countries are emergency power, interchange power (economy
Page 14
14
energy), limited time power exchange and long term power contracts. To start with, the cross boundary exchanges could be enhanced in radial
mode by connecting load of importing system to the exporting system or by connecting generating unit(s) of the exporting system to the
importing system. However, in future synchronous operation of the grids should also be considered to provide for flexibility of operation and
to avail the benefits of inter-connected operation. Inter connection by HVDC systems though more expensive option may also be examined if
the quantum of exchange is expected to be at a high load factor. Detailed studies covering techno-economical, social and environmental issues
are required to be carried out to examine the possibilities of enhanced cross boundary exchanges. Agencies such as ADB and USAID can help
in undertaking the studies, providing the inputs on experiences and practices of cross boundary trading in advanced countries and act as
catalysts in enhancing the regional cooperation.
PTC has been nominated by Govt. of India as the nodel agency for coordinating the trading with Nepal and Bhutan and may also be extended
for trading with Bangladesh. Similar nodel agencies could also be nominated by the neighbouring countries. In the end we would like to quote
from the writings of Dr. Fuller and Rabindranath Tagore which have been picked up from a paper by POWERGRID presented in Regional
Workshop held in Dhaka in August, 1998.
“Dr. Buckminister Fuller proposed interconnecting regional power systems into a single, continuous worldwide electric energy grid as number
one solution to world’s pressing problems. He also saw power grid as the way to reduce human suffering, preserve the environment and make
war obsolete”.
“Come out of your shell and you will find the whole world is waiting for you”.
- Rabindranath Tagore
“No more delay, let’s go hand in hand, the paradise of unit is ahead of us”
- RabindraNath Tagore
Page 15
15
INTER – REGIONAL LINKS AT 220kV AC AND ABOVE AND HVDC EXHIBIT – I
(Existing/New Approved Scheme)
Chukha (Bhutan)
500MW
500 MW
Legend
500MW
Existing 220kV
Proposed 220kV
Existing 400kV Proposed 400 kV
HVDC back to back
link
HVDC
bipole
500MW
1000MW
500MW
2000MW
Sahupuri
Allahabad
Northern
(Installed Existing Capacity-
27042 MW)
Kota Auraiya
Singrauli
Dehri
Birpara
Sasaram
Malda
Eastern
(Installed Existing Capacity-
15714 MW)
Budhipadar
Rourkela
Talcher Balimela
Jeypore
Salakati
North-Eastern
Bongaigaon
(Installed Existing Capacity-
1790MW)
Ujjain Korba
Malanpur Vindhyachal
Western
(Installed Existing Capacity-
30777 MW)
Raipur
Kolhapur Chandrapur Barsoor
Belgaum Ramagundam
Lower Sileru
Gazuwaka Kolar Upper
Sileru
Southern
(Installed Existing Capacity-- 24765 MW)
Page 16
16
INTER – REGIONAL LINKS
EXHIBIT – II
(Existing/New Approved Scheme and Proposed for Hirma/Tala)
Tala
Chukha (Bhutan)
500MW
500MW
765kV
2500MW
Legend
500MW
Existing 400kV Proposed 400kV
Existing 220kV Proposed 220kV
Proposed 765kV
HVDC back to back
link
HVDC
bipole
500MW
1000MW
500MW
2000MW
200 MW
Sahupuri
Gorakhpur
Northern
(Installed Existing Capacity-
27042 MW)
Bhiwadi Allahabad
Kota
Auraiya Singrauli Jaipur
Dehri Silguri
Birpara
Muzaffarpur
Sasaram Malda
Hirma
Eastern
(Installed Existing Capacity
15714MW)
Budhipadar
Rourkela
Jeypore
Talcher
Balimela
Salakati
North-Eastern
Bongaigaon
(Installed Exiting Capacity-
1790MW)
Ujjain Raipur
Malanpur Vindhyachal Sipat
Western
Korba
Raipur
(Installed Existing Capacity-
30777 MW)
Kolhapur Chandrapur
Barsoor
Belgaum Ramagundam Lower Sileru
Gazuwaka Kolar Upper
Sileru
Southern
(Installed Existing Capacity 24765 MW)
Page 17
17
more
ANDHRA PRADESH ELECTRICITY REGULATORY COMMISSION
DRAFT REGULATION ON
TRANSMISSION LICENSEE STANDARDS OF PERFORMANCE
Inviting Comments & Suggestions by 18-12-06
Regulation No. _______ of 2006
In exercise of the powers conferred by sections 181 read with section 57 (1), 57 (2) and 86 (1) (i) of the Electricity Act, 2003 (36 of 2003), the Andhra Pradesh Electricity Regulatory Commission makes the following Regulation, namely:
1. SHORT TITLE AND COMMENCEMENT
1.1 This Regulation may be called the “Andhra Pradesh Electricity Regulatory Commission (Transmission Standards of Performance) Regulation, 2006”.
1.2 This Regulation shall be applicable to the State Transmission Utility/ Transmission Licensee in the State of Andhra Pradesh.
1.3 This Regulation extends to the whole of the State of Andhra Pradesh.
1.4 This Regulation shall come into force on the date of its publication in the official Gazette of Andhra Pradesh.
2. DEFINITIONS
2.1 In this Regulation, unless the context otherwise requires:
(a) “Act” means the Electricity Act, 2003 (Central Act No. 36 of 2003);
(b) “APTRANSCO” means Transmission Corporation of Andhra Pradesh Limited registered under the Companies Act, 1956;
(c) “CEA” means the Central Electricity Authority;
(d) “Commission” means Andhra Pradesh Electricity Regulatory Commission;
(e) “Consumer” in the context of this Regulation means any person who is provided with the transmission services by the transmission licensee and includes any person whose premises are for the time being connected for the purpose of providing transmission services from the licensee, and persons who have applied for availing transmission services from a transmission licensee.
(f) “EHV/EHT” means Extra High Voltage/Extra High Tension (voltage level above 33,000 volts);
(g) “Grid Code” means the set of principles and guidelines prepared in accordance with the terms of Section 86 (1) (h) of the Electricity Act 2003;
(h) “IEGC” means the Indian Electricity Grid Code approved by Central Electricity Regulatory Commission (CERC) and shall include any Grid Code specified by Central Commission under clause (h) of sub-section (1) of section 79 of the Act;
(i) “PGCIL” means Power Grid Corporation of India Limited, a Central Transmission Utility notified under sub-section (1) of section 38 of the Act;
(j) “Rules” means the Indian Electricity Rules, 1956 and/or any other rules made under Act;
(k) “State” means the State of Andhra Pradesh
(l) “State Transmission System” means the system of EHV electric lines and electrical equipment operated and/or maintained by State Transmission Utility and/or any Transmission Licensee for the purpose of the transmission of electricity among generating stations, external interconnections, distribution systems and any other user connected to it with in the state of Andhra Pradesh;
a. “User” means a person, including Generating Stations within the State, Transmission Licensees or Distribution Licensees within the State and open access customer who use the State Transmission System and who must comply with the provisions of the Grid Code;
2.2 Words and expressions used but not defined herein shall have the meaning assigned to them in Electricity Act 2003, Indian Electricity Grid Code, Andhra Pradesh Electricity Grid Code and Indian Electricity Rules, 1956.
3. OBJECTIVE
This Regulation lays down the performance standards to maintain certain critical grid parameters within the permissible limits. These standards shall serve as guidelines for State Transmission Utility (STU)/Transmission Licensee to operate the Intra-State Transmission System for providing an efficient, reliable, coordinated and economical system of electricity supply and transmission. The main objectives of these performance standards are:
(a). To ensure that the grid performance meets minimum standards essential for the Users’ system demand and proper functioning of equipment;
(b). To enable the Users to design their systems and equipment to suit the electrical environment that they operate in; and
(c). To enhance the quality standards of the State Transmission System in order to move towards standards stipulated in or established under the authority of National and State Acts and Rules in the short term and gradually towards the international standards in the long term.
4. STANDARDS OF PERFORMANCE
4.1 The Transmission performance standards are classified under the following two categories:
(a) Mandatory Standards - Those performance standards, the failure to maintain which attracts the provisions of sub-section (2) of the section 57.
(b) Desirable Standards - Those performance standards, which are desirable for providing quality, continuity and reliability of services by the Licensees, and though also specified by the Commission do not, unless provided otherwise by the Commission from time to time, attract the provisions of sub-section (2) of the section 57.
4.2 The following standards are the mandatory standards:
(a) Voltage Variation
(b) Safety Standards
These are statutory standards to be complied with by the Licensee as per Electricity Rules 1956 wherever not inconsistent with the Act. The new Rules under section 53 of Act are yet to be issued by the CEA in consultation with the State Government. The standards specified in this Regulation shall therefore be revised after new Rules under the Act come into effect.
4.3 Desirable standards too have been specified herein under section 86 (1) (i) of the Act, with the main objective of providing quality, continuity and reliability of services to the consumers. The Commission shall fix the time-bound schedule for implementation/compliance of/with each parameter of these standards. The following standards are specified herein as desirable of achievement:
(a) Feeder Availability
(b) Sub-station Availability
(c) Voltage Unbalance
(d) Neutral Voltage Displacement (NVD)
(e) Voltage Variation Index (VVI)
(f) System Adequacy
(g) System Security
5. PHASING OF IMPLEMENTATION
5.1 The performance standards excepting the Mandatory Standards, specified herein shall
more
Subscribe to:
Post Comments (Atom)
.jpg)
.jpg)
.jpg)
.jpg)
.jpg)
Posts
)
.jpg)
.jpg)
.jpg)
.jpg)
.jpg)
.jpg)
.jpg)
.jpg)
No comments:
Post a Comment