Proposed Amendments to Tariff Policy Under Electricity Act 2003

No comments : Labels: ,
Proposed Amendments to Tariff Policy Under Electricity Act 2003

The existing tariff policy has recently been reviewed by the expert committee and the following necessary amendments have been proposed in the Tariff Policy under section 3 of Electricity Act 2003.  Following are the proposed amendments to the act which might give us a food for thought regarding the existing tariff policy. For your Reference you may download the existing policy and Amendment from the links below.
Download pdf file:  Tariff Policy, Amendment to Tariff Policy
Amendment: 8.3(1) In accordance with the National Electricity Policy, consumers below poverty line who consume below a specified level, say 30 units per month, may receive a special support through cross subsidy. Tariffs for such designated group of consumers will be at least 50% of the average cost of supply. This provision will be re-examined after five years.
Justification: The review of the above clause was considered by the Working Group and observed that no modification of the clause is required and hence, the same provision can be continued further and therefore the phrase "This- provision will be re-examined after five years" is now required to be deleted.
Amendment: 8.5.1- National Electricity Policy lays down..........is used to bring about competition in the larger interest of consumers. Accordingly, when open access is allowed the surcharge for the purpose of sections 38,39,40 and sub-section 2 of section 42 would be computed as the difference between (i) the tariff applicable to the relevant category of consumers and (ii) the cost of the distribution licensee to supply electricity to the consumers of the applicable class. In case of a consumer opting for open access, the distribution licensee could be in a position to discontinue purchase of power at the margin in the merit order.
Accordingly, the cost of supply to the consumer for this purpose may be computed as the aggregate of (a) the weighted average of power purchase costs (inclusive"of fixed and variable charges) of top 5% power at the margin, excluding liquid fuel based generation, in the merit order approved by the SERC adjusted for average loss compensation of the relevant voltage level and (b) the distribution charges determined on the principles as laid down for intra-state transmission charges.
Surcharge formula:
S = T - [ C (1+ L / 100) + D ]
Where
S is the surcharge
T is the Tariff payable by the relevant category of consumers;
C is the Weighted average cost of power purchase of top 5% at the margin excluding liquid fuel based generation and renewable power
D is the Wheeling charge
L is the system Losses for the applicable voltage level, expressed as a percentage

The cross- subsidy surcharge should be brought down progressively and, as far as possible, at a linear rate to a maximum of 20% of its opening level by the year 2010-11.
Accordingly, an alternative formulation for calculating cross subsidy surcharge could be worked out to ensure that neither open access is throttled nor does the host DISCOM unduly suffer.
SERCs may calculate Cross-Subsidy Surcharge based on the assumptions that the power available as a result of exit of open access consumer will be sold at the average revenue realization rate. This appears to be the most practical scenario in a situation of shortage of power supply. The SERCs may assume certain percentage (say 10%) of the total consumption by eligible open access consumers for the purpose of estimation of power available for sale at average realization rate. The wheeling . charge (grossed up by the system loss at appropriate level) to be recovered from the open access consumers should also be factored into computation of surcharge. At the same time it should also be ensured that the formula incentivizes the distribution licensees to reduce their distribution losses.
For a situation where there is no power cut, SERCs may calculate Cross-Subsidy Surcharge based on the estimation that the DISCOM will avoid purchase of the quantum of power for which open access has been sought. This principle of avoided cost method should be adopted in areas where there are no power shortages. Other assumptions relating to quantum of power avoided and the wheeling charges could be on the same lines as above.
Justification: An opinion was-expressed for review of the formula given in the Tariff Policy which uses the weighted average cost of power purchase of top 5 % as a factor and leads to a negative cross subsidy surcharge in certain cases. Allowing consumers to migrate to open access under these conditions increases the burden of the DISCOM and this was not in line with the spirit of the cross - subsidy surcharge as per the Tariff Policy. There is thus a need to re-determine the formula for calculating cross subsidy surcharge. The options suggested were based on the average cost or bottom 5% costs.
Section 61 (g) of the Electricity Act, 2003 provides that appropriate Commission shall determine tariff keeping in view the factor that the tariff progressively reflects the cost of supply of electricity and also, reduces cross-subsidies in the manner specified by the Appropriate Commission. However, very few SERCs have specified the roadmap of reduction of cross subsidies. Therefore, roadmap of reduction of cross subsidies should be specified by SERCs in line with the spirit of the Act.
Amendment: 8.5.6 In case of outages of generator supplying to a consumer on open access-----standby arrangements should be provided by the licensee on the payment tariff for temporary connection to that consumer category as specified by the Appropriate Commission. charges may be decided by mutual agreement between the open access consumers and the distribution companies.
Justification: The issue of Universal Service Obligation (USO) and standby charges was taken up by the Task Force on Operationalisation of Open Access in the Planning Commission with the M/o Law & Justice.
After consultation with M/o Law & Justice/Ld. Attorney General of India Ministry of Power had issued clarification vide letter dated 30.11.2011 that "all 1MW and above consumers are deemed to be open access consumers and that the regulator has no jurisdiction over fixing the energy charges for them". All concerned have been requested to take necessary. steps for implementing the provisions relating to open access in the Electricity Act, 2003 in light of the said opinion.
Amendment: Para 8.4: 1(iii) It will take some time before non- conventional technologies can compete with conventional sources in terms of cost of electricity. Therefore, procurement by distribution companies shall be done at preferential tariffs determined by the Appropriate Commission.
2. Such procurement by Distribution Licensees for future requirements shall be done, as far as possible, through competitive bidding process under Section 63 of the Act within suppliers offering energy from same type of non-conventional sources. In the long- term, these technologies would need to compete with other sources in terms of full costs. Short term procurement through Purchase of Renewable Energy Certificates (REC) or at preferential tariffs.
Justification: In order to bring more competition to the Renewable Energy sector with consequent reduction in prices of power production through the renewable sources of energy, the following options were deliberated:

  • Long term procurement of power by the distribution licensee to be done only through competitive bidding process (CBP) .and Power Purchase Agreements (PPA). 
  • REC Mechanism has already been launched by CERC which along with the preferential tariffs takes care of the short, term procurement by the distribution licensees.

In the absence of competitive bidding for long term procurement from renewable energy sources there will be no competition in the sector and consumer will be deprived of the competitive rates for renewable energy.
Amendment: Para 6.4: Pursuant to provisions of section 86(1 )(e) of the Act, the Appropriate Commission shall fix a minimum percentage of the.....obligations. In view of the comparatively higher cost of electricity from solar energy currently, the REC mechanism should also have a solar specific REC. (iii) It will take some time before non- conventional technologies can compete with conventional sources in terms of cost of electricity. Therefore, procurement by distribution companies shall be done at preferential tariffs determined by the Appropriate Commission. Long term trajectory for RPO for the development of renewable energy to be prescribed by the Appropriate Commission.
Justification: Renewable Purchase Obligation (RPO) is fundamental to the growth of renewable energy as without this commitment, given higher cost of renewable energy, the States may not be willing to purchase such power. In order to meet the targets set up under the National Action Plan on Climate Change (NAPCC) the States should strive to make mandatory RPO equivalent to the minimum as per the NAPCC targets.
Stable RPO regime is a pre- requisite for promotion of renewable energy sources. The long term trajectory for Renewable Purchase Obligation would give greater visibility for the market players to plan their investment in the Renewable Energy Sector.
It is desirable that States should formulate long term trajectory for RPO for the development of renewable energy sector.
Amendment: Para 7.1 (6): However, in the following cases the exemptions from competitive bidding route may be adopted:

  1. 1200 kV EHVAC and HVDC systems upto 13th Plan i.e. year 2021-22, after which it shall be reviewed for introduction of competitive bidding.
  2. Works required to be done by CTU/STUs to cater to an urgent situation or, which are required in a compressed time schedule by CTU/STUs or, which are of National importance/backbone of National Grid, as decided by Central Government on case to case basis.
  3. The intra-state transmission projects by STUs will be exempted from competitive bidding route for further 2 years beyond 6.1.2011.
  4. Transmission scheme with estimated project cost less than Rs. 200 crores. This limit could be reviewed by the Ministry of Power from time to time.

Justification: There is a difference between the technology for 1200 kV EHVAC lines and sub-stations and HVDC stations and bipole. This involves different sets of equipments. Therefore as recommended by Empowered Committee it would be desirable to seek exemption from 1200 kV EHVAC system separately.
CEA is of the view that considering the technical complexity involved in the HVDC converter stations and the importance of control of flow of power in the HVDC converter stations in the national grid CEA is of the view that it should be exempted from tariff based competitive bidding route. HVDC bipole lines alongwith the converter stations form a complete system as a whole, and hence should not be seen in isolation, so both the bipole as well as convertor stations may be exempted from the realm of competitive bidding.
In its 30th meeting held on 31.10:2012 the Empowered Committee had recommended that projects costing less than Rs. 200 crores may be implemented through regulated tariff mechanism as small schemes are not amenable to tariff based competitive bidding as reputed parties may not be interested due to high overheads and the need for setting up independent O&M for 35 years.
Amendment: Clause 5.1 (d): Long-term PPA would be at least for 60% of the total saleable design energy. However, this figure of 60% would get enhanced by 5% for delay of every six months in commissioning of the last unit of the project against the scheduled date approved by the Appropriate Commission before commencement of the construction. The graded reduction in % of allowable merchant sales be limited to delays attributable to the developer. The time period for commissioning of all the units of the project shall be four years from the date of approval of the commissioning schedule by the Appropriate Commission. However, the Appropriate Commission may, after recording reasons in writing, fix longer time period for large storage projects and run-of-river projects of more than 500 MW capacity. Adherence to the agreed timelines to achieve the fixed commissioning schedule shall be verified through independent third party verification through a mechanism prescribed by the Central Government.
The graded reduction in % of allowable merchant sales may not be completely dispensed with since the provision of merchant power has been extended as an incentive for timely completion of projects. However, it is also felt that the provision to reduce the permitted percentage of merchant sale for delays in commissioning of the project, the total delay may be limited to the delay which is attributable to the Developer. 
Justification: It has been observed over time that hydro projects are prone to time and cost over runs due the reasons which are beyond the control of the developers. Over the past few years IPPs have been raising the issue of reduction in maximum permissible limit of Merchant Sale in Hydro Projects (i.e. 40%) on account of delay in Project construction beyond six months @ 5% for delay of every six months in commissioning of the last unit of the project. The IPPs have assigned various reasons for delay in commissioning the units including inter-alia geological surprises, R&R issues, law & order problems etc. They have represented that they ought not to be penalized for reasons which are beyond their control. During the 5th meeting of the Hydro Task Force some State Govts have raised the aforesaid issue of reduction in maximum permissible limit of merchant sale on account of delay in commissioning of projects.
The Division had suggested that notwithstanding the inherent uncertainties in completion of hydro projects as mentioned above, the graded reduction in % of allowable merchant sales may not be completely dispensed with since the provision of merchant power had been extended as an incentive for timely completion of projects. However, it is also felt that reduction in % of allowed merchant sale may be limited to the delay attributable to the Developer.

The graded reduction in % of allowable merchant sales may not be completely dispensed with since the provision of merchant power has been extended as an incentive for timely completion of projects. However, it is also felt that the provision to reduce the permitted percentage of merchant sale for delays in commissioning of the project, the total delay may be limited to the delay which is attributable to the Developer. 




Read More

Salient features of Pooling of prices of Domestic and Imported coal

No comments : Labels: , ,
Salient Features of Pooling of Prices of Domestic and Imported Coal

It has been proposed for pooling for the identified capacity of 60,000 MW which has been committed coal supply during the XII Plan period (option -I) with sector wise break up as Central Sector- 17,500 MW, State Setor- 12,675 MW and Private Sector- 29,825 MW for the plants commissioned/ to be commissioned during the period 01.04.2009 to 31.03.2015 and having PPAs with DISCOMs/ State Designated Agencies.
  • The proposed scheme would facilitate capacity utilization of new units, reduce logistic constraints along with rationalization of movement of imported coal and thereby reduce the cost of generation of power, recovery of cost of imported coal by charging its price in line with price of CIL's domestic coal of equivalent quality, utilization of power from new plants under merit order dispatch through across the board increase in the price of domestic coal supply of CIL among all the linked consumers.
  • In the competitively bid projects, the Developers conclude the PPAs based on the domestic coal LOA granted by CIL. The fuel charge escalation is permitted based on CERC notified escalation rates. The fuel charge based on imported coal may not be a pass through unless the coal supply is through CIL.
  • Imported coal to be supplied @ INR 4500 per tonne which is the price of domestic coal of equivalent quality instead of the prevailing price of INR 6000 per tonne. The coal quantity required to be imported for meeting the FSA commitments would be 15 million tonnes and 20 million tonnes in 2013-14 and 2014-15 respectively. In case option I is adopted, it will result to an increase of INR 58 and INR 71 per tonne in 2013-14 and 2014-15 respectively, with the percentage increase of 5 & 6 in the domestic coal prices.
  • Imported coal would basically be supplied to the plants which are nearer to coasts, irrespective of whether these have come up before 31.03.2009 or after that. There will be an increase of domestic coal to the new units coming up between 01.04.2009 and 31.03.2015 which are nearer to mines, corresponding to the decrease in coal supply to be made to the pre- 31.03.2009 coastal plants. Keeping in view the decisions conveyed by MoC on 17.02.2012 , supplies would be made in the following manner:-
    • New plants nearer to mines- domestic 80%
    • New plants nearer to coasts- domestic 65 % + imported 10% (eqvt. to 15% domestic coal)
    • Pre-31.03.2009 plants nearer to coasts- domestic 80%+ imported 6.67% (eqvt. to 10% domestic coal). Excess presently delivered to be diverted to (a) above.
    • Remaining pre-31.03.2009 plants- domestic 90%
  • Impact of price pooling on individual utilities will vary, depending upon proportion of existing and the new plants and their relative distance from associated ports and mines. If the mechanism is applied across the table, new utilities coming up after 31.03.2009 would benefit more.
  • The proposed mechanism would be price neutral to CIL as the higher cost of imported coal would be evenly distributed amongst all the old and new power plants using domestic as well as imported coal. It would however lead to savings of INR 1015 Crore and INR 1189 Crore by way of savings on rail freight in 2013-14 and 2014-15 respectively, as the proposed supply matrix would minimize movement of imported coal as well as domestic coal - thereby reducing the overall transportation costs.
  • The proposed mechanism would result to additional generation of power to the tune of 30 BU and 40 BU in 2013-14 and 2014-15 respectively.
  • The technological limitations of the plants for blending domestic coal with imported coal have to be kept in view while deciding the mechanism. To take care of this problem, it has also been proposed that lower GCV coal may be imported to match the characteristics of domestic coal.
  • Pooling of prices of domestic coal and imported coal would be an interim measure for 2013-14 and 2014-15 only. Depending upon its success, it can be extended further.
  • For meeting the remaining requirements, power utilities would continue to make their own imports which they are doing now.
  • Out of the 60,000 MW capacity for which option-1 has been proposed, where long-term PPAs with DISCOMs is a pre condition for coal supply, private sector is yet to tie up PPAs to the tune of 12,000 MW. As FSA commitments for this quantity are not to be met till the PPAs are in place, either the remaining 48,000 MW capacity may be supplied additional coal beyond FSA capacity or new units of 12,000 MW capacity may be adjusted for signing FSA.
  • Pooling of prices may benefit the private sector developers more, but the exact quantum of such benefits cannot be worked out because the power generated by the private sector will ultimately go to the DISCOMs for further supply to the consumers at regulated tariff. The proposed matrix of movement of imported and domestic coal in the proposed scheme would however, result to savings on rail freight, bringing down the overall transportation costs.
Source: Cerebral Business Research Pvt. Ltd.

Read More

Coal Pool Pricing – How and what it aims to work for?

9 comments : Labels: , ,
Coal Pool Pricing – How and what it aims to work for?

In regard to the commitment of 80% supply, it has been estimated that CIL would be able to meet roughly 65% of the committed quantity through indigenous sources during the first three years of the current Plan and shortfall from 80% would require to be met by imported coal.
  • In respect of the plants commissioned up to March 31, 2009, domestic coal will continue to be supplied as hitherto at Coal India Limited (CIL) notified prices.
  • In respect of the plants (with aggregate capacity of about 60,000 MW) commissioned/ to be commissioned during the period from 1.4.2009 to 31.3.2015 and also other plants (with aggregate capacity of about 7,000 MW) that are likely to be commissioned by 31.3.2015 after achieving milestones, CIL will provide imported coal on cost plus basis to all producers willing to take such coal, in addition to domestic coal producers who have already signed. Fuel Supply Agreements (FSAs) with the provision of imported coal to be supplied by CIL on cost plus basis will also be given an opportunity to exercise their option afresh for imported coal on cost plus basis. Such plants as are unwilling to take imported coal on cost plus basis will be supplied imported coal at a pooled price. The pooled price will be worked out by CIL as per the methodology and modalities mentioned in the note.
  • The guidelines in paragraph above will also be applicable in respect of the plants (with aggregate capacity of about 11,000 MW) which have been given tapering linkage.
  • The case of the plants (with aggregate capacity of about 16,000 MW) which would be commissioned by 31.3.2015 but which have not been given linkage, any be examined by an inter-ministerial committee headed by Secretary, Ministry of Coal to see it the guidelines in paragraph 2 above can also be applicable in respect of these plants with a appropriate lower trigger for penalty; and
  • The higher cost of imported coal will be allowed as a pass through as proposed in the note.
    The Committee directed that based on the above guidelines, the Ministry of Coal and the Ministry of State (Independent Charge) of the Ministry of Power will work out specific capacities / quantities in consultation with the Ministry of Finance and thereafter, the Ministry of Coal will place an appropriate proposal before the CCEA within five weeks.
Existing provision of import of coal
Under the New Coal Distribution Policy (NCDP) of October 2007, "normative requirement" of coal is required to be supplied under Fuel Supply Agreements (FSAs) at 100% level in respect of regulated sectors of Power Utilities, Fertilizer, Defence & Railways and at the level of 75% for remaining coal consuming sectors. Clause 5.2 of the NCDP provides that "In order to meet the domestic requirement of coal, CIL may have to import coal as may be required from time to time, if feasible. CIL may adjust its overall price accordingly".
Need for Import of Coal through CIL
As per the existing import policy, any entity can import coal. Every year, CEA/MOP sets targets for import of coal by different power utilities and imports are being made accordingly. The basic reason stated by Ministry of Power/CEA and the power industry for supply of imported coal by CIL is the assumption that the fuel charge based on imported coal may not be a pass through in the cases of the competitively bid projects unless the coal supply is through CIL. According to them, failure in supply of full linkage quantity by CIL as per FSA/MoU is likely to have the following consequences:
  • Developers are likely to default in supply of power as per PPA.
  • Developers may not be able to recover full capacity (fixed) charge as the availability will be much below 85%.
  • Default in payment by Developers (IPPs) to the Banks/FIs on account of non-recovery of capacity charge and ROE due to poor availability of plant.
  • The cost incurred by DISCOMs in arranging electricity from other sources through short term/medium term would be much higher.
Status of import of coal by power utilities during 2011-12 and target for 2012-13
  • The requirement of coal for Power Utilities for 2011-12 projected by CEA was 442 MT. Against estimated requirement, the indigenous availability was estimated at 388 MT (335 MT from CIL, 31 MT from SCCL and 22 MT from captive mines).
  • The gap of 54 MT between projected requirement and indigenous availability was proposed to be met through import of 35 Million Tonnes (which is considered equivalent to about 54 MT of indigenous coal) by Power Plants, during 2011-12.
  • Against the target of 366 MT for CIL and SCCL together, they supplied about 348.50 million tonnes, which is about 95% materialization, to the power utilities.
  • The power utilities imported 27 million tonnes against the target of 35 million tonnes (about 80% of the target) during 2011-12.
  • MOP has fixed a target of 46 MT for import by power utilities during 2012-13 to meet the gap between estimated indigenous availability and coal requirement. Till 31.10.2012, as against the pro-rata target of 26.8 MT, the power utilities have imported only 16.3 MT of coal. 
Source: Cerebral Business Research Pvt. Ltd.
Read More

Climate Change - A threat asking us to shift towards Renewables

No comments : Labels: , ,
Climate Change - A threat asking us to shift towards Renewable Energy

Climate change has long-since ceased to be a scientific curiosity, and is no longer just one of many environmental and regulatory concerns. As the United Nations Secretary General has said, it is the major, overriding environmental issue of our time, and the single greatest challenge facing environmental regulators. It is a growing crisis with economic, health and safety, food production, security, and other dimensions.

Shifting weather patterns, for example, threaten food production through increased unpredictability of precipitation, rising sea levels contaminate coastal freshwater reserves and increase the risk of catastrophic flooding, and a warming atmosphere aids the pole-ward spread of pests and diseases once limited to the tropics. 

The news to date is bad and getting worse. Ice-loss from glaciers and ice sheets has continued, leading, for example, to the second straight year with an ice-free passage through Canada's Arctic islands, and accelerating rates of ice-loss from ice sheets in Greenland and Antarctica. Combined with thermal expansion warm water occupies more volume than cold. The melting of ice sheets and glaciers around the world is contributing to rates and an ultimate extent of sea-level rise that could far outstrip those anticipated in the most recent global scientific assessment. 

There is alarming evidence that important tipping points, leading to irreversible changes in major ecosystems and the planetary climate system, may already have been reached or passed. Ecosystems as diverse as the Amazon rainforest and the Arctic tundra, for example, may be approaching thresholds of dramatic change through warming and drying. Mountain glaciers are in alarming retreat and the downstream effects of reduced water supply in the driest months will have repercussions that transcend generations. Climate feedback systems and environmental cumulative effects are building across Earth systems demonstrating behaviours we cannot anticipate. 

The potential for runaway greenhouse warming is real and has never been more present. The most dangerous climate changes may still be avoided if we transform our hydrocarbon based energy systems and if we initiate rational and adequately financed adaptation programmes to forestall disasters and migrations at unprecedented scales. The tools are available, but they must be applied immediately and aggressively.
Read More

Smart Grid Vision and Roadmap for India

No comments : Labels: , , , , , ,
Smart Grid Vision and Roadmap for India in Coming Five Year Plans
The most discussed topic by the budding young mangers of power is smart grids and reason being the vision, "Access, Availability and afforadability of Quality Power for All". Below is a description on how India has planned the roadmap  to achieve a complete smart grid in India in the five year plans. This is only a snapshot of the visionary document.

The roadmap is aligned to the Ministry of Power's overarching policy of "Access, Availability and afforadability of Quality Power for All" and it prescribes different technologies that would help achieve these objectives in time bound manner. This roadmap has placed highest importance to providing supply of electricity to all households by 2017 through smartgrid technologies. Ministry of Power is committed to working with all the state governments, Regulators and utilities to implement the programmes and policies envisaged in the smartgrid reoadmap.
Highlights of Smart Grid Milestones and Activities
During 12th Five Year plan
During 13th Five Year plan
During 14th Five Year plan
A) Enable Access and Availability of Quality Power for All
• Electrification of all households by 2017

• Reduction in power cuts;
24 hrs availability of power at principal cities, 22 hrs for all towns and Life line supply (8 hrs, including evening peak) to all by 2017 		• 24 hour supply in all urban areas; Minimum 12 hour supply to all consumers (including evening peak) by 2022 •Stable and quality 24x7 power supply to all categories of consumers across the
country
B) Loss Reduction
• Reduction of AT&C losses in all Distribution Utilities to below 15%
• Reduction of transmission losses (66 kV or above) to below 4% 		• Reduction of AT&C losses in all Distribution Utilities to below 12%
• Reduction of transmission losses (66 kV or above) to below 3.5% 		• Reduction of AT&C losses to below 10% in all Distribution Utilities
• Reduction of transmission losses (66 kV or above) to below 3%
C) Smart Grid Rollouts including Automation, Microgrids and other improvements
• SG Pilots, full SG roll out in pilot project cities
• Infrastructure for AMI roll out for all consumers with load
>20kW or as per prioritised target areas of Utilities
• Deployment of Wide Area
Monitoring Systems (WAMS)

• Development of micro grids in
1,000 villages/industrial parks/commercial hubs
• Enablement of “Prosumers”
in select areas 		• SG roll out in all urban areas

• Nationwide AMI roll out for customers with 3-phase connections.

• Deployment of WAMS at all substations and grid connected generation units
• Development of micro grids in total 10,000 villages/industrial parks/commercial hubs
• Enablement of “Prosumers” in metros and major urban areas 		• SG rollout nationwide

• Nationwide AMI roll out for all customers


• Development of micro grids in
20,000 villages/industrial parks/commercial hubs
• Active Participation of
“Prosumers”
D) Policies and Tariffs
• Implementation of Dynamic
Tariffs

• Mandatory Demand
Response programs for select categories of consumers
•Tariff mechanism for roof top solar PV's – Net Metering/Feed in Tariffs 		• Choice of electricity supplier (open access) to consumers in metros and select urban areas
• Mandatory Demand
Response programs for larger sections of consumers 		• Choice of electricity supplier (open access) to all consumers
E) Green Power and Energy Efficiency
• Renewable integration of 30
GW
• Energy Efficiency Programs for lighting and HVAC in Metros and state capitals; initiation of Dynamic (smart) Energy Efficiency Programs
• Policies for mandatory roof top PV and Energy efficient building code for all new large public infrastructures by 2014 		• Renewable integration of 80
GW
• Energy Efficiency Programs for lighting and HVAC in all urban areas; expansion of Dynamic (smart) Energy Efficiency Programs to all urban areas 		• Renewable integration of 130
GW
• Dynamic (smart) Energy Efficiency Programs nationwide
F) Electric Vehicles and Energy Storage
• Development of EV and smart grid synergy plan (in coordination with National Electric Mobility Mission)
• EV charging stations in urban areas and along selected highways
• Introduction of Battery Parks and other Energy Storage Systems on trial basis 		• Large roll outs of Energy
Storage Systems


• EV charging stations in all urban areas and strategic locations on highways 		• EV charging stations in all urban areas and along all state and national highways
G) Enablers and Other Initiatives
• First set of technical standards after completion of pilots, including standards for EVs and its charging infrastructure
• Cost-Benefit Analysis of smart grid projects with inputs from the pilots and assessment of direct and indirect benefits to consumers and other stakeholders
• Development of indigenous low cost smart meter by 2014
• Finalization of frameworks for cyber security assessment, audit and certification of power utilities by 2013
• Initiation of Customer Outreach and Engagement Programs
• Research & Development, Training & Capacity Building -
10% Utility technical personnel to be trained in smart grid technologies 		• Standards Development for Smart Infrastructure (SEZ, Buildings, Roads/Bridges, Parking lots, Malls)

• Export of SG products, solutions and services
• Development of business models to create alternate revenue streams by leveraging the smart grid infrastructure to offer other services (security solutions, water metering, traffic solutions etc) to municipalities, state governments and other
agencies; integration of meter data with other databases
etc. 		• Continuous Research & Development; Training & Capacity Building



Source: Cerebral Business Research Pvt. Ltd.
Read More

State-wise Status of Financial Restructuring Plan for Discoms

No comments : Labels: , , ,
State-wise Status of Financial Restructuring Plan for Discoms
It has now been more than a year after the release of order for financial restructuring of DISCOMS. The State-wise status of implementation of Financial Restructuring Plan for Discoms is given below and you may post your comments below regarding the same.
  1. Tamil Nadu:Discoms have already issued bond for 100% of the required amount to 24 Bankers and restructuring has also been completed. Bankers have also agreed to sanction 70% of operational losses of 2012-13 and balance 30% losses will be sanctioned by end of July 2013. State Government is taking over the liability by issuing special security in a period of 2 years instead of the maximum time allowed i.e. 5 years and the first year phasing is likely to be completed in July. Phasing for 2013-14 will be INR 3000 Crore and for 2014-15 INR 3300 Crore. Tariff increase for 2012-13 is 37% and for 2013-14, increase is 4%. Tamil Nadu Discom has informed that prepaid meters may not be required as they do not have any outstanding energy bills; State governments as well as large consumers are making payments in a timely manner. Tamil Nadu Discoms have low AT&C losses, therefore, involvement of private participation may not be required. However, the matter has been discussed with State government. Ministry of Power has suggested that option of private participation in some towns or rural areas having higher AT&C losses may be explored. Tamil Nadu Discom informed that UCO bank has sanctioned only INR 185.15 Crore out of their share of INR 610 Crore in 70% cash loss funding due to exposure norms constraint.
  2. Uttar Pradesh: FRP was finalized and bankers have verified it independently. It informed that bonds have not yet been issued as bonds could be issued only after all bankers agree to it. However, they are absolutely ready for it. Dena Bank & State Bank of India have not yet submitted the proposal to their head office & exposure limit of Allahabad Bank has been exhausted. A meeting of consortium of all bankers is being organized on 10th July to resolve the issue. MoP has asked DFS to take up the issue with Banks and requested that a suitable mechanism may be introduced to address such common issues. UP Government has informed that bonds are likely to be issued to bankers by end of July 2013. However, PFC & REC are not willing to take the bonds. The State Government also informed that out of total loan (INR 7844 Crore) sanctioned against operational losses, INR 1000 Crore has been disbursed by bankers. Tariff increase for 2012-13 is 20%, and for 2013-14 it's 9%. State Government will take over bonds amounting to INR 3500 Crore in 2013-14.
  3. Rajasthan: Earlier banks had lot of issues with regard to FRP but now bankers have agreed to it. However, except PNB no bank has yet sanctioned any amount. Rajasthan Government further informed that out of total 36, banks 9 banks have not yet sent the proposal to their head offices. Bonds are likely to be issued by end of July 2013 after banks convey their approval. State Government has given phasing of INR 3000 Crore 4500 Crore and 5700 Crore for the year 2013-14, 2014-15 & 2015-16 respectively for taking over bonds. Tariff increase for 11-12, 12-13 & 13-14 is 23%, 18.5% and 13.6% respectively.
  4. Haryana: Banks are charging higher interest on account of NPV protection on amount restructured prior to introduction of FRP scheme. The Bonds will be issued by end of September 2013. Tariff increase for 10-11, 12-13 and 13-14 is 4%, 16% and 13% respectively. Operational losses funding required for 2012-13, 2013-14 & 2015-16 is INR 3000 Crore, 3209 Crore and 3467 Crore respectively. The amount of funding of operational losses projected was increasing, which is against the spirit of FRP, this requires detailed examination by the State Government
  5. Himachal Pradesh: UCO bank was appointed as Nodal Bank for FRP. However, UCO bank has no exposure in HP Discoms; therefore UCO bank advised to appoint SBI as nodal banker, the request is pending with DFS. Due to this problem, banks have yet to respond. Tariff increase for 2011-12, 2012-131 2013-14 is 9%, 12% and 13% respectively. HP government informed that they have not yet finalized their accounts & it will take time beyond 31st July 2013.
  6. Meghalaya: Has responded to FRP very late & they got nodal bank appointed in June 2013 only. Therefore, the matter is now being taken up with the banks. Tariff increase for 10-11, 11-12, 12-13 and 13-14 is 7%, 1%, 15% and 7% respectively. Accounts of 10-11 & 11-12 are yet to be finalized.
  7. Andhra Pradesh: Discom's have huge Short term loans however books do not have corresponding accumulated losses due to their accounting policies of booking irrecoverable trade receivables in revenue. However auditors have qualified their books on this issue. Credit rating agencies like ICRA and CRISIL have also given lower rating considering the huge trade receivables.
  8. Karnataka: Has similar problem as in case of Andhra Pradesh. State Government has not yet given consent to FRP.
  9. Bihar: Electricity board has been unbundled after 31.03.2012. Transfer notification has been issued and transfer of assets has also been completed. The State government has conveyed that it is ready to abide by all conditions. MoP has stated that losses & liabilities of distribution business only be considered and AG certification will be required in this regard. The Government of Bihar assured that they will furnish details of distribution business losses certified by AG in two weeks. It has also informed that Canara Bank (Nodal Bank) has given in principle approval to FRP. Tariff increase for 11-12, 12-13, 13-14 is 19%, 12% and 6.9% respectively.
  10. Jharkhand: Jharkhand could not un-bundle as on 31.03.2012 due to Supreme Court's Stay. The Stay has been vacated and they have taken up the unbundling process & transfer notification is likely to be issued by 15th July 2013 & they have no STL outstanding to Banks. The State government has informed that they have outstanding energy bills of INR 148 Crore which have been agreed by State Government and payment of INR 50 Crore has already been received. The government has been asked to release the balance amount before 31st July 2013. Jharkhand had no dues with Banks but it has to pay INR 2300 Crore to DVC & INR 1500 Crore to TVNC. Tariff increase for 10-11, 11-12 & 12-13 is 18%, 16% and 16% respectively.
  11. Kerala: State Government decided to form strategic business units instead of unbundling into separate companies. MoP has clarified that FRP scheme cannot be taken up without fulfillment of mandatory conditions, particularly, unbundling of the State Power Utility.


Read More

Key Highlights of State Electricity Distribution Management Responsibility Bill, 2013

1 comment : Labels: , ,
Key Highlights of State Electricity Distribution Management Responsibility Bill, 2013

The new bill “State Electricity Distribution Management Responsibility Bill, 2013” aim at providing for responsibilities of the State Government to ensure financial and operational turnaround and long-term sustainability of the State-owned Distribution Licensee to enable adequate electricity supply to consumers through financial restructuring, support on sustainable basis in the areas of long term planning, corporate governance, regulatory compliances, and laying down of policy directives and various other measures. The Key highlights in the bill are discussed below.

Statement to be laid before the State Legislature
  • The State Government shall lay, in each financial year during the Budget Session,  a State Electricity Distribution Management Statement on the measures taken by the State Government in relation to electricity distribution in the State including, in the areas of long-term planning, consumer protection, regulatory compliance, corporate governance, financial restructuring of the State Distribution Licensee, so as to bring about the operational and financial viability of the State Distribution Licensee, on sustainable basis.
  • Prepare and action plan on long-term, medium term and short-term basis, laying down time bound programme to execute strategic priorities to achieve Key Performance Indicators, monitor and ensure compliance of the KPIs and strategic priorities
Long term Planning for sustainability of State Distribution Licensee
  • The State Government shall take appropriate measures on Distribution Licensee estimates of demand, AT&C Loss and availability of electricity on long term basis and, contracts, with the approval of the State Commission, through long/ medium/ short term agreements for purchase of power to meet the demand.
  • State Distribution Licensee undertakes energy accounting and auditing of all 33 kV feeders, 11 kV feeders and Distribution Transformers along with consumer indexing and time bound metering of each category of consumers.
  • State Government shall declare the quantum of subsidy in advance categorically stating the consumer or the class of consumers to whom it is to be provided and also timely release of subsidies
  • Ensure that there are no arrears of electricity charges for electricity supplied to various departments and institutions of the State Government on or before the date of coming into force of this Act.
  • Ensure that the State Load Despatch Centre is operated within six months from the date of coming into force of this Act, by a Government company or any authority or corporation.
Financial Restructuring Plan for State Distribution Licensee
  • State government to ensure that the trajectories of the operational and financial parameters in the Financial Restructuring Plan (FRP) are achieved within the stipulated time frame.
  • State Government shall make FRP or such other financial scheme a part of the State budget statements for effective monitoring of its impact on the State finances.
  • State Government shall ensure that the State Distribution Licensee does not resort to short term loans for funding operational losses except as provided in the FRP.
Accounting measures
  • State government shall establish an Empowered Committee to ensure identification, provisioning and write offs of receivables and bad and doubtful debts.
Corporate Governance
  • State Government to ensure that the Board of Directors of the State Distribution Licensee has an optimum combination of functional, nominee and independent directors.
  • State Government shall lay down a code of conduct in line with the Guidelines on Corporate Governance for Public Sector Enterprises.
Regulatory compliance and tariff filings
  • State Government shall ensure regular and timely filing of true-up petitions, Aggregate Revenue Requirement (ARR) and tariff petitions, and petitions for adjustments on account of fuel and cost of power purchased by the State Distribution Licensee.
  • State Government to make fiscal provision or provision of grant to the State Distribution Licensee.
Memorandum of Understanding
  • State Government and the State Distribution Licensee shall enter into a memorandum of understanding for setting targets for KPIs and performance evaluation.
  • State Distribution Licensee shall submit every six months, a report to the State Government, on its operational and financial performance.
Monitoring Mechanism
  • The State Government shall establish a Committee for effective implementation of this Act.
Measures to enforce compliance and Applicability
  • The committee established shall review and recommend remedial measures, if any, every quarter, compliance of the obligations cast on the State Government under this Act and the State Government shall place before the State Legislature.
  • Nothing in this Act shall apply to any Distribution Licensee that is not owned or controlled by the State Government




Source: Cerebral Business Research PVt. Ltd.
Read More

A brief Status of Progress of Implementation of R-APDRP During 2012-13

1 comment : Labels:
A brief Status of Progress of Implementation of R-APDRP During 2012-13
  • Part-a (IT)
    • Projects worth Rs.5196 Cr sanctioned for all eligible 1402 towns in 29 States/ UTs. [ITIAs appointed by all states]
    • Data Center commissioned in 9 states (AP, Gujarat, Karnataka, Maharashtra, MP, Punjab, UP, Uttarakhand and WB) & 239 Towns integrated to Data Center
  • Part-a (scada)
    • Projects worth Rs.1442 Cr sanctioned for 63 of 67 eligible towns
    • SIA appointed for 32 Towns
  • Part-b
    • Projects worth Rs.25685 Cr sanctioned for 1132 of 1150 env. towns
    • Implementation Agencies appointed for 669 Towns.
    • Funds Released Under R-apdrp: Rs.6600.67Cr
Categorization Of States (On Basis of Implementation)
  • Category-I: States Progressing Well: Gujarat, West Bengal, Andhra Pradesh, Uttaranchal, Madhya Pradesh, Karnataka, Punjab, Maharashtra, Uttar Pradesh
  • Category-ll : States Progressing Satisfactorily, but need to expedite: Rajasthan, HP, Tamil Nadu, Bihar, Jharkhand, J&K and NE states
  • Category-Ill: States Lagging in Implementation: Haryana, Kerala, Chhattisgarh, Goa
Points for Discussion
  • Development & Testing of software modules: Business Process automation and integration with legacy system taking longer time. Karnataka. Raiasthan. TN, Bihar. Goa. Jharkhand & J&K delayed on this count
  • Longer time for establishment of Meter Data Acquisition System (Delays in Arun. Pradesh. Naealand. Maniour. J&K and Jharkhand)
  • Establishment of GIS (Consumer indexing and assets mapping) State utilities to form joint team to speed up validation process.
  • Network connectivity also a challenge. WB. AP. UP. Uttrakhand and NE states are facing issues of last mile connectivity
  • Lack of Domain Knowledge in IT by Utilities
Extract from: Cerebral Business Research Pvt. Ltd
Read More

Comparison of Earlier Tariff System and Availability Based Tariff (ABT)

1 comment : Labels: ,
Comparison of Earlier Tariff System and Availability Based Tariff (ABT)
Description of item
Earlier system
Draft ABT proposal
ABT order
Capacity / Fixed Charge Annual Fixed Charge (AFC) include :
a). Interest on loan
b). Depreciation
c). O&M
d). Return on Equity
e). Income-Tax
f). Interest on Working Capital  		Fixed charges excluding ROE i.e. all other five items of the existing system. ROE treated separately Capacity charge as per existing system
Basis of recovery Recovered at 62.79% deemed PLF. 50% AFC at 0% PLF and full recovery at 68.49% deemed PLF. FC excluding RoE recovered at 30% availability on pro-rata basis between 0% and 30% availability. ROE recovered on pro-rata availability between 30% and 70% Pro-rata recovery of capacity charge for :i) NTPC stations: between 0 to 80% availability in the first year and 0 to 85% availability in the second year ii) NLC Stations Between 0 to 77% availability in the first year and 0 to 82% availability in the second year iii) NHPC Stations between 0 to 85% availability in the first year and availability in the second year to be announced by the commission separately. 
(Note: RoE, in all the three cases would be recoverable proportionately upto 80%, 77% and 82% for thermal, lignite and hydro power projects respectively. Beyond, this level, 100% RoE is recoverable.)
Incentives Above 68.49% deemed PLF, incentives at 1 paise/KWh for each 1% increase in PLF. Incentive beyond target availability of 70% is as follows:
(a) 70% to 85% : 0.4% of equity for each 1% increase in availability beyond 85%. 		1 paise/KWh/each percentage increase in PLF of 80%/ 85% in the first/ second year for NTPC/NLC and 85% in  the first year for NHPC..
Sharing of fixed cost Based on actual energy drawls Based on allocated capacity Based on allocated capacity
Recovery of variable cost Based on actual energy drawls Based on Scheduled Energy Based on Scheduled Energy
Deviations from schedule – UI charges No penalties for such deviation Varying between 0 to 360 paise/kwh for the frequency range of 50.5 Hz to 49 Hz Varying between 0 to 420 paise/kwh for the frequency range of 50.5 Hz to 49 Hz
Norms for tariff determination GOI Tariff notification GoI Tariff notification GoI Tariff notification till such time Commission finalizes its views.
Procedure for payment of capacity charge if ABT is introduced in the middle of a financial year Not applicable Not specified Specified
Prolonged Outages Included in item (2) above Provided for payment of adjusted capacity charges Does not provide for payment of capacity charges
Marketing of surplus energy Not applicable Not specified Encouraged and will not require commission’s approval
Splitting up of capacity and energy charge for hydro stations. Capacity charge covered depreciation and interest on loan. Energy covered ROE, income tax, O&M and interest on working capital. Capacity charge covered depreciation and interest on loan. Energy covered ROE, income tax, O&M and interest on working capital. Till such commission notifies peak and off-peak energy rates for hydro-stations, primary energy charge would be taken as 90% of the lowest variable charge of the thermal power station in the concerned region. The balance of total charges would be recovered as capacity charges.
Payment of dues to generators As per agreements As per agreements As per orders of the commission
Applicability All central generating stations All central generating stations staggered region wise i). ABT implementation is staggered region wise ii) Fixed charge recovery and basis for incentive payments revised from 1st April, 2000.iii)  GOI to decide about ABT for automatic power stations.
PLF for incentives during interim period Not applicable Not specified. Till the introduction of ABT in other regions and after 1.4.2000, the actual PLF for incentive purposes for NTPC shall be 80% instead of deemed PLF of 68.49%. The PLF in the first year for incentive purposes for NHPC shall be 85%.
Read More

Statewise Prominent Issues in Implementation of RGGVY

No comments : Labels: ,
Statewise Prominent Issues in Implementation of RGGVY 
  • Arunachal Pradesh:
    • Slow progress in Kurung Kumai, East Kameng and West Siang
    • 12 new substations are yet to be completed
    • Over 650 villages are yet to be energized
  • Bihar:
    • Slow progress in Katihar project.
    • Over 1700 villages are yet to be energized
    • 71 substations are yet to be completed
    • Land for one substation of Vaishali project yet to be provided
    • 11 projects sanctioned in Phase-ll are yet to be awarded.
  • Chhattisgarh:
    • Slow progress in Bastar project.
    • Over 400 villages are yet to be energized
    • 7 new substations in Bastar, Dantewada and Sarguja projects are yet to be completed.
  • Jammu & Kashmir:
    • Non-issuance of 'C form certificate by the state and non-reimbursement of work contract tax, causing financial distress for the contract agencies executing the projects.
    • 12 new substations are yet to be completed in Doda, Kargil and Leh projects. Poor progress in Kupwara 10th Plan project (sanctioned in October 2005).
  • Mizoram:
    • Slow progress in respect of electrification of villages as well as providing free service connection to BPL households.
    • 6 new sub-stations are yet to be completed.
  • Jharkhand:
    • 26 new substations are yet to be completed.
    • Works in Palamu, Latehar and Garhwa have stopped.
    • Delay in creation of upstream network in Simdega, Giridih and Chatra districts.
    • Over 1800 villages yet to be energized.
    • Progress under 6 projects of 11th Plan is not satisfactory.
    •  Works yet to begin in 7 new projects sanctioned in Phase-ll
  • Manipur:
    • Slow progress in Churachandpur, Ukhrul and Senapati
    • 11 new sub-stations are yet to be completed.
  • Meghalaya:
    • Slow progress in respect of East Garo Hills, South Garo Hills and West Garo Hills
    • Not a single substation completed out of total 5 sub-stations
    • 650 villages yet to be energized.
  • Odisha:
    • Delay in taking over of the completed villages by the State DISCOMs.
    • Over 1000 villages yet to be energised
  • Punjab:
    • Non-completion of electrification works in 11840 partially electrified villages and poor progress in release of BPL connections.
  • Uttar Pradesh:
    • None of the 22 projects sanctioned under Phase-ll (8 projects in December 2011 and 14 projects in March 2012) has been awarded so far.
  • West Bengal:
    • Land for one new substation is yet to be handed over for Purulia project and over 5 lakhs BPL households are yet to be provided with free electricity connections under this scheme for the State.
    • Darjeeling district sanctioned under Phase-ll in February 2012 is yet to be awarded.
Issues for Discussion :
  1. Timely & quality implementation.
  2. Regular review & monitoring.
  3. Providing upstream networks.
  4. Energisation and maintenance of infrastructure.
  5. Regular supply of quality power.
RGGVY: Coverage vs Achievement as on 01.01.2013
Projects Approved under No. of Projects Sanctioned Cost (Rs. Cr.) Funds Released (Rs. Cr.) Un-electrified Villages (Nos) Intensive Electrification of  Partially-electrified Villages (Nos)  Free Electricity Connection to BPL Households (Nos. in Lakhs)
Scope Achmt Scope Achmt Scope Achmt
10th Plan 235 13304 11729 64745 63528 104550 99047 77.28 75.8
11th Plan 341 20943 17019 46141 42680 237981 185862 152.11 128.06
Total Phase-I (X+XI) 576 34247 28748 110886 106208 342831 284909 229.39 203.86
Phase-ll 72 8104 318 1909 0 53505 0 45.59 0
G. Total 648 42351 29066 112795 106208 396336 284909 274.98 203.86
 Source: Cerebral Business Research

Extract from: Cerebral Business Research Pvt. Ltd
Read More

Overview of Indian Power Sector (2012-13)

1 comment : Labels: , , , , , ,
Overview of Indian Power Sector
Generation
As on 28th February 2013, India's Installed Capacity stood at 214630.02 MW. Thermal sources continued to have a dominant share accounting for two-thirds of the capacity at 144544.48 MW, followed by hydro- power with 19% or 39449.4 MW, renewable energy with 12.1% or 25856.14 MW and nuclear power with 2.3% or 4780 MW. Overall, the capacity addition during the Eleventh Plan stood at 54,964 MW. This accounted for 88 per cent of the revised target of 62,374 MW set by the Planning Commission in its midterm appraisal and 70 per cent of the original target of 78,700 MW. Also, 14,660 MW of grid-connected renewable capacity was added against the target of 14,000 MW.

Source: Central Electricity Authority

The proposed targets are higher than those suggested by the Working Group on Power for Twelfth Plan. It has suggested a capacity addition target of 75,785 MW of conventional capacity, 18,500 MW of renewable capacity and 13,000 MW of captive capacity. The conventional capacity addition includes 62,695 MW of coal-based projects, 9,204 MW of hydro capacity, 2,800 MW of nuclear capacity and 1,086 MW of gas- based capacity. The private sector is expected to contribute the maximum at 42,131 MW accounting for 56 per cent of the total capacity addition while the central sector is expected to account for 26 per cent (19,858 MW) and the state sector, which currently has the highest installed capacity, will contribute only about 18 per cent (13,796 MW).
In terms of power generation the achievement by the end of February 2013 has been 831435.46 MU which is 98.23% against the targeted value of 846398.00 MU, the sector recorded a growth of 8.1 per cent in 2011-12 to reach 876,888 MU's from 765,832 MU's in 2010-11. In comparison, it recorded a growth of only about 5.2 per cent in 2010-11 over the previous year.

Source: Central Electricity Authority
The private sector's contribution in the total installed capacity has been increasing consistently from 8.66 per cent in March 2003 to 27 per cent in March 2012 since the passage of the Electricity Act, 2003. This share is expected to increase further to 40 per cent by 2017 if all the targets proposed by the working group are met. The private sector contributed about 42 per cent of the total addition during the Eleventh Plan period, over 10 times more than its contribution in the Tenth Plan period.
Energy and Peak Shortages
Improving the PLF's of existing plants is crucial, particularly in light of the high average and peak shortages in the country, and also because greenfield projects. The plant load factor (PLF) of thermal plants stood at 69.97 during 2012-13 (up to February 2013) while that of 73.32 per cent during 2011-12. The availability of power from new baseload capacities led to a fall in average shortages in the past two to three years, these continue to be significant in absolute terms. The peak shortage recorded during 2012-13(up to February 2013) stood at 9.0% while that of 10.6% during 2011-12 was higher than that in the previous year (9.8 per cent) due to severe coal shortages during September-December 2011.

Source: Central Electricity Authority
Coal Consumption by Thermal Power Plants
Thermal power generation suffered a shortfall of 20 BUs during 2011-12 - 9 BUs and 11 BUs due to a shortage of coal and gas respectively. The coal consumption in the year 2011-12 has been 417.56 MT and 387 MT in the year 2010-11. almost all new thermal capacity added during the Thirteenth Plan is expected to be supercritical, given that the gov­ernment has decided to grant coal link­ages only to such projects.

Source: Central Electricity Authority

Transmission
The recent grid failure, which resulted in the world's biggest blackout, plunging 21 states and 600 million people into darkness, reaffirms the need to establish a strong and resilient power transmission network in the country. While 88 GW of generation capacity is proposed to be added in the Twelfth Plan (2012-17) to meet the rising demand for power, a reliable and efficient transmission network is critical to leverage the new capacity.
There have been several positive developments in the transmission segment. Private investments, which increased to 14 per cent of the total transmission investments in 2010-11, became more attractive with tariff-based competitive bidding for all interstate transmission projects being made mandatory from 2011. The implementation of a new direction- and quantum- sensitive transmission pricing mechanism in July 2011 is beginning to pro- age lines, and 425,866 MVA of transformer capacity at the 220 kV and above voltage levels. The ±500 kVhigh voltage direct current (HVDC) links had a capacity of 14,200 MW. The transmission line length grew at a CAGR of 7 per cent between 2007-08 and 2011-12. This growth was mainly driven by the addition of 765 kV and 400 kV lines, with the length of 765 kV lines doubling between 2009-10 and 2011-12.

Source: Central Electricity Authority
The transmission target has been set at 109,440 ckt. km of line length and 270,000 MVA of substation capacity. About 27,000 ckt. km will be constructed at the 765 kV voltage level. The HVDC capacity is expected to almost double from 13,500 MW to 26,500 MW by the end of the Thirteenth Plan period. The interregional transfer capacity addition target is 37,800 MW, or one and a half times the existing transfer capacity. Further, the 765 kV transmission system associated with the Krishnapatnam UMPP, which will be commissioned in 2013-14, will facilitate synchronisation of the southern regional grid with the north-east-west grid, marking the creation of a synchronous national grid.
Powergrid is constructing 11 high capacity transmission corridors at an estimated cost of Rs 580 billion to evacuate around 80 GW of power, which is scheduled to be commissioned over the next five to seven years. The generation projects comprise six ultra mega power projects (UMPPs) aggregating 28 GW and independent power plants with a combined capacity of 55 GW concentrated in the coal belts of the country's eastern regions and coastal areas.
These entail the construction of 23,000 ckt. km of transmission lines, of which more than 70 per cent will be at the 765 kV level; 29 substations of more than 60,000 MVA capacity; and four HVDC terminals of 7,000 MW capacity. Powergrid plans to start commission- by the states were the key reasons for the grid collapse in July 2012, as per the Central Electricity Regulatory Commission's (CERC) panel report on the grid failure. To prevent this in future, the power ministry plans to amend the existing legislations pertaining to the sector. These amendments will aim at vesting powers in the CERC to prevent states from overdrawing beyond their allotted quota. The ministry is also looking at amending the existing Indian Electricity Grid Code (IEGC) for putting in place a defence mechanism to prevent future blackouts as well as ensuring that states adhere strictly to the IEGC norms.
To effectively implement the new transmission tariff structure based on the point-of-connection (PoC) methodology, the CERC amended the existing regulations in November 2011 and March 2012. This new transmission pricing mechanism not only allows for the sharing of transmission costs among emerge as the main transmission network voltage in the future. Technologies like gas-insulated switchgear substations and supervisory control and data acquisition for substation automation, compact tower designs, and aluminium conductor steel reinforced conductors are witnessing faster adoption at both the central and state levels.

Distribution
Renewed efforts are being made to reform the power distribution segment. Long-delayed tariff revisions are being undertaken due to both regulatory and lender pressure. The latter has also driven debt restructuring to address the issue of weak utility finances. At the operational level, there is a greater acceptance of information technology (IT) as utilities try to reduce losses and improve business processes. The challenge, however, lies in sustaining these reforms. AT&C Losses in the country have been very high and is the major concern that the country's utilities face. The losses according to the PFC report on distribution utilities for the year 2010-11 has been 26.2% and the T&D losses during the same year has been 24.0%. Both these have reduced by a value close to 8% from the year 2003-04 which were 34.8 and 32.5 respectively.

Source: Central Electricity Authority
Investments worth Rs 300 billion have been planned by the distribution utilities during the Twelfth Plan period. The key focus areas are loss reduction and network upgradation. Some of the major initiatives in this regard are feeder segregation schemes, improvement of metering practices and increasing IT penetration. Utilities in Andhra Pradesh and Gujarat have undertaken feeder segregation to improve the quality of power supplied to rural and agricultural consumers. This has been complemented with high voltage distribution systems. IT deployment has increased in the power distribution segment, partly due to government support. For several utilities, it has enabled a target-based loss reduction. Enterprise resource planning has been among the leading IT applications. Other key applications include supervisory control and data acquisition, customer relationship management and distribution line maintenance systems. Also, utilities with an already established IT infrastructure base are now deploying key functionalities such as outage management systems, geographic information system (GIS) and asset management systems.
At the financial level, the utilities' debt position has been a cause of concern. Industry estimates put their accumulated debt at over Rs 1 trillion. This has adversely impacted their creditworthiness and, in some cases, led to the rejection of short-term loan proposals by banks. To avoid an impending financial crisis, comprehensive debt restructuring has been undertaken. For the second time in about a decade, the government has approved a debt restructuring package to clean up the discoms' books of accounts. This package involves half of the loans being transferred to the state governments, for which bonds will be issued. Financial institutions will restructure the remaining half of the outstanding loans.
The emerging business environment of power distribution involves rising power purchase costs, stringent finan­cial scrutiny as well as regulatory focus on performance and consumer satisfac­tion. The key areas of cost pressure are thermal power generation costs, slip­pages in generation capacity addition, higher capital costs of new generation projects and debt servicing costs. This necessitates tariff revisions and explains the increasing number of utilities adopting multi-year tariffs to recover fuel cost escalations.
The long-pending issue of open access at the distribution level is now being taken up. The MoP recently noti­fied that all industrial consumers (1 MW and above) will be deemed "open access consumers". These consumers can buy power from another supplier or from the open market by issuing a notice to the discom and the discom is obligated to provide network access. While this benefits industrial consumers, it has ramifications for the utilities' business. The risk lies in the migration of high- value consumers, that is, the industries that often cross-subsidise other consumer categories.
Extract from: Cerebral Business Research Pvt. Ltd.
Content by: Prashanth Dudi, Research Analyst.
Email: p.dudi@cerebralbusiness.com
Read More
Subscribe to: Posts ( Atom )