ANDHRA PRADESH ELECTRICITY REGULATORY COMMISSION
11-4-660, 4th and 5th floors, Singareni
Bhavan, Red hills,
O.P.No. 506 of 2002
Dated: 29 -
07 - 2002
Sri. G.P.Rao, Chairman
Sri. D.Lakshminarayana, Member
Transmission Corporation of
Andhra Pradesh Limited (APTRANSCO)
…….. Applicant
The matter of load forecasting for the period FY 2000-2001 to FY 2006-2007 has come up before the Commission during the hearing of various PPA’s between the APTRANSCO and IPP’s. APTRANSCO has submitted the power purchase agreements (PPAs) of BPL, RTPP-II, BSES, GVK-II, Konaseema, Vemagiri and Gautami power projects, for the consent of the Commission.
In this context, the Commission has analysed the demand forecast and
supply expansion plan with reference to the business plan of APTRANSCO. The
Commission having considered the written submissions of APTRANSCO, through
letters dated
ORDER
1)
Provisions in the Andhra Pradesh Electricity Reform Act:
As per the Sections 21 (4) (b) of the Andhra Pradesh Electricity Reform Act, 1998, a holder of a supply or transmission licence may enter into arrangements for the purchase of electricity from any person or Generating Company with the consent of the Commission
Section 11(1)(g) of the Reform Act provides for one of the functions of the Commission as to forecast on the demand and use of electricity.
2)
Provisions in the License:
The transmission and bulk supply license issued to APTRANSCO (OP No. 3&4 of 1999) provides that the Licensee shall not purchase electrical capacity and/or energy without an authorisation granted by the Commission under the terms of paragraph 16 of this license. It mentions in Paragraph 16.2:
“The Licensee shall purchase electrical capacity and/or energy in an economical and efficient manner and under a transparent power purchase or procurement process and in accordance with the Regulations, directions, guidelines and orders made for the purpose by the Commission from time to time.”
Paragraph 16.4 of the license further mentions:
“An authorisation required under Paragraph 16.1 shall be granted when the Licensee has demonstrated to the Commission’s satisfaction that:
(a) The additional electrical capacity and/or energy is necessary to meet the Licensee’s service obligation in accordance with Paragraph 17 (this relates to the power supply planning and security standard); and
(b) The Licensee has examined the economic, technical, system and environmental aspects of commercially viable alternatives to the proposals for purchasing additional electrical capacity and/or energy and such examination has been carried out in a manner approved by the Commission.”
3)
Power procurement guideline:
As per paragraph 3.3.1 of the Power procurement guidelines issued by the Commission, APTRANSCO shall formulate a resource plan for the State in co-ordination with the Distribution and Generating Companies, and in consultation with the State Government, the Commission, the Regional Electricity Board, the Government of India and the Central Electricity Authority which shall take into account all the available generation resources and shall spell out the additional power required to meet the future energy demand of the State as assessed by the Licensee (a "Power Procurement Plan").
Paragraph 3.3.3 further mentions that each Power Procurement Plan shall describe:
(a) Existing resources including generating plant exclusively contracted to APTRANSCO, allocation from central sector plants (CSPs), surplus capacity from CSPs, and any other existing sources of bulk power;
(b) Energy utilisation, peak load and power factor data and annual load factors for the previous 5 year period;
(c) Available data for each supplying generating station indicating energy and peaking capacity during plan period (as collected from Generating Companies);
(d) Existing and proposed Demand Side Management (DSM) programs and their impact;
(e) Annual capacity and energy balance statements for the plan period, showing available net capacity from existing resources, additional net generation capacity to be added indicating year of commissioning, and total capacity as achieved after each addition;
(f) The plan for additional power procurement indicating unit sizes, type, gross capacity, year of commissioning, incremental net energy generated, and expected unit cost (to include energy, capacity and where appropriate transmission costs). The plan should show the options that were evaluated, the method of evaluation or proposed competitive solicitation, and the results or expected results of evaluation of alternative options. The plan should justify, in terms of economic advantage, APTRANSCO’s preferred options for meeting new capacity requirements;
(g) A two-year implementation plan, related to the first two years of the Power Procurement Plan. The Licensee shall make explicit the steps it intends to take in the first two years that will enable the acquisition of the resources required in the remaining years of the Power Procurement Plan.
4)
Licensee’s submission during BPL Hearing:
As per the above provision of the Act, License and Power Procurement Guidelines, APTRANSCO filed, vide Lr.No.CE/RAC/11 Power Procurement Plan/ D.No 177/ 2001-dated 30-6-2001, the details of long term forecast and power procurement plan from 2001-02 to 2006-07. This was done at the time of hearing on the matter of PPA between M/S BPL and APTRANSCO. This was presented to justify the need for the BPL project. APTRANSCO had submitted additional capacity requirement of 4489 MW during the period 2001-02 till 2006-07.
5)
Commission’s Order on the load forecast:
The Commission in the letter number Lr.
No. APERC/Secy./Dir.-Engg/F-LF&PP/D.No.4178/A/2001 dated
6)
Commission’s observation regarding demand projection in the BPL
order:
Though the Commission
approved the load forecast submitted by APTRANSCO through its letter dated
7)
APTRANSCO’s submission during BSES Public hearing:
During the public hearing held on the 16-01-2002 on the proposal of APTRANSCO to give consent to the power purchase agreement (PPA) signed with BSES, APTRANSCO made a revised demand projections for the period FY2002 to FY2007 in respect of requirement of power for the entire AP system. APTRANSCO submitted an additional capacity requirement of 4270 MW during the period 2001-02 till 2006-07.
Government of Andhra Pradesh (GoAP)
forwarded a copy of the business plan of all the licensees to the Commission on
8)
Show-cause notice of the Commission
After careful examination of the demand forecast and supply plan of
APTRANSCO submitted on the
(a) Projection of Sales: Having analysed the historic sales and seen that sales to consumers have grown at CAGR of 5.9% in the last 10 years and only at CAGR of 2.2% in the last 5 years, the Commission expressed that APTRANSCO is not justified in saying that past is no indication of future. Commission also made the observation that as per the AP statistical reports there has been no restrictions in supply to any of the category of consumers except for Agriculture and rural domestic since May 1998.
From the observations made with regard to sales projections, the Commission considered that it would not be desirable to rely on econometric modelling method based on which the growth rate in sales will have to be 10.15% year on year in the remaining years till FY07, which is unrealistic. Hence, the Commission considered appropriate to consider 5.9% historic growth rate to forecast future sales.
(b) System load factor: APTRANSCO has submitted that the load factor of 65% should be used in the calculation of the system peak requirement. Commission expressed its view that current system load factor is in excess of 85% as per APTRANSCO’s own submission. Further, during the plan period, agriculture category will continue to have regulated supply, and this would help in maintaining higher system load factor. Commission considered appropriate to assume system load factor of 70% as assumed by CEA for AP system planning. The Commission also assured to review the position on system load factor during the same process next year if evidence shows that load factor is lower than 70% for FY 2002-03.
(c) System reserve margin: In the show cause notice, the Commission took into cognisance APERC staff’s concern that system reliability should be achieved over a period of time and not be targeted from year one of the planning period. APTRANSCO has submitted that through complex mathematical simulation that took into consideration the probability of a plant being available at the time of system peak, they have arrived at the stated reserve margin for the targeted reliability.
Considering the fact that system reliability in terms of generation availability would increase with a system margin being provided, Commission is accepting APTRANSCO’s suggestion for an average system margin of 14% for achieving 1 % loss of load probability (LOLP).
(d) Non-conventional Energy Development Corporation of Andhra Pradesh (NEDCAP) projects: APTRANSCO in their correspondence with the Commission, had submitted that the size of the NEDCAP projects, being less than 6 MW, would cause dispatch problems for the system operator, as they would have no communication link with these generators. Moreover, they expressed their doubts about the availability of fuel.
Commission ignored the NEDCAP projects coming up in the wind, mini-hydel, bagasse etc., as the
supply from these units would be erratic in nature. However, as per the
information provided by APTRANSCO vide letter no Lr.No.CE/121/F.NCES/D.No
80/2002 dated
The Commission also stated that NEDCAP projects on account of their special promoted status are not subject to any merit order selection and hence will be dispatched irrespective of State Load Dispatch Centre’s (SLDC’s) direction. In this regard, the Commission is also of the view that suitable provisions can be incorporated in the commercial agreements for the units to operate at the peak period. Commission also reviewed the fuel availability situation for biomass and came to the conclusion that 250 MW of biomass capacity can be sustained in AP. The Commission, thus, considered 250 MW of biomass capacity in the supply expansion plan and the capacity from other sources like wind, mini-hydel, bagasse, municipal waste etc were ignored.
(e) Auxiliary Consumption: Commission required APTRANSCO to assume auxiliary consumption for every generating station as per the technical requirement rather than taking the auxiliary of the system as a whole.
(f) Non-inclusion of projects: Commission noted that as per the power procurement guidelines, the plan submitted by the licensee can not be considered as a least cost supply plan as several projects such as NTPC–Talcher, NTPC-Ramagundam, GVK-II are ignored and are not evaluated in the planning exercise.
(g) Financial Impact: Commission did the analysis of the business plan and found out that if all the projects as submitted by APTRANSCO and left out projects like NTPC and NEDCAP are approved by the Commission, it would add an additional burden of Rs 2200 Crores on account of power purchase cost during the plan period. And this may go up substantially in the subsequent period, defeating the objective of gradual reduction and phasing out of the GoAP subsidy to the power sector.
While doing the financial analysis, an inflation rate of 6% and an exchange rate variation of 6.68% have been used by the Commission unlike business plan, which has used inflation rate of 5% and exchange rate variation of 2.25%. Commission’s assumption on Exchange rate Variation and inflation is again based on historical facts.
(h) Scheduling of projects: The Commission advised APTRANSCO that in view of the gestation period required for setting up projects APTRANSCO should be very clear about when individual projects would materialise. It was added by the Commission, that the relative costs of the various proposals have to be evaluated before taking a final decision.
Based on the above observations, the Commission in its show cause notice concluded that only 2405 MW of cumulative additional capacity is required as against APTRANSCO’s submission of 4270 MW.
9)
APTRANSCO response to the show-cause notice
APTRANSCO filed its response
to the show cause notice on
(a)
The latest forecast submitted
is even lower than the conservative estimates presented by them in July 2001
and Commission itself in its order on this subject vide Lr.
No. APERC/Secy./Dir.-Engg/F-LF&PP/D.No.4178/A/2001 dated
Moreover, there has been no surplus power during the period 1990 to 2001. Considerable amount of statutory power cuts to HT industries has happened from the late 1980s till May 1998. APTRANSCO has adopted restrictions and control method to manage the growing load within the existing generating resources. This is reflected in the 132 kV interruptions, low voltage and low frequency in the system. In view of these facts, APTRANSCO firmly submitted that it is neither prudent nor rational to wholly rely on the historical growth rate of 5.9%.
APTRANSCO has also presented the 132 kV feeder manual tripping information before the Commission. This is presented in the Annex –I.
(b) APTRANSCO contended that the high load factor in the system at present is due to supply restriction in the system. Similar system in Madhya Pradesh has been planned for 57% load factor. If the system is planned for 70% load factor, there will be definite load shedding during the peak hours. Also in the Availability Based Tariff (ABT) regime APTRANSCO will have to either shed more load or install new capacity or buy power from other sources to maintain the required grid frequency. Thus, the Commission’s recommended value of 70% load factor is not adequate.
(c) The auxiliary consumption taken for each of the generating unit was not uniformly assumed at 10% of the gross capacity of all units and APTRANSCO have been adopted from APGENCO published data for existing units and CEA norms for future capacity. Thus there is no error in the estimated planned capacity of 4270 MW.
(d) They did not assume a reserve margin of 14%, instead it is derived figure for achieving 1 % loss of load probability (LOLP) and did not submit the break-up of reserve margin into spinning reserve of 3% and stand by reserve of 11%. In this regard they have to maintain the power supply quality as per the norms fixed in the State Grid Code of APERC and Indian Electricity Grid Code of CERC.
(e) System operator lacks the ability to dispatch and monitor the NEDCAP projects. APTRANSCO will have to incur huge amount of capital to set up control and communication gear to dispatch uneconomical smaller units. APTRANSCO will incur financial losses if these were to be treated as firm capacity and will have to back down cheaper generation from mine mouth coal or hydro or gas plants. Also the success rate of these projects to fruition from the date of sanction to-date is very dismal.
(f) GoAP had permitted 31 mini power plants (MPPs) based on residual fuel totalling a capacity 979.8 MW. Permission for 12 projects totalling 384.5 MW were cancelled in June 1998 due to lack of progress from the date of sanction. Power purchase from 3 MPPs namely Vathsas Power Limited (15.4 MW), RVK Energy Limited (20 MW) and Krishna Godavari Power Limited (2*30 MW) can be considered. However, APTRANSCO has not included these projects in the power procurement plan. But submitted that these will be submitted at appropriate time and the impact on finances is expected to be insignificant.
(g) Regarding NTPC Talcher-II and Ramagundam-II projects APTRANSCO has submitted that these projects are being built for the entire southern region which is reeling under supply shortage. Should these NTPC projects come on line as per their projected schedule there may not be any difficulty in absorbing power from these by APTRANSCO because the gas projects contemplated to materialise in FY 04 and FY 05 may be delayed as per the present trend of events. Even if the gas projects are expedited to give results as per the business plan, APTRANSCO will try to market the surplus power to the needy States through power trading corporation or temporarily transfer NTPC power to other needy States till the load demand in AP picks up.
(h) APTRANSCO submitted that the domestic inflation rate assumed in the business plan is in line with the average inflation rate in the last five years and the assumed exchange rate variation is as per the purchasing power parity, which has been validated based on the past trend. Any increase in the power purchase cost due to uncontrollable & unforeseen events, would need to be bridged through a combination of measures such as reduction in line losses, internal efficiency improvements, tariff increase and additional subsidy. Further, opportunity to market and sell power inter-state would result in APTRANSCO generating more revenues and profits from this excess power. Therefore, the Regulator’s apprehension on the increased financial burden may not materialise.
10) Commission analysis on the
Demand of the AP System
(a) Sales Projection for AP
System
APTRANSCO has done the system planning exercise for the entire AP system using econometric modelling method to forecast the sales for all the categories except agriculture. While for agriculture category for which end use consumption method was followed in the planning period. Based on the above-mentioned methodology, the sales forecast submitted has a Compounded Annual Growth Rate (CAGR) of 7.38% for the period FY01-07.
It should be noted here that with the two years of the planned period already passed, the system has to achieve an annual compounded growth rate of 8.32% for the remaining period of the plan period if we consider FY 2001-02 actual sales number submitted by APTRANSCO as the base. This growth rate goes up to 10.15% if we consider the category-wise sales figures approved by the Commission in its tariff order for FY 2002-03 as the base.
The detailed break-up of the sales forecast made by APTRANSCO in the planning period as submitted by the licensee is enclosed as Annex II.
Commission has analysed the historic sales of the AP system including that of the APSEB/APTRANSCO, wheeling consumers and captive consumers for the period, FY 1990 till FY 2001. This is provided in the Annex III.
The sales of the APSEB/APTRANSCO system has grown at CAGR of 5.9% in this period, the captive consumption has grown at 7.75% and the wheeling consumption at 30.11% in the same period. If we consider AP system as a whole, the total demand has grown at a CAGR of 6.8% in the past 11 years.
(b) Un-served energy in the AP
System
APTRANSCO submitted that there is significant gap still existing between demand and supply in AP resulting in forced interruptions in the 132 kV system. The Commission understands that AP consumers have suffered power shortages arising out of 132 kV interruptions, which are due to the shortage in the capacity.
Commission did an analysis of these interruptions of the 132 kV feeders and the resultant loss of load. This is presented in the Annex IV. The amount of un-served energy in FY02 was of the order of 1225 MU. If this is adjusted for FY 2002 system losses of 31.5% and design system load factor of 70% is applied, the MW requirement to meet the unserved energy works out to be 292 MW.
Based on these workings, if an additional 300MW of capacity is added to the capacity expansion plan to correct the base distortion, the supply-constraint related interruptions could be avoided.
(c) Sales forecast approved by
Commission
Commission believes that since the planning is being done for the entire AP system while following a historical method, it should consider the sales growth rate for the entire AP system, that is, 6.8% in the last 11 years.
Further, Commission believes that if the 300 MW power is taken as base correction to amend the mismatch between demand and supply existing at present. This together with the historical growth rate of 6.8% if applied on the FY02 actual sales of the APTRANSCO as mentioned in the business plan, would give a realistic picture of the sales projection during the plan period.
It should be noted here that the two aspects of historic growth rate of 6.8% and 300 MW compensation for past deficit taken together constitute a sales growth rate of 7.74% for the remaining period of the plan period. Since we have the information about the actual sales figures of the FY01 and FY02 available now, we must make use of this information. Commission, for the planning purpose has, in fact adopted the sale of 10300 MUs to agriculture in FY 02, rather than 9815 MUs allowed in the tariff order. The 300 MW allowed as the base correction has been converted into MUs by applying system load factor of 70%. The gross level of MUs achieved by taking an overall growth rate of 6.8% and correction factor for 300 MW is then allocated among categories in the same ratio as the sales mix in the APTRANSCO forecast for the particular year.
Based on the above calculations, AP system requirement works out to be 58,776 MU at the end of the plan period FY 2007 compared to 59,818 MU assumed by the licensee for FY 07.
(d) System Load factor:
Commission has analysed APTRANSCO’s submission regarding assumption of system load factor. They have shown that during the year 1983-84 the system load factor was 69.2, during 1984-85 it was 66.3% and during 1985-86 it was 66.1%. All these years, there was no restriction on the demand. But Commission understands that during the above-mentioned years, there was no regulation of supply to agriculture consumers. Moreover, the proportion of agriculture load to the total sales of the system was in the range of 20-25% during these years.
Right now the AP system has nearly 37% of the sales to this category and they are having a regulated supply of 9 hours in two spells. APTRANSCO also confirms that this category will continue to have regulated power supply during the plan period. Reiterating the argument forwarded by the Commission in the show-cause notice, the Licensee’s system will continue to have 37% of total sales to agriculture sector and continue to have regulated supply, giving the flexibility to the system operator to flatten the load curve vis-ŕ-vis a totally un-restricted system. The present monthly system load factor ranges from 80 to 88% in the AP System.
Under these circumstances Commission believes that 70% load factor will be adequate to meet the projected system peak demand and there will be no load shedding during the peak hour as a result of this. For the plan period Commission believes that 70% system load factor would be adequate .
The position can be reviewed during the same process next year if there is a fall in FY 2003 load factor, which is a power surplus year according to APTRANSCO’s submission of ARR for FY 2002-03.
(e) Loss of load probability
(LOLP) & System Margin:
APTRANSCO has adopted a target Loss of Load Probability (LOLP) of 1% or 87.6 hours/year as the measure of reliability in estimating reserve capacity. This is to take care of the probability of failure of plants during the system peak demand. APTRANSCO also submitted that the system reserve margin required to achieve this target level of LOLP is found out by mathematical modelling whose input are factors such as the condition of generating units, their past planned and un-planned shut-downs, the hydel-thermal mix, the hydrology factor etc. This gave them a resultant average system margin for the plan period as 14%.
It is surprising to notice APTRANSCO’s
submission on the
Commission is willing to go by the APTRANSCO submission regarding the system reserve margin. However, in the revised calculation for demand estimates Commission has assumed uniform system margin of 14% each year of the plan period.
(f) Capacity Requirement in
the planning period:
Commission has heard APTRANSCO’s submissions regarding their assumption for Captive repatriation and wheeling consumption. Commission believes that if the Licensees implement the policy measures outlined by the Commission regarding these categories it is not difficult for them to get back the wheeling and captive consumers, as proposed by APTRANSCO.
The sales figures of the Distribution Companies arrived after applying 300 MW base correction factor and 6.8% growth rate added with the captive and wheeling consumers’ consumption provides the total AP system consumption. By applying system load factor of 70% and system reserve margin of 14%, Commission has arrived at the system peak requirement for the plan period as at Annex VI.
Commission has worked out the existing system capacity after deducting the auxiliary consumption for each of the generating units. The captive and wheeling capacity has been matched on the supply side to cater to the exact demand from these units on to the system. The gross installed capacity so arrived is 9204 MW in FY 2002 as at Annex VII.
The resultant demand-supply situation is provided in the Table 1 below:
Table 1
|
All figures in MW |
FY 02 |
FY 03 |
FY 04 |
FY 05 |
FY 06 |
FY 07 |
|
Installed
Capacity Requirement |
9,916[1] |
10436 |
10589 |
10775 |
11170 |
11636 |
|
Existing Capacity |
9,204[2] |
9235 |
9046 |
8457 |
8457 |
8457 |
|
Annual Additions required |
712 |
489 |
342 |
775 |
395 |
467 |
|
Cumulative Capacity
Required |
712 |
1201 |
1543 |
2318 |
2713 |
3180 |
It should be recalled that APTRANSCO had submitted for 4270 MW of supply expansion plan (including 142 MW of captive). Against this 4128 MW, Commission has come to the conclusion that the system requirement is 3180 MW of additional capacity during the plan period.
Hence, as per the power vested under Section 11 (1) (g) of the Reform Act, Commission projects that:
(a) The System peak demand in the year FY 2006-07 shall be 11636 MW and the energy requirement shall be 58776 MU.
(b) The annual capacity addition required is as provided in the Table1 above.
(c) The cumulative capacity required to be added during the period 2001-02 till 2006-07 would be 3180 MW.
11) Supply Expansion - Commission Analysis
APTRANSCO first submitted their demand forecast and supply expansion plan before the Commission in July 2001. They had mentioned that the net installed capacity of the existing system without captive generation as on March 2001 was 7738 MW and with captive it was 8939 MW. Their submission for the system expansion is reproduced in the Table 2 here:
Table 2
|
|
Load Forecast[3] |
Capacity Retirement |
Imports |
Thermal Capacity Addition |
Hydel Capacity Addition |
Total Capacity Addition |
Total Net Capacity |
|
2001-02 |
8768 |
|
|
673 CC-1 (213.4) + Simhadri-I
(460) |
447 Sri Sailam
|
1120 |
10058 |
|
2002-03 |
9042 |
328 Captive |
|
Simhadri-Unit-II (460) |
298 Sri Sailam |
758 |
10816 |
|
2003-04 |
9405 |
|
|
432 CC-2 |
149 Sri Sailam |
581 |
11069 |
|
2004-05 |
9887 |
711 (400 Eastern region and 311
Captive) |
|
CC-3 (358.9) and BPL (475.6) |
|
835 |
11193 |
|
2005-06 |
10447 |
|
|
CC-4 (450.1) and CC-5 (358.9) |
|
809 |
12002 |
|
2006-07 |
11085 |
20 (Captive) |
|
385 RTPP-II |
|
385 |
12367 |
|
2007-08 |
11739 |
|
425.2 Talcher |
|
|
425 |
12792 |
|
Total (MW) |
|
1059 |
425 |
3594 |
894 |
4914 |
|
(Source:
APTRANSCO Submission July 2001, Page 44, Table 2.3, and Generation Expansion
Plan)
It is interesting to note the following facts from the above submission:
i) APTRANSCO had named the projects and their schedule in the first submission in July 2001.
ii) NTPC Talcher figures in this plan in the year FY 2008.
iii) This also included CC-5 in FY 2006.
iv) Captive repatriation of 659 MW was assumed.
v) 4489 MW of capacity expansion was proposed till FY07.
Further, while APTRANSCO resubmitted their demand forecast and supply expansion plan during the BSES public hearing in January 2002, they presented the following supply expansion plan shown in Table 3:
Table 3
|
|
Projected Peak Demand |
Capacity Retirement |
Thermal Capacity Addition |
Hydel Capacity Addition |
Total Capacity Addition |
Total Net Capacity |
|
2001-02 |
9162 |
|
CC-1 (213.4) + Simhadri-I
(460) + New Captives (56.3) |
298 Sri Sailam
|
1028 |
9994 |
|
2002-03 |
9441 |
160 Captive |
Simhadri-Unit-II (460) + New Captive 84.4 |
298 Sri Sailam
|
842 |
10836 |
|
2003-04 |
9717 |
|
432 CC-2 |
298 Sri Sailam
|
730 |
11406 |
|
2004-05 |
9904 |
569 (400 Eastern region and 169
Captive) |
CC-3 (359) and Coal (475.6) |
|
835 |
11672 |
|
2005-06 |
10338 |
|
CC-4 (450.1) |
|
450 |
12122 |
|
2006-07 |
10887 |
|
385 Coal |
|
385 |
12507 |
|
Total (MW) |
|
729 |
3594 |
894 |
4270 |
|
(Source: APTRANSCO Submission January 2002
Table: Power Procurement Plan)
It is interesting to note the following facts from the above submission:
i) The supply expansion plan was revised to 4270 MW with Captive plants contributing 142 MW and the other projects 4128 MW.
ii) Except for Simhadri and Sri Sailam projects, APTRANSCO has not named any of the projects and mentioned only the net capacity and the fuel types.
iii) NTPC-Talcher-II and CC-5 find no mention in this plan whereas they figured in the earlier supply plan of APTRANSCO.
iv) NTPC-Ramagundam-II finds no mention in this plan.
Meanwhile APTRANSCO has forwarded the following PPAs before the Commission for their consent to the PPA as per Section 21 (4) of the Reform Act.
Table 4
|
Projects Under Scrutiny |
Capacity (MW) |
Commissioning Date |
|
BPL |
520 |
FY 2005 |
|
RTPP-II |
420 |
FY 2007 |
|
BSES |
220 |
FY 2002 |
|
Konaseema |
445 |
FY 2004 |
|
Vemagiri |
370 |
FY 2005 |
|
Gautami |
464 |
FY 2005 |
|
GVK Industries |
220 |
FY 2005 |
12) Criteria for Drawing up
the Supply Expansion Plan
Commission requires APTRANSCO to submit their supply expansion plan indicating generation capacity to the tune of 3180 MW. Commission requires APTRANSCO to follow the criteria while drawing up the supply expansion plan:
i) Drawing up the least cost generation expansion plan and demonstrating to the satisfaction of the Commission that the plan suggested is indeed a least cost plan. Commission suggests that APTRANSCO should submit the “levelised tariffs” of each of these projects and their underlying assumptions before the Commission while submitting least cost option.
ii)
There is need to include NTPC Ramagundam-II (146 MW AP Share) and NTPC Talcher-II (425 MW AP Share) projects in the supply plan as
there has been an agreement of GoAP with NTPC to this
effect. NTPC vide Letter Number 09/SRHQ/P&M dated
Table 5
|
FY04 |
FY05 |
FY06 |
FY07 |
Total |
|
98 MW NTPC Talcher |
98 MW NTPC Talcher |
98 MW NTPC Talcher 134 MW NTPC Ramagundam |
98 MW NTPC Talcher |
526 MW |
iii) All PPAs that are being forwarded for consent of the Commission must be first evaluated for their inclusion in the generation expansion plan of APTRANSCO. For example, CC-5 has been forwarded to the Commission for their consent but it does not find a place in the supply expansion plan of APTRANSCO.
iv) It is not sufficient for APTRANSCO to say that the mini-power plants (MPPs) have insignificant impact on the business plan and capacity planning. Specific MPPs that are being forwarded for the consent of the Commission should be included in the supply expansion plan as well as the business plan.
v) NEDCAP Projects: Commission is of the opinion that, NEDCAP projects on account of their special promoted status are not subjected to any merit order selection criteria. Thus, whenever they are ready to generate power they will be dispatched obviating the need for any instruction from the SLDC. After series of deliberations with NEDCAP and APTRANSCO, the Commission is of the view that biomass plants, which operate at a PLF of more than 70%, should be considered for the supply planning exercise. Based on this observation, the Commission hasn’t included firm supply from mini hydel stations, wind, municipal waste, bagasse etc.
The Commission is also of the opinion that number of plants considered in the biomass segment shall add to the diversity factor, which will be an advantage for system planning. In this context, the Commission expresses that, if required, these biomass plants can be regulated to operate at the peak hours, so that firm power can be assured from these NEDCAP projects.
Commission also does not agree with APTRANSCO that the success rates of these projects are dismal. As the facts indicate, as of FY02 already 90 MW of biomass projects are in operation.
Though NEDCAP has projected a capacity availability of 440 MW in the Biomass segment in the planning period, the Commission has made a conservative estimate of 250MW availability from the biomass projects in the planning period as shown below in the table 6.
Table 6
|
(in MW) |
FY02 |
FY03 |
FY04 |
FY05 |
FY06 |
FY07 |
|
Net Capacity for the Year (MW) |
89.55 |
41.35 |
54.13 |
64.97 |
0 |
0 |
|
Cumulative Capacity (MW) |
89.55 |
130.9 |
185.03 |
250 |
250 |
250 |
.
vi) Sri Sailam Left Bank Project: Commission has been through much expert deliberation regarding the viability of the Sri Sailam project. There is consensus that the project can operate in the conventional mode during the monsoon months only for a few days.
But there is scepticism about the plant’s viability in the pumping mode operation. APTRANSCO in their presentation before the Commission suggested that for the Sri Sailam project to operate in the reverse pumping mode the minimum water level at Nagarjuna Sagar should be 531.5 Ft and maximum level of water at Sri Sailam should be 863.5 Ft. They further presented the past 5 years’ water levels for these two reservoirs for two crucial months of March and April. As it can be seen from the table 7 below, out of the 10 data points only once, that is, on 01-03-1999 the water level at Nagarjuna Sagar reservoir was above the critical level of 531.5 Ft required for the pumping operation at Sri Sailam LB.
It has been further pointed out that since 1996 after the Almatti and Upper Krishna Projects taking shape the hydrology factors have worsened drastically.
Table 7
|
Sri Sailam Reservoir level as on in ft. |
FY 98 |
FY 99 |
FY 00 |
FY 01 |
FY 02 |
|
1st of March |
862.8 |
864.6 |
860.3 |
847.2 |
861.5 |
|
1st of April |
835.0 |
829.1 |
840.2 |
821.7 |
820.5 |
|
Nagarjuna Sagar Reservoir level as on in
ft. |
|
|
|
|
|
|
1st of March |
523.4 |
536.9 |
515.1 |
515.6 |
515.2 |
|
1st of April |
525.5 |
529.3 |
512.2 |
517.6 |
516.8 |
(Source: APTRANSCO presentation on
19-6-2002, slide 9 and 10)
Further, being a multi-purpose project, the irrigation department has the first choice for release of water.
Although APGENCO has been assuring that they are making efforts to rectify the situation by creating a “water sheet” etc. the Commission is concerned with the fact that this project has been included in the capacity planning for meeting the system peak demand. Commission strongly recommends that APTRANSCO and APGENCO should have a critical analysis of this project and if it is unrealistic to assume this project for capacity planning purpose, they should suggest alternate capacity in its place. Commission would further deal with this issue in detail while dealing with the APGENCO PPA.
vii) As per the power procurement guidelines issued by the Commission, “The plan should justify, in terms of economic advantage, APTRANSCO’s preferred options for meeting new capacity requirements;” Once any project figures in the approved supply expansion plan of the Commission, APTRANSCO should forward the PPA for Commission’s approval estimating the gestation period and the time taken for Commission consent. For example, by their admission APTRANSCO requires 835 MW of additional capacity in FY05, but they have proposed 1574 MW of gross capacity for the year FY05 as per the PPAs pending before the Commission for their consent.
viii) Commission is of the opinion that while doing capacity planning for future, APTRANSCO can’t plan for the surplus capacity for selling them outside the State. Such sale of surplus power is gainful only if the selling rate is above the total cost per unit and not just the variable cost imposed by the new plant on the system.
13) Order
In the facts and circumstances mentioned above the Commission directs as under:
(a) In terms of Section 11 (1) (g) of the Reform Act, the System peak demand in the year FY 2006-07 shall be fixed at 11636 MW and the energy requirement at 58776 MU.
(b) The annual capacity addition required shall be as provided in the Table1 above. The cumulative capacity required to be added during the period 2001-02 till 2006-07 shall be 3180 MW.
(c) APTRANSCO shall revise the power procurement plan to match the capacity requirement of 3180 MW, as projected by the Commission.
(d) While doing the capacity planning APTRANSCO shall include 250 MW of NEDCAP projects.
(e) Similarly APTRANSCO shall include NTPC Talcher-II and NTPC Ramagundam-II projects.
(f) APTRANSCO shall consider all projects including CC-5 and MPPs. And decide on the inclusion of the projects to cover the demand forecasted drawing up a least cost generation plan and if exception to be made either in terms of this order or otherwise give reasons for the same.
(g) APTRANSCO shall consider the prospects of Sri Sailam Left Bank Project not contributing to the system peak.
The Power Purchase Agreements submitted before the Commission for consent and pending public hearing would be taken up by the Commission once they appear in the revised supply expansion plan, which should be submitted by APTRANSCO as per this order.
As per the paragraph 2.2 of the power procurement guidelines the licensee shall submit its load forecast to the Commission in the month of April of each year.
This Order
is signed by the Andhra Pradesh Electricity Regulatory Commission on
|
Sd/ |
Sd/ |
|
D. LAKSHMINARAYANA |
G.P. RAO |
|
MEMBER |
CHAIRMAN |