A new IGCEP (Indicated Generation Capacity Expansion Plan) has been submitted by NTDC (National Transmission and Despatch Company) for the regulator’s approval. There are some questionable recommendations made in the model that we will discuss in this space. Should we adopt the recommendations because a computer model has been used or we should apply our minds and analyze and evaluate it keeping in view some peculiarities? Also, all models should be taken with a pinch of salt as there are many issues related to assumptions, methodologies and data accuracy. On the other hand, there is a risk of arbitrariness in fiddling with the model. However, let us first praise the effort of NTDC professionals who have prepared the IGCEP through their own indigenous efforts.
A weaker side of the IGCEP appears to be the demand side modeling on which the authors of the plan themselves have made similar submissions. While on the supply side, sufficient details have been given like the utilization of PLEXO software and others, there is lack of transparency in demand modeling. External help should have been sought from academia where there is no dearth of qualified and experienced economists and econometricians. Even at this late stage, it may be desirable to have advice and input from academia.
Out of a total of 25,263MW new capacity only 2,183MW are candidate projects and 23,080MW are committed projects about the latter IGCEP has no option to alter. What is the basis for these committed power plants? Then what is the purpose of all this exercise? There may be exceptional cases like hydro where a long planning horizon is required. Perhaps IGCEP should start earlier to minimize the volume of committed projects.
The most startling point in this IGCEP is that there would be no use for the RLNG Combined Cycle Power Plants (RLNGCCPPs) by the year 2023, while one of which TRIMMU has been recently approved. On the other hand, other power plants working on gas with an aggregate capacity of 5,278MW would keep working. It is a common knowledge that RLNGCCPPs are much more efficient with efficiency of more than 60% while other plants have an efficiency of around 40%. Let us trace as to why has the model given this outcome? An obvious reason appears to be that local gas is cheaper while RLNG expensive. Due to this factor, an inefficient power plant working on cheaper gas would come higher in merit order than a more efficient power plant working on expensive RLNG. However, running a power plant on RLNG or local gas is an arbitrary administrative decision. There is no technical constraint preventing RLNGCCPPs in using cheaper local gas. This is not to suggest that RLNGCCPPs should be run on gas, although this is a possibility.
A problem with merit order based on fuel cost is that there is no filtering criterion for capital intensive projects overburdening cash flow, e.g., nuclear power with a fuel cost of 0.49 USD/Gj and a capex of 4227 USD/MW would always be selected even if CAPEX goes to 10,000 USD/MW. Some solution has to be found in this respect. And it eliminates efficient power plants (RLNGCCPPs) due to fuel price anomalies as discussed elsewhere.
I would suggest the opposite that all power plants are run on RLNG, except where there may be technical or legal constraints such as low Btu local gas etc. This can be done notionally but preferably actually. Local gas should be reserved for residential, commercial and industrial use. It would be politically impossible for any government to use RLNG for domestic sector and charge accordingly or provide huge subsidy, keeping in view the low domestic gas tariff. Thus, cheaper local gas would be saved for the most eligible domestic sector. Also, the price anomaly would be done away with which is creating an unacceptable situation of shunning newly installed and more efficient RLNGCCPPs and prefer older and less efficient power plants.
It appears that there is a need for further optimization. For a demand of 32,000MW, a capacity of 52,000MW appears to be too much, although lower capacity factors of the renewable and hydro power plants may be partly the reason for a large difference. Capacity payment and circular debt constitute a major issue facing the economy. An alternate combination of capacity may be simulated to see if the investments and generation costs can be lesser. Also, demand management may also be an issue which we have discussed in this space recently and the plan also points out these issues.
Existing Capacity in the year 2021 is 34,000MW. It has been proposed to add 19,215MW in the next ten years so as to have an installed capacity of 53,100MW. This is by not utilizing LNG power plants of capacity of 5,839MW. It would be almost senseless to not utilize these plants, waste the investment and propose to add additional capacity, simply because the planners’ tools and methodology says so. I am sure that if a due diligence is made of the proposed IGCEP, other opportunities to save capacity investments may be discovered.
A hydro capacity of 23,035MW has been suggested to be installed by the year 2030 as against the present installed capacity of 9,888MW which means that a capacity of 13,147MW would be installed in the period 2021-2030. The main question is: Is it feasible to install such large hydro capacity in the next ten years? As against this, there would be a solar capacity of only 1,964MW and wind power of 3,795MW. This is a rather sensitive provincial issue. Hydro is located in KP, wind in Sindh and solar is everywhere. Solar energy’s costs have come down tremendously and should be more than 50 percent cheaper than hydro’s. Also, long transmission lines have to be laid out to bring the electricity to demand centres. The new paradigm is distributed generation; produce near the consumption centers. Hydro has an advantage of water storage and hence it appears that large hydros with storage may be preferred. Solar capacity should be enhanced as opposed to the models recommendations.
Provincial allocations seem to be missing. Perhaps the choice of the plant type would partly determine this or the availability of ready projects. It appears that Sindh has excess capacity with nuclear and coal power plant. Thar coal and wind power should receive priority. Otherwise, longer and expensive transmission capacity would be required. The model should be reviewed accordingly. Adoption of more solar can deal with this situation.
Finally, there are transmission issues due to which merit order cannot be implemented strictly. Some efficient power plants cannot be run because of the lack of transmission capacity in certain segments and lesser efficient plants are used. Another issue is the use of RFO which has been recommended to be discontinued and is already disallowed in some way. RFO is being produced as a co-product with gasoline and diesel. If RFO is not used by power plants and thus not produced by oil refineries, gasoline and diesel production would have to be reduced. Oil refineries are already complaining of heavy losses. Another factor that is emerging is that most RFO power plants have no capacity payments to be made. And thirdly, RLNG and RFO prices are coming closer. Times change fascinatingly. RFO was a taboo and RLNG was a new comer. Now the model is rejecting RLNG power plants and we are talking of the merits of RFO.
(The writer is former Member Energy, Planning Commission, author of several books on the
energy sector)
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Table E1: Summary of Load Forecast (2021-30)
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Low Normal High
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Year Energy Peak Energy Peak Energy Peak
Demand Demand Demand
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GWh MW GWh MW GWh MW
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2020-21 128,979 24,102 129,001 24,106 129,024 24,110
2023-24 148,664 27,076 149,897 27,311 150,839 27,490
2026-27 160,351 29,473 165,927 30,540 170,347 31.386
2029-30 172,641 32,015 184,900 34,377 195,244 36,369
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ACGR 2021-30 3.29% 3.21% 4.08% 4.02% 4.71% 4.67%
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Table E2: Summary of Installed Capacity (MW) of All Scenarios by 2030
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Technology Base Low Demand High Demand
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Installed Capacity (MW) by 2030
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Imported Coal 4,920 4,920 4,920
Local Coal 3,630 3,630 3,630
RLNG 6,786 6,786 6,786
Gas 2,582 2,582 2,582
Nuclear 3,635 3,635 3,635
Bagasse 749 749 749
Solar 1,964 882 4,954
Hydro 23,035 23,035 23,035
Cross Border 1,000 1,000 1,000
Wind 3,795 2,795 4,694
RFO 1,220 1,220 1,220
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Total (MW) 53,315 51,233 57,204
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Table E3: Summary of Energy Generation (GWh) of All Scenarios by 2030
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Technology Base Low Demand High Demand
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Energy Generation (GWh) by 2030
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Imported Coal 18,007 17,532 18,136
Local Coal 19,985 14,490 20,499
RLNG 36 - 61
Gas 5,278 5,226 5,573
Nuclear 24,912 24,912 24,912
Baggase 3,380 3,380 3,380
Solar 3,478 1,432 9,127
Hydro 91,866 91,866 91,866
Cross Border 3,443 3,443 3,443
Wind 14,514 10,360 18,247
RFO - - -
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Total (GWh) 184,900 172,641 195,244
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Table 6-7 Year wise Installed Capacity Addition (MW)
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Net Capacity Addition Over the Plan Period (2021-30)
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Year Local Hydro RLNG Nuclear Imported RE Natural Furnace Cross Yearly Cumulative
Coal Coal Gas Oil Border Addition Total
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(MW)
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2021 660 9.888 5.839 2.490 3.960 1.746 3,012 6.506 0 34.100
2022 2.310 87 1,119 1.145 0 860 0 0 0 5.521 39.621
2023 330 873 0 0 960 222 -205 -3.000 0 -820 38.801
2024 330 2.432 0 0 0 1.854 0 0 0 4.615 43.416
2025 0 1.088 0 0 0 1.000 0 0 1.000 3.088 46.504
2026 0 1.979 0 0 0 0 0 0 0 1.979 48.483
2027 0 364 0 0 0 0 -225 -1.423 0 -1.284 47.199
2028 0 701 0 0 0 827 0 0 0 1.528 48.726
2029 0 5.624 0 0 0 0 0 -727 0 4.897 53.623
2030 0 0 -172 0 0 0 0 -136 0 -308 53.315
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Total 3.630 23.035 6.786 3.635 4.920 6.508 2.582 1.220 1.000 53.315
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Table 5-5: Economic Parameters of Generic Power Plants
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# Technology Capital Cost with IDC Discount Rate Fuel Price
($/kW) (%) ($/Giga Joule)
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1 Nuclear (1,100 MW) 4,227 0.49
2 OCGT. (400 MW) 445 7.27
3 CCGT. (1,263 MW) 595 7.27
4 Imported Coal (660 MW) 1,604 2.92
5 Thar Coal (660 MW) 1,327 1.67
6 RYK Imp. Coal (660 MW) 1,196 5.40
7 Hybrid Muzaffargarh RLNG (933 MW) 407 10% 5.55
8 KAPCO Imp.Coal (660 MW) 1,344 2.79
9 Jamshoro Coal Unit 2 (660 MW) 626 4.35
10 C-5 Nuclear (1,100 MW) 4,227 0.49
11 Battery Energy Storage System 386
(100 MW/100 MWH)
12 Bagasse (100 MW) 891 2.31
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