Integrated Power System Plan
Ministry of Energy (Power Division)
April 2025
Power Planning - Legal Framework
NEPRA Act Section 14(A):
The Federal Government shall, from time to time, with approval of the
Council of Common Interests, prepare and prescribe a national
electricity policy for development of power markets
National Electricity Policy Section 5.1.1 states that
Expansion in generation capacity shall be only on competitive and
least cost basis (for Strategic Projects, Least Cost Violation is
calculated)
Grid Code PC.4 mentions that
System Operator should develop an Integrated System Plan (ISP)
(annually based on least cost principle) that should include Demand
Forecast, IGCEP & TSEP and should be submitted to the Authority for
approval
Legal Framework – Strategic Projects
National National Procurement
Electricity Electricity Regulation
Policy Plan
Expansion in generation capacity shall The proposed strategic projects shall be Electric power procurement from a
be only on competitive and least cost evaluated, to be declared as committed project approved by the federal
basis (except for strategic projects, for in IGCEP, based on the following: government as a strategic project in
which: accordance with the national electricity
a) Qualification Criteria: The project policy and subsequently selected in the
(a) the qualification and methodology fulfills at least one of the following IGCEP
shall be provided in the National
Electricity Plan,
objectives provided hereunder:
i. security of energy supply; Provided that the Authority while
(b) the Government, in consultation with ii. water – energy – food nexus; determining the tariff of the project shall
the Provincial Governments, shall iii. regional integration; ensure that it does not exceed the
approve such projects on case-to-case iv. municipal waste management. least cost of the project.
basis and
b) Methodology: The incremental cost
(c) the relevant sponsoring Government
shall provide the funding to bridge
(beyond least cost), herein referred to
the incremental cost as LCV, of each strategic project, shall
be borne by the relevant sponsoring
Government/Provincial Government.
Indicative Generation Capacity Expansion Plan (IGCEP)
Objectives Parameters Considered (>30) Tool: PLEXOS
Technical:
Users: :UK, USA, Australia, China, Germany,
Affordability • Hourly Demand Forecast (8,760 Hrs) France, South Africa, UAE, Thailand, India, New
(Least Cost) • Plant-wise data: Zealand, Saudi Arabia, Japan, Singapore, etc.
• Operational Capacity
• Ramp Rates
Reliability • Minimum stable level
• Thermal Efficiency
(LOLP , 1% = 87 hrs/yr) • Seasonal, Daily & hourly Availability
Commercial
• Technical Life Technical & Economic
• Scheduled & Forced Outages
Sustainability • Regional Transmission line flows
(Environment / Financial) • System Operational Reserves
Commercial & Economic: Contractual PLEXOS
& Legal
• Fuel Prices along with indexation
IGCEP Preparation Process
• Fixed and Variable O&M Costs
Data Gathering (Inputs) • New Plants Capital Costs
• Relevant Transmission line cost
• Debt and Equity Life
Modeling and Analysis
• Cost of Capital, Discount Rate
Least Cost, Reliable and
Stakeholder Consultation Contractual & Legal: Sustainable Generation
• Existing & future generation Commitment ExpansionISP
Plan
Process
• Fuel Contracts (RLNG, Gas) Link Process Link
Development & Submission • Must Run Commitments
Data Gathering
*LoLP: Loss of Load Probability
Demand Profile: Capacity (MW)
NTDC System 2018-2023
Demand Profile: Energy (TWh)
≈3% Growth
96.5
≈1.5% Growth
30.6
Surplus Generation Capacity – Existing IGCEP
Actual Forecasted
Parameter FY-2024 FY-2034
Summer Winter Summer Winter
Installed Capacity 39,666 60,009
Power Capacity
Firm Capacity 29,066 23,077 44,445 29,422
Avg. Demand 20,677 10,251 26,004 14,911
Electricity Demand
Peak Demand 24,036 12,228 31,677 18,349
Avg. Demand 6,332 11,801 15,840 13,020
Surplus Capacity
Peak Demand 2,626 9,560 9,600 9,238
Demand Growth YoY (%)
FY’22 FY’23 FY’24 FY’25 (till Mar) FY 26-34 (Projected)
9% -10% -3% -2.49% 2.8%
Impact of Excess Capacity (Old IGCEP)
Revised IGCEP & TSEP
Rationalization of Capacity Addition
through Policy Intervention
Common Assumptions for all Scenarios:
‐ Demand Forecast: @ 2.8% from FY-26 onwards
‐ Inclusion of 8,000 MW Net metering
‐ Four (4) Imported Coal Coal Plants dispatch as per Merit Order
‐ Transmission cost of Diamer-Basha (2,790 Mln $) and Chashma-5 (143 Mln $) considered as part
of project cost, which will not be incurred if the projects are not selected
‐ Transmission line expansion for interconnection with K-Electric has been assumed from FY-28
onwards
Impact of Modifications done on Diamer Basha
Parameter Units Old data Revised data Difference
Build Cost $/KW 1,720 1,720 -
WACC % 5.24 5.24 -
Cascaded Bln units
per annum
18.9 22.6 3.7 (20%)
Generation
VO&M $/MWh 4.3 0.5 3.8 (88%)
Levelized Tariff
(incl. Transmission Cents/unit 4.0 3.12 0.88 (22%)
charges)
As the revised data has been used for the selection of Diamer Basha on least cost basis in IGCEP.
NEPRA while determining the tariff of the project shall ensure that it does not exceed the least
cost of the project (as provided in the approved IGCEP).
Revised Commissioning Dates by WAPDA
Installed
CoD CoD
Plant Name Units Capacity Extended Timeline
(Previous) (New)
(MW)
Dasu-I 1 360 01-May-2027 01-May-2027 -
Dasu-I 2 360 01-Jul-2027 01-Jul-2027 -
Dasu-I 3 360 01-Aug-2027 01-Aug-2027 -
Dasu-I 4 360 01-Nov-2027 01-Nov-2027 -
Dasu-I 5 360 01-Feb-2028 01-Feb-2028 -
Dasu-I 6 360 01-May-2028 01-May-2028 -
Mohmand Dam 1 200 25-Apr-2027 01-Nov-2027 6.25
Mohmand Dam 2 200 09-Jun-2027 16-Dec-2027 6.25
Mohmand Dam 3 200 24-Jul-2027 30-Jan-2028 6.25
Mohmand Dam 4 200 07-Sept-2027 15-Mar-2028 6.25
Tarbela_Ext_5 1 510 01-Jul-2026 21-Sept-2026 2.70
Tarbela_Ext_5 2 510 01-Aug-2026 15-Nov-2026 3.48
Tarbela_Ext_5 3 510 01-Sept-2026 15-Dec-2026 3.45
Diamer Bhasha 1 375 01-Jan-2029 01-Oct-2032 45.01
Diamer Bhasha 2 375 01-Feb-2029 01-Dec-2032 45.99
Diamer Bhasha 3 375 01-Apr-2029 01-Feb-2033 46.09 Month
Diamer Bhasha 4 375 01-May-2029 01-Apr-2033 47.05
s
Diamer Bhasha 5 375 01-Jun-2029 01-Jun-2033 48.03
Diamer Bhasha 6 375 01-Jul-2029 01-Aug-2033 49.05
Diamer Bhasha 7 375 01-Aug-2029 01-Feb-2034 54.08
Diamer Bhasha 8 375 01-Sept-2029 01-Apr-2034 55.00
Diamer Bhasha 9 375 01-Oct-2029 01-Jun-2034 56.02
Diamer Bhasha 10 375 01-Nov-2029 01-Aug-2034 57.01
Diamer Bhasha 11 375 01-Jan-2030 01-Feb-2035 61.05
Diamer Bhasha 12 375 01-Feb-2030 01-Apr-2035 61.97
No Coal Conversion
• Least Cost Selection: 9,042 MW Wind: 3,342, DBD: 4,500, C-5
Capacity Rationalization 1,200
Rationalized Additions: 15,017 MW (7,017+8,000) • Power Purchase Price: 35,568 (1,004) Bln Rs
Capacity evaluated on Least Cost: 9,482 MW
• Avg. Consumer Rate: 39.21 (0.9) Rs/Unit
• Least Cost Selection: 8,041 MW (Wind: 3,536, Batdara, DBD:
Electricity Market 4,500)
Existing IGCEP (2024-34) Capacity due to Market: 3,110 MW • Power Purchase Price: 35,557 (1,015) Bln Rs
• Forced Additions: 24,499 MW (16,499+8,000)
(2,674 PV, 435.8 Wind)
• Avg. Consumer Rate: 39.20 (0.91) Rs/Unit
• Least Cost Selection: 1,627 MW (Wind: 1,622)
• Power Purchase Price: 36,572 Bln Rs
• Avg. Consumer Rate: 40.11 Rs/Unit
Market with LCV • Least Cost Selection: 6,740 MW (Wind:1,040, C-5:1,200, DBD:
4,500)
Capacity due to Market: 3,110 MW
(2,674 PV, 435.8 Wind) • LCV C-5 (2032): 0.079 Bln $
• Least Cost Selection: 9,042 MW Wind: 3,342, DBD: 4,500, C-5 1200
10 Plants Retirement • Power Purchase Price: 35,751 (821) Bln Rs
Capacity Retired: 2,101 MW • Avg. Consumer Rate: 39.36 (0.75) Rs/Unit
• Present value impact on other Cons: 360 Bln Rs
* LCV: Least Cost Violation
* Criteria for committed projects: Public Projects: Financial Commitment, Private Projects: Financial Close
Implications: Process to Practice
Savings
through
Process
Implications: Process to Practice
